Aker BP

Quarterly Report • Oct 28, 2021

QUARTERLY REPORT Q3 2021

THIRD QUARTER 2021 SUMMARY

Aker BP reported total income of USD 1,563 (1,124) million and operating profit of USD 849 (614) million for the third quarter 2021. Net profit was USD 206 (154) million. The company paid a dividend of USD 112.5 million (USD 0.3124 per share) in the quarter. The Board has resolved to pay a dividend of USD 150 million (USD 0.4165 per share) in the fourth quarter 2021.

The company's net production in the third quarter was 210.0 (198.6) thousand barrels of oil equivalents per day (mboepd). The increase was driven by completion of planned maintenance and project activities at the company's producing assets in the previous quarter. Net sold volume was 224.8 (195.1) mboepd. The average realised liquids price increased to USD 71.5 (66.9) per barrel, while the average realised price for natural gas increased to USD 91.3 (45.1) per barrel of oil equivalents (boe).

Production costs for the oil and gas sold in the quarter increased to USD 209 (158) million due to increased volume sold. The average production cost per produced unit remained stable at USD 9.0 (9.0) per boe. Exploration expenses amounted to USD 97 (102) million. Depreciation was USD 247 (240) million, equivalent to USD 12.8 (13.3) per boe. Impairments amounted to USD 154 million, driven by revisions of future production and cost profiles for the Ula area.

This resulted in operating profit of USD 849 (614) million. After net financial expenses of USD 47 (62) million, profit before taxes ended at USD 802 (552) million. Tax expenses amounted to USD 596 (399) million, and net profit was USD 206 (154) million for the quarter.

The company continued progressing its portfolio of field development projects according to plan. During the third quarter, the development concept has been selected for the NOAKA area, and the resource estimate for the development has been increased to 600 mmboe. Moreover, the PDO for Frosk in the Alvheim area was submitted to the authorities. Capital expenditure amounted to USD 378 (391) million in the quarter.

At the end of the third quarter 2021, Aker BP had total available liquidity of USD 4.8 (4.4) billion. Net interest-bearing debt was USD 2.3 (2.8) billion, including 0.2 (0.2) billion in lease debt.

In July, the company disbursed dividends of USD 112.5 million, equivalent to USD 0.3124 per share, reflecting an annualised dividend level of USD 450 million. The Board has resolved to increase the annualised dividend level to USD 600 million effective from the fourth quarter 2021, and hence to pay a quarterly dividend in November 2021 of USD 150 million, equivalent to USD 0.4165 per share. This will bring total dividend payments in 2021 to USD 487.5 million, compared to the previous plan of USD 450 million communicated in February.

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	Q3 2021	Q2 2021	Q3 2020	2021 YTD	2020 YTD
Total income	USDm	1 563	1 124	684	3 820	2 146
EBITDA	USDm	1 250	855	511	2 983	1 505
Net profit/loss	USDm	206	154	80	487	(85)
Earnings per share (EPS)	USD	0.57	0.43	0.22	1.35	(0.24)
Capex	USDm	378	391	275	985	1 007
Exploration spend	USDm	109	143	54	338	166
Abandonment spend	USDm	27	63	35	188	73
Production cost	USD/boe	9.0	9.0	7.3	8.9	8.4
Taxes paid/refunded	USDm	98	(23)	(109)	63	20
Net interest-bearing debt	USDm	2 332	2 818	3 771	2 332	3 771
Leverage ratio		0.56	0.85	1.46	0.56	1.46
Dividend per share	USD	0.31	0.31	0.20	0.93	0.98
Average USDNOK exchange rate		8.77	8.37	9.13	8.55	9.55

Production summary

	UNIT	Q3 2021	Q2 2021	Q3 2020	2021 YTD	2020 YTD
Alvheim area	mboepd	46.6	45.9	51.2	47.5	55.6
Ivar Aasen	mboepd	15.3	16.1	17.0	17.2	20.6
Johan Sverdrup	mboepd	63.4	64.3	53.1	63.0	49.3
Skarv	mboepd	34.5	20.6	17.5	28.0	19.3
Ula area	mboepd	8.5	6.4	10.4	7.9	11.2
Valhall area	mboepd	41.5	45.3	52.3	46.5	49.8
Other	mboepd	0.2	0.0	0.0	0.1	0.7
Net production	mboepd	210.0	198.6	201.6	210.2	206.5
Over/underlift	mboepd	14.7	(3.6)	(13.9)	4.1	2.5
Net sold volume	mboepd	224.8	195.1	187.7	214.3	209.0
-Liquids	mboepd	183.6	163.4	157.5	176.7	176.6
-Natural gas	mboepd	41.2	31.6	30.2	37.7	32.4
Realised price liquids	USD/boe	71.5	66.9	42.7	66.2	38.6
Realised price natural gas	USD/boe	91.3	45.1	18.8	59.8	17.9

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q3 2021	Q2 2021	Q3 2020	2021 YTD	2020 YTD
Total income	1 563	1 124	684	3 820	2 146
EBITDA	1 250	855	511	2 983	1 505
EBIT	849	614	242	2 054	155
Pre-tax profit	802	552	191	1 855	(72)
Net profit/loss	206	154	80	487	(85)
EPS (USD)	0.57	0.43	0.22	1.35	(0.24)

Total income in the third quarter 2021 amounted to USD 1,563 (1,124) million. The increase was driven by increased volume sold and by higher oil and gas prices. Sold volumes were 224.8 (195.1) mboepd in the quarter. Realised prices for liquids increased by 7 percent, while realised prices for natural gas doubled from the previous quarter.

Production costs related to oil and gas sold in the quarter amounted to USD 209 (158) million. Production cost per produced unit amounted to USD 9.0 (9.0) per boe. See note 3 for further details on production costs.

Exploration expenses amounted to USD 97 (102) million, of which field evaluation costs were USD 43 (62) million. The latter includes costs related to finalising the development concept for NOA Fulla ahead of the concept select decision, as well as costs related to other future development projects. Dry well expenses were USD 38 (16) million and were mainly related to the Stangnestind and Merckx Ty exploration wells.

Depreciation amounted to USD 247 (240) million, corresponding to USD 12.8 (13.3) per barrel of oil equivalents. The

change was driven by variations in the relative share of production from different fields. Impairments amounted to USD 154 million, driven by revisions of future production and cost profiles for the Ula area (see note 5 for further details). Other operating expenses amounted to USD 7 (9) million.

Operating profit increased to USD 849 (614) million for the third quarter. Net financial expenses amounted to USD 47 (62) million.

Profit before taxes amounted to USD 802 (552) million. Tax expense was USD 596 (399) million. The effective tax rate was 74 percent. See note 9 for further details on tax.

This resulted in a net profit for the third quarter 2021 of USD 206 (154) million.

Statement of financial position

(USD MILLION)	Q3 2021	Q2 2021	Q4 2020	Q3 2020
Total non-current assets	11 307	11 381	11 162	11 102
Total current assets	2 275	1 695	1 258	1 392
Total assets	13 582	13 076	12 420	12 495
Total equity	2 128	2 030	1 987	1 929
Bank and bond debt	3 595	3 615	3 969	4 373
Total abandonment provisions	2 716	2 760	2 806	2 825
Deferred taxes	3 142	3 050	2 642	2 563
Other liabilities	2 001	1 621	1 016	806
Total equity and liabilities	13 582	13 076	12 420	12 495
Net interest-bearing debt	2 332	2 818	3 647	3 771

At the end of the third quarter 2021, total assets amounted to USD 13,582 (13,076) million, of which current assets were USD 2,275 (1,695) million.

Equity amounted to USD 2,128 (2,030) million at the end of the quarter, corresponding to an equity ratio of 16 (16) percent.

Deferred tax liabilities amounted to USD 3,142 (3,050) million and total abandonment provisions amounted to USD 2,716 (2,760) million. Bank and bond debt totalled USD 3,595 (3,615) million. This was entirely made up of bond debt as the company's bank facilities were not drawn.

At the end of the third quarter, the company had total available liquidity of USD 4.8 (4.4) billion, comprising USD 1,421 (975) million in cash and cash equivalents, and USD 3.4 (3.4) billion in undrawn credit facilities.

Cash flow

(USD MILLION)	Q3 2021	Q2 2021	Q3 2020*	2021 YTD	2020 YTD*
Cash flow from operations	1 063	1 108	587	3 071	1 333
Cash flow from investments	(432)	(490)	(323)	(1 243)	(1 035)
Cash flow from financing	(184)	(35)	412	(943)	413
Net change in cash & cash equivalents	447	583	676	885	712
Cash and cash equivalents	1 421	975	819	1 421	819

* 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 1,063 (1,108) million in the quarter. Pre-tax profit increased in the quarter, driven by higher realised oil and gas prices. This was however offset by working capital changes and taxes paid.

Net cash used for investment activities was USD 432 (490) million, of which investments in fixed assets amounted to USD 360 (379) million for the quarter. Investments in capitalised exploration were USD 49 (56) million. Payments for decommissioning activities amounted to USD 23 (55) million.

Net cash outflow from financing activities was USD 184 million, compared to an outflow of USD 35 million in the previous quarter. The main items were dividend disbursements of USD 113 (113) million, interest payments (including interest element of lease payments) of USD 55 (25) million, and payments of lease debt related to investments in fixed assets of USD 16 (10) million.

Risk management

The company is using various types of economic hedging instruments. Commodity derivatives are used to hedge the risk of oil price reduction. Aker BP 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 marked to market with changes in market value recognized in the income statement.

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

OIL PUT OPTIONS	Q4 2021	Q1 2022	Q2 2022	Q3 2022	Q4 2022
Share of oil production covered (after tax)	74 %	60 %	71 %	16 %	15 %
Average strike (USD/bbl)	46	45	45	45	45
Average premium (USD/bbl)	2.1	1.9	1.9	2.0	2.0

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.

During the first nine months of 2021, the company has disbursed dividends of USD 337.5 million, equivalent to USD 0.9372 per share.

On 27 October 2021, the Board resolved to increase the annualised dividend level from USD 450 to 600 million effective from fourth quarter 2021, and hence to pay a quarterly dividend in November 2021 of USD 150 million, equivalent to USD 0.4165 per share. This will bring total dividend payments in 2021 to USD 487.5 million, compared to the previous plan of USD 450 million communicated in February.

OPERATIONAL REVIEW

Aker BP's net production was 19.3 (18.1) mmboe in the third quarter of 2021, corresponding to 210.0 (198.6) mboepd. Net sold volume was 224.8 (195.1) mboepd. The average realised liquids price was USD 71.5 (66.9) per barrel, while the average realised gas price was USD 91.3 (45.1) per boe.

Alvheim Area

KEY FIGURES	AKER BP INTEREST	Q3 2021	Q2 2021	Q1 2021	Q4 2020	Q3 2020
Production, boepd
Alvheim	65%	36 061	34 799	35 176	35 921	29 447
Bøyla (incl. Frosk)	65%	865	1 191	2 921	3 843	4 858
Skogul	65%	4 449	4 542	4 450	6 891	8 091
Vilje	46.904%	1 971	1 789	2 707	2 899	2 616
Volund	65%	3 264	3 602	4 892	5 192	6 200
Total production		46 610	45 923	50 147	54 746	51 212
Production efficiency		96 %	91 %	99 %	98 %	92 %

Third quarter production from the Alvheim area was 46.6 mboepd net to Aker BP, up one percent from the previous quarter as production efficiency increased to 96 (91) percent.

During the quarter, the semi-submersible drilling rig Deepsea Nordkapp completed the drilling of a single lateral side-track well on the Volund field. First oil from this well is expected in the fourth quarter. The rig moved on from Volund to start on the Kameleon Infill West (KIW) well, which was sanctioned during the quarter. The KIW will be drilled in the fourth quarter, with completion of the subsea tie-back campaign and first oil planned in the first quarter of 2022. Preparations for the Kobra East & Gekko (KEG) project execution phase is progressing according to plan.

The Frosk Development project reached the final investment decision during the third quarter, with the subsequent submission of a plan for development and operation (PDO) to the Ministry of Petroleum and Energy (MPE) on 27 September. The Frosk drilling campaign is scheduled to start in the third quarter of 2022, with first oil planned in the first quarter of 2023. The development will be carried out in cooperation with Aker BP's alliance partners.

The Trell and Trine project is progressing towards a concept select decision by year-end. Unitization of the Trell and Trine licenses was approved by MPE during the quarter.

Ivar Aasen

KEY FIGURES	AKER BP INTEREST	Q3 2021	Q2 2021	Q1 2021	Q4 2020	Q3 2020
Production, boepd
Total production	34.7862%	15 285	16 129	20 206	18 723	17 025
Production efficiency		86 %	89 %	90 %	90 %	75 %

Third quarter production from Ivar Aasen was 15.3 mboepd net to Aker BP, down five percent from the previous quarter. The reduction was mainly caused by a power outage at Edvard Grieg in September, which together with a planned rig move caused the production efficiency to drop from 89 percent in the second quarter to 86 percent in the third quarter.

On 10 September, Edvard Grieg was affected by a power outage, with the power transformer consequently being temporarily shut down. The transformer has been shipped to shore for inspection, testing and repair. The field continues to operate at limited capacity while the transformer is being repaired and made ready for reinstallation at Edvard Grieg, which is expected during the fourth quarter 2021.

The 2021 drilling campaign was finalised in the third quarter. The completion of the last production well was cancelled due to poor reservoir properties, while a water injector was successfully completed, and is scheduled to be put into operation in the fourth quarter, pending resolution of the power situation at Edward Grieg.

The Hanz project is progressing as planned towards the final investment decision by the end of the year. First oil from Hanz is currently expected in first quarter 2024.

Johan Sverdrup

KEY FIGURES	AKER BP INTEREST	Q3 2021	Q2 2021	Q1 2021	Q4 2020	Q3 2020
Production, boepd
Total production	11.5733%	63 424	64 262	61 178	59 613	53 051

Johan Sverdrup produced at 535,000 barrels per day (gross), in accordance with the upgraded process capacity with high regularity through the third quarter of 2021, except for a brief shutdown in July when a Phase 2 module was installed on the Riser Platform. Production efficiency so far in 2021 has been 97.5 percent. Production well number 14 was put on stream in August.

Phase 2 of the Johan Sverdrup development progressed safely according to plan and cost, despite challenges caused by COVID-19. Hook-up and commissioning of the second processing platform is progressing well at Aibel's construction site in Haugesund. The 5,000 tonne Riser Platform module, constructed by Aker Solutions at Stord, was successfully installed offshore as planned in July.

Skarv Area

KEY FIGURES	AKER BP INTEREST	Q3 2021	Q2 2021	Q1 2021	Q4 2020	Q3 2020
Production, boepd
Total production	23.835 %	34 476	20 581	28 973	26 121	17 544
Production efficiency		97 %	58 %	84 %	98 %	86 %

Production from Skarv in the quarter was 34.5 mboepd net to Aker BP, an increase of 68 percent from the previous quarter. Production efficiency in the third quarter was 97 percent, compared to 58 percent in second quarter. The improvement was driven by completion of planned turnaround activities to increase the gas handling capacity and resolution of operational challenges in the second quarter. The increased gas capacity on the Skarv FPSO will cater for further gas discoveries in the area.

Skarv is an oil and gas field, where gas injection is used to maximize the liquids production. In the third quarter, the Skarv partners decided to temporarily reduce the injection activity and instead increase the gas exports from the field in response to the global gas market tightness.

The Ærfugl Phase 2 project is progressing according to plan. The project remains on schedule for production start in the fourth quarter 2021.

Ula Area

KEY FIGURES	AKER BP INTEREST	Q3 2021	Q2 2021	Q1 2021	Q4 2020	Q3 2020
Production, boepd
Ula	80 %	4 622	3 539	5 464	6 239	3 929
Tambar	55 %	2 725	1 927	1 413	1 092	2 595
Oda	15 %	1 192	930	1 865	2 959	3 887
Total production		8 539	6 396	8 741	10 290	10 411
Production efficiency		84 %	64 %	80 %	75 %	87 %

Production from the Ula area increased in the third quarter, driven by improved production efficiency and by the completion of planned maintenance activities in the second quarter, as well as added production from the new Tambar and Ula wells which came on stream in May and September.

The Ula Power Project progressed well in the quarter. The third and final generator has been lifted on board and is being installed in its final position. The project is estimated to be finished in the first half of next year.

An impairment charge of USD 157 million was made in the third quarter, based on an updated assessment of future production and cost profiles for the Ula fields (see note 5 for further details). This was mainly driven by weaker than expected reservoir performance, and by reduced availability of gas for WAG injection.

Valhall Area

KEY FIGURES	AKER BP INTEREST	Q3 2021	Q2 2021	Q1 2021	Q4 2020	Q3 2020
Production, boepd
Valhall	90%	40 983	44 699	52 526	52 881	51 647
Hod	90%	467	596	446	682	682
Total production		41 450	45 295	52 972	53 564	52 329
Production efficiency		76 %	81 %	91 %	90 %	90 %

Third quarter production from Valhall was 41.5 mboepd net to Aker BP, down eight percent from the previous quarter. The reduction in produced volumes was a result of planned downtime related to installation of Hod facilities and by chalk influx in several wells necessitating well intervention activities, as well as natural decline.

During the quarter, the Maersk Invincible jack-up rig finalised drilling of the third well in the Flank North infill well campaign. Upon completion at Flank North, the rig moved to the Hod field development to commence a six-well program.

The Hod field development is progressing as planned with the jacket and topsides safely installed in early July and August, respectively. The offshore work related to tie-in to existing facilities at Valhall and subsea installation campaigns has also been initiated.

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

Planning of the Valhall NCP (New Central Platform) project continued in the third quarter. The project will add new slots for further development of the Valhall Area. Aker BP is now aiming to include the King Lear gas discovery as part of the project. The proposed concept comprises a bridge-linked central processing platform with slots at the Valhall field center and with an unmanned wellhead installation at King Lear, both with power from shore. The NCP/King Lear project will modernise the Valhall field complex, ensuring long-term efficiency of production and increased reserves. Furthermore, the project secures the development of King Lear and adds flexibility for future area development. Aker BP is targeting a concept select decision in the fourth quarter of 2021 and a final investment decision in the fourth quarter of 2022.

North of Alvheim, Krafla and Fulla (NOAKA)

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

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

During the third quarter, the partners made a final concept select decision for NOA Fulla. Following this decision, Aker BP has awarded front end engineering and design (FEED) worth nearly NOK 700 million to its alliance partners.

In October, proposals for impact assessment programs for both the NOA Fulla and Krafla development projects were submitted to Norwegian authorities. This marks the start of the process with plan for development and operation.

Aker BP ASA and LOTOS Exploration and Production Norge AS have entered into an agreement to swap licence interests in licences in the NOA Fulla area. The purpose is to simplify the ownership structure ahead of the project development. Following this transaction, Aker BP will have 87.7 percent interest in the NOA area (licences 026, 026B, 364, 442, 442B, 442C, 874) and 47.7 percent in Fulla (licence 873). LOTOS will have 12.3 percent interest in all the licences covered by the agreement. The transaction is subject to approval by the Norwegian authorities.

EXPLORATION

Total exploration spend in the third quarter was USD 109 (143) million, while USD 97 (102) 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 third quarter, these costs amounted to USD 43 (62) million, with NOAKA as the main driver.

The drilling of the Stangnestind prospect in licence 858 was completed in the quarter and resulted in a minor gas discovery. Preliminary estimates place the size of the discovery between 10-13 million barrels of oil equivalents. The discovery is not considered to be commercial, and there are no further drilling plans in the licence.

Drilling of the Liatårnet prospect in licence 442 was also completed in the quarter. Aker BP has an ownership interest of 90.26 percent in the licence. The results of the appraisal well will entail a downward adjustment of the previous resource estimates (80-200 million barrels of oil equivalents), but further analysis is necessary to give an updated estimate for the discovery.

During the quarter, operator Lundin Energy AS concluded the drilling of a wildcat well and an appraisal well on the Lille Prinsen oil and gas discovery. Both wells encountered oil

columns, with total preliminary estimates between 12-60 million barrels of oil equivalents. The licensees are considering a subsea development to the Ivar Aasen or Edvard Grieg host platforms. Aker BP has an ownership interest of 10 percent in the licence.

Lundin Energy also concluded drilling of the Merckx Ty prospect in licence 981 during the quarter. Aker BP has an ownership interest of 40 percent in the licence. The well was dry.

Operator DNO Norge AS concluded drilling of the Gomez prospect in licence 006C during the quarter which resulted in an oil discovery. Preliminary analyses indicate significant uncertainty regarding oil mobility, necessitating further studies before a resource estimate can be established for the discovery. Aker BP has an ownership interest of 15 percent in the licence, which will increase to 35 percent pending government approval of a transaction with DNO.

Preparations to develop the Garantiana discovery have been postponed in order to optimize the tie-in to the planned host platform Snorre B and to provide more time to explore the upside potential in the licence. The revised timeline includes a final investment decision in 2026 and production start in 2029.

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	Q3 2021	Q2 2021	Q1 2021	Q4 2020	Q3 2020
Total recordable injury frequency (TRIF) L12M	Per mill. exp. hours	1.5	1.2	1.3	1.2	1.2
Serious incident frequency (SIF) L12M	Per mill. exp. hours	0	0	0	0.2	0.2
Acute spill	Count	0	0	0	0	1
Process safety events Tier 1 and 2	Count	0	0	0	0	0
CO2 emissions intensity L12M	Kg CO2/boe	4.4	4.2	4.3	4.5	5.0

The change in Total Recordable Injuries Frequency (TRIF) is mainly due to a slight increase in personal injuries, which is being addressed systematically in accordance with the company's governing processes.

from all assets during the Covid-19 outbreak. There have been no cases brought to our offshore assets nor have we experienced staff being infected at the office premises. As of mid-October, most Covid-19 measures are discontinued both onshore and offshore, but actions are made to enable responsible and efficient handling of potential infections.

The company has been working systematically to protect personnel and to ensure continued and uninterrupted production

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. As at the end of the third quarter, the main items of the company's financial plan for 2021 are as follows*:

• Production of 210-220 mboepd (towards the lower end)
• Capex of around USD 1.5 billion (reduced from USD 1.6 billion)
• Exploration spend of USD 400-500 million
• Abandonment spend of around USD 200 million
• Production cost of USD 8.5-9.0 per boe (towards the higher end)
• Dividends of USD 487.5 million (increased from 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
		Q3 Q2 Q3			01.01.-30.09.
(USD 1 000)	Note	2021	2021	2020	2021	2020
Petroleum revenues		1 558 228	1 128 183	674 801	3 819 112	2 038 055
Other income		4 447	-4 429	9 065	556	107 700
Total income	2	1 562 675	1 123 754	683 865	3 819 667	2 145 755
Production costs	3	208 798	158 235	133 690	542 939	485 907
Exploration expenses	4	97 477	102 020	32 267	270 414	132 377
Depreciation	6	246 846	240 372	268 645	744 771	832 410
Impairments	5,6	153 881	-	-	183 538	517 825
Other operating expenses		6 534	8 965	7 309	23 725	22 430
Total operating expenses		713 537	509 592	441 912	1 765 387	1 990 949
Operating profit/loss		849 138	614 162	241 954	2 054 281	154 806
Interest income		342	331	1 081	1 040	3 674
Other financial income		33 449	46 197	107 142	85 129	131 653
Interest expenses		27 018	39 432	46 566	113 461	134 037
Other financial expenses		54 218	68 840	112 335	171 743	228 078
Net financial items	8	-47 444	-61 744	-50 678	-199 035	-226 788
Profit/loss before taxes		801 694	552 418	191 276	1 855 246	-71 982
Tax expense (+)/income (-)	9	595 860	398 607	110 983	1 368 571	12 770
Net profit/loss		205 834	153 811	80 293	486 674	-84 752
Weighted average no. of shares outstanding basic and diluted		359 336 759	359 610 213	359 533 743	359 593 679	359 709 902
Basic and diluted earnings/loss USD per share		0.57	0.43	0.22	1.35	-0.24

STATEMENT OF COMPREHENSIVE INCOME

		Group
		Q3	Q2	Q3	01.01.-30.09.
(USD 1 000)	Note	2021	2021	2020	2021	2020
Profit/loss for the period		205 834	153 811	80 293	486 674	-84 752
Total comprehensive income/loss in period		205 834	153 811	80 293	486 674	-84 752

STATEMENT OF FINANCIAL POSITION

(USD 1 000)	Note	30.09.2021	30.06.2021	31.12.2020	30.09.2020
ASSETS
Intangible assets
Goodwill	6	1 647 436	1 647 436	1 647 436	1 647 436
Capitalized exploration expenditures	6	404 515	475 456	521 922	507 349
Other intangible assets	6	1 374 238	1 397 743	1 521 311	1 543 538
Tangible fixed assets
Property, plant and equipment	6	7 666 727	7 630 389	7 266 137	7 218 548
Right-of-use assets	6	105 248	115 705	132 735	126 433
Financial assets
Long-term receivables		73 975	74 626	29 086	26 620
Other non-current assets		32 553	34 868	30 210	28 498
Long-term derivatives	12	2 765	4 560	12 841	4 075
Total non-current assets		11 307 457	11 380 784	11 161 678	11 102 498
Inventories
Inventories		123 430	121 826	112 704	117 126
Receivables
Trade receivables		412 195	341 247	297 880	78 127
Tax receivables	9	-	-	-	71 038
Other short-term receivables	10	307 293	238 307	286 817	307 211
Short-term derivatives	12	10 860	18 327	23 212	-
Cash and cash equivalents
Cash and cash equivalents	11	1 420 783	975 360	537 801	818 547
Total current assets		2 274 561	1 695 066	1 258 414	1 392 050
TOTAL ASSETS		13 582 017	13 075 850	12 420 091	12 494 548

STATEMENT OF FINANCIAL POSITION

		Group
(USD 1 000)	Note	30.09.2021	30.06.2021	31.12.2020	30.09.2020
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		-1 566 492	-1 664 048	-1 707 071	-1 765 714
Total equity		2 127 860	2 030 304	1 987 281	1 928 638
Non-current liabilities
Deferred taxes	9	3 142 033	3 050 315	2 642 461	2 562 528
Long-term abandonment provision	15	2 637 470	2 679 423	2 650 263	2 649 759
Long-term bonds	14	3 594 939	3 614 833	3 968 566	3 966 815
Long-term derivatives	12	2 006	1 114	-	-
Long-term lease debt	7	95 772	99 548	131 856	136 074
Total non-current liabilities		9 472 221	9 445 232	9 393 146	9 315 176
Current liabilities
Trade creditors		166 599	121 435	113 517	97 733
Short-term bonds	14	-	-	-	406 000
Accrued public charges and indirect taxes		25 203	26 066	25 761	23 193
Tax payable	9	990 482	597 387	163 352
Short-term derivatives	12	27 675	24 534	3 539	15 288
Short-term abandonment provision	15	78 750	80 230	155 244	174 958
Short-term lease debt	7	61 869	79 432	83 904	81 075
Other current liabilities	13	631 358	671 228	494 346	452 488
Total current liabilities		1 981 937	1 600 313	1 039 664	1 250 734
Total liabilities		11 454 157	11 045 546	10 432 810	10 565 910
TOTAL EQUITY AND LIABILITIES		13 582 017	13 075 850	12 420 091	12 494 548

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	-	-	-	-	-	-283 333	-283 333	-283 333
Profit/loss for the period	-	-	-	-	-	-165 045	-165 045	-165 045
Purchase of treasury shares2)	-	-	-	-	-	-7 122	-7 122	-7 122
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	-	-	-	-	-	-70 833	-70 833	-70 833
Profit/loss for the period	-	-	-	-	-	80 293	80 293	80 293
Sale of treasury shares2)	-	-	-	-	-	7 094	7 094	7 094
Equity as of 30.09.2020	57 056	3 637 297	573 083	-85	-115 491	-2 223 221	-1 765 714	1 928 638
Dividend distributed	-	-	-	-	-	-70 833	-70 833	-70 833
Profit/loss for the period	-	-	-	-	-	129 467	129 467	129 467
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	-	-	-	-	-	-225 000	-225 000	-225 000
Profit/loss for the period	-	-	-	-	-	280 841	280 841	280 841
Purchase of treasury shares2)	-	-	-	-	-	-12 818	-12 818	-12 818
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
Dividend distributed	-	-	-	-	-	-112 500	-112 500	-112 500
Profit/loss for the period	-	-	-	-	-	205 834	205 834	205 834
Net sale of treasury shares2)	-	-	-	-	-	4 223	4 223	4 223
Equity as of 30.09.2021	57 056	3 637 297	573 083	-76	-115 491	-2 024 008	-1 566 492	2 127 860

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
		Q3	Q2	Q3		01.01.-30.09.
				Restated		Restated
(USD 1 000)	Note	2021	2021	2020	2021	2020
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		801 694	552 418	191 276	1 855 246	-71 982
Taxes paid	9	-97 680			-97 680	-128 731
Taxes refunded	9	-	23 220	108 835	34 640	108 835
Depreciation	6	246 846	240 372	268 645	744 771	832 410
Impairment	5,6	153 881	-	-	183 538	517 825
Accretion expenses	8,15	28 624	28 641	28 911	84 933	87 649
Total interest expenses (excluding amortized loan costs)	8	23 975	30 426	39 800	94 039	117 304
Changes in derivatives	2,8	13 295	26 955	-36 801	48 570	27 729
Amortized loan costs	8	3 043	9 006	6 766	19 422	16 733
Expensed capitalized dry wells	4,6	37 603	15 780	11 708	65 584	50 556
Changes in inventories, trade creditors and receivables		-27 388	-39 389	-9 176	-71 958	38 521
Changes in other current balance sheet items		-121 030	220 797	-22 764	110 343	-263 634
NET CASH FLOW FROM OPERATING ACTIVITIES		1 062 862	1 108 226	587 201	3 071 447	1 333 215
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields		-23 241	-54 572	-28 861	-156 389	-64 797
Disbursements on investments in fixed assets (excluding capitalized interest)		-359 969	-378 887	-261 234	-955 017	-941 382
Disbursements on investments in capitalized exploration		-48 562	-56 267	-32 842	-131 808	-83 509
Cash received from sale of licenses		-	-	-	-	54 747
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-431 772	-489 726	-322 937	-1 243 214	-1 034 942
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment/fees related to revolving credit facility		-	-7 675	-400 000	-7 675	-1 451 550
Repayment of bonds		-	-767 813	-212 553	-1 282 503	-212 553
Net proceeds from bond issue		-	899 334	1 234 342	899 334	2 718 248
Receipt/payment upon settlement of derivatives related to financing		-	-	-56 804	-	-56 804
Interest paid (including interest element of lease payments)		-54 766	-25 291	-69 495	-142 642	-148 102
Payments on lease debt related to investments in fixed assets		-15 580	-10 360	-11 935	-26 680	-56 914
Payments on other lease debt		-5 850	-10 837	-8 045	-36 739	-24 837
Paid dividend		-112 500	-112 500	-70 833	-337 500	-354 167
Net purchase/sale of treasury shares		4 223	-	7 094	-8 595	-28
NET CASH FLOW FROM FINANCING ACTIVITIES		-184 473	-35 142	411 771	-943 000	413 294
Net change in cash and cash equivalents		446 617	583 358	676 034	885 233	711 567
Cash and cash equivalents at start of period		975 360	392 276	142 333	537 801	107 104
Effect of exchange rate fluctuation on cash held		-1 195	-273	180	-2 251	-125
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	1 420 783	975 360	818 547	1 420 783	818 547

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 27 October 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.

	Q3	01.01.-30.09.
Breakdown of restating impact on Statetment of Cash Flow (USD 1 000)	2020	2020
NET CASH FLOW FROM OPERATING ACTIVITIES
- Prior to restating	526 259	1 212 039
- After restating	587 201	1 333 215
Change	60 942	121 176
NET CASH FLOW FROM INVESTMENT ACTIVITIES
- Prior to restating	-331 490	-1 065 368
- After restating	-322 937	-1 034 942
Change	8 553	30 426
NET CASH FLOW FROM FINANCING ACTIVITIES
- Prior to restating	481 266	564 896
- After restating	411 771	413 294
Change	-69 495	-151 602
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.

Note 2 Income

	Group
	Q3	Q2	Q3	01.01.-30.09.
Breakdown of petroleum revenues (USD 1 000)	2021	2021	2020	2021	2020
Sales of liquids	1 208 591	995 281	618 692	3 193 383	1 867 262
Sales of gas	345 849	129 801	52 134	614 873	158 973
Tariff income	3 788	3 101	3 975	10 856	11 819
Total petroleum revenues	1 558 228	1 128 183	674 801	3 819 112	2 038 055
Sales of liquids (boe 1 000)	16 892	14 871	14 489	48 231	48 384
Sales of gas (boe 1 000)	3 787	2 879	2 779	10 286	8 877
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-6 638	-3 044	-7 458	-12 725	62 938
Unrealized gain/loss (-) on oil derivatives	4 094	-10 663	-1 105	-8 881	-3 453
Gain on license transactions	-	-	-	-	5 417
Other income1)	6 991	9 278	17 628	22 161	42 797
Total other income	4 447	-4 429	9 065	556	107 700

1) Including partner coverage of operational assets such as supply vessels and buildings leased by the company and so recognised on a gross basis in the balance sheet.

Note 3 Production costs

	Group
	Q3	Q2	Q3	01.01.-30.09.
Breakdown of production cost (USD 1 000)	2021	2021	2020	2021	2020
Cost of operations	114 051	106 674	88 428	333 248	327 197
Shipping and handling	46 173	43 814	38 679	137 705	120 834
Environmental taxes	14 199	12 176	8 958	37 209	26 731
Production cost based on produced volumes	174 422	162 663	136 066	508 162	474 762
Adjustment for over/underlift (-)	34 376	-4 429	-2 376	34 777	11 145
Production cost based on sold volumes	208 798	158 235	133 690	542 939	485 907
Total produced volumes (boe 1 000)	19 322	18 075	18 548	57 396	56 576
Production cost per boe produced (USD/boe)	9.0	9.0	7.3	8.9	8.4

Note 4 Exploration expenses

	Group
	Q3	Q2	Q3	01.01.-30.09.
Breakdown of exploration expenses (USD 1 000)	2021	2021	2020	2021	2020
Seismic	3 953	11 893	-66	20 059	23 895
Area fee	3 926	3 731	3 251	11 824	11 395
Field evaluation	43 423	61 685	10 089	145 751	23 410
Dry well expenses1)	37 603	15 780	11 708	65 584	50 556
Other exploration expenses	8 571	8 932	7 284	27 196	23 122
Total exploration expenses	97 477	102 020	32 267	270 414	132 377

1) Dry well expenses in Q3 2021 are mainly related to the Stangnestind well.

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 Q3 2021, impairment test has been performed for fixed assets and related intangible assets, including technical goodwill.

Impairment is recognized 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 recognized 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 Q3 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 30 September 2021.

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 Q4 2021 to the end of Q3 2024. From Q4 2024, the oil and gas prices are based on the company's long-term price assumptions. Long-term oil price assumption is unchanged from year-end 2020.

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

Year	USD/BOE
2021	77.8
2022	74.2
2023	68.7
2024	66.2
From 2025 (in real 2021 terms)	65.0

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

Year	GBP/therm
2021	2.39
2022	1.50
2023	0.86
2024	0.62
From 2025 (in real 2021 terms)	0.48

Oil and gas reserves

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

Future expenditure

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

Discount rate

The post tax nominal discount rate used is 8.1 percent, consistent with the rate applied at Q4 2020.

Currency rates
Year	USD/NOK
2021	8.75
2022	8.81
2023	8.89
2024	8.71
From 2025	8.00

Inflation

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

Impairment testing of assets including technical goodwill

The technical goodwill recognized in previous business combinations is allocated to each CGU for the purpose of impairment testing. Hence, the impairment test of technical goodwill is included in the impairment testing of assets, and the technical goodwill is written down before the asset. The carrying value of the assets is the sum of tangible assets, intangible assets and technical goodwill as of the assessment date. 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 reversal of impairment and the carrying value per cash generating unit where impairments and reversals have been recognized in Q3 2021:

Cash-generating unit (USD 1 000)	Ivar Aasen	Ula/Tambar
Net carrying value	951 779	663 872
Recoverable amount	1 018 646	506 953
Impairment/reversal (-)1)	-3 038	156 919
Allocated as follows:
Technical goodwill	-	-
Other intangible assets/license rights	-	4 251
Tangible fixed assets	-3 038	152 668

1) Reversal of impairment on Ivar Aasen is capped at maximun available reversal amount adjusted for depreciation.

The main reasons for the Ula impairment charge are the effect of updated cost and production profiles offset by the increase in short-term oil and gas prices. The main reason for the Ivar Aasen impairment reversal is the increase in short-term oil and gas prices.

For details of the allocation of the impairment/reversal to tangible fixed assets and intangible assets, see note 6.

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. The CGU's impacted are Ula/Tambar and Ivar Aasen.

	Change in impairment after
Assumption (USD 1 000)	Change	Increase in assumptions	Decrease in assumptions
Oil and gas price forward period	+/- 50 %	-184 003	437 816
Oil and gas price long-term	+/- 20 %	-151 026	231 298
Production profile (reserves)	+/- 5 %	-58 389	62 731
Discount rate	+/- 1 % point	4 359	-2 925
Currency rate USD/NOK	+/- 2.0 NOK	-176 680	324 961
Inflation	+/- 1 % point	-33 105	30 534

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
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	407 491	240 395	8 153	656 039
Disposals/retirement	-	-	-	-
Reclassification	-172 523	276 720	2 597	106 794
Acquisition cost 30.06.2021	1 323 722	10 403 990	252 053	11 979 765
Accumulated depreciation and impairments 31.12.2020	-	3 824 491	126 305	3 950 795
Depreciation	-	429 902	21 814	451 716
Impairment/reversal (-)	-	-53 135	-	-53 135
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
Acquisition cost 30.06.2021	1 323 722	10 403 990	252 053	11 979 765
Additions	167 044	153 603	1 373	322 019
Disposals/retirement	-	-	-	-
Reclassification	835	88 340	-78	89 097
Acquisition cost 30.09.2021	1 491 601	10 645 933	253 348	12 390 882
Accumulated depreciation and impairments 30.06.2021	-	4 201 258	148 118	4 349 376
Depreciation	-	214 248	10 900	225 148
Impairment/reversal (-)	-	149 630	-	149 630
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 30.09.2021	-	4 565 136	159 018	4 724 154
Book value 30.09.2021	1 491 601	6 080 797	94 329	7 666 727

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	-10 554	-1 262	-	-	-11 816
Disposals/retirement	-	-	-	-	-
Reclassification	-4 222	-841	-	-	-5 063
Acquisition cost 30.06.2021	33 188	59 912	51 709	2 303	147 112
Accumulated depreciation and impairments 31.12.2020	6 099	4 620	14 902	353	25 974
Depreciation	-	1 224	4 121	88	5 433
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
Acquisition cost 30.06.2021	33 188	59 912	51 709	2 303	147 112
Additions	-	-	706	-	706
Allocated to abandonment activity1)	-964	-559	-	-	-1 522
Disposals/retirement	-	-	-	-	-
Reclassification2)	-6 424	-773	-	-	-7 198
Acquisition cost 30.09.2021	25 800	58 580	52 416	2 303	139 099
Accumulated depreciation and impairments 30.06.2021	6 099	5 844	19 023	441	31 407
Depreciation	-	332	2 068	44	2 444
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2021	6 099	6 176	21 091	485	33 851
Book value 30.09.2021	19 701	52 404	31 325	1 818	105 248

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		-		83 246	-
Disposals/retirement/expensed dry wells	-	-	-	27 981	-
Reclassification	-	-	-	-101 731	-
Acquisition cost 30.06.2021	2 368 985	7 501	2 376 486	621 563	2 726 583
Accumulated depreciation and impairments 31.12.2020	847 674	7 501	855 175	146 107	1 079 146
Depreciation	40 777	-	40 777	-	-
Impairment/reversal (-)	82 791	-	82 791	-	-
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
Acquisition cost 30.06.2021	2 368 985	7 501	2 376 486	621 563	2 726 583
Additions	-	-	-	48 562	-
Disposals/retirement/expensed dry wells	-	-	-	37 603	-
Reclassification1)	-	-	-	-81 899	-
Acquisition cost 30.09.2021	2 368 985	7 501	2 376 486	550 622	2 726 583
Accumulated depreciation and impairments 30.06.2021	971 241	7 501	978 742	146 107	1 079 146
Depreciation	19 255	-	19 255	-	-
Impairment/reversal (-)	4 251	-	4 251	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2021	994 747	7 501	1 002 248	146 107	1 079 146
Book value 30.09.2021	1 374 238	-	1 374 238	404 515	1 647 436

1) The reclassification is mainly related to the NOA Fulla project, which passed concept select during Q3 2021.

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

	Group
Depreciation in the income statement (USD 1 000)	Q3	Q2	Q3	01.01.-30.09.
	2021	2021	2020	2021	2020
Depreciation of tangible fixed assets Depreciation of right-of-use assets	225 148 2 444	219 212 2 839	243 239 2 423	676 864 7 877	741 675 17 194
Depreciation of other intangible assets	19 255	18 322	22 983	60 031	73 541
Total depreciation in the income statement	246 846	240 372	268 645	744 771	832 410
Impairment in the income statement (USD 1 000)
Impairment/reversal of tangible fixed assets	149 630	-	-	96 495	9 492
Impairment/reversal of other intangible assets	4 251	-	-	87 042	296 854
Impairment/reversal of capitalized exploration expenditures	-	-	-	-	146 107
Impairment of goodwill	-	-	-	-	65 373
Total impairment in the income statement	153 881	-	-	183 538	517 825

Note 7 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)	Q3	01.01.-30.06.	01.01.-31.12.
Lease debt as of beginning of period	178 980	215 760	313 256
New lease debt recognized in the period	706	5 282	16 834
Payments of lease debt1)	-24 138	-48 471	-118 224
Lease debt derecognized in the period	-	-	-12 767
Interest expense on lease debt	2 708	6 483	16 629
Currency exchange differences	-615	-74	32
Total lease debt	157 641	178 980	215 760
Short-term	61 869	79 432	83 904
Long-term	95 772	99 548	131 856
1) Payments of lease debt split by activities (USD 1 000):
Investments in fixed assets	17 549	12 724	67 125
Abandonment activity	3 357	28 155	27 660
Operating expenditures	1 492	3 975	18 075
Exploration expenditures	578	1 053	874
Other income	1 162	2 564	4 489
Total	24 138	48 471	118 224
Nominal lease debt maturity breakdown (USD 1 000):
Within one year	69 417	88 187	95 124
Two to five years	69 980	71 135	99 809
After five years	46 880	51 044	57 464
Total	186 276	210 366	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 8 Financial items

	Group
	Q3		Q3	01.01.-30.09.
(USD 1 000)	2021	2021	2020	2021	2020
Interest income	342	331	1 081	1 040	3 674
Realized gains on derivatives	3 640	8 713	3 183	21 868	9 628
Change in fair value of derivatives	-	-	94 709		37 017
Net currency gains	29 810	37 483	9 250	63 262	85 008
Total other financial income	33 449	46 197	107 142	85 129	131 653
Interest expenses	30 611	37 369	44 498	112 431	134 632
Interest on lease debt	2 708	3 075	3 855	9 190	13 098
Capitalized interest cost, development projects	-9 344	-10 018	-8 553	-27 582	-30 426
Amortized loan costs	3 043	9 006	6 766	19 422	16 733
Total interest expenses	27 018	39 432	46 566	113 461	134 037
Net currency loss	-	-	-	-	-
Realized loss on derivatives	8 205	34	70 563	8 239	116 670
Change in fair value of derivatives	17 389	16 292	-	39 689	4 490
Accretion expenses	28 624	28 641	28 911	84 933	87 649
Other financial expenses	1	23 872	12 861	38 882	19 269
Total other financial expenses	54 218	68 840	112 335	171 743	228 078
Net financial items	-47 444	-61 744	-50 678	-199 035	-226 788

Note 9 Tax

	Group
	Q3	Q2	Q3	01.01.-30.09.
Tax for the period (USD 1 000)	2021	2021	2020	2021	2020
Current year tax payable/receivable	500 466	129 515	16 920	858 627	-358 940
Change in current year deferred tax	94 625	267 563	91 308	503 543	368 494
Prior period adjustments	769	1 529	2 756	6 402	3 217
Tax expense (+)/income (-)	595 860	398 607	110 983	1 368 571	12 770

		Group
	2021		2020
Calculated tax payable (-)/tax receivable (+) (USD 1 000)	Q3	01.01.-30.06.	01.01.-31.12.
Tax payable/receivable at beginning of period	-597 387	-163 352	-361 157
Current year tax payable/receivable	-500 466	-358 161	333 104
Tax payable/receivable related to acquisitions/sales	-	-	-3 855
Net tax payment/refund	97 680	-34 640	-180 922
Prior period adjustments and change in estimate of uncertain tax positions	-3 677	-48 769	-10 425
Currency movements of tax payable/receivable	13 367	7 535	59 903
Net tax payable (-)/receivable (+)	-990 482	-597 387	-163 352
Tax receivable included as current assets (+)	-	-	-
Tax payable included as current liabilities (-)	-990 482	-597 387	-163 352

	Group
	2021		2020
Deferred tax liability (-)/asset (+) (USD 1 000)	Q3	01.01.-30.06.	01.01.-31.12.
Deferred tax liability/asset at beginning of period	-3 050 315	-2 642 461	-2 235 357
Change in current year deferred tax	-94 625	-408 917	-448 393
Deferred tax related to acquisitions/sales	-	-	37 727
Prior period adjustments	2 907	1 064	3 595
Deferred tax charged to OCI and equity	-	-	-33
Net deferred tax liability (-)/asset (+)	-3 142 033	-3 050 315	-2 642 461

	Group
	Q3	Q2	Q3 01.01.-30.09.
Reconciliation of tax expense (USD 1 000)	2021	2021	2020	2021	2020
78 % tax rate on profit/loss before tax	625 321	430 886	149 195	1 447 092	-56 146
Tax effect of uplift	-69 449	-72 561	-62 755	-190 574	-207 263
Permanent difference on impairment	4 149	-	-	2 829	168 174
Foreign currency translation of monetary items other than USD	-22 772	-28 432	-7 893	-48 807	-65 066
Foreign currency translation of monetary items other than NOK	-18 432	10 637	91 334	1 558	-100 655
Tax effect of financial and other 22 % items	44 088	42 390	1 765	105 067	145 713
Currency movements of tax balances1)	27 840	10 650	-65 982	34 891	123 047
Other permanent differences, prior period adjustments and change in estimate of	5 115	5 037	5 319	16 516	4 966
uncertain tax positions
Tax expense (+)/income (-)	595 860	398 607	110 983	1 368 571	12 770

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 10 Other short-term receivables

	Group
(USD 1 000)	30.09.2021	30.06.2021	31.12.2020	30.09.2020
Prepayments	41 535	47 743	59 635	62 553
VAT receivable	7 683	6 635	6 770	4 152
Underlift of petroleum	21 741	46 812	53 537	47 808
Accrued income from sale of petroleum products	145 465	42 822	49 441	98 119
Other receivables, mainly balances with license partners	90 869	94 295	117 433	94 579
Total other short-term receivables	307 293	238 307	286 817	307 211

Note 11 Cash and cash equivalents

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

	Group
Breakdown of cash and cash equivalents (USD 1 000)	30.09.2021	30.06.2021	31.12.2020	30.09.2020
Bank deposits	1 420 783	975 360	537 801	818 547
Cash and cash equivalents	1 420 783	975 360	537 801	818 547
Unused RCF facility	3 400 000	3 400 000	4 000 000	4 000 000

The RCF is undrawn as at 30 September 2021 and the remaining unamortized fees of USD 18.0 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 September 2021 the Leverage Ratio is 0.56 and Interest Coverage Ratio is 19.6 (see APM section for further details), which are well within the thresholds mentioned above. Based on the group's current business plans and applying oil and gas price forward curves at end of Q3 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 12 Derivatives

	Group
(USD 1 000)	30.09.2021	30.06.2021	31.12.2020	30.09.2020
Unrealized gain currency contracts	2 765	4 560	12 841	4 075
Long-term derivatives included in assets	2 765	4 560	12 841	4 075
Unrealized gain on currency contracts	10 860	18 327	23 212	-
Short-term derivatives included in assets	10 860	18 327	23 212	-
Total derivatives included in assets	13 625	22 887	36 053	4 075
Unrealized losses currency contracts	2 006	1 114	-	-
Long-term derivatives included in liabilities	2 006	1 114	-	-
Unrealized losses commodity derivatives	12 420	16 514	3 539	5 257
Unrealized losses currency contracts	15 255	8 020	-	10 031
Short-term derivatives included in liabilities	27 675	24 534	3 539	15 288
Total derivatives included in liabilities	29 681	25 648	3 539	15 288

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 marked 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 13 Other current liabilities

	Group
Breakdown of other current liabilities (USD 1 000)	30.09.2021	30.06.2021	31.12.2020	30.09.2020
Balances with license partners	77 026	56 573	20 915	44 862
Share of other current liabilities in licenses	357 849	382 071	245 158	232 423
Overlift of petroleum	14 312	5 006	11 331	28 882
Payroll liabilities, accrued interest and other provisions	182 171	227 577	216 942	146 320
Total other current liabilities	631 358	671 228	494 346	452 488

Note 14 Bonds

		Group
Senior unsecured bonds (USD 1 000)	Maturity	30.09.2021	30.06.2021	31.12.2020	30.09.2020
AKERBP – USD Senior Notes 4.750% (19/24)	Jun 2024	-	-	743 329	742 853
AKERBP – USD Senior Notes 3.000% (20/25)	Jan 2025	497 075	496 856	496 417	496 195
AKERBP – USD Senior Notes 5.875% (18/25)	Mar 2025	-	-	495 523	495 260
AKERBP – USD Senior Notes 2.875% (20/26)	Jan 2026	496 926	496 748	496 394	495 930
AKERBP – EUR Senior Notes 1.125% (21/29)	May 2029	862 939	883 572	-	-
AKERBP – USD Senior Notes 3.750% (20/30)	Jan 2030	993 424	993 227	992 764	992 585
AKERBP – USD Senior Notes 4.000% (20/31)	Jan 2031	744 575	744 430	744 139	743 993
Long-term bonds - book value		3 594 939	3 614 833	3 968 566	3 966 815
Long-term bonds - fair value		3 823 194	3 848 454	4 191 375	4 002 625
AKERBP – USD Senior Notes 6.000% (17/22)	Jul 2022	-	-	-	406 000
Short-term bonds - book value		-	-	-	406 000
Short-term bonds - fair value		-	-	-	406 000

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

	Group
	2021	2021	2020
(USD 1 000)	Q3	01.01.-30.06.	01.01.-31.12.
Provisions as of beginning of period	2 759 653	2 805 507	2 788 218
Change in abandonment liability due to asset sales	-	-	-13 122
Incurred removal cost	-24 763	-144 964	-162 741
Accretion expense	28 624	56 309	116 947
Impact of changes to discount rate	-	-	20 554
Change in estimates and provisions relating to new drilling and installations1)	-47 294	42 801	55 650
Total provision for abandonment liabilities	2 716 220	2 759 653	2 805 507
Short-term	78 750	80 230	155 244
Long-term	2 637 470	2 679 423	2 650 263

1) The change in estimate is mainly related to discounting effects after the approval of the lifetime extension on the Alvheim area, which was triggered by the PDO submission on the Kobra East Gekko (KEG) project.

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	30.09.2021	30.06.2021
Aker BP as operator	79	81
Aker BP as partner	45	51

Changes in production licenses in which Aker BP is the operator:			Changes in production licenses in which Aker BP is a partner:
License:	30.09.2021	30.06.2021 License:		30.09.2021	30.06.2021
PL 9641)	0.000%	40.000 % PL 7801)		0.000%	40.000 %
PL 10082)	100.000%		60.000 % PL 852B1)	0.000%	40.000 %
PL 10811)	0.000%		60.000 % PL 852C1)	0.000%	40.000 %
			PL 9611)	0.000%	30.000 %
			PL 9621)	0.000%	20.000 %
			PL 9661)	0.000%	30.000 %
Total	1		3 Total	-	6

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

2) Wellesley has withdrawn from the license

Note 19 Selected historical interim information

	2021
(USD 1 000)	Q3	Q2	Q1	Q4	Q3
Total income	1 562 675	1 123 754	1 133 238	833 508	683 865
Production costs	208 798	158 235	175 906	142 068	133 690
Exploration expenses	97 477	102 020	70 917	41 722	32 267
Depreciation	246 846	240 372	257 554	289 408	268 645
Impairments	153 881	-	29 656	55 302	-
Other operating expenses	6 534	8 965	8 225	27 028	7 309
Total operating expenses	713 537	509 592	542 258	555 528	441 912
Operating profit/loss	849 138	614 162	590 980	277 980	241 954
Net financial items	-47 444	-61 744	-89 846	-42 313	-50 678
Profit/loss before taxes	801 694	552 418	501 134	235 667	191 276
Tax expense (+)/income (-)	595 860	398 607	374 104	106 200	110 983
Net profit/loss	205 834	153 811	127 029	129 467	80 293

	2021		2020
(boe 1 000)	Q3	Q2	Q1	Q4	Q3
Sold volumes
Liquids Gas	16 892 3 787	14 871 2 879	16 468 3 620	16 165 3 507	14 489 2 779

	2021		2020
(USD 1 000)	Q3	Q2	Q1	Q4	Q3
Assets
Goodwill	1 647 436	1 647 436	1 647 436	1 647 436	1 647 436
Other intangible assets	1 778 753	1 873 199	1 878 702	2 043 233	2 050 887
Property, plant and equipment	7 666 727	7 630 389	7 392 321	7 266 137	7 218 548
Right-of-use asset	105 248	115 705	126 861	132 735	126 433
Receivables and other assets	963 070	833 760	803 603	792 750	561 657
Calculated tax receivables (short)	-	-	-	-	71 038
Cash and cash equivalents	1 420 783	975 360	392 276	537 801	818 547
Total assets	13 582 017	13 075 850	12 241 198	12 420 091	12 494 548
Equity and liabilities
Equity	2 127 860	2 030 304	1 988 993	1 987 281	1 928 638
Other provisions for liabilities incl. P&A (long)	2 639 476	2 680 537	2 665 343	2 650 263	2 649 759
Deferred tax	3 142 033	3 050 315	2 781 602	2 642 461	2 562 528
Bonds and bank debt	3 594 939	3 614 833	3 474 328	3 968 566	4 372 815
Lease debt	157 641	178 980	200 346	215 760	217 148
Other current liabilities incl. P&A	929 586	923 494	678 456	792 407	763 660
Tax payable	990 482	597 387	452 131	163 352
Total equity and liabilities	13 582 017	13 075 850	12 241 198	12 420 091	12 494 548

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 7.

		Q3	Q2	Q3	01.01.-30.09.	01.01.-31.12.
(USD 1 000)	Note	2021	2021	2020	2021	2020
Abandonment spend
Payment for removal and decommissioning of oil fields		23 241	54 572	28 861	156 389	150 306
Payments of lease debt (abandonment activity)	7	3 357	8 377	6 059	31 512	27 660
Abandonment spend		26 598	62 949	34 921	187 901	177 966
Depreciation per boe
Depreciation	6	246 846	240 372	268 645	744 771	1 121 818
Total produced volumes (boe 1 000)	3	19 322	18 075	18 548	57 396	77 101
Depreciation per boe		12.8	13.3	14.5	13.0	14.6
Dividend per share
Paid dividend		112 500	112 500	70 833	337 500	425 000
Number of shares outstanding		359 337	359 610	359 534	359 594	359 808
Dividend per share		0.31	0.31	0.20	0.94	1.18
Capex
Disbursements on investments in fixed assets (excluding capitalized interest)		359 969	378 887	261 234	955 017	1 238 601
Payments of lease debt (investments in fixed assets)	7	17 549	11 863	14 238	30 273	67 125
CAPEX		377 518	390 749	275 472	985 290	1 305 727
EBITDA
Total income	2	1 562 675	1 123 754	683 865	3 819 667	2 979 263
Production costs	3	-208 798	-158 235	-133 690	-542 939	-627 975
Exploration expenses	4	-97 477	-102 020	-32 267	-270 414	-174 099
Other operating expenses		-6 534	-8 965	-7 309	-23 725	-49 457
EBITDA		1 249 865	854 534	510 599	2 982 590	2 127 731
EBITDAX
Total income	2	1 562 675	1 123 754	683 865	3 819 667	2 979 263
Production costs	3	-208 798	-158 235	-133 690	-542 939	-627 975
Other operating expenses		-6 534	-8 965	-7 309	-23 725	-49 457
EBITDAX		1 347 342	956 554	542 866	3 253 004	2 301 830
Equity ratio
Total equity		2 127 860	2 030 304	1 928 638	2 127 860	1 987 281
Total assets		13 582 017	13 075 850	12 494 548	13 582 017	12 420 091
Equity ratio		16%	16%	15%	16%	16%
Exploration spend
Disbursements on investments in capitalized exploration expenditures		48 562	56 267	32 842	131 808	127 283
Exploration expenses	4	97 477	102 020	32 267	270 414	174 099
Dry well	4	-37 603	-15 780	-11 708	-65 584	-56 626
Payments of lease debt (exploration expenditures)	7	578	558	221	1 631	874
Exploration spend		109 013	143 065	53 622	338 269	245 629

		Q3	Q2	Q3	01.01.-30.09.	01.01.-31.12.
(USD 1 000)	Note	2021	2021	2020	2021	2020
Interest coverage ratio
Twelve months rolling EBITDA	19	3 605 280	2 866 013	2 250 209	3 605 280	2 127 731
Twelve months rolling EBITDA, impacts from IFRS 16	7	-14 052	-14 358	-25 528	-14 052	-23 438
Twelve months rolling EBITDA, excluding impacts from IFRS 16		3 591 228	2 851 656	2 224 680	3 591 228	2 104 293
Twelve months rolling interest expenses	8	162 300	176 186	177 185	162 300	184 501
Twelve months rolling amortized loan cost	8	22 502	26 226	21 196	22 502	19 813
Twelve months rolling interest income	8	1 128	1 867	4 013	1 128	3 763
Net interest expenses		183 674	200 545	194 367	183 674	200 552
Interest coverage ratio		19.6	14.2	11.4	19.6	10.5
Leverage ratio
Long-term bonds	14	3 594 939	3 614 833	3 966 815	3 594 939	3 968 566
Short-term bonds	14	-	-	406 000	-	-
Cash and cash equivalents	11	1 420 783	975 360	818 547	1 420 783	537 801
Net interest-bearing debt excluding lease debt		2 174 157	2 639 473	3 554 268	2 174 157	3 430 766
Twelve months rolling EBITDAX	19	3 917 416	3 112 940	2 467 269	3 917 416	2 301 830
Twelve months rolling EBITDAX, impacts from IFRS 16	7	-12 111	-12 774	-25 005	-12 111	-22 564
Twelve months rolling EBITDAX, excluding impacts from IFRS 16		3 905 305	3 100 166	2 442 263	3 905 305	2 279 266
Leverage ratio		0.56	0.85	1.46	0.56	1.51
Net interest-bearing debt
Long-term bonds	14	3 594 939	3 614 833	3 966 815	3 594 939	3 968 566
Long-term lease debt	7	95 772	99 548	136 074	95 772	131 856
Short-term bonds	14	-	-	406 000	-	-
Short-term lease debt	7	61 869	79 432	81 075	61 869	83 904
Cash and cash equivalents	11	1 420 783	975 360	818 547	1 420 783	537 801
Net interest-bearing debt		2 331 798	2 818 452	3 771 416	2 331 798	3 646 526

Operating profit/loss see Income Statement

Production cost per boe see note 3

KPMG AS Sørkedalsveien 6 Postboks 7000 Majorstuen 0306 Oslo

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

To the Board of Directors of Aker BP ASA

Independent Auditors' Report on Review of Interim Financial Information

Introduction

We have reviewed the accompanying condensed consolidated statement of financial position of Aker BP ASA as at 30 September 2021 and the related condensed consolidated income statement, and condensed consolidated statement of cash flow for the three-month and nine-month periods ended 30 September 2021, the condensed consolidated statement of changes in equity for the three-month period ended 30 September 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, 27 October 2021

KPMG AS

Roland Fredriksen State Authorised Public Accountant (Norway)

Oslo	Elverum	Mo i Rana	Stord
Alta	Finnsnes	Molde	Straume
Arendal	Hamar	Skien	Tromsø
Bergen	Haugesund	Sandefjord	Trondheim
Bodø	Knarvik	Sandnessjøen	Tynset
Drammen	Kristiancand	Stavanner	A asuna

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