Aker BP

Quarterly Report • Jul 15, 2021

QUARTERLY AND HALF YEAR REPORT Q2 2021

SECOND QUARTER 2021 SUMMARY

Aker BP reported total income of USD 1,124 (1,133) million and operating profit of USD 614 (591) million for the second quarter 2021. Net profit was USD 154 (127) million. The company paid a dividend of USD 112.5 million (USD 0.3124 per share) in the quarter. All field development projects are progressing as planned.

The company's net production in the second quarter was 198.6 (222.2) thousand barrels of oil equivalents per day (mboepd). The reduction was driven by planned maintenance and project activities at the company's producing assets. Net sold volume was 195.1 (223.2) mboepd. The average realised liquids price increased to USD 66.9 (60.1) per barrel, while the average realised price for natural gas increased to USD 45.1 (38.5) per barrel of oil equivalents (boe).

Production costs for the oil and gas sold in the quarter reduced to USD 158 (176) million. Due to lower production volumes, the average production cost per produced unit increased to USD 9.0 (8.6) per boe. Exploration expenses amounted to USD 102 (71) million. Total cash spend on exploration was USD 143 (86) million, reflecting higher exploration drilling and field evaluation activity. Depreciation was USD 240 (258) million, equivalent to USD 13.3 (12.9) per boe. Net financial expenses were USD 62 (90) million.

This resulted in operating profit of USD 614 (591) million and profit before taxes of USD 552 (501) million. Tax expenses amounted to USD 399 (374) million, and net profit ended at USD 154 (127) million for the quarter.

Capital expenditure for the development of fixed assets amounted to USD 391 (217) million in the second quarter. All field development projects progressed according to plan. Abandonment expenditures were USD 63 (98) million for the quarter.

At the end of the second quarter 2021, Aker BP had total available liquidity of USD 4.4 (4.4) billion. Net interest-bearing debt was USD 2.8 (3.3) billion, including 0.2 (0.2) billion in lease debt. In May, the company issued EUR 750 million Senior Notes with a coupon of 1.125% due in 2029. During the quarter, the company also redeemed its USD 750 million Senior Notes 4.75% (2019/2024) and extended its senior unsecured Revolving Credit Facility.

In May, the company disbursed dividends of USD 112.5 million, equivalent to USD 0.3124 per share. The Board has resolved to pay a quarterly dividend in July 2021 of USD 112.5 million, equivalent to USD 0.3124 per share. The ambition is to pay total dividends of USD 450 million in 2021.

Aker BP continues to apply appropriate measures to minimise the risk to people and operations from the COVID-19 pandemic. The company has established a normalisation plan with three steps towards a state where extraordinary measures are no longer required. In mid-June, the first step of the offshore normalisation plan was implemented. If the situation allows, additional steps on the normalisation plan will be taken in early autumn.

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	Q2 2021	Q1 2021	Q2 2020	2021 YTD	2020 YTD
Total income	USDm	1 124	1 133	590	2 257	1 462
EBITDA	USDm	855	878	329	1 733	994
Net profit/loss	USDm	154	127	170	281	-165
Earnings per share (EPS)	USD	0.43	0.35	0.47	0.78	-0.46
Capex	USDm	391	217	372	608	732
Exploration spend	USDm	143	86	59	229	112
Abandonment spend	USDm	63	98	16	161	39
Production cost	USD/boe	9.0	8.6	9.1	8.8	8.9
Taxes paid/refunded	USDm	-23	-11	81	-35	129
Net interest-bearing debt	USDm	2 818	3 282	3 806	2 818	3 806
Leverage ratio		0.85	1.23	1.46	0.85	1.46
Dividend per share (DPS)	USD	0.31	0.31	0.20	0.62	0.79
Average USDNOK exchange rate		8.37	8.51	10.00	8.44	9.76

Production summary

	UNIT	Q2 2021	Q1 2021	Q2 2020	2021 YTD	2020 YTD
Alvheim area	mboepd	45.9	50.1	58.0	48.0	57.8
Ivar Aasen	mboepd	16.1	20.2	22.1	18.2	22.4
Johan Sverdrup	mboepd	64.3	61.2	51.0	62.7	47.5
Skarv	mboepd	20.6	29.0	20.6	24.8	20.2
Ula area	mboepd	6.4	8.7	10.4	7.6	11.6
Valhall area	mboepd	45.3	53.0	47.0	49.1	48.5
Other	mboepd	0.0	0.0	0.6	0.0	1.0
Net production	mboepd	198.6	222.2	209.8	210.4	208.9
Over/underlift	mboepd	-3.6	1.0	22.2	-1.3	10.8
Net sold volume	mboepd	195.1	223.2	232.0	209.1	219.7
- Liquids	mboepd	163.4	183.0	198.2	173.1	186.2
- Natural gas	mboepd	31.6	40.2	33.8	35.9	33.5
Realised price liquids	USD/boe	66.9	60.1	29.9	63.3	36.8
Realised price natural gas	USD/boe	45.1	38.5	13.2	41.4	17.5

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q2 2021	Q1 2021	Q2 2020	2021 YTD	2020 YTD
Total income	1 124	1 133	590	2 257	1 462
EBITDA	855	878	329	1 733	994
EBIT	614	591	178	1 205	-87
Pre-tax profit	552	501	151	1 054	-263
Net profit/loss	154	127	170	281	-165
EPS (USD)	0.43	0.35	0.47	0.78	-0.46

Total income in the second quarter 2021 amounted to USD 1,124 (1,133) million, as higher oil and gas prices compensated for reduced volume sold. Sold volumes were 195.1 (223.2) mboepd in the quarter. Realised prices increased by 11 percent for liquids and 17 percent for natural gas.

Production costs related to oil and gas sold in the quarter amounted to USD 158 (176) million. Production cost per produced unit amounted to USD 9.0 (8.6) per boe. See note 3 for further details on production costs.

Exploration expenses amounted to USD 102 (71) million. This included field evaluation costs of USD 62 (41) million, and included costs related to finalising the development concept for NOA and Fulla ahead of the upcoming concept select decision, as well as costs related to other future development projects. Dry well expenses were USD 16 (12) million and were mainly related to the Shenzhou exploration well.

Depreciation amounted to USD 240 (258) million, corresponding to USD 13.3 (12.9) per produced barrel. The increase was driven by changes in relative production between the different fields. There were no impairments in the quarter, compared to impairments of USD 30 million in the previous quarter. Other operating expenses amounted to USD 9 (8) million.

Operating profit increased to USD 614 (591) million for the second quarter. Net financial expenses amounted to USD 62 (90) million and included USD 24 million in costs related to early redemption of the company's USD 750 million 4.75% Senior Notes (2019/2024).

Profit before taxes amounted to USD 552 (501) million. Tax expense was USD 399 (374) million. The effective tax rate was 72 percent. See note 8 for further details on tax.

This resulted in a net profit for the second quarter 2021 of USD 154 (127) million.

Statement of financial position

(USD MILLION)	Q2 2021	Q1 2021	Q4 2020	Q2 2020
Total non-current assets	11 381	11 155	11 162	11 050
Total current assets	1 695	1 086	1 258	839
Total assets	13 076	12 241	12 420	11 889
Total equity	2 030	1 989	1 987	1 912
Bank and bond debt	3 615	3 474	3 969	3 712
Total abandonment provisions	2 760	2 753	2 806	2 817
Deferred taxes	3 050	2 782	2 642	2 471
Other liabilities	1 621	1 243	1 016	976
Total equity and liabilities	13 076	12 241	12 420	11 889
Net interest-bearing debt	2 818	3 282	3 647	3 806

At the end of the second quarter 2021, total assets amounted to USD 13,076 (12,241) million, of which current assets were USD 1,695 (1,086) million.

Equity amounted to USD 2,030 (1,989) million at the end of the quarter, corresponding to an equity ratio of 16 (16) percent.

Deferred tax liabilities amounted to USD 3,050 (2,782) million and total abandonment provisions amounted to USD 2,760 (2,753) million. Bank and bond debt totalled USD 3,615 (3,474) million, of which the company's bonds constitute the entire debt at the end of this quarter.

During the quarter, the company redeemed the USD 750 million Senior Notes (2019/2024), carrying a semi-annual fixed coupon of 4.75 percent. The company's inaugural EUR 750 million bond was successfully issued in May under the Euro Medium Term Note programme, due in 2029 with an annual fixed coupon of 1.125 percent and priced at a yield of 1.21

percent. In addition, the senior unsecured Revolving Credit Facility (RCF) was extended during the quarter. The Working Capital Facility was extended from 2022 to 2024 with options for up to two years extension, while the committed amount was reduced from USD 2.0 billion to USD 1.4 billion. The Liquidity Facility was extended from 2025 to 2026, and the committed amount remains USD 2.0 billion until 2025 and then reduces to USD 1.65 billion for the final year. Other terms of the facilities remain unchanged.

At the end of the second quarter, the company had total available liquidity of USD 4.4 (4.4) billion, comprising USD 975 (392) million in cash and cash equivalents, and USD 3.4 (4.0) billion in undrawn credit facilities.

Cash flow

(USD MILLION)	Q2 2021	Q1 2021	Q2 2020*	2021 YTD	2020 YTD*
Cash flow from operations	1 108	900	176	2 009	746
Cash flow from investments	-490	-322	-330	-811	-712
Cash flow from financing	-35	-723	-25	-759	2
Net change in cash & cash equivalents	583	-145	-179	439	36
Cash and cash equivalents	975	392	142	975	142

* As described in note 1, the presentation of payment of borrowing costs in the statement of cash flows has been changed. As from first quarter 2021, these cash flows are presented as financing activities, while they previously were presented as operational activities. Comparative figures have been restated accordingly.

Net cash flow from operating activities was USD 1,108 (900) million in the quarter. The increase was mainly driven by higher realised oil and gas prices and working capital changes.

Net cash used for investment activities was USD 490 (322) million, of which investments in fixed assets amounted to USD 379 (216) million for the quarter. Investments in capitalised exploration were USD 56 (27) million. Payments for decommissioning activities amounted to USD 55 (79) million driven by a campaign to plug and abandon depleted wells, slot recovery

in conjunction with infill drilling on Valhall Flank North, and removal of the old Quarters Platform Jacket at Valhall.

Net cash outflow from financing activities was USD 35 million, compared to an outflow of USD 723 million in the previous quarter. The main items consisted of the issuance of a new bond amounting to USD 899 million, repayment of bonds amounting to USD 768 million and dividend disbursements of USD 113 (113) million.

Risk management

The company seeks to reduce the risk related to foreign exchange, interest rates and commodity prices through hedging instruments. The company actively manages its exposures through a mix of forward contracts and options.

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

OIL PUT OPTIONS	Q3 2021	Q4 2021	Q1 2022	Q2 2022	Q3 2022
Share of oil prod. covered (after tax)	72 %	71 %	58 %	57 %	0 %
Average strike (USD/bbl)	46	46	45	45	-
Average premium (USD/bbl)	2.1	2.1	1.9	1.9	-

Dividends

At the Annual General Meeting in April 2021, the Board was authorised to approve the distribution of dividends based on the company's annual accounts for 2020 pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.

Both in February and May, the company disbursed dividends of USD 112.5 million, equivalent to USD 0.3124 per share.

On 14 July 2021, the Board resolved to pay a quarterly dividend of USD 112.5 million (USD 0.3124 per share) on or about 28 July 2021. The ambition is to pay total dividends in 2021 of USD 450 million.

OPERATIONAL REVIEW

Aker BP's net production was 18.1 (20.0) mmboe in the second quarter of 2021, corresponding to 198.6 (222.2) mboepd. Net sold volume was 195.1 (223.2) mboepd. The average realised liquids price was USD 66.9 (60.1) per barrel, while the average realised gas price was USD 45.1 (38.5) per boe.

Alvheim Area

KEY FIGURES	AKER BP INTEREST	Q2 2021	Q1 2021	Q4 2020	Q3 2020	Q2 2020
Production, boepd
Alvheim	65 %	34 799	35 176	35 921	29 447	33 770
Bøyla	65 %	1 191	2 921	3 843	4 858	6 568
Skogul	65 %	4 542	4 450	6 891	8 091	7 899
Vilje	46.904 %	1 789	2 707	2 899	2 616	3 259
Volund	65 %	3 602	4 892	5 192	6 200	6 511
Total production		45 923	50 147	54 746	51 212	58 006
Production efficiency		91%	99 %	98 %	92 %	96 %

Second quarter production from the Alvheim area was 45.9 mboepd net to Aker BP, down 8 percent from the previous quarter. Production efficiency was 91 percent.

The reduction in produced volumes was mainly driven by natural decline and a planned production slowdown in April, when required maintenance and work on the gas de-bottlenecking project was carried out. The Frosk test producer has been shut in pending well intervention in September. However, the production decline in the second quarter was partly offset by new volumes from the Boa Attic South well which came on stream at the end of the first quarter.

During the quarter, a final investment decision was made for a dual-lateral well on Kameleon Infill West (KIW). This well will be drilled by the Semi-submersible rig Deepsea Nordkapp after it has finished the drilling of a single lateral sidetrack well on the Volund field, which was sanctioned in the previous quarter. First oil from the new Volund well and from the well on KIW

is expected in fourth quarter 2021 and first quarter 2022 respectively.

The Frosk development project has been matured towards a final investment decision, scheduled to take place in the third quarter this year. The Trell and Trine project is on schedule towards concept select by the end of the year.

On 30 June, the company and its licence partners submitted a plan for development and operation (PDO) for Kobra East & Gekko (KEG) to the Ministry of Petroleum and Energy. Gross investments in the project are estimated to approximately USD 1 billion and production is scheduled to start in the first quarter of 2024. Recoverable reserves in KEG are estimated at around 40 million mmboe gross. Aker BP holds 65 percent interest in KEG. The development will be carried out in cooperation with Aker BP's alliance partners. The estimated break-even price for the project is below USD 30 per barrel.

Ivar Aasen

KEY FIGURES	AKER BP INTEREST	Q2 2021	Q1 2021	Q4 2020	Q3 2020	Q2 2020
Production, boepd
Total production	34.7862 %	16 129	20 206	18 723	17 025	22 089
Production efficiency		89 %	90 %	90 %	75 %	98 %

Second quarter production from Ivar Aasen was 16.1 mboepd net to Aker BP, down 20 percent from the previous quarter. The reduction was mainly caused by gas export restrictions from SAGE due to maintenance at other gas fields in the pipeline system and multiple unplanned shutdowns at Edvard Grieg, which supplies Ivar Aasen with power and processing. From fourth quarter 2022, both Edvard Grieg and Ivar Aasen will receive power from shore via the Johan Sverdrup platform. Production efficiency at Ivar Aasen remained stable at 89 percent, compared to 90 percent in the previous quarter.

Preparations are underway for the 2021 drilling campaign. One oil producer and one water injector will be drilled by the jack-up rig Maersk Integrator. First oil is targeted in the fourth quarter 2021.

The Hanz project is progressing as planned and passed concept select in the second quarter. Work towards the final investment decision by the end of the year is ongoing. First oil from Hanz is currently expected in first quarter 2024.

Johan Sverdrup

KEY FIGURES	AKER BP INTEREST	Q2 2021	Q1 2021	Q4 2020	Q3 2020	Q2 2020
Production, boepd
Total production	11.5733 %	64 262	61 178	59 613	53 051	51 027

Production at Johan Sverdrup continued with high regularity through the second quarter of 2021. Production efficiency since start-up has been above 96 percent and around 99 percent in the last 6 months.

Process capacity was further increased in early May from 500,000 to 535,000 barrels per day following comprehensive capacity testing and water injection capacity upgrade to ensure full voidage replacement and close to original reservoir pressure.

Phase 2 of the Johan Sverdrup development progressed safely according to plan and cost, despite challenges caused by COVID-19. The three modules for the second processing platform were integrated as planned before hook-up and commissioning started at Aibel's construction site in Haugesund

Offshore installation at the field centre is planned in the first half of 2022.

The jacket for the second processing platform, constructed by Aker Solutions in Verdal, was installed offshore as planned in June. The Riser-Platform-module constructed by Aker Solutions at Stord is planned to be installed offshore in July. The five subsea templates have been installed and installation of the power cable from shore is completed.

Ongoing studies indicate that the full field process capacity can be increased to 755,000 barrels per day when Phase 2 is finished in late 2022. The estimated break-even price for the full field has been reduced from below 20 dollars per barrel to below 15 dollars per barrel.

Skarv Area

KEY FIGURES	AKER BP INTEREST	Q2 2021	Q1 2021	Q4 2020	Q3 2020	Q2 2020
Production, boepd
Total production	23.835 %	20 581	28 973	26 121	17 544	20 599
Production efficiency		58 %	84 %	98 %	86 %	97 %

Production in the quarter was 20.6 mboepd net to Aker BP, down 29 percent from the previous quarter. Production efficiency decreased from 84 percent to 58 percent. The reduction was mainly a result of a planned turnaround to increase the gas handling capacity, in addition to a few days of unplanned downtime due to operational challenges with the power supply which have now been resolved. The increased gas capacity on the Skarv FPSO will cater for further gas discoveries in the area.

Production from Gråsel started in June, six months after the final investment decision and four months ahead of the original schedule. The record-fast implementation was enabled by early access to a drilling rig and an agile project team. The Gråsel development consists of a new producer drilled from an existing well slot on the Skarv field, with pressure support from a shared injector for Gråsel and Tilje. The reservoir contains

around 13 million barrels of oil equivalents. The development has an estimated break-even price of around USD 15 per barrel.

The Ærfugl Phase 2 project is progressing well with offshore preparations on track. The project remains on schedule for planned production start in the fourth quarter 2021.

The Skarv FPSO has the capacity to become a central hub for several surrounding discoveries. Together with its partners, Aker BP has continued to mature the Skarv satellites project during the quarter. The partners in the Ørn gas discovery have chosen Skarv as the host installation for this development. Following this decision, the operatorship for the Ørn development will be transferred from Equinor to Aker BP.

Ula Area

KEY FIGURES	AKER BP INTEREST	Q2 2021	Q1 2021	Q4 2020	Q3 2020	Q2 2020
Production, boepd
Ula	80 %	3 539	5 464	6 239	3 929	4 250
Tambar	55 %	1 927	1 413	1 092	2 595	2 932
Oda	15 %	930	1 865	2 959	3 887	3 258
Total production		6 396	8 741	10 290	10 411	10 441
Production efficiency		64 %	80 %	75 %	87 %	80 %

Production and production efficiency from the Ula area decreased in the second quarter, mainly due to planned shutdowns. The shutdowns were related to modifications and drilling of an infill well. In addition, production from Oda continued to decline due to increased water breakthrough. The reduction in Ula area production was partly mitigated by the increase in production from Tambar where a new well started production in May.

The jack-up rig Maersk Integrator left the Tambar field and arrived at Ula in mid-April for drilling of an infill well. The drilling operation was completed in mid-June, and the rig left the Ula field ahead of the original schedule.

The Ula Power Project progressed well in the quarter, and the second gas turbine was put into operation. Work on the third and final gas turbine is estimated to be finished in first quarter next year.

Valhall Area

KEY FIGURES	AKER BP INTEREST	Q2 2021	Q1 2021	Q4 2020	Q3 2020	Q2 2020
Production, boepd
Valhall	90 %	44 699	52 526	52 881	51 647	46 750
Hod	90 %	596	446	682	682	225
Total production		45 295	52 972	53 564	52 329	46 975
Production efficiency		81 %	91 %	90 %	90 %	78 %

Second quarter production from Valhall was 45.3 mboepd net to Aker BP, down 14 percent from the previous quarter, mainly driven by a planned shutdown to perform safety-critical maintenance and to test the emergency shut down system. The scope was delivered according to plan.

The Maersk Invincible drilling rig finalised the campaign to plug and abandon depleted wells at the old drilling platform (DP) in the quarter. The rig then moved to Flank North for drilling of three infill wells, of which two were finalised during the quarter. After finishing the third infill well at Flank North, the rig will move to Hod for drilling of the six wells for the Hod field development.

The Hod field development is progressing as planned with construction of a wellhead platform at the Aker Solutions yard in Verdal. The jacket was safely installed at the field in early July and is ready to receive the topside module later in the third

North of Alvheim and Krafla-Askja (NOAKA)

The NOAKA area 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 more than 500 million barrels of oil equivalents, with further exploration and appraisal potential. The partners in the licences are Aker BP ASA, Equinor ASA and LOTOS Exploration & Production Norge AS.

During the second quarter, Aker BP continued working with its strategic partners to finalise the development concept for NOA and Fulla, including quality assurance and documentation for a formal concept select decision scheduled for the third quarter this year.

The development concept includes a fixed platform at the Frigg Gamma Delta fields, operated by Aker BP. The fixed platform will function as an area hub, with processing, drilling, and living quarters. In June, Aker BP awarded a FEED contract with the option for installation of the platform topside to Allseas.

The oil will be exported via Oseberg transport system and the gas will be exported through Statpipe. The area will be powered from shore to ensure minimal carbon footprint.

quarter. The offshore work related to tie-in to existing facilities at Valhall and subsea installation campaigns has also been initiated.

The Maersk Reacher rig will arrive Valhall during the third quarter. This will contribute to accelerating the stimulation and intervention activity and bring more wells up to their full production potential.

In the second quarter, the Original Valhall Decommissioning Project (OVD) reached a new milestone when the old Quarters Platform Jacket (QP) was removed. The topside was removed in 2019.

Planning of the Valhall NCP (New Central Platform) project continued in the second quarter. The project will add new slots for further development of the Valhall Area. A concept select decision is planned in the third quarter.

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 area hub at Frigg Gamma Delta.

The development concept has flexibility for potential tie-in of new discoveries. One such potential discovery is Liatårnet, where an appraisal well will be drilled during the third quarter by the Semi-submersible rig Deepsea Nordkapp. The purpose of this well is to gather data on reservoir properties and oil quality, which in turn will be used to evaluate the commerciality of this discovery.

Equinor is the operator for Krafla and is maturing the Krafla concept in close collaboration with Aker BP to optimise the total area development concept. The Krafla development will be tied back to the area hub at Frigg Gamma Delta for oil and produced water processing. All partners in the area have started planning for the next phase leading up to final investment decision in fourth quarter 2022.

EXPLORATION

Total exploration spend in the second quarter was USD 143 (86) million, while USD 102 (71) million was recognised as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation and G&G costs.

Field evaluation costs are driven by activities related to discoveries and projects which have not yet been sanctioned. In the second quarter, these costs amounted to USD 62 (41) million, with NOAKA as the main driver.

The drilling of the Garantiana West prospect in licence 544 was completed in the quarter and resulted in an oil discovery. Recoverable resources are estimated to 8-23 million barrels of oil equivalents. The licence partners will consider including the discovery in the Garantiana field development project. The licence is operated by Equinor and Aker BP has an ownership interest of 30 percent.

Drilling of the Shenzhou prospect in licence 722 in the Barents Sea, operated by Equinor, was also completed in the quarter. Aker BP has an ownership interest of 20 percent in the licence. The well was drilled by the Semi-submersible rig Deepsea Nordkapp. The well was classified as dry and has been permanently plugged and abandoned.

After finishing the Shenzhou prospect, Deepsea Nordkapp moved to the Stangnestind prospect in licence 858 in the Barents Sea. Aker BP is the operator with an ownership interest of 40 percent. Operations at Stangnestind were still ongoing at the time of this report. This licence was awarded in June 2016 and is the final well in the company's Barents Sea campaign.

BUSINESS DEVELOPMENT

In the second quarter, Aker BP entered into an agreement to take over the operatorship of the Ørn discovery in licence 942 from Equinor Energy AS. The change in operatorship is a result of an area collaboration to find optimal development solutions in the Skarv area. The ownership interest is unchanged, and Aker BP continues to hold a 30 percent interest in the licence. The operatorship will be transferred to Aker BP following customary regulatory approvals.

Aker BP also entered into an agreement with DNO Norge AS to diversify interests in exploration targets in the Southern North Sea. As part of the agreement, Aker BP reduced its interest in the Tanumåsen prospect in licence 1085 by 25 percent and in the Mugnetind prospect in licence 906 by 10 percent, while the company increases its interest in the Gomez prospect in licence 006C by 20 percent. Drilling of the Gomez prospect is planned in the third quarter 2021. Following the transaction, Aker BP holds 55 percent in Tanumåsen, 50 percent in Mugnetind and 35 percent Gomez. The agreement is subject to customary regulatory approvals.

During the second quarter, Aker BP received regulatory approval and completed the previously announced swap transaction with Lundin Energy Norway AS to align ownership interests in the Alvheim area. Through this transaction, Aker BP reduced its interest in the Trine and Trell area (licences PL036E, PL036F, PL102D, PL102F, PL102G and PL102H) by six percent, and increased its interest in the Froskelår discovery (licence PL869) by five percent and in the Lyderhorn exploration prospect (licence PL1041) by 15 percent. Following the transaction, Aker BP holds 65 percent in Froskelår, 58 percent in Trine, 44 percent in Trell and 55 percent in Lyderhorn.

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	Q2 2021	Q1 2021	Q4 2020	Q3 2020	Q2 2020
Total recordable injury frequency (TRIF) L12M	Per mill. exp. hours	1.2	1.3	1.2	1.2	1.7
Serious incident frequency (SIF) L12M	Per mill. exp. hours	0	0	0.2	0.2	0.2
Acute spill	Count	0	0	0	1	0
Process safety events Tier 1 and 2	Count	0	0	0	0	0
CO2 emissions intensity L12M	Kg CO2/boe	4.2	4.3	4.5	5.0	5.7

The overall HSSE performance continues to show a positive trend. The company maintains its systematic and targeted approach to further improve the HSSE performance. To strengthen the focus on safety in a period of high activity on the offshore installations, the company is conducting an awareness campaign during the summer months.

The work to protect personnel and to ensure uninterrupted production from all assets during the COVID-19 pandemic continues. Aker BP has established a normalisation plan with three steps towards a state where extraordinary measures are no longer required. In mid-June, the first step of the offshore normalisation plan was implemented. If the situation allows, additional steps on the normalisation plan will be taken in early autumn.

REPORT FOR THE FIRST HALF 2021

	UNIT	PER 30 JUNE 2021	PER 30 JUNE 2020
Total production	mboepd	210.4	208.9
Realised price liquids	USD/boe	63.3	36.8
Total income	USDm	2 257	1 462
EBITDA	USDm	1 733	994
Net profit	USDm	281	-165
Net interest-bearing debt	USDm	2 818	3 806

During the first six months of 2021, the company reported total income of USD 2,257 (1,462)* million. The increase compared with the first half 2020 was mainly driven by the higher realised liquids and gas prices. Production in the period increased to 210.4 (208.9) thousand barrels of oil equivalent per day (mboepd). Average realised liquids prices increased to USD 63.3 per barrel of oil equivalents, compared to USD 36.8 in the first half 2020, while the average realised price for natural gas increased to USD 41.4 (17.5) per barrel of oil equivalents (boe).

Production costs for the oil and gas sold were USD 334 (352) million. Production costs were USD 8.8 (8.9) per produced boe, in line with the guiding of USD 8.5-9.0 per boe in 2021.

Exploration expenses amounted to USD 173 (100) million. EBITDA amounted to USD 1,733 (994) million and EBIT was USD 1,205 (-87) million. Net profit for the first half of 2021 was USD 281 million, compared to a net loss of USD 165 million for the first half of 2020.

Net cash flow from operating activities amounted to USD 2,009 (746) million, driven by the higher oil and gas prices and lower tax payments. Net cash flow to investment activities amounted to USD 811 (712) million, driven by field development activities across the company's portfolio. Net cash

outflow from financing activities was USD 759 million, compared to an inflow of USD 2 million in the previous period.

Two bonds have been redeemed during the first half of 2021. The company's USD 500 million Senior Notes 5.875% (2018/2025) were redeemed in March, and the USD 750 million Senior Notes 4.75% (2019/2024) were redeemed in June. In May, the company issued EUR 750 million Senior Notes with a coupon of 1.125% due in 2029. Furthermore, the maturity for the senior unsecured Revolving Credit Facility (RCF) was extended in the period.

As of 30 June 2021, the company had net interest-bearing debt of USD 2,818 (3,806) million. Available liquidity was USD 4.4 (3.7) billion comprising of cash and cash equivalents of USD 975 (142) million and undrawn credit facilities of USD 3.4 (3.6) billion.

HSSE remains 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. The company delivered strong HSSE performance during the first half of 2021, with a strong safety record, efficient management of the COVID-19 pandemic and low CO2 emissions per unit produced.

^* In the report for the first-half 2021 all figures in brackets apply to first-half 2020.

RISKS AND UNCERTAINTY

Investment in Aker BP involves risks and uncertainties as described in the Board of Director's report in the company's annual report for 2020.

As an oil and gas company operating on the Norwegian Continental Shelf, exploration results, reserve and resource estimates and estimates for capital and operating expenditures are associated with uncertainty. The production performance of oil and gas fields may be variable over time.

The company is exposed to various forms of financial risks, including, but not limited to, fluctuation in oil prices, exchange rates, interest rates and capital requirements; these are described in the company's annual report and accounts, and in note 28 to the accounts for 2020. The company is also exposed to uncertainties relating to the international capital markets and access to capital and this may influence the speed with which development projects can be brought on stream.

The COVID-19 pandemic has caused significant business disruption globally and may impact the longer-term demand for oil and gas. This represents a risk to the company's future price realisations, results from operations, cash flows, financial condition, and access to capital.

The pandemic also represents an additional risk of interruptions to the company's operations with potential negative effect on the company's results from operations and cash flows, as it could lead to temporary production shortfalls, increased costs and / or delays or cancellations to the company's investment program. Correspondingly, there is also a risk of future impairments of the book value of the company's assets.

OUTLOOK

Aker BP's main priorities are the safety of its people and the environment as well as its main financial priorities which are to secure the company's financial robustness, to protect its investment grade credit profile, and to maintain financial flexibility to pursue value-accretive growth opportunities going forward.

The company has a strong financial position and remains well positioned for future value creation. The main items of the company's financial plan for 2021 are unchanged since the previous quarter and are as follows*:

• Production of 210-220 mboepd
• Capex of USD ~1.6 billion
• Exploration spend of USD 400-500 million
• Abandonment spend of USD ~200 million
• Production cost of USD 8.5-9.0 per boe
• Dividends of USD 450 million

^*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
		Q2	Q1	Q2		01.01.-30.06.
(USD 1 000)	Note	2021	2021	2020	2021	2020
Petroleum revenues		1 128 183	1 132 700	584 170	2 260 883	1 363 254
Other income		-4 429	537	5 614	-3 891	98 635
Total income	2	1 123 754	1 133 238	589 784	2 256 992	1 461 889
Production costs	3	158 235	175 906	196 174	334 140	352 217
Exploration expenses	4	102 020	70 917	49 774	172 937	100 110
Depreciation	5	240 372	257 554	286 353	497 926	563 765
Impairments	5	-	29 656	-135 872	29 656	517 825
Other operating expenses		8 965	8 225	14 897	17 191	15 120
Total operating expenses		509 592	542 258	411 326	1 051 850	1 549 038
Operating profit/loss		614 162	590 980	178 458	1 205 142	-87 148
Interest income		331	366	1 224	697	2 593
Other financial income		46 197	9 515	112 550	51 680	82 203
Interest expenses		39 432	47 011	47 430	86 443	87 471
Other financial expenses		68 840	52 717	93 762	117 525	173 435
Net financial items	7	-61 744	-89 846	-27 418	-151 591	-176 110
Profit/loss before taxes		552 418	501 134	151 040	1 053 551	-263 258
Tax expense (+)/income (-)	8	398 607	374 104	-18 649	772 711	-98 213
Net profit/loss		153 811	127 029	169 689	280 841	-165 045
Weighted average no. of shares outstanding basic and diluted		359 610 213	359 839 591	359 613 509	359 724 268	359 798 949
Basic and diluted earnings/loss USD per share		0.43	0.35	0.47	0.78	-0.46

STATEMENT OF COMPREHENSIVE INCOME

	Group
	Q2	Q1	Q2	01.01.-30.06.
(USD 1 000) Note	2021	2021	2020	2021	2020
Profit/loss for the period	153 811	127 029	169 689	280 841	-165 045
Total comprehensive income/loss in period	153 811	127 029	169 689	280 841	-165 045

STATEMENT OF FINANCIAL POSITION

	Group
(USD 1 000)	Note	30.06.2021	31.03.2021	31.12.2020	30.06.2020
ASSETS
Intangible assets
Goodwill	5	1 647 436	1 647 436	1 647 436	1 647 436
Capitalized exploration expenditures	5	475 456	462 637	521 922	487 027
Other intangible assets	5	1 397 743	1 416 065	1 521 311	1 566 521
Tangible fixed assets
Property, plant and equipment	5	7 630 389	7 392 321	7 266 137	7 175 129
Right-of-use assets	5	115 705	126 861	132 735	137 296
Financial assets
Long-term receivables		74 626	74 927	29 086	25 535
Other non-current assets		34 868	29 042	30 210	10 709
Long-term derivatives	11	4 560	5 955	12 841	-
Total non-current assets		11 380 784	11 155 243	11 161 678	11 049 653
Inventories
Inventories		121 826	110 895	112 704	99 324
Receivables
Trade receivables		341 247	274 510	297 880	82 722
Tax receivables	8	-	-	-	186 630
Other short-term receivables	9	238 307	283 742	286 817	327 922
Short-term derivatives	11	18 327	24 532	23 212	-
Cash and cash equivalents
Cash and cash equivalents	10	975 360	392 276	537 801	142 333
Total current assets		1 695 066	1 085 955	1 258 414	838 931
TOTAL ASSETS		13 075 850	12 241 198	12 420 091	11 888 584

STATEMENT OF FINANCIAL POSITION

		Group
(USD 1 000)	Note	30.06.2021	31.03.2021	31.12.2020	30.06.2020
EQUITY AND LIABILITIES
Equity
Share capital		57 056	57 056	57 056	57 056
Share premium		3 637 297	3 637 297	3 637 297	3 637 297
Other equity		-1 664 048	-1 705 359	-1 707 071	-1 782 268
Total equity		2 030 304	1 988 993	1 987 281	1 912 084
Non-current liabilities
Deferred taxes	8	3 050 315	2 781 602	2 642 461	2 471 221
Long-term abandonment provision	15	2 679 423	2 665 343	2 650 263	2 640 527
Long-term bonds	13	3 614 833	3 474 328	3 968 566	3 121 781
Long-term derivatives	11	1 114	-	-	14 951
Long-term lease debt	6	99 548	115 299	131 856	156 396
Other interest-bearing debt	14	-	-	-	380 708
Total non-current liabilities		9 445 232	9 036 572	9 393 146	8 785 584
Current liabilities
Trade creditors		121 435	83 157	113 517	93 702
Short-term bonds	13	-	-	-	209 803
Accrued public charges and indirect taxes		26 066	18 226	25 761	27 217
Tax payable	8	597 387	452 131	163 352	-
Short-term derivatives	11	24 534	6 293	3 539	89 867
Short-term abandonment provision	15	80 230	87 850	155 244	176 520
Short-term lease debt	6	79 432	85 047	83 904	79 863
Other current liabilities	12	671 228	482 929	494 346	513 945
Total current liabilities		1 600 313	1 215 633	1 039 664	1 190 916
Total liabilities		11 045 546	10 252 205	10 432 810	9 976 500
TOTAL EQUITY AND LIABILITIES		13 075 850	12 241 198	12 420 091	11 888 584

STATEMENT OF CHANGES IN EQUITY - GROUP

				Other equity
					Other comprehensive income
					Foreign currency
		Share	Other paid-in	Actuarial	translation	Accumulated	Total other
(USD 1 000)	Share capital	premium	capital	gains/losses	reserves1)	deficit	equity	Total equity
Equity as of 31.12.2019	57 056	3 637 297	573 083	-85	-115 491	-1 784 274	-1 326 767	2 367 585
Dividend distributed	-	-	-	-	-	-212 500	-212 500	-212 500
Profit/loss for the period	-	-	-	-	-	-334 734	-334 734	-334 734
Purchase of treasury shares2)	-	-	-	-	-	-7 122	-7 122	-7 122
Equity as of 31.03.2020	57 056	3 637 297	573 083	-85	-115 491	-2 338 630	-1 881 123	1 813 229
Dividend distributed	-	-	-	-	-	-70 833	-70 833	-70 833
Profit/loss for the period	-	-	-	-	-	169 689	169 689	169 689
Equity as of 30.06.2020	57 056	3 637 297	573 083	-85	-115 491	-2 239 774	-1 782 268	1 912 084
Dividend distributed	-	-	-	-	-	-141 667	-141 667	-141 667
Profit/loss for the period	-	-	-	-	-	209 760	209 760	209 760
Purchase/sale of treasury shares2)	-	-	-	-	-	7 094	7 094	7 094
Other comprehensive income for the period	-	-	-	9	-	-	9	9
Equity as of 31.12.2020	57 056	3 637 297	573 083	-76	-115 491	-2 164 587	-1 707 071	1 987 281
Dividend distributed	-	-	-	-	-	-112 500	-112 500	-112 500
Profit/loss for the period	-	-	-	-	-	127 029	127 029	127 029
Purchase of treasury shares2)	-	-	-	-	-	-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
Dividend distributed	-	-	-	-	-	-112 500	-112 500	-112 500
Profit/loss for the period	-	-	-	-	-	153 811	153 811	153 811
Equity as of 30.06.2021	57 056	3 637 297	573 083	-76	-115 491	-2 121 564	-1 664 048	2 030 304

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

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

STATEMENT OF CASH FLOW

				Group
		Q2	Q1	Q2		01.01.-30.06.
				Restated		Restated
(USD 1 000)	Note	2021	2021	2020	2021	2020
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		552 418	501 134	151 040	1 053 551	-263 258
Taxes paid	8		-	-80 581	-	-128 731
Taxes refunded	8	23 220	11 420	-	34 640	-
Depreciation	5	240 372	257 554	286 353	497 926	563 765
Impairment Accretion expenses	5 7,15	- 28 641	29 656 27 668	-135 872 29 474	29 656 56 309	517 825 58 738
Total interest expenses (excluding amortized loan costs)	7	30 426	39 638	42 500	70 064	77 505
Changes in derivatives	2,7	26 955	8 321	-39 080	35 275	64 529
Amortized loan costs	7	9 006	7 372	4 930	16 379	9 966
Expensed capitalized dry wells	4,5	15 780	12 201	9 866	27 981	38 847
Changes in inventories, trade creditors and receivables		-39 389	-5 181	-89 159	-44 570	47 697
Changes in other current balance sheet items		220 797	10 577	-3 708	231 373	-240 870
NET CASH FLOW FROM OPERATING ACTIVITIES		1 108 226	900 358	175 763	2 008 584	746 015
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields		-54 572	-78 576	-15 007	-133 148	-35 936
Disbursements on investments in fixed assets (excluding capitalized interest)		-378 887	-216 162	-350 541	-595 048	-680 149
Disbursements on investments in capitalized exploration		-56 267	-26 978	-19 413	-83 246	-50 666
Cash received from sale of licenses		-	-	54 747	-	54 747
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-489 726	-321 717	-330 214	-811 442	-712 004
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment/fees related to revolving credit facility		-7 675	-	98 450	-7 675	-1 051 550
Repayment of bonds		-767 813	-514 690	-	-1 282 503	-
Net proceeds from bond issue		899 334	-	-	899 334	1 483 906
Interest paid (including interest element of lease payments)		-25 291	-62 585	-22 653	-87 876	-78 607
Payments on lease debt related to investments in fixed assets		-10 360	-740	-18 372	-11 100	-44 978
Payments on other lease debt		-10 837	-20 051	-11 609	-30 889	-16 792
Paid dividend		-112 500	-112 500	-70 833	-225 000	-283 333
Net purchase/sale of treasury shares		-	-12 818	-	-12 818	-7 122
NET CASH FLOW FROM FINANCING ACTIVITIES		-35 142	-723 384	-25 018	-758 527	1 523
Net change in cash and cash equivalents		583 358	-144 742	-179 469	438 616	35 533
Cash and cash equivalents at start of period		392 276	537 801	322 789	537 801	107 104
Effect of exchange rate fluctuation on cash held		-273	-783	-987	-1 056	-305
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	975 360	392 276	142 333	975 360	142 333

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 2020 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 14 July 2021.

Note 1 Accounting principles

The accounting principles used for this interim report are consistent with the principles used in the group's 2020 annual financial statements, except for a change in presentation of payment of borrowing costs in the statement of cash flows. From Q1 2021, the group presents these cash flows as financing activities, while they prior to 2021 were presented as operational and investment activities. The reason behind the change is that borrowing costs are directly linked to the group's financing activities, and are thus deemed more relevant to include under financing activities. Comparative figures have been restated accordingly and the impact on relevant previous periods is included in the table below.

	Q2	01.01.-30.06.
Breakdown of restating impact on Statetment of Cash Flow (USD 1 000)	2020	2020
NET CASH FLOW FROM OPERATING ACTIVITIES
- Prior to restating	162 083	685 780
- After restating	175 763	746 015
Change	13 680	60 234
NET CASH FLOW FROM INVESTMENT ACTIVITIES
- Prior to restating	-339 186	-733 877
- After restating	-330 214	-712 004
Change	8 972	21 873
NET CASH FLOW FROM FINANCING ACTIVITIES
- Prior to restating	-2 365	83 630
- After restating	-25 018	1 523
Change	-22 653	-82 107
Impact on net change in cash and cash equivalents	-	-

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 2020 annual financial statements. The COVID-19 pandemic and associated uncertainties and disruption to the global economy may have negative effects on demand for oil and gas and / or result in interruptions to the group's operations. Such events may adversely impact the group's future results from operations and cash flows, and may lead to impairment of assets.

Note 2 Income

	Group
	Q2	Q1	Q2	01.01.-30.06.
Breakdown of petroleum revenues (USD 1 000)	2021	2021	2020	2021	2020
Sales of liquids	995 281	989 511	539 643	1 984 792	1 248 570
Sales of gas	129 801	139 224	40 652	269 025	106 839
Tariff income	3 101	3 966	3 874	7 067	7 845
Total petroleum revenues	1 128 183	1 132 700	584 170	2 260 883	1 363 254
Sales of liquids (boe 1 000)	14 871	16 468	18 036	31 339	33 895
Sales of gas (boe 1 000)	2 879	3 620	3 073	6 499	6 099
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-3 044	-3 044	55 914	-6 087	70 397
Unrealized gain/loss (-) on oil derivatives	-10 663	-2 312	-70 764	-12 975	-2 348
Gain on license transactions	-	-	5 417	-	5 417
Other income1)	9 278	5 893	15 047	15 171	25 169
Total other income	-4 429	537	5 614	-3 891	98 635

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

Note 3 Production costs

	Group
	Q2	Q1	Q2	01.01.-30.06.
Breakdown of production cost (USD 1 000)	2021	2021	2020	2021	2020
Cost of operations	106 674	112 523	124 429	219 197	238 769
Shipping and handling	43 814	47 719	40 237	91 532	82 155
Environmental taxes	12 176	10 834	8 813	23 010	17 773
Production cost based on produced volumes	162 663	171 076	173 479	333 739	338 696
Adjustment for over/underlift (-)	-4 429	4 830	22 695	401	13 521
Production cost based on sold volumes	158 235	175 906	196 174	334 140	352 217
Total produced volumes (boe 1 000)	18 075	19 999	19 090	38 074	38 028
Production cost per boe produced (USD/boe)	9.0	8.6	9.1	8.8	8.9

Note 4 Exploration expenses

	Group
	Q2	Q1	Q2	01.01.-30.06.
Breakdown of exploration expenses (USD 1 000)	2021	2021	2020	2021	2020
Seismic	11 893	4 213	21 559	16 106	23 961
Area fee	3 731	4 167	4 371	7 898	8 143
Field evaluation	61 685	40 643	6 790	102 328	13 321
Dry well expenses1)	15 780	12 201	9 866	27 981	38 847
Other exploration expenses	8 932	9 693	7 188	18 624	15 838
Total exploration expenses	102 020	70 917	49 774	172 937	100 110

1) Dry well expenses in Q2 2021 are mainly related to the Shenzhou 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	137 414	87 760	6 073	231 247
Disposals/retirement	-	-	-	-
Reclassification	-172 675	244 384	2 597	74 305
Acquisition cost 31.03.2021	1 053 493	10 219 019	249 974	11 522 485
Accumulated depreciation and impairments 31.12.2020	-	3 824 491	126 305	3 950 795
Depreciation	-	221 906	10 598	232 504
Impairment/reversal (-)	-	-53 135	-	-53 135
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 31.03.2021	-	3 993 262	136 903	4 130 165
Book value 31.03.2021	1 053 493	6 225 757	113 071	7 392 321
Acquisition cost 31.03.2021	1 053 493	10 219 019	249 974	11 522 485
Additions	270 077	152 635	2 079	424 791
Disposals/retirement	-	-	-	-
Reclassification	153	32 336	-	32 489
Acquisition cost 30.06.2021	1 323 722	10 403 990	252 053	11 979 765
Accumulated depreciation and impairments 31.03.2021	-	3 993 262	136 903	4 130 165
Depreciation	-	207 996	11 216	219 212
Impairment/reversal (-)	-	-	-	-
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 30.06.2021	-	4 201 258	148 118	4 349 376
Book value 30.06.2021	1 323 722	6 202 732	103 935	7 630 389

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	-	-	5 282	-	5 282
Allocated to abandonment activity	-7 388	-932	-	-	-8 319
Disposals/retirement	-	-	-	-	-
Reclassification	-	-242	-	-	-242
Acquisition cost 31.03.2021	40 575	60 842	51 709	2 303	155 430
Accumulated depreciation and impairments 31.12.2020	6 099	4 620	14 902	353	25 974
Depreciation	-	490	2 060	44	2 595
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 31.03.2021	6 099	5 110	16 962	397	28 569
Book value 31.03.2021	34 476	55 732	34 747	1 906	126 861
Acquisition cost 31.03.2021	40 575	60 842	51 709	2 303	155 430
Additions	-	-	-	-	-
Allocated to abandonment activity1)	-3 166	-331	-	-	-3 497
Disposals/retirement	-	-	-	-	-
Reclassification2)	-4 222	-599	-	-	-4 821
Acquisition cost 30.06.2021	33 188	59 912	51 709	2 303	147 112
Accumulated depreciation and impairments 31.03.2021	6 099	5 110	16 962	397	28 569
Depreciation	-	734	2 060	44	2 839
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 30.06.2021	6 099	5 844	19 023	441	31 407
Book value 30.06.2021	27 088	54 068	32 687	1 862	115 705

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

	Other intangible assets		Capitalized exploration
(USD 1 000)	Licenses etc.	Software	Total	expenditures	Goodwill
Book value 31.12.2020	1 521 311	-	1 521 311	521 922	1 647 436
Acquisition cost 31.12.2020	2 368 985	7 501	2 376 486	668 029	2 726 583
Additions		-		26 978	-
Disposals/retirement/expensed dry wells	-	-	-	12 201	-
Reclassification	-	-	-	-74 063	-
Acquisition cost 31.03.2021	2 368 985	7 501	2 376 486	608 743	2 726 583
Accumulated depreciation and impairments 31.12.2020	847 674	7 501	855 175	146 107	1 079 146
Depreciation	22 455	-	22 455	-	-
Impairment/reversal (-)	82 791	-	82 791	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 31.03.2021	952 920	7 501	960 421	146 107	1 079 146
Book value 31.03.2021	1 416 065	-	1 416 065	462 637	1 647 436
Acquisition cost 31.03.2021	2 368 985	7 501	2 376 486	608 743	2 726 583
Additions		-		56 267	-
Disposals/retirement/expensed dry wells	-	-	-	15 780	-
Reclassification	-	-	-	-27 668	-
Acquisition cost 30.06.2021	2 368 985	7 501	2 376 486	621 563	2 726 583
Accumulated depreciation and impairments 31.03.2021	952 920	7 501	960 421	146 107	1 079 146
Depreciation	18 322	-	18 322	-	-
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 30.06.2021	971 241	7 501	978 742	146 107	1 079 146
Book value 30.06.2021	1 397 743	-	1 397 743	475 456	1 647 436

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

	Group
	Q2	Q1	Q2		01.01.-30.06.
Depreciation in the income statement (USD 1 000)	2021	2021	2020	2021	2020
Depreciation of tangible fixed assets	219 212	232 504	253 302	451 716	498 436
Depreciation of right-of-use assets	2 839	2 595	11 032	5 433	14 771
Depreciation of other intangible assets	18 322	22 455	22 018	40 777	50 558
Total depreciation in the income statement	240 372	257 554	286 353	497 926	563 765
Impairment in the income statement (USD 1 000)
Impairment/reversal of tangible fixed assets	-	-53 135	-68 967	-53 135	9 492
Impairment/reversal of other intangible assets	-	82 791	-68 186	82 791	296 854
Impairment/reversal of capitalized exploration expenditures	-	-	1 281	-	146 107
Impairment of goodwill	-	-	-	-	65 373
Total impairment in the income statement	-	29 656	-135 872	29 656	517 825

Note 6 Leasing

The incremental borrowing rate applied in discounting of the nominal lease debt is between 2.71 percent and 6.71 percent, dependent on the duration of the lease and when it was intially recognized.

		Group
		2021	2020
(USD 1 000)	Q2	01.01.-31.03.	01.01.-31.12.
Lease debt as of beginning of period	200 346	215 760	313 256
New lease debt recognized in the period	-	5 282	16 834
Payments of lease debt1)	-24 272	-24 199	-118 224
Lease debt derecognized in the period	-	-	-12 767
Interest expense on lease debt	3 075	3 407	16 629
Currency exchange differences	-169	96	32
Total lease debt	178 980	200 346	215 760
Short-term	79 432	85 047	83 904
Long-term	99 548	115 299	131 856
1) Payments of lease debt split by activities (USD 1 000):
Investments in fixed assets	11 863	861	67 125
Abandonment activity	8 377	19 778	27 660
Operating expenditures	2 172	1 803	18 075
Exploration expenditures	558	495	874
Other income	1 302	1 261	4 489
Total	24 272	24 199	118 224
Nominal lease debt maturity breakdown (USD 1 000):
Within one year	88 187	95 208	95 124
Two to five years	71 135	84 512	99 809
After five years	51 044	55 107	57 464
Total	210 366	234 827	252 397

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
	Q2	Q1	Q2	01.01.-30.06.
(USD 1 000)	2021	2021	2020	2021	2020
Interest income	331	366	1 224	697	2 593
Realized gains on derivatives	8 713	9 515	2 706	18 228	6 445
Change in fair value of derivatives	-	-	109 844		-
Net currency gains	37 483	-	-	33 452	75 758
Total other financial income	46 197	9 515	112 550	51 680	82 203
Interest expenses	37 369	44 451	47 140	81 819	90 134
Interest on lease debt	3 075	3 407	4 333	6 483	9 243
Capitalized interest cost, development projects	-10 018	-8 220	-8 972	-18 238	-21 873
Amortized loan costs1)	9 006	7 372	4 930	16 379	9 966
Total interest expenses	39 432	47 011	47 430	86 443	87 471
Net currency loss	-	4 031	29 211	-	-
Realized loss on derivatives	34	-	35 071	34	46 107
Change in fair value of derivatives	16 292	6 008		22 300	62 181
Accretion expenses	28 641	27 668	29 474	56 309	58 738
Other financial expenses1)	23 872	15 009	6	38 881	6 408
Total other financial expenses	68 840	52 717	93 762	117 525	173 435
Net financial items	-61 744	-89 846	-27 418	-151 591	-176 110

1) Includes USD 5.8 million in remaining unamortized fees and USD 17.8 million in early redemption premium on the USD 750 million 4.75% Senior Notes due 2024, which was redeemed on 15 June 2021.

Note 8 Tax

			Group
	Q2	Q1	Q2		01.01.-30.06.
Tax for the period (USD 1 000)	2021	2021	2020	2021	2020
Current year tax payable/receivable	129 515	228 646	-370 512	358 161	-375 860
Change in current year deferred tax	267 563	141 355	355 571	408 917	277 186
Prior period adjustments	1 529	4 103	-3 708	5 632	461
Tax expense (+)/income (-)	398 607	374 104	-18 649	772 711	-98 213

		Group
		2021	2020
Calculated tax payable (-)/tax receivable (+) (USD 1 000)	Q2	01.01.-31.03.	01.01.-31.12.
Tax payable/receivable at beginning of period	-452 131	-163 352	-361 157
Current year tax payable/receivable	-129 515	-228 646	333 104
Tax payable/receivable related to acquisitions/sales	-	-	-3 855
Net tax payment/refund	-23 220	-11 420	-180 922
Prior period adjustments and change in estimate of uncertain tax positions	-379	-48 390	-10 425
Currency movements of tax payable/receivable	7 857	-323	59 903
Net tax payable (-)/receivable (+)	-597 387	-452 131	-163 352
Tax receivable included as current assets (+)	-	-	-
Tax payable included as current liabilities (-)	-597 387	-452 131	-163 352

		Group
	2021		2020
Deferred tax liability (-)/asset (+) (USD 1 000)	Q2	01.01.-31.03.	01.01.-31.12.
Deferred tax liability/asset at beginning of period	-2 781 602	-2 642 461	-2 235 357
Change in current year deferred tax	-267 563	-141 355	-448 393
Deferred tax related to acquisitions/sales	-	-	37 727
Prior period adjustments	-1 150	2 214	3 595
Deferred tax charged to OCI and equity	-	-	-33
Net deferred tax liability (-)/asset (+)	-3 050 315	-2 781 602	-2 642 461

			Group
	Q2	Q1	Q2		01.01.-30.06.
Reconciliation of tax expense (USD 1 000)	2021	2021	2020	2021	2020
78 % tax rate on profit/loss before tax	430 886	390 884	117 811	821 770	-205 341
Tax effect of uplift	-72 561	-48 564	-109 217	-121 126	-144 508
Permanent difference on impairment	-	-1 320	-2 613	-1 320	168 174
Foreign currency translation of monetary items other than USD	-28 432	2 397	21 497	-26 035	-57 173
Foreign currency translation of monetary items other than NOK	10 637	9 354	219 217	19 991	-191 989
Tax effect of financial and other 22 % items	42 390	18 588	-98 302	60 978	143 949
Currency movements of tax balances1)	10 650	-3 600	-162 338	7 051	189 029
Other permanent differences, prior period adjustments and change in estimate of uncertain tax positions	5 037	6 365	-4 705	11 402	-353
Tax expense (+)/income (-)	398 607	374 104	-18 649	772 711	-98 213

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)	30.06.2021	31.03.2021	31.12.2020	30.06.2020
Prepayments	47 743	63 972	59 635	67 247
VAT receivable	6 635	7 326	6 770	14 638
Underlift of petroleum	46 812	40 584	53 537	33 695
Accrued income from sale of petroleum products	42 822	80 843	49 441	110 866
Other receivables, mainly balances with license partners	94 295	91 018	117 433	101 476
Total other short-term receivables	238 307	283 742	286 817	327 922

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
30.06.2021	31.03.2021	31.12.2020	30.06.2020
975 360	392 276	537 801	142 333
975 360	392 276	537 801	142 333
3 400 000	4 000 000	4 000 000	3 600 000

Note 11 Derivatives

		Group
(USD 1 000)	30.06.2021	31.03.2021	31.12.2020	30.06.2020
Unrealized gain currency contracts	4 560	5 513	12 841	-
Unrealized gain on commodity contracts	-	442	-	-
Long-term derivatives included in assets	4 560	5 955	12 841	-
Unrealized gain on currency contracts	18 327	24 532	23 212	-
Short-term derivatives included in assets	18 327	24 532	23 212	-
Total derivatives included in assets	22 887	30 487	36 053	-
Unrealized losses currency contracts	1 114	-	-	14 951
Long-term derivatives included in liabilities	1 114	-	-	14 951
Unrealized losses commodity derivatives	16 514	6 293	3 539	4 153
Unrealized losses interest rate swaps	-	-	-	57 246
Unrealized losses currency contracts	8 020	-	-	28 468
Short-term derivatives included in liabilities	24 534	6 293	3 539	89 867
Total derivatives included in liabilities	25 648	6 293	3 539	104 818

The group has various types of economic hedging instruments. Commodity derivatives are used to hedge the risk of oil price reduction. The group currently has limited exposure towards fluctuations in interest rate, but generally manages such exposure by using interest rate derivatives. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR and GBP. These derivatives are mark to market with changes in market value recognized in the income statement. The nature of the instruments and the valuation method is consistent with the disclosed information in the annual financial statements as at 31 December 2020.

The company established its Euro Medium Term Note ('EMTN') programme in April 2021 and issued EUR 750 million Senior Notes in May 2021. As these Senior Notes bonds are EUR denominated there are currency risks associated with the translation to the company's USD functional currency and the cash payments of interest and principle amounts, though EUR denominated gas sales mitigate the risks associated with payments. The company has not entered any foreign currency exchange derivatives related to the EUR Senior Notes.

Note 12 Other current liabilities

	Group
Breakdown of other current liabilities (USD 1 000)	30.06.2021	31.03.2021	31.12.2020	30.06.2020
Balances with license partners	56 573	14 810	20 915	39 482
Share of other current liabilities in licenses	382 071	250 378	245 158	299 451
Overlift of petroleum	5 006	3 207	11 331	17 145
Payroll liabilities, accrued interest and other provisions	227 577	214 535	216 942	157 866
Total other current liabilities	671 228	482 929	494 346	513 945

Note 13 Bonds

			Group
Senior unsecured bonds (USD 1 000)	Maturity	30.06.2021	31.03.2021	31.12.2020	30.06.2020
AKERBP – USD Senior Notes 6.000% (17/22)	Jul 2022	-	-	-	396 027
AKERBP – USD Senior Notes 4.750% (19/24)1)	Jun 2024	-	743 806	743 329	742 376
AKERBP – USD Senior Notes 3.000% (20/25)	Jan 2025	496 856	496 636	496 417	495 976
AKERBP – USD Senior Notes 5.875% (18/25)	Mar 2025	-	-	495 523	494 996
AKERBP – USD Senior Notes 2.875% (20/26)	Jan 2026	496 748	496 571	496 394	-
AKERBP – EUR Senior Notes 1.125% (21/29)	May 2029	883 572	-	-	-
AKERBP – USD Senior Notes 3.750% (20/30)	Jan 2030	993 227	993 030	992 764	992 405
AKERBP – USD Senior Notes 4.000% (20/31)	Jan 2031	744 430	744 285	744 139	-
Long-term bonds - book value		3 614 833	3 474 328	3 968 566	3 121 781
Long-term bonds - fair value		3 848 454	3 619 250	4 191 375	3 089 480
DETNOR02 - NOK Senior unsecured bond	Jul 2020	-	-	-	209 803
Short-term bonds - book value		-	-	-	209 803
Short-term bonds - fair value		-	-	-	211 229

1) The bond was redeemed on 15 June 2021.

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 Other interest-bearing debt

(USD 1 000)	30.06.2021	31.03.2021	31.12.2020	30.06.2020
Revolving credit facility1)	-	-	-	380 708
Other interest-bearing debt	-	-	-	380 708

1) The RCF is undrawn as at 30 June 2021 and the remaining unamortized fees of USD 20.1 million related to the facility are therefore included in other non-current assets.

The senior unsecured Revolving Credit Facility (RCF) was established in May 2019, with the Working Capital facility amended and extended in April 2021. The Working Capital Facility has a committed amount of USD 1.4 billion and is due in 2024, with options for up to two years extension. The Liquidity facility is due in 2026, and has a committed amount of USD 2.0 billion until 2025 and then reduces to USD 1.65 billion for the final year. The interest rate is LIBOR plus a margin of 1.25 percent for the Working Capital Facility and 1.00 percent for the Liquidity Facility. In addition, a utilization fee is applicable for the Liquidity Facility. A commitment fee of 35 percent of applicable margin is paid on the undrawn facility. The financial covenants are as follows:

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

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

The financial covenants are calculated on a 12 months rolling basis. As at 30 June 2021 the Leverage Ratio is 0.85 and Interest Coverage Ratio is 14.2 (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 Q2 2021, the group's estimates show that the financial covenants will continue to be within the thresholds by a substantial margin.

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

Note 15 Provision for abandonment liabilities

		Group
	2021	2021	2020
(USD 1 000)	Q2	01.01.-31.03.	01.01.-31.12.
Provisions as of beginning of period	2 753 193	2 805 507	2 788 218
Change in abandonment liability due to asset sales	-	-	-13 122
Incurred removal cost	-58 068	-86 896	-162 741
Accretion expense	28 641	27 668	116 947
Impact of changes to discount rate	-	-	20 554
Change in estimates and provisions relating to new drilling and installations	35 887	6 914	55 650
Total provision for abandonment liabilities	2 759 653	2 753 193	2 805 507
Short-term	80 230	87 850	155 244
Long-term	2 679 423	2 665 343	2 650 263

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 3.1 percent and 4.6 percent. The credit margin included in the discount rate is 3.0 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 occured between the end of the reporting period and the date of this report.

Note 18 Investments in joint operations

Total number of licenses	30.06.2021	31.03.2021
Aker BP as operator	81	80
Aker BP as partner	51	50

Changes in production licenses in which Aker BP is the operator:			Changes in production licenses in which Aker BP is a partner:
License:	30.06.2021	31.03.2021 License:		30.06.2021	31.03.2021
PL 036E1)	58.000%	64.000 % PL 1674)		10.000%	0.000 %
PL 036F1)	58.000%		64.000 % PL 167B4)	10.000%	0.000 %
PL 102D1)	44.000%		50.000 % PL 167C4)	10.000%	0.000 %
PL 102F1)	44.000%	50.000 % PL 8523)		0.000%	40.000 %
PL 102G1)	44.000%		50.000 % PL 10563)	0.000%	10.000 %
PL 102H1)	44.000%	50.000 %
PL 261C2)	23.835%	0.000 %
PL 8691)	65.000%	60.000 %
PL 10411)	55.000%	40.000 %
Total	9		8 Total	3	2

1) Swap with Lundin Energy regarding Alvheim licenses

2) New license - will become part of Skarv Unit

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

4) Transaction with Equinor

Note 19 Selected historical interim information

	2021		2020
(USD 1 000)	Q2	Q1	Q4	Q3	Q2
Total income	1 123 754	1 133 238	833 508	683 865	589 784
Production costs	158 235	175 906	142 068	133 690	196 174
Exploration expenses	102 020	70 917	41 722	32 267	49 774
Depreciation	240 372	257 554	289 408	268 645	286 353
Impairments	-	29 656	55 302	-	-135 872
Other operating expenses	8 965	8 225	27 028	7 309	14 897
Total operating expenses	509 592	542 258	555 528	441 912	411 326
Operating profit/loss	614 162	590 980	277 980	241 954	178 458
Net financial items	-61 744	-89 846	-42 313	-50 678	-27 418
Profit/loss before taxes	552 418	501 134	235 667	191 276	151 040
Tax expense (+)/income (-)	398 607	374 104	106 200	110 983	-18 649
Net profit/loss	153 811	127 029	129 467	80 293	169 689

	2021
(boe 1 000)	Q2	Q1	Q4	Q3	Q2
Sold volumes
Liquids Gas	14 871 2 879	16 468 3 620	16 165 3 507	14 489 2 779	18 036 3 073

	2021		2020
(USD 1 000)	Q2	Q1	Q4	Q3	Q2
Assets
Goodwill	1 647 436	1 647 436	1 647 436	1 647 436	1 647 436
Other intangible assets	1 873 199	1 878 702	2 043 233	2 050 887	2 053 548
Property, plant and equipment	7 630 389	7 392 321	7 266 137	7 218 548	7 175 129
Right-of-use asset	115 705	126 861	132 735	126 433	137 296
Receivables and other assets	833 760	803 603	792 750	561 657	546 212
Calculated tax receivables (short)	-	-	-	71 038	186 630
Cash and cash equivalents	975 360	392 276	537 801	818 547	142 333
Total assets	13 075 850	12 241 198	12 420 091	12 494 548	11 888 584
Equity and liabilities
Equity	2 030 304	1 988 993	1 987 281	1 928 638	1 912 084
Other provisions for liabilities incl. P&A (long)	2 680 537	2 665 343	2 650 263	2 649 759	2 655 478
Deferred tax	3 050 315	2 781 602	2 642 461	2 562 528	2 471 221
Bonds and bank debt	3 614 833	3 474 328	3 968 566	4 372 815	3 712 292
Lease debt	178 980	200 346	215 760	217 148	236 259
Other current liabilities incl. P&A	923 494	678 456	792 407	763 660	901 251
Tax payable	597 387	452 131	163 352	-	-
Total equity and liabilities	13 075 850	12 241 198	12 420 091	12 494 548	11 888 584

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.

		Q2	Q1	01.01.-30.06.	Q2	01.01.-31.12.
(USD 1 000)	Note	2021	2021	2021	2020	2020
Abandonment spend
Payment for removal and decommissioning of oil fields		54 572	78 576	133 148	15 007	150 306
Payments of lease debt (abandonment activity)	6	8 377	19 778	28 155	1 077	27 660
Abandonment spend		62 949	98 354	161 303	16 084	177 966
Depreciation per boe
Depreciation	5	240 372	257 554	497 926	286 353	1 121 818
Total produced volumes (boe 1 000)	3	18 075	19 999	38 074	19 090	77 101
Depreciation per boe		13.3	12.9	13.1	15.0	14.6
Dividend per share
Paid dividend		112 500	112 500	225 000	70 833	425 000
Number of shares outstanding		359 610	359 840	359 724	359 614	359 808
Dividend per share		0.31	0.31	0.63	0.20	1.18
Capex
Disbursements on investments in fixed assets (excluding capitalized interest)		378 887	216 162	595 048	350 541	1 238 601
Payments of lease debt (investments in fixed assets)	6	11 863	861	12 724	21 027	67 125
CAPEX		390 749	217 023	607 773	371 568	1 305 727
EBITDA
Total income	2	1 123 754	1 133 238	2 256 992	589 784	2 979 263
Production costs	3	-158 235	-175 906	-334 140	-196 174	-627 975
Exploration expenses	4	-102 020	-70 917	-172 937	-49 774	-174 099
Other operating expenses		-8 965	-8 225	-17 191	-14 897	-49 457
EBITDA		854 534	878 190	1 732 724	328 939	2 127 731
EBITDAX
Total income	2	1 123 754	1 133 238	2 256 992	589 784	2 979 263
Production costs	3	-158 235	-175 906	-334 140	-196 174	-627 975
Other operating expenses		-8 965	-8 225	-17 191	-14 897	-49 457
EBITDAX		956 554	949 107	1 905 661	378 713	2 301 830
Equity ratio
Total equity		2 030 304	1 988 993	2 030 304	1 912 084	1 987 281
Total assets		13 075 850	12 241 198	13 075 850	11 888 584	12 420 091
Equity ratio		16%	16%	16%	16%	16%
Exploration spend
Disbursements on investments in capitalized exploration expenditures		56 267	26 978	83 246	19 413	127 283
Exploration expenses	4	102 020	70 917	172 937	49 774	174 099
Dry well	4	-15 780	-12 201	-27 981	-9 866	-56 626
Payments of lease debt (exploration expenditures)	6	558	495	1 053	123	874
Exploration spend		143 065	86 190	229 255	59 443	245 629

		Q2	Q1	01.01.-30.06.	Q2	01.01.-31.12.
(USD 1 000)	Note	2021	2021	2021	2020	2020
Interest coverage ratio
Twelve months rolling EBITDA	19	2 866 013	2 340 418	2 866 013	2 219 431	2 127 731
Twelve months rolling EBITDA, impacts from IFRS 16	6	-14 358	-22 535	-14 358	-27 485	-23 438
Twelve months rolling EBITDA, excluding impacts from IFRS 16		2 851 656	2 317 883	2 851 656	2 191 945	2 104 293
Twelve months rolling interest expenses	7	176 186	185 958	176 186	175 754	184 501
Twelve months rolling amortized loan cost	7	26 226	22 149	26 226	18 883	19 813
Twelve months rolling interest income	7	1 867	2 760	1 867	6 284	3 763
Net interest expenses		200 545	205 347	200 545	188 354	200 552
Interest coverage ratio		14.2	11.3	14.2	11.6	10.5
Leverage ratio
Long-term bonds	13	3 614 833	3 474 328	3 614 833	3 121 781	3 968 566
Other interest-bearing debt	14	-	-	-	380 708	-
Short-term bonds	13	-	-	-	209 803	-
Cash and cash equivalents	10	975 360	392 276	975 360	142 333	537 801
Net interest-bearing debt excluding lease debt		2 639 473	3 082 052	2 639 473	3 569 959	3 430 766
Twelve months rolling EBITDAX	19	3 112 940	2 535 098	3 112 940	2 474 436	2 301 830
Twelve months rolling EBITDAX, impacts from IFRS 16	6	-12 774	-21 387	-12 774	-26 965	-22 564
Twelve months rolling EBITDAX, excluding impacts from IFRS 16		3 100 166	2 513 711	3 100 166	2 447 471	2 279 266
Leverage ratio		0.85	1.23	0.85	1.46	1.51
Net interest-bearing debt
Long-term bonds	13	3 614 833	3 474 328	3 614 833	3 121 781	3 968 566
Long-term lease debt	6	99 548	115 299	99 548	156 396	131 856
Other interest-bearing debt	14	-	-	-	380 708	-
Short-term bonds	13	-	-	-	209 803	-
Short-term lease debt	6	79 432	85 047	79 432	79 863	83 904
Cash and cash equivalents	10	975 360	392 276	975 360	142 333	537 801
Net interest-bearing debt		2 818 452	3 282 398	2 818 452	3 806 218	3 646 526

Operating profit/loss see Income Statement

Production cost per boe see note 3

STATEMENT BY THE BOARD OF DIRECTORS AND CHIEF EXECUTIVE OFFICER

Pursuant to the Norwegian Securities Trading Act section § 5-5 with pertaining regulations, we hereby confirm that, to the best of our knowledge, the company's interim financial statements for the period 1 January to 30 June 2021 have been prepared in accordance with IAS 34, as endorsed by the EU, and in accordance with the requirements for additional information provided for by the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair picture of the company's liabilities, financial position and results overall.

To the best of our knowledge, the Board of Directors' half-yearly report together with the yearly report, gives a true and fair picture of the development, performance and financial position of the company, and includes a description of the principal risk and uncertainty factors facing the company.

Øyvind Eriksen, Chair of the Board Kjell Inge Røkke, Board member Anne Marie Cannon, Deputy Chair Trond Brandsrud, Board member Paula Doyle, Board member Murray Auchincloss, Board member Ingard Haugeberg, Board member Terje Solheim, Board member Tore Vik, Board member Kate Thomson, Board member Karl Johnny Hersvik, Chief Executive Officer Hilde Kristin Brevik, Board member The Board of Directors and the CEO of Aker BP ASA Akerkvartalet, 14 July 2021

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 30 June 2021 and the related condensed consolidated income statement, and condensed consolidated statement of cash flow for the three-month and six-month periods ended 30 June 2021, the condensed consolidated statement of changes in equity for the three-month periods ended 31 March 2021 and 30 June 2021 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, 14 July 2021

KPMG AS

Roland Fredriksen State Authorised Public Accountant (Norway)

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