Aker BP

Quarterly Report • Feb 4, 2021

Q UA RT E R LY R E P O RT Q 4 2 0 2 0

FOURTH QUARTER 2020 SUMMARY

Aker BP reported total income of USD 834 (684) million and operating profit of USD 278 (242) million for the fourth quarter 2020, positively impacted by increased production and higher oil and gas prices. Net profit was USD 129 (80) million. The Ærfugl phase I development was completed and started production in the quarter.

The company's net production in the fourth quarter was 223.1 (201.6) thousand barrels of oil equivalents per day (mboepd). The increase from the previous quarter was driven by new wells on production at Ærfugl and Alvheim, by higher production from Johan Sverdrup, and by generally higher production efficiency. Due to underlift in the quarter, net sold volume was 213.8 (187.7) mboepd. Average production for the year 2020 was 210.7 mboepd, within the previous guidance range.

Average realised liquids price was USD 44.2 (42.7) per barrel, while the realised price for natural gas averaged USD 0.20 (0.12) per standard cubic metre (scm).

Production costs for the oil and gas sold in the quarter amounted to USD 142 (134) million. Production cost per produced unit amounted to USD 8.1 (7.3) per boe in the fourth quarter, and USD 8.3 per boe on average for the full year 2020.

Exploration expenses amounted to USD 42 (32) million. Total cash spend on exploration was USD 80 (54) million and included costs related to a discovery well at Alve NE. For the full year, the company's exploration spend was USD 246 million, somewhat below previous guidance of USD 300 million as two exploration wells were moved to 2021.

Other operating expenses increased to USD 27 (7) million, driven by non-recurring items. Depreciation was USD 289 (269) million, equivalent to USD 14.1 (14.5) per boe. Impairments amounted to USD 55 (0) million. Net financial expenses were USD 42 (51) million in the quarter. Profit before taxes amounted to USD 236 (191) million. Tax expense was USD 106 (111) million. The company reported a net profit of USD 129 (80) million for the fourth quarter.

Capital expenditure for the development of fixed assets amounted to USD 298 (275) million in the fourth quarter. All development

projects progressed according to plan, and the Ærfugl phase I development was completed on schedule and started production in November. For the full year, capital expenditure was USD 1,306 million, in line with previous guidance. Abandonment expenditures were USD 105 (35) million for the quarter, bringing the full year total to USD 178 million, slightly below previous guidance of USD 200 million.

Aker BP has implemented a wide range of measures to minimise the risk to people and operations from the COVID-19 pandemic, including reduced offshore manning, mandatory testing for all offshore personnel, social distancing, travel restrictions and working from home. The company has so far avoided any virus-related disruptions to its operations. The relevant policies and procedures will remain in place for as long as necessary.

Following the temporary changes in the Petroleum Tax Law enacted in June 2020, the tax value of any losses incurred in 2020 and 2021 are refundable. During the fourth quarter, Aker BP received net tax refunds of USD 201 million.

At the end of the fourth quarter, Aker BP had total available liquidity of USD 4.5 (4.8) billion. Net interest-bearing debt was USD 3.6 (3.8) billion, including 0.2 (0.2) billion in lease debt. The company's USD 400 million Senior Notes 6.000% (2017/2022) were redeemed in October.

In November, the company disbursed dividends of USD 70.8 million, equivalent to USD 0.1967 per share. In total, the company paid USD 425 million in dividends in 2020. The Board has resolved to pay a quarterly dividend of USD 112.5 million, equivalent to USD 0.3124 per share, in February 2021, with an ambition to pay total dividends of USD 450 million in 2021 if current market conditions prevail.

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	Q4 2020	Q3 2020	Q4 2019	2020	2019
Total income	USDm	834	684	1 003	2 979	3 347
EBITDA	USDm	623	511	745	2 128	2 286
Net profit/loss	USDm	129	80	112	45	141
Earnings per share (EPS)	USD	0.36	0.22	0.31	0.12	0.39
Capex	USDm	298	275	506	1 306	1 667
Exploration spend	USDm	80	54	79	246	501
Abandonment spend	USDm	105	35	10	178	109
Production cost	USD/boe	8.1	7.3	9.1	8.3	12.4
Taxes paid/refunded	USDm	-201	-109	199	-181	619
Net interest-bearing debt	USDm	3 647	3 771	3 493	3 647	3 493
Leverage ratio		1.5	1.5	1.2	1.5	1.2
Dividend per share (DPS)	USD	0.20	0.20	0.52	1.18	2.08
Average USDNOK exchange rate		9.02	9.13	9.11	9.41	8.80

See the description of "Alternative performance measures" at the end of this report for definitions.

Production summary

	UNIT	Q4 2020	Q3 2020	Q4 2019	2020	2019
Alvheim area	mboepd	54.7	51.2	56.4	55.4	54.4
Ivar Aasen	mboepd	18.7	17.0	23.1	20.1	21.8
Johan Sverdrup	mboepd	59.6	53.1	31.5	51.9	7.9
Skarv	mboepd	26.1	17.5	22.1	21.0	22.3
Ula area	mboepd	10.3	10.4	11.1	11.0	8.5
Valhall area	mboepd	53.6	52.3	45.4	50.7	39.0
Other	mboepd	0.0	0.0	1.4	0.5	1.9
Net production	mboepd	223.1	201.6	191.1	210.7	155.9
Over/underlift	mboepd	-9.3	-13.9	-6.6	-0.5	1.8
Net sold volume	mboepd	213.8	187.7	184.5	210.2	157.6
- Liquids	mboepd	175.7	157.5	151.4	176.4	126.6
- Natural gas	mboepd	38.1	30.2	33.1	33.8	31.0
Realised price liquids	USD/boe	44.2	42.7	64.2	40.0	64.8
Realised price natural gas	USD/scm	0.20	0.12	0.17	0.14	0.18

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q4 2020	Q3 2020	Q4 2019	2020	2019
Total income	834	684	1 003	2 979	3 347
EBITDA	623	511	745	2 128	2 286
EBIT	278	242	491	433	1 327
Pre-tax profit	236	191	424	164	1 084
Net profit/loss	129	80	112	45	141
EPS (USD)	0.36	0.22	0.31	0.12	0.39

Total income in the fourth quarter 2020 increased to USD 834 (684) million, driven by an increase in sold volumes and higher realised prices compared to the previous quarter. Sold volumes were 213.8 (187.7) mboepd in the quarter. Realised prices increased by 4 percent for liquids and 69 percent for natural gas.

Production costs related to oil and gas sold in the quarter amounted to USD 142 (134) million. Production cost per produced unit amounted to USD 8.1 (7.3) per boe, and the increase was mainly driven by higher well maintenance costs in the fourth quarter.

Exploration expenses amounted to USD 42 (32) million. This included USD 6 (12) million in dry well expenses mainly related to the Bask exploration well, which was concluded as a dry well after the end of the quarter. Field evaluation costs increased driven by concept studies for NOAKA.

Depreciation amounted to USD 289 (269) million, corresponding to USD 14.1 (14.5) per produced barrel. Impairments of fixed assets amounted to USD 55 (0) million, mainly related to Ivar Aasen, driven by changes in accounting assumptions described in note 5. Other operating expenses amounted to USD 27 (7) million and were impacted by approximately USD 20 million in non-recurring items.

Operating profit was USD 278 (242) million in the quarter. Net financial expenses amounted to USD 42 (51) million and profit before taxes amounted to USD 236 (191) million. Tax expense was USD 106 (111) million. The effective tax rate was 45 percent. The main drivers for the relatively low effective tax rate were the treatment of uplift under the temporary tax system, as well as positive currency effects. See note 9 to the financial statements for further details.

This resulted in a net profit for the fourth quarter 2020 of USD 129 (80) million.

Statement of financial position

(USD MILLION)	Q4 2020	Q3 2020	Q4 2019
Total non-current assets	11 162	11 102	11 508
Total current assets	1 258	1 392	719
Total assets	12 420	12 495	12 227
Total equity	1 987	1 929	2 368
Bank and bond debt	3 969	4 373	3 287
Total abandonment provisions	2 806	2 825	2 788
Deferred taxes	2 642	2 563	2 235
Other liabilities	1 016	806	1 549
Total equity and liabilities	12 420	12 495	12 227
Net interest-bearing debt	3 647	3 771	3 493

At the end of the fourth quarter 2020, total assets amounted to USD 12,420 (12,495) million, of which current assets were USD 1,258 (1,392) million.

Equity amounted to USD 1,987 (1,929) million at the end of the quarter, corresponding to an equity ratio of 16 (15) percent.

Deferred tax liabilities amounted to USD 2,642 (2,563) million and total abandonment provisions amounted to USD 2,806 (2,825) million.

Bank and bond debt totalled USD 3,969 (4,373) million, of which the company's bonds constitute the entire debt at the end of this quarter.

At the end of the fourth quarter, the company had total available liquidity of USD 4.5 (4.8) billion, comprising USD 538 (819) million in cash and cash equivalents, and USD 4.0 (4.0) billion in undrawn credit facilities.

Cash flow

(USD MILLION)	Q4 2020	Q3 2020	Q4 2019	2020	2019
Cash flow from operations	645	526	525	1 857	1 885
Cash flow from investments	-435	-331	-541	-1 501	-2 178
Cash flow from financing	-491	481	117	74	356
Net change in cash & cash equivalents	-281	676	101	431	62
Cash and cash equivalents	538	819	107	538	107

Net cash flow from operating activities was USD 645 (526) million in the quarter. The main reason for the increase was the tax refund of USD 201 (109) million following the temporary changes to the Norwegian petroleum tax system.

Net cash used for investment activities was USD 435 (331) million, of which investments in fixed assets amounted to USD 306 (270) million for the quarter. Investments in capitalised exploration were USD 44 (33) million. Payments for decommissioning activities increased to USD 86 (29) million due to a P&A campaign at Valhall.

Net cash flow from financing activities was negative at USD 491 million, compared to a positive net cash flow from financing activities of USD 481 million in the previous quarter. Repayment of bonds amounted to USD 400 million and dividend disbursements were USD 71 (71) million. Payments on lease debt amounted to USD 20 (20) 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	Q1 2021	Q2 2021	Q3 2021	Q4 2021
Share of oil prod. covered (after tax)	37 %	40 %	28 %	27 %
Average strike (USD/bbl)	40	40	40	40
Average premium (USD/bbl)	1.8	1.8	2.0	2.0

Dividends

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

In November, the company disbursed dividends of USD 70.8 million, equivalent to USD 0.1967 per share. Total dividend distributions in 2020 amounted to USD 425 million (USD 1.18 per share).

On 3 February 2021, the Board resolved to pay a quarterly dividend of USD 112.5 million (USD 0.3124 per share) on or about 18 February 2021. The ambition is to pay total dividends of USD 450 million in 2021 if current market conditions prevail.

OPER ATIONAL RE VIE W

Aker BP's net production was 20.5 (18.5) mmboe in the fourth quarter of 2020, corresponding to 223.1 (201.6) mboepd. Due to underlift, net sold volume was 213.8 (187.7) mboepd. The average realised liquids price was USD 44.2 (42.7) per barrel, while the average realised gas price was USD 0.20 (0.12) per scm.

Alvheim Area

Key figures	Aker BP interest	Q4 2020	Q3 2020	Q2 2020	Q1 2020	Q4 2019
Production, boepd
Alvheim	65 %	35 921	29 447	33 770	36 995	36 588
Bøyla	65 %	3 843	4 858	6 568	7 631	7 534
Skogul	65 %	6 891	8 091	7 899	1 622	-
Vilje	46.904 %	2 899	2 616	3 259	3 472	3 279
Volund	65 %	5 192	6 200	6 511	7 774	9 040
Total production		54 746	51 212	58 006	57 494	56 441
Production efficiency		98 %	92 %	96 %	98 %	98 %

Fourth quarter production from the Alvheim area was 54.7 mboepd net to Aker BP, up 7 percent from the previous quarter. Production efficiency increased to 98 percent. There have been no unplanned shutdowns at Alvheim in 2020.

First oil from the Kameleon Infill Mid well was achieved in November. Drilling of the Boa Attic South well started in November with the semi-submersible rig Deepsea Nordkapp. First oil from Boa Attic South is planned in the second quarter 2021. Furthermore, a new dual-lateral well, Kameleon Infill West, is being matured and drilling is scheduled to take place during the fourth quarter 2021.

Test production at Frosk continued through the Bøyla template. The Frosk development project is being matured towards final investment decision, planned in the second half of 2021.

A concept decision for the development of the Kobra East and the Gekko (KEG) discoveries was made during the fourth quarter, with final investment decision planned for the second half of 2021. These discoveries are located approximately 10 km south-east of the Alvheim FPSO. The plan is to develop these discoveries with four multilateral wells and a subsea tie-back to Alvheim through the Kneler B manifold.

A project to upgrade the water capacity at the Alvheim FPSO was sanctioned during the fourth quarter, with offshore installation planned during the second and third quarter 2021. The installation will be done in conjunction with a gas debottlenecking project, increasing the gas capacity with approximately 15 percent. Together, these projects will improve the capacity for future tie-back projects at Alvheim.

Ivar Aasen

Key figures	Aker BP interest	Q4 2020	Q3 2020	Q2 2020	Q1 2020	Q4 2019
Production, boepd
Total production	34.7862 %	18 723	17 025	22 089	22 705	23 139
Production efficiency		90 %	75 %	98 %	97 %	97 %

Fourth quarter production from Ivar Aasen was 18.7 mboepd net to Aker BP, up 10 percent from the previous quarter. Production efficiency increased to 90 percent.

As for the previous quarter, both production and production efficiency were impacted by planned activities related to well intervention, drilling operations and maintenance, in addition to turbine service at Edvard Grieg. However, there was no unplanned production loss during the quarter.

Drilling of the two wells of the 2020 IOR-campaign was completed in the quarter. One of these wells came stream in January 2021, and the second is expected to start in February 2021. A new twowell IOR-campaign has been sanctioned for drilling in 2021, with first oil planned in fourth quarter 2021.

Johan Sverdrup

Key figures	Aker BP interest	Q4 2020	Q3 2020	Q2 2020	Q1 2020	Q4 2019
Production, boepd
Total production	11.5733 %	59 613	53 051	51 027	43 877	31 521

The production at Johan Sverdrup continued with high regularity in the fourth quarter, with 59.6 mboepd net to Aker BP. Following a successful process capacity test in early November, the process capacity was increased from 470,000 to 500,000 barrels per day. The operator is working to increase the water injection capacity at the field, which is expected to lead to a further increase in production capacity to 535,000 barrels per day during 2021.

The twelfth oil production well, drilled from the fixed drilling platform at the field, was put on stream in October. With this well completed, the well production capacity is robust for the increased process capacity. Drilling of the twelfth water injection well started thereafter.

Phase 2 of the Johan Sverdrup development progressed according to plan, despite challenges caused by COVID-19 at several construction sites. The first of three main modules for the second processing platform arrived in early November at the construction site in Haugesund. This module will be integrated with the two other main modules before commissioning and transport offshore for installation at the field centre in 2022.

Skarv Area

Key figures	Aker BP interest	Q4 2020	Q3 2020	Q2 2020	Q1 2020	Q4 2019
Production, boepd
Total production	23.835 %	26 121	17 544	20 599	19 788	22 119
Production efficiency		98 %	86 %	97 %	99 %	100 %

Following the successful start-up of Ærfugl Phase 1 in November, production from the Skarv Area increased by around 50 percent compared to the previous quarter, to 26.1 mboepd net to Aker BP. Production efficiency increased to 98 percent, following a temporary reduction in the previous quarter related to turnaround and Ærfugl-related pull-in operations.

Phase 2 of the Ærfugl development is progressing well with drilling start planned in first quarter 2021 with the Deepsea Nordkapp semi-submersible rig. Production from the remaining two wells of phase 2 is expected to start in fourth quarter 2021. Production from the Ærfugl reservoir will also improve the energy efficiency on the Skarv FPSO, bringing down CO2 emissions by 30-40 percent per barrel produced.

During the quarter, Aker BP and its license partners approved the final investment decision for the Gråsel development. Gråsel has gross reserves of around 13 million boe and will utilize available capacity at the Skarv FPSO. Drilling is scheduled to commence in the second quarter 2021, and first oil is planned for the fourth quarter of 2021.

Ula Area

Key figures	Aker BP interest	Q4 2020	Q3 2020	Q2 2020	Q1 2020	Q4 2019
Production, boepd
Ula	80 %	6 239	3 929	4 250	5 512	4 339
Tambar	55 %	1 092	2 595	2 932	3 642	3 054
Oda	15 %	2 959	3 887	3 258	3 623	3 713
Total production		10 290	10 411	10 441	12 777	11 106
Production efficiency		75 %	87 %	80 %	88 %	78 %

Production from the Ula area was stable at 10.3 mboepd net to Aker BP in the fourth quarter, in line with the previous quarter. Production efficiency decreased to 75 percent due to well integrity work at Tambar.

At the Ula field, two additional wells came on stream during the quarter as part of the Ula Infill Drilling campaign, contributing to higher production.

Two new infill wells will be drilled at Ula and Tambar in 2021 with the jack-up rig Maersk Integrator. The first well is planned to be drilled at Tambar in the first quarter, and the second well at Ula in the second quarter.

In recent years, Aker BP has been working to mature a re-development plan for Ula. In 2020, it was concluded that such re-development did not meet the company's investment criteria. Consequently, the company has now adopted a late-life strategy for Ula.

Valhall Area

Key figures	Aker BP interest	Q4 2020	Q3 2020	Q2 2020	Q1 2020	Q4 2019
Production, boepd
Valhall	90 %	52 881	51 647	46 750	49 093	44 205
Hod	90 %	682	682	225	982	1 176
Total production		53 564	52 329	46 975	50 075	45 381
Production efficiency		90 %	90 %	78 %	88 %	90 %

Fourth quarter production from Valhall was 53.6 mboepd net to Aker BP, up 2 percent from the previous quarter. Production efficiency was stable at 90 percent. Stimulation and intervention activities continued to bring the wells up to full production potential.

The Maersk Invincible drilling unit remained at the field center throughout the quarter to plug and abandon (P&A) the remaining wells at the old Drilling Platform (DP) which is subject to removal. The P&A operations are progressing well and are expected to continue into the first quarter. The partnership has sanctioned two additional wells on Flank North to be drilled in 2021, following the completion of the P&A campaign.

The Hod project is progressing as planned at the Aker Solutions yard in Verdal. A milestone was reached when the Ministry of Petroleum and Energy (MPE) approved the Plan for Development (PDO) on 8 December. Production start is planned for first quarter 2022, and the recoverable reserves are estimated at around 40 million barrels of oil equivalents. In conjunction with the PDO approval the Hod production license (PL033) was granted an extension through 2035.

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.

Aker BP and Equinor have entered into an agreement in principle on commercial terms for a coordinated development of Krafla, Fulla and North of Alvheim (NOA). The development plans for the area consist of a processing platform in the south operated by Aker BP, an unmanned processing platform in the north operated by Equinor and several satellite platforms and tiebacks to cover the various discoveries.

Aker BP is working together with its strategic partners in cross-functional teams to further mature and improve the development concept for NOA and Fulla. Equinor, as operator for Krafla, is maturing the Krafla concept in close collaboration with Aker BP to optimize the total area development concept. A concept select decision is planned for the third quarter 2021, and the ambition is to submit Plans for Development and Operations (PDO) in the fourth quarter 2022.

E XPLOR ATION

Total exploration spend in the fourth quarter was USD 80 (54) million, while USD 42 (32) million was recognised as exploration expenses in the period, relating to dry well costs, seismic, area fees, field evaluation and G&G costs.

The drilling of the Alve NE prospect in licence PL127 C, operated by Aker BP, was completed in November. The well was drilled northeast of the Alve Nord discovery in the Norwegian Sea and resulted in a minor oil and gas discovery. The discovery will be evaluated in connection with the Alve Nord discovery and other nearby discoveries in the area for further follow-up. Aker BP has 88.08 percent working interest in the licence.

Drilling of the Bask prospect in licence 533 in the Barents Sea, operated by Lundin Energy, was delayed due to operational incidents on the West Bollsta semi-submersible rig. Drilling operations resumed in January, and the well has now been concluded as dry. Aker BP has a 35 percent working interest in the licence.

Field evaluation costs are driven by activities related to discoveries and projects which have not yet been sanctioned. In the fourth quarter, these costs amounted to USD 21 million, with NOAKA as the main driver.

BUSINESS DEVELOPMENT

In December, Aker BP entered into an agreement with Equinor Energy AS to acquire 10 percent interest in licences PL167, PL167B and PL167C on Utsira High in the North Sea.

The licences are located northeast of the Aker BP operated Ivar Aasen field and hold the Lille Prinsen and Verdandi discoveries, as well as further exploration potential. A well to appraise the Lille Prinsen discovery and test additional exploration potential is planned for 2021.

HE ALTH, SAFET Y, SECURIT Y AND THE ENVIRONMENT

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

KEY HSSE INDICATORS	UNIT	Q4 2020	Q3 2020	Q2 2020	Q1 2020	Q4 2019
Total recordable injury frequency (TRIF) L12M	Per mill. exp. hours	1.6	1.5	2.1	2.7	3.5
Serious incident frequency (SIF) L12M	Per mill. exp. hours	0.5	0.6	0.5	0.6	0.7
Loss of primary containment (LOPC)	Count	0	1	0	0	0
Process safety events Tier 1 and 2	Count	0	0	0	0	0
CO2 emissions intensity*	Kg CO2/boe	3.8	4.0	5.3	5.1	7.9

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

The overall HSSE performance shows a positive trend. The company is working systematically to protect personnel and to ensure continued and uninterrupted production from all assets during the COVID-19 outbreak. The company's policies and procedures have proved effective and will remain in place for as long as necessary.

The average CO2 emissions was 3.8 (4.0) kg per boe. The reduction was mainly driven by increased production from Johan Sverdrup, which has CO2 emissions below 1 kg per boe.

OUTLOOK

The COVID-19 pandemic has created challenges for the oil industry. Under these extraordinary circumstances, 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's financial position continues to be very robust, and the company remains well prepared for future value creation. The main items of the company's financial plan for 2021 are as follows1:

• 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

¹ The majority of the company's cost elements (both capex and production cost) are denominated in NOK. The guidance is based on an average USDNOK for 2021 of 8.50.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT

				Group
		Q4	Q3	Q4	01.01.-31.12.
(USD 1 000)	Note	2020	2020	2019	2020	2019
Petroleum revenues		830 098	674 801	979 561	2 868 153	3 338 667
Other income		3 410	9 065	23 112	111 110	8 421
Total income	2	833 508	683 865	1 002 673	2 979 263	3 347 088
Production costs	3	142 068	133 690	154 272	627 975	720 321
Exploration expenses	4	41 722	32 267	84 683	174 099	305 516
Depreciation	6	289 408	268 645	255 015	1 121 818	811 874
Impairments Other operating expenses	5,6	55 302 27 028	- 7 309	-509 18 550	573 128 49 457	146 808 35 328
Total operating expenses		555 528	441 912	512 011	2 546 477	2 019 848
Operating profit/loss		277 980	241 954	490 661	432 786	1 327 241
Interest income		89	1 081	338	3 763	16 490
Other financial income		49 203	107 142	51 341	170 865	35 255
Interest expenses		47 640	46 566	37 762	181 677	76 587
Other financial expenses		43 965	112 335	80 580	262 052	218 145
Net financial items	8	-42 313	-50 678	-66 663	-269 101	-242 986
Profit/loss before taxes		235 667	191 276	423 998	163 685	1 084 254
Tax expense (+)/income (-)	9	106 200	110 983	312 448	118 970	943 204
Net profit/loss		129 467	80 293	111 550	44 715	141 051
Weighted average no. of shares outstanding basic and diluted		360 100 643	359 533 743	360 113 509	359 808 121	360 014 176
Basic and diluted earnings/loss USD per share		0.36	0.22	0.31	0.12	0.39

STATEMENT OF COMPREHENSIVE INCOME

		Group
	Q4	Q3	Q4		01.01.-31.12.
(USD 1 000)	Note 2020	2020	2019	2020	2019
Profit/loss for the period		129 467 80 293	111 550	44 715	141 051
Items which will not be reclassified over profit and loss (net of taxes) Actuarial gain/loss pension plan		9 -	-4	9	-4
Total comprehensive income/loss in period		129 477 80 293	111 546	44 724	141 046

STATEMENT OF FINANCIAL POSITION

			Group
(USD 1 000)	Note	31.12.2020	30.09.2020	31.12.2019
ASSETS
Intangible assets
Goodwill	6	1 647 436	1 647 436	1 712 809
Capitalized exploration expenditures	6	521 922	507 349	621 315
Other intangible assets	6	1 521 311	1 543 538	1 915 968
Tangible fixed assets
Property, plant and equipment	6	7 266 137	7 218 548	7 023 276
Right-of-use assets	6	132 735	126 433	194 328
Financial assets
Long-term receivables		29 086	26 620	27 418
Other non-current assets		30 210	28 498	10 364
Long-term derivatives	12	12 841	4 075	2 706
Total non-current assets		11 161 678	11 102 498	11 508 183
Inventories
Inventories		112 704	117 126	87 539
Receivables
Accounts receivable		297 880	78 127	193 444
Tax receivables	9	-	71 038	-
Other short-term receivables	10	286 817	307 211	330 516
Short-term derivatives	12	23 212	-	-
Cash and cash equivalents
Cash and cash equivalents	11	537 801	818 547	107 104
Total current assets		1 258 414	1 392 050	718 603
TOTAL ASSETS		12 420 091	12 494 548	12 226 786

STATEMENT OF FINANCIAL POSITION

		Group
(USD 1 000)	Note	31.12.2020	30.09.2020	31.12.2019
EQUITY AND LIABILITIES
Equity
Share capital		57 056	57 056	57 056
Share premium		3 637 297	3 637 297	3 637 297
Other equity		-1 707 071	-1 765 714	-1 326 767
Total equity		1 987 281	1 928 638	2 367 585
Non-current liabilities
Deferred tax	9	2 642 461	2 562 528	2 235 357
Long-term abandonment provision	16	2 650 263	2 649 759	2 645 420
Long-term bonds	14	3 968 566	3 966 815	1 630 936
Long-term lease debt	7	131 856	136 074	202 592
Other interest-bearing debt	15	-	-	1 429 132
Total non-current liabilities		9 393 146	9 315 176	8 143 437
Current liabilities
Trade creditors		113 517	97 733	144 942
Short-term bonds	14	-	406 000	226 700
Accrued public charges and indirect taxes		25 761	23 193	25 974
Tax payable	9	163 352	-	361 157
Short-term derivatives	12	3 539	15 288	42 994
Short-term abandonment provision	16	155 244	174 958	142 798
Short-term lease debt	7	83 904	81 075	110 664
Other current liabilities	13	494 346	452 488	660 535
Total current liabilities		1 039 664	1 250 734	1 715 765
Total liabilities		10 432 810	10 565 910	9 859 201
TOTAL EQUITY AND LIABILITIES		12 420 091	12 494 548	12 226 786

STATEMENT OF CHANGES IN EQUITY - GROUP

				Other equity
					Other comprehensive income
					Foreign currency
		Share	Other paid-in	Actuarial	translation	Retained	Total other
(USD 1 000)	Share capital	premium	capital	gains/losses	reserves1)	earnings	equity	Total equity
Equity as of 31.12.2018	57 056	3 637 297	573 083	-81	-115 491	-1 175 324	-717 814	2 976 539
Dividends distributed	-	-	-	-	-	-750 000	-750 000	-750 000
Profit/loss for the period	-	-	-	-	-	141 051	141 051	141 051
Other comprehensive income for the period	-	-	-	-4	-	-	-4	-4
Equity as of 31.12.2019	57 056	3 637 297	573 083	-85	-115 491	-1 784 274	-1 326 767	2 367 585
Dividend distributed	-	-	-	-	-	-354 167	-354 167	-354 167
Profit/loss for the period	-	-	-	-	-	-84 752	-84 752	-84 752
Purchase/sale of treasury shares2)	-	-	-	-	-	-28	-28	-28
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

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 company's share saving plan.

STATEMENT OF CASH FLOW

				Group
		Q4	Q3	Q4		01.01.-31.12.
(USD 1 000)	Note	2020	2020	2019	2020	2019
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		235 667	191 276	423 998	163 685	1 084 254
Taxes paid	9	-16 556	-	-198 663	-145 286	-618 593
Tax refund	9	217 373	108 835	-	326 208	-
Depreciation	6	289 408	268 645	255 015	1 121 818	811 874
Impairment	5,6	55 302	-	-509	573 128	146 808
Accretion expenses	8,16	29 298	28 911	31 210	116 947	121 723
Interest expenses (including interest element of lease payments)	8	53 400	48 353	48 011	201 131	199 569
Interest paid (including interest element of lease payments)		-35 966	-69 495	-41 908	-184 068	-194 033
Changes in derivatives	2,8	-43 728	-36 801	-46 474	-15 999	22 484
Amortized loan costs	8	3 081	6 766	4 463	19 813	21 705
Expensed capitalized dry wells	4,6	6 071	11 708	47 277	56 626	176 419
Changes in inventories, accounts payable and receivables		-199 547	-9 176	-51 019	-161 027	14 369
Changes in other current balance sheet items		51 211	-22 764	54 061	-215 923	98 567
NET CASH FLOW FROM OPERATING ACTIVITIES		645 014	526 259	525 463	1 857 053	1 885 146
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields		-85 508	-28 861	-9 295	-150 306	-104 890
Disbursements on investments in fixed assets		-306 061	-269 787	-490 457	-1 277 869	-1 703 213
Disbursements on investments in capitalized exploration		-43 774	-32 842	-41 597	-127 283	-370 185
Cash received from sale of licenses		-	-	-	54 747	-
Disbursements on investments in licenses		-	-	-	-	-143
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-435 343	-331 490	-541 348	-1 500 710	-2 178 431
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment of revolving credit facility		-	-400 000	350 000	-1 451 550	1 425 222
Repayment of bonds		-400 000	-212 553	-	-612 553	-
Net drawdown/repayment of short-term debt		-	-	-15 000	-	-
Net drawdown/repayment of reserve-based lending facility		-	-	-	-	-950 000
Net proceeds from bond issue		-	1 234 342	-	2 721 748	740 159
Receipt/payment upon settlement of derivatives related to financing	8	-	-56 804	-	-56 804	-
Payments on lease debt related to investments in fixed assets		-971	-11 935	-25 278	-57 885	-88 718
Payments on other lease debt		-18 873	-8 045	-5 156	-43 709	-20 880
Paid dividend		-70 833	-70 833	-187 500	-425 000	-750 000
Net purchase/sale of treasury shares		-	7 094	-	-28	-
NET CASH FLOW FROM FINANCING ACTIVITIES		-490 677	481 266	117 065	74 219	355 782
Net change in cash and cash equivalents		-281 006	676 034	101 180	430 562	62 498
Cash and cash equivalents at start of period		818 547	142 333	5 066	107 104	44 944
Effect of exchange rate fluctuation on cash held		259	180	859	134	-338
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	537 801	818 547	107 104	537 801	107 104

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 2019 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 not been subject to review or audit by independent auditors.

These interim financial statements were authorised for issue by the company's Board of Directors on 3 February 2021.

Note 1 Accounting principles

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

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

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

The disruption to the global economy caused by COVID-19 resulted in a sharp decrease in oil prices and triggered a reduction in the company's investment program, though operational performance and production levels have been maintained. The fall in oil and gas prices has had a negative impact on operational results and cash flows in the period, and impairments of USD 654 million were recognized in Q1 2020. This impairment have subsequently been partly reversed, mainly as a result of increased oil and gas prices.

In the second quarter, temporary changes to the Norwegian petroleum tax system strengthened the company's investment capacity and are contributing to liquidity (see note 9).

Actions have been taken to protect financial flexibility, including an updated and reduced investment program, cut in dividends and issuance of new bonds. As of 31 December 2020 available liquidity on the Revolving Credit Facility is USD 4.0 billion and the related financial covenants meets the applicable thresholds by a substantial margin (see note 15).

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 company's operations. Such events may adversely impact the company's future results from operations and cash flows, and may lead to impairment of assets.

Note 2 Income

	Group
	Q4	Q3	Q4		01.01.-31.12.
Breakdown of petroleum revenues (USD 1 000)	2020	2020	2019	2020	2019
Sales of liquids	714 514	618 692	894 926	2 581 776	2 993 456
Sales of gas	111 431	52 134	80 047	270 404	328 816
Tariff income	4 154	3 975	4 588	15 973	16 395
Total petroleum revenues	830 098	674 801	979 561	2 868 153	3 338 667
Sales of liquids (boe 1 000)	16 165	14 489	13 930	64 549	46 224
Sales of gas (boe 1 000)	3 507	2 779	3 046	12 384	11 317
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-7 611	-7 458	-2 215	55 328	-12 824
Unrealized gain/loss (-) on oil derivatives	1 718	-1 105	-2 533	-1 734	-19 058
Gain on license transactions	-	-	-	5 417	-
Other income1)	9 302	17 628	27 860	52 099	40 303
Total other income	3 410	9 065	23 112	111 110	8 421

1) Includes insurance settlement during Q4 2020, in addition to partner coverage of RoU assets recognized on gross basis in the balance sheet and used in operated activity.

Note 3 Produced volumes and over/underlift adjustment

	Group
	Q4	Q3	Q4		01.01.-31.12.
(USD 1 000)	2020	2020	2019	2020	2019
Total produced volumes (boe 1 000)	20 525	18 548	17 578	77 101	56 886
Production cost per boe produced (USD/boe)	8.1	7.3	9.1	8.3	12.4
Production cost based on produced volumes	165 349	136 066	160 293	640 111	706 308
Adjustment for over/underlift (-)	-23 281	-2 376	-6 021	-12 137	14 014
Production cost based on sold volumes	142 068	133 690	154 272	627 975	720 321

Note 4 Exploration expenses

	Group
	Q4	Q3	Q4		01.01.-31.12.
Breakdown of exploration expenses (USD 1 000)	2020	2020	2019	2020	2019
Seismic	1 627	-66	12 644	25 522	28 875
Area fee	3 877	3 251	3 578	15 272	15 537
Field evaluation	21 308	10 089	9 723	44 718	42 532
Dry well expenses1)	6 071	11 708	47 277	56 626	176 419
Other exploration expenses	8 839	7 284	11 461	31 961	42 153
Total exploration expenses	41 722	32 267	84 683	174 099	305 516

1) Dry well expenses in Q4 2020 are mainly related to the Bask 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 Q4 2020, two categories of impairment tests have been performed:

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

• Impairment test of residual goodwill

Impairment is recognized when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. 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 Q4 has been performed in accordance with the fair value method (level 3 in fair value hierarchy) and based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years.

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

Prices

Future price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil and gas prices are therefore based on the forward curve from the beginning of Q1 2021 to the end of Q4 2023. From Q1 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 2019.

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

Year	USD/BOE
2021	51.4
2022	50.2
2023	49.6
From 2024 (in real terms)	65.0

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

2021	0.47
2022	0.43
2023	0.42
From 2024 (in real terms)1)	0.52

1) Except for 2026 and 2027 where 0.37 GBP/therm (in real terms) are applied.

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. This represents a change from 7.8 percent applied in previous quarters in 2020.

Currency rates
Year	USD/NOK
2021	8.59
2022	8.62
2023	8.67
From 2024	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 Q4 2020:

Cash-generating unit (USD 1 000)	Ula/Tambar	Ivar Aasen
Net carrying value	685 615	988 323
Recoverable amount	689 876	928 497
Impairment/reversal (-)	-4 261	59 825
Allocated as follows:
Technical goodwill	-	-
Other intangible assets/license rights	-4 261	1 957
Tangible fixed assets	-	57 869

The main reasons for the impairment charge are the net effect of changes in accounting assumptions, as well as updated cost and production profiles.

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, Ivar Aasen and Alvheim.

	Change in impairment after
Assumption (USD 1 000)	Change	Increase in assumptions	Decrease in assumptions
Oil and gas price forward period	+/- 50 %	-171 841	605 232
Oil and gas price long-term	+/- 20 %	-171 841	351 629
Production profile (reserves)	+/- 5 %	-133 225	133 225
Discount rate	+/- 1 % point	68 234	-73 544
Currency rate USD/NOK	+/- 2.0 NOK	-152 416	412 548
Inflation	+/- 1 % point	-145 025	131 350

Residual goodwill

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

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 31.12.2019	1 250 365	5 687 957	84 954	7 023 276
Acquisition cost 31.12.2019	1 250 365	9 066 022	170 413	10 486 800
Additions	529 848	452 269	21 007	1 003 124
Disposals/retirement	-	675 733	-69	675 664
Reclassification	-624 433	610 322	48 867	34 756
Acquisition cost 30.09.2020	1 155 780	9 452 880	240 357	10 849 017
Accumulated depreciation and impairments 31.12.2019	-	3 378 065	85 459	3 463 524
Depreciation	-	711 599	30 076	741 675
Impairment/reversal (-)	-	9 492	-	9 492
Disposals/retirement depreciation	-	-584 292	69	-584 223
Accumulated depreciation and impairments 30.09.2020	-	3 514 864	115 605	3 630 468
Book value 30.09.2020	1 155 780	5 938 016	124 752	7 218 548
Acquisition cost 30.09.2020	1 155 780	9 452 880	240 357	10 849 017
Additions	56 453	286 897	947	344 297
Disposals/retirement	-	-	-	-
Reclassification1)	-123 479	147 098	-	23 619
Acquisition cost 31.12.2020	1 088 754	9 886 875	241 304	11 216 933
Accumulated depreciation and impairments 30.09.2020	-	3 514 864	115 605	3 630 468
Depreciation	-	252 020	10 700	262 720
Impairment/reversal (-)	-	57 607	-	57 607
Disposals/retirement depreciation	-	-	-	-
Accumulated depreciation and impairments 31.12.2020	-	3 824 491	126 305	3 950 795
Book value 31.12.2020	1 088 754	6 062 384	114 999	7 266 137

1) The reclassification is mainly relating to the Ærfugl phase 1 development project within the Skarv area, which entered into production phase during Q4 2020.

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

Right-of-use assets
		Vessels and
(USD 1 000)	Drilling Rigs	Boats	Office	Other	Total
Book value 31.12.2019	101 487	68 941	21 774	2 127	194 328
Acquisition cost 31.12.2019	106 856	72 106	29 593	2 303	210 859
Additions	-	-	-	-	-
Abandonment activity	3 848	700	-	-	4 548
Disposals/retirement	16 197	5 920	-	-	22 117
Reclassification	-31 461	-2 483	-	-	-33 944
Acquisition cost 30.09.2020	55 351	63 004	29 593	2 303	150 251
Accumulated depreciation and impairments 31.12.2019	5 369	3 166	7 820	177	16 531
Depreciation	9 265	2 152	5 645	132	17 194
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-8 535	-1 373	-	-	-9 907
Accumulated depreciation and impairments 30.09.2020	6 099	3 945	13 465	309	23 818
Book value 30.09.2020	49 252	59 059	16 128	1 994	126 433
Acquisition cost 30.09.2020	55 351	63 004	29 593	2 303	150 251
Additions	-	-	16 834	-	16 834
Abandonment activity1)	7 388	500	-	-	7 887
Disposals/retirement	-	-	-	-	-
Reclassification2)	-	-489	-	-	-489
Acquisition cost 31.12.2020	47 963	62 016	46 427	2 303	158 709
Accumulated depreciation and impairments 30.09.2020	6 099	3 945	13 465	309	23 818
Depreciation	-	675	1 437	44	2 156
Impairment/reversal (-)	-	-	-	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 31.12.2020	6 099	4 620	14 902	353	25 974
Book value 31.12.2020	41 864	57 395	31 525	1 950	132 735

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
(USD 1 000)	Licenses etc.	Software	Total	expenditures	Goodwill
Book value 31.12.2019	1 915 968	-	1 915 968	621 315	1 712 809
Acquisition cost 31.12.2019	2 396 433	7 501	2 403 934	621 315	2 738 973
Additions		-		83 509	-
Disposals/retirement/expensed dry wells	27 448	-	27 448	50 556	12 391
Reclassification	-	-	-	-812	-
Acquisition cost 30.09.2020	2 368 985	7 501	2 376 486	653 456	2 726 583
Accumulated depreciation and impairments 31.12.2019	480 465	7 501	487 966	-	1 026 165
Depreciation	73 541	-	73 541	-	-
Impairment/reversal (-)	296 854	-	296 854	146 107	65 373
Disposals/retirement depreciation	-25 413	-	-25 413	-	-12 391
Accumulated depreciation and impairments 30.09.2020	825 447	7 501	832 948	146 107	1 079 146
Book value 30.09.2020	1 543 538	-	1 543 538	507 349	1 647 436
Acquisition cost 30.09.2020	2 368 985	7 501	2 376 486	653 456	2 726 583
Additions		-		43 774	-
Disposals/retirement/expensed dry wells	-	-	-	6 071	-
Reclassification	-	-	-	-23 130	-
Acquisition cost 31.12.2020	2 368 985	7 501	2 376 486	668 029	2 726 583
Accumulated depreciation and impairments 30.09.2020	825 447	7 501	832 948	146 107	1 079 146
Depreciation	24 532	-	24 532	-	-
Impairment/reversal (-)	-2 305	-	-2 305	-	-
Disposals/retirement depreciation	-	-	-	-	-
Accumulated depreciation and impairments 31.12.2020	847 674	7 501	855 175	146 107	1 079 146
Book value 31.12.2020	1 521 311	-	1 521 311	521 922	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
	Q4	Q3	Q4		01.01.-31.12.
Depreciation in the income statement (USD 1 000)	2020	2020	2019	2020	2019
Depreciation of tangible fixed assets	262 720	243 239	223 279	1 004 395	705 282
Depreciation of right-of-use assets	2 156	2 423	3 807	19 350	16 531
Depreciation of other intangible assets	24 532	22 983	27 930	98 073	90 060
Total depreciation in the income statement	289 408	268 645	255 015	1 121 818	811 874

Impairment in the income statement (USD 1 000)

Impairment/reversal of tangible fixed assets	57 607	-	-509	67 099	-509
Impairment/reversal of other intangible assets	-2 305	-	-	294 549	-
Impairment/reversal of capitalized exploration expenditures	-	-	-	146 107	-
Impairment of goodwill	-	-	-	65 373	147 317
Total impairment in the income statement	55 302	-	-509	573 128	146 808

Note 7 Leasing

The incremental borrowing rate applied in discounting of the nominal lease debt is between 2.71 percent and 6.67 percent, dependent on the duration of the lease and when it was intially recognized.

	Group
	2020		2019
(USD 1 000)	Q4	01.01.-30.09.	01.01.-31.12.
Lease debt as of beginning of period	217 148	313 256	389 833
New lease debt recognized in the period	16 834	-	34 385
Payments of lease debt1)	-23 375	-94 849	-134 253
Lease debt derecognized in the period	-	-12 767	-
Interest expense on lease debt	3 531	13 098	23 897
Currency exchange differences	1 621	-1 590	-606
Total lease debt	215 760	217 148	313 256
Short-term	83 904	81 075	110 664
Long-term	131 856	136 074	202 592
1) Payments of lease debt split by activities (USD 1 000):
Investments in fixed assets	1 144	65 982	108 587
Abandonment activity	19 003	8 658	4 444
Operating expenditures	1 820	16 255	15 278
Exploration expenditures	310	564	1 384
Other income	1 098	3 391	4 561
Total	23 375	94 849	134 253
Nominal lease debt maturity breakdown (USD 1 000):
Within one year	95 124	93 140	127 747
Two to five years	99 809	110 394	175 947
After five years	57 464	51 302	61 518
Total	252 397	254 836	365 212

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

Note 8 Financial items

	Group
	Q4	Q3	Q4	01.01.-31.12.
(USD 1 000)	2020	2020	2019	2020	2019
Interest income	89	1 081	338	3 763	16 490
Realized gains on derivatives	7 193	3 183	2 334	16 821	11 261
Change in fair value of derivatives	42 010	94 709	49 007	74 537	7 316
Net currency gains	-	9 250	-	79 507	16 677
Total other financial income	49 203	107 142	51 341	170 865	35 255
Interest expenses	49 869	44 498	42 552	184 501	175 672
Interest on lease debt	3 531	3 855	5 458	16 629	23 897
Capitalized interest cost, development projects Amortized loan costs	-8 842 3 081	-8 553 6 766	-14 712 4 463	-39 267 19 813	-144 686 21 705
Total interest expenses	47 640	46 566	37 762	181 677	76 587
Net currency loss	5 501	-	24 592	-	-
Realized loss on derivatives	9 121	70 563	23 860	125 791	46 751
Change in fair value of derivatives	-	-	-	-	10 742
Accretion expenses	29 298	28 911	31 210	116 947	121 723
Other financial expenses	45	12 861	919	19 314	38 929
Total other financial expenses	43 965	112 335	80 580	262 052	218 145
Net financial items	-42 313	-50 678	-66 663	-269 101	-242 986

	Group
	Q4	Q3	Q4		01.01.-31.12.
Tax for the period (USD 1 000)	2020	2020	2019	2020	2019
Current year tax payable/receivable	25 836	16 920	346 791	-333 104	461 984
Change in current year deferred tax	79 900	91 308	-44 863	448 393	463 106
Prior period adjustments	463	2 756	10 521	3 680	18 113
Tax expense (+)/income (-)	106 200	110 983	312 448	118 970	943 204

		Group
	2020		2019
Calculated tax payable (-)/tax receivable (+) (USD 1 000)	Q4	01.01.-30.09.	01.01.-31.12.
Tax payable/receivable at beginning of period	71 038	-361 157	-540 860
Current year tax payable/receivable	-25 836	358 940	-461 984
Tax payable/receivable related to acquisitions/sales	-307	-3 548	520
Net tax payment/refund	-200 818	19 896	618 593
Prior period adjustments and change in estimate of uncertain tax positions	-3 613	-6 811	16 955
Currency movements of tax payable/receivable	-3 816	63 719	5 619
Net tax payable (-)/receivable (+)	-163 352	71 038	-361 157
Tax receivable included as current assets (+)	-	71 038	-
Tax payable included as current liabilities (-)	-163 352	-	-361 157

	Group
		2020	2019
Deferred tax liability (-)/asset (+) (USD 1 000)	Q4	01.01.-30.09.	01.01.-31.12.
Deferred tax liability/asset at beginning of period	-2 562 528	-2 235 357	-1 752 757
Change in current year deferred tax	-79 900	-368 494	-463 106
Deferred tax related to acquisitions/sales	-	37 727	-
Prior period adjustments	-	3 595	-19 509
Deferred tax charged to OCI and equity	-33	-	15
Net deferred tax liability (-)/asset (+)	-2 642 461	-2 562 528	-2 235 357

	Group
	Q4	Q3	Q4	01.01.-31.12.
Reconciliation of tax expense (USD 1 000)	2020	2020	2019	2020	2019
78 % tax rate on profit/loss before tax	183 820	149 195	330 719	127 674	845 718
Tax effect of uplift	-61 301	-62 755	-33 642	-268 564	-129 619
Permanent difference on impairment	1 497	-	-	169 670	114 907
Foreign currency translation of NOK monetary items	3 026	-7 893	18 487	-62 040	-12 535
Foreign currency translation of USD monetary items	229 697	91 334	88 763	129 042	-16 006
Tax effect of financial and other 22 % items	-107 953	1 765	-25 576	37 761	81 593
Currency movements of tax balances1)	-153 368	-65 982	-76 648	-30 321	34 297
Other permanent differences, prior period adjustments and change in estimate of	10 782	5 319	10 347	15 748	24 848
uncertain tax positions
Tax expense (+)/income (-)	106 200	110 983	312 448	118 970	943 204

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).

Certain temporary changes in the Petroleum Tax Law were enacted on 19 June 2020. The changes in tax law included a temporary rule for depreciation and uplift, whereby all investments incurred for income year 2020 and 2021 including 24% uplift can be deducted for special tax (56%) in the year of investment. The temporary changes will also be applicable for investments up to and including year of production start in accordance with new PDOs delivered within 31 December 2022 and approved within 31 December 2023. In addition, the value of tax losses incurred in 2020 and 2021 will be refunded from the state.

In accordance with statutory requirements, the calculation of current tax is required to be based on NOK functional currency. This may impact the effective tax rate as the company's functional currency is USD.

Note 10 Other short-term receivables

	Group
(USD 1 000)	31.12.2020	30.09.2020	31.12.2019
Prepayments	59 635	62 553	65 813
VAT receivable	6 770	4 152	8 904
Underlift of petroleum	53 537	47 808	46 515
Accrued income from sale of petroleum products	49 441	98 119	80 514
Other receivables, mainly balances with license partners	117 433	94 579	128 770
Total other short-term receivables	286 817	307 211	330 516

Note 11 Cash and cash equivalents

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

31.12.2019
107 104
107 104
2 550 000

Note 12 Derivatives

	Group
(USD 1 000)	31.12.2020	30.09.2020	31.12.2019
Unrealized gain currency contracts	12 841	4 075	2 706
Long-term derivatives included in assets	12 841	4 075	2 706
Unrealized gain on currency contracts	23 212	-	-
Short-term derivatives included in assets	23 212	-	-
Total derivatives included in assets	36 053	4 075	2 706
Unrealized losses commodity derivatives	3 539	5 257	1 805
Unrealized losses interest rate swaps	-	-	37 017
Unrealized losses currency contracts	-	10 031	4 172
Short-term derivatives included in liabilities	3 539	15 288	42 994
Total derivatives included in liabilities	3 539	15 288	42 994

The company has various types of economic hedging instruments. Commodity derivatives are used to hedge the risk of oil price reduction. The company 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 2019.

Note 13 Other current liabilities

	Group
Breakdown of other current liabilities (USD 1 000)	31.12.2020	30.09.2020	31.12.2019
Balances with license partners	20 915	44 862	67 199
Share of other current liabilities in licenses	245 158	232 423	379 787
Overlift of petroleum	11 331	28 882	15 660
Payroll liabilities, accrued interest and other provisions	216 942	146 320	197 889
Total other current liabilities	494 346	452 488	660 535

Note 14 Bonds

Senior unsecured bonds (USD 1 000)	Maturity	31.12.2020	30.09.2020	31.12.2019
AKERBP – Senior Notes 6.000% (17/22)	Jul 2022	-	-	395 046
AKERBP – Senior Notes 4.750% (19/24)	Jun 2024	743 329	742 853	741 421
AKERBP – Senior Notes 3.000% (20/25)	Jan 2025	496 417	496 195	-
AKERBP – Senior Notes 5.875% (18/25)	Mar 2025	495 523	495 260	494 470
AKERBP – Senior Notes 2.875% (20/26)	Jan 2026	496 394	495 930	-
AKERBP – Senior Notes 3.750% (20/30)	Jan 2030	992 764	992 585	-
AKERBP – Senior Notes 4.000% (20/31)	Jan 2031	744 139	743 993	-
Long-term bonds - book value		3 968 566	3 966 815	1 630 936
Long-term bonds - fair value		4 191 375	4 002 625	1 727 205
AKERBP – Senior Notes 6.000% (17/22)1)	Jul 2022	-	406 000	-
DETNOR02 Senior unsecured bond	Jul 2020	-	-	226 700
Short-term bonds - book value		-	406 000	226 700
Short-term bonds - fair value		-	406 000	238 744

1) The bond was repaid in Q4 2020.

Interest is paid on a semi annual basis. None of the bonds have financial covenants.

Note 15 Other interest-bearing debt

	Group
(USD 1 000)	31.12.2020	30.09.2020	31.12.2019
Revolving credit facility1)	-	-	1 429 132
Other interest-bearing debt	-	-	1 429 132

1) The outstanding amounts under the RCF was repaid in connection with the bond issuance in Q3. The remaining unamortized fees of USD 16.0 million is thus included in other non-current assets at 31 December 2020.

The senior unsecured Revolving Credit Facility (RCF) was established in May 2019 and comprise a 3-year USD 2.0 billion Working Capital Facility and a USD 2.0 billion 5-year Liquidity Facility. The Liquidity Facility includes two 12-month extension options, of which the first was exercised in April 2020. The interest rate is LIBOR plus a margin of 1.08 percent for the Liquidity Facility and 1.33 percent for the Working Capital Facility. In addition, a utilization fee is applicable for the Liquidity Facility. A commitment fee of 35 percent of applicable margin is paid on the undrawn facility. The financial covenants are as follows:

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

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

The financial covenants are calculated on a 12 months rolling basis. As at 31 December 2020 the Leverage Ratio is 1.51 and Interest Coverage Ratio is 10.5 (see APM section for further details), which are well within the thresholds mentioned above. Based on the company's current business plans and applying oil and gas price forward curves at end of Q4 2020, the company'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 16 Provision for abandonment liabilities

		Group
		2020
(USD 1 000)	Q4	01.01.-30.09.	01.01.-31.12.
Provisions as of beginning of period	2 824 716	2 788 218	2 552 592
Change in abandonment liability due to asset sales	-	-13 122	-
Incurred removal cost	-93 396	-69 345	-108 332
Accretion expense	29 298	87 649	121 723
Impact of changes to discount rate	20 554	-	238 053
Change in estimates and provisions relating to new drilling and installations	24 335	31 316	-15 818
Total provision for abandonment liabilities	2 805 507	2 824 716	2 788 218
Short-term	155 244	174 958	142 798
Long-term	2 650 263	2 649 759	2 645 420

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. For previous quarters in 2020 and year end 2019 the inflation rate was 2.0 percent and the discount rate was between 3.8 percent and 4.6 percent. The credit margin included in the discount rate is 3.0 percent. For previous quarters in 2020 and year end 2019 the credit margin was 2.2 percent.

Note 17 Contingent liabilities and assets

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

Note 18 Subsequent events

On 26 January 2021 the result of the exploration well Bask was announced by the operator Lundin Energy. Although traces of hydrocarbons were found, it is not considered commercial and the well is classified as dry. Hence, USD 7 million representing incurred capitalized exploration as of year end 2020, has been charged to the income statement as dry well cost in Q4 2020.

Note 19 Investments in joint operations

Fields operated:	31.12.2020	30.09.2020
Alvheim	65.000%	65.000 %
Bøyla	65.000%	65.000 %
Hod	90.000%	90.000 %
Ivar Aasen Unit	34.786%	34.786 %
Valhall	90.000%	90.000 %
Vilje	46.904%	46.904 %
Volund	65.000%	65.000 %
Tambar	55.000%	55.000 %
Skogul	65.000%	65.000 %
Tambar Øst	46.200%	46.200 %
Ula	80.000%	80.000 %
Skarv	23.835%	23.835 %

Production licenses in which Aker BP is the operator:
License:	31.12.2020	30.09.2020 License:	31.12.2020	30.09.2020
PL 001B	35.000%	35.000 % PL 460	65.000%	65.000 %
PL 006B	90.000%	90.000 % PL 685	40.000%	40.000 %
PL 019	80.000%	80.000 % PL 7621)	0.000%	20.000 %
PL 019E	80.000%	80.000 % PL 784	40.000%	40.000 %
PL 019F	55.000%	55.000 % PL 814	40.000%	40.000 %
PL 026	92.130%	92.130 % PL 818	40.000%	40.000 %
PL 026B	90.260%	90.260 % PL 818B	40.000%	40.000 %
PL 028B	35.000%	35.000 % PL 822S	60.000%	60.000 %
PL 033	90.000%	90.000 % PL 838	35.000%	35.000 %
PL 033B	90.000%	90.000 % PL 858	40.000%	40.000 %
PL 036C	65.000%	65.000 % PL 867	40.000%	40.000 %
PL 036D	46.904%	46.904 % PL 867B	40.000%	40.000 %
PL 036E	64.000%	64.000 % PL 868	60.000%	60.000 %
PL 036F	64.000%	64.000 % PL 869	60.000%	60.000 %
PL 065	55.000%	55.000 % PL 873	40.000%	40.000 %
PL 065B	55.000%	55.000 % PL 874	90.260%	90.260 %
PL 088BS	65.000%	65.000 % PL 906	60.000%	60.000 %
PL 102D	50.000%	50.000 % PL 907	60.000%	60.000 %
PL 102F	50.000%	50.000 % PL 914S	34.786%	34.786 %
PL 102G	50.000%	50.000 % PL 915	35.000%	35.000 %
PL 102H	50.000%	50.000 % PL 919	65.000%	65.000 %
PL 127C	88.083%	88.083 % PL 932	60.000%	60.000 %
PL 146	77.800%	77.800 % PL 941	50.000%	50.000 %
PL 150	65.000%	65.000 % PL 964	40.000%	40.000 %
PL 159D	23.835%	23.835 % PL 977	60.000%	60.000 %
PL 203	65.000%	65.000 % PL 978	60.000%	60.000 %
PL 212	30.000%	30.000 % PL 979	60.000%	60.000 %
PL 212B	30.000%	30.000 % PL 986	30.000%	30.000 %
PL 212E	30.000%	30.000 % PL 1005	40.000%	40.000 %
PL 242	35.000%	35.000 % PL 1008	60.000%	60.000 %
PL 261	50.000%	50.000 % PL 1022	40.000%	40.000 %
PL 262	30.000%	30.000 % PL 1026	40.000%	40.000 %
PL 300	55.000%	55.000 % PL 1028	50.000%	50.000 %
PL 333	77.800%	77.800 % PL 1030	50.000%	50.000 %
PL 340	65.000%	65.000 % PL 1041	40.000%	40.000 %
PL 340BS	65.000%	65.000 % PL 1042	40.000%	40.000 %
PL 364	90.260%	90.260 % PL 1045	65.000%	65.000 %
PL 442	90.260%	90.260 % PL 1047	40.000%	40.000 %
PL 442B	90.260%	90.260 % PL 1066	50.000%	50.000 %
PL 442C	90.260%	90.260 % PL 1081	60.000%	60.000 %
Number of licenses in which Aker BP is the operator			79	80

1) Relinquished license

Fields non-operated:	31.12.2020	30.09.2020
Atla	10.000%	10.000 %
Enoch	2.000%	2.000 %
Johan Sverdrup	11.573%	11.573 %
Oda	15.000%	15.000 %

Production licenses in which Aker BP is a partner:
License:	31.12.2020	30.09.2020 License:	31.12.2020	30.09.2020
PL 006C	15.000%	15.000 % PL 782SC	20.000%	20.000 %
PL 006E	15.000%	15.000 % PL 782SD	20.000%	20.000 %
PL 006F	15.000%	15.000 % PL 838B	30.000%	30.000 %
PL 035	50.000%	50.000 % PL 852	40.000%	40.000 %
PL 035C	50.000%	50.000 % PL 852B	40.000%	40.000 %
PL 048D	10.000%	10.000 % PL 852C	40.000%	40.000 %
PL 102C	10.000%	10.000 % PL 862	50.000%	50.000 %
PL 127	50.000%	50.000 % PL 892	30.000%	30.000 %
PL 127B	50.000%	50.000 % PL 902	30.000%	30.000 %
PL 220	15.000%	15.000 % PL 902B	30.000%	30.000 %
PL 265	20.000%	20.000 % PL 942	30.000%	30.000 %
PL 272	50.000%	50.000 % PL 954	20.000%	20.000 %
PL 272B	50.000%	50.000 % PL 955	30.000%	30.000 %
PL 405	15.000%	15.000 % PL 961	30.000%	30.000 %
PL 457BS	40.000%	40.000 % PL 962	20.000%	20.000 %
PL 492	60.000%	60.000 % PL 966	30.000%	30.000 %
PL 502	22.222%	22.222 % PL 968	20.000%	20.000 %
PL 533	35.000%	35.000 % PL 981	40.000%	40.000 %
PL 533B	35.000%	35.000 % PL 982	40.000%	40.000 %
PL 554	30.000%	30.000 % PL 985	20.000%	20.000 %
PL 554B	30.000%	30.000 % PL 1031	20.000%	20.000 %
PL 554C	30.000%	30.000 % PL 1040	30.000%	30.000 %
PL 554D	30.000%	30.000 % PL 1051	20.000%	20.000 %
PL 719	20.000%	20.000 % PL 1052	20.000%	20.000 %
PL 722	20.000%	20.000 % PL 1054	30.000%	30.000 %
PL 780	40.000%	40.000 % PL 1056	10.000%	10.000 %
PL 782S	20.000%	20.000 % PL 1064	30.000%	30.000 %
PL 782SB	20.000%	20.000 % PL 1069	50.000%	50.000 %
Number of licenses in which Aker BP is the partner			56	56

Note 20 Results from previous interim reports

		2019
(USD 1 000)	Q4	Q3	Q2	Q1	Q4
Total income	833 508	683 865	589 784	872 105	1 002 673
Production costs	142 068	133 690	196 174	156 043	154 272
Exploration expenses	41 722	32 267	49 774	50 336	84 683
Depreciation	289 408	268 645	286 353	277 412	255 015
Impairments	55 302	-	-135 872	653 697	-509
Other operating expenses	27 028	7 309	14 897	223	18 550
Total operating expenses	555 528	441 912	411 326	1 137 711	512 011
Operating profit/loss	277 980	241 954	178 458	-265 606	490 661
Net financial items	-42 313	-50 678	-27 418	-148 691	-66 663
Profit/loss before taxes	235 667	191 276	151 040	-414 298	423 998
Tax expense (+)/income (-)	106 200	110 983	-18 649	-79 564	312 448
Net profit/loss	129 467	80 293	169 689	-334 734	111 550

	2020				2019
(boe 1 000)	Q4	Q3	Q2	Q1	Q4
Sold volumes
Liquids Gas	16 165 3 507	14 489 2 779	18 036 3 073	15 858 3 026	13 930 3 046

	2020				2019
(USD 1 000)	Q4	Q3	Q2	Q1	Q4
Assets
Goodwill	1 647 436	1 647 436	1 647 436	1 647 436	1 712 809
Other intangible assets	2 043 233	2 050 887	2 053 548	2 001 150	2 537 283
Property, plant and equipment	7 266 137	7 218 548	7 175 129	7 060 700	7 023 276
Right-of-use asset	132 735	126 433	137 296	170 834	194 328
Receivables and other assets	792 750	561 657	546 212	524 382	651 986
Calculated tax receivables (short)	-	71 038	186 630	-	-
Cash and cash equivalents	537 801	818 547	142 333	322 789	107 104
Total assets	12 420 091	12 494 548	11 888 584	11 727 291	12 226 786
Equity and liabilities
Equity	1 987 281	1 928 638	1 912 084	1 813 229	2 367 585
Other provisions for liabilities incl. P&A (long)	2 650 263	2 649 759	2 655 478	2 699 246	2 645 420
Deferred tax	2 642 461	2 562 528	2 471 221	2 153 376	2 235 357
Bonds and bank debt	3 968 566	4 372 815	3 712 292	3 593 387	3 286 768
Lease debt	215 760	217 148	236 259	277 356	313 256
Other current liabilities incl. P&A	792 407	763 660	901 251	930 616	1 017 244
Tax payable	163 352		-	260 081	361 157
Total equity and liabilities	12 420 091	12 494 548	11 888 584	11 727 291	12 226 786

Alternative Performance Measures

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

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

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

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

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

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

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

Equity ratio is total equity divided by total assets

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

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

Interest coverage ratio is calculated as twelve months rolling EBITDA, divided by interest expenses, 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.

		Q4	Q3	01.01.-31.12.	Q4	01.01.-31.12.
(USD 1 000)	Note	2020	2020	2020	2019	2019
Abandonment spend
Payment for removal and decommissioning of oil fields		85 508	28 861	150 306	9 295	104 890
Payments of lease debt (abandonment activity)	7	19 003	6 059	27 660	949	4 444
Abandonment spend		104 511	34 921	177 966	10 243	109 334
Depreciation per boe
Depreciation	6	289 408	268 645	1 121 818	255 015	811 874
Total produced volumes (boe 1 000)	3	20 525	18 548	77 101	17 578	56 886
Depreciation per boe		14.1	14.5	14.6	14.5	14.3
Dividend per share
Paid dividend		70 833	70 833	425 000	187 500	750 000
Number of shares outstanding		360 101	359 534	359 808	360 114	360 014
Dividend per share		0.20	0.20	1.18	0.52	2.08
Capex
Disbursements on investments in fixed assets		306 061	269 787	1 277 869	490 457	1 703 213
Payments of lease debt (investments in fixed assets)	7	1 144	14 238	67 125	30 441	108 587
Capitalized interest	8	-8 842	-8 553	-39 267	-14 712	-144 686
CAPEX		298 363	275 472	1 305 727	506 186	1 667 113
EBITDA
Total income	2	833 508	683 865	2 979 263	1 002 673	3 347 088
Production costs	3	-142 068	-133 690	-627 975	-154 272	-720 321
Exploration expenses	4	-41 722	-32 267	-174 099	-84 683	-305 516
Other operating expenses		-27 028	-7 309	-49 457	-18 550	-35 328
EBITDA		622 690	510 599	2 127 731	745 168	2 285 922
EBITDAX
Total income	2	833 508	683 865	2 979 263	1 002 673	3 347 088
Production costs	3	-142 068	-133 690	-627 975	-154 272	-720 321
Other operating expenses		-27 028	-7 309	-49 457	-18 550	-35 328
EBITDAX		664 412	542 866	2 301 830	829 850	2 591 439
Equity ratio
Total equity		1 987 281	1 928 638	1 987 281	2 367 585	2 367 585
Total assets		12 420 091	12 494 548	12 420 091	12 226 786	12 226 786
Equity ratio		16%	15%	16%	19%	19%
Exploration spend
Disbursements on investments in capitalized exploration expenditures		43 774	32 842	127 283	41 597	370 185
Exploration expenses	4	41 722	32 267	174 099	84 683	305 516
Dry well	4	-6 071	-11 708	-56 626	-47 277	-176 419
Payments of lease debt (exploration expenditures)	7	310	221	874	-98	1 384
Exploration spend		79 735	53 622	245 629	78 903	500 666

		Q4	Q3	01.01.-31.12.	Q4	01.01.-31.12.
(USD 1 000)	Note	2020	2020	2020	2019	2019
Interest coverage ratio
Twelve months rolling EBITDA	20	2 127 731	2 250 209	2 127 731	2 285 922	2 285 922
Twelve months rolling EBITDA, impacts from IFRS 16	7	-23 438	-25 528	-23 438	-20 636	-20 636
Twelve months rolling EBITDA, excluding impacts from IFRS 16		2 104 293	2 224 680	2 104 293	2 265 287	2 265 287
Twelve months rolling interest expenses	8	184 501	177 185	184 501	175 672	175 672
Twelve months rolling amortized loan cost	8	19 813	21 196	19 813	21 705	21 705
Twelve months rolling interest income	8	3 763	4 013	3 763	16 490	16 490
Net interest expenses		200 552	194 367	200 552	180 886	180 886
Interest coverage ratio		10.5	11.4	10.5	12.5	12.5
Leverage ratio
Long-term bonds	14	3 968 566	3 966 815	3 968 566	1 630 936	1 630 936
Other interest-bearing debt	15	-	-	-	1 429 132	1 429 132
Short-term bonds	14	-	406 000	-	226 700	226 700
Cash and cash equivalents	11	537 801	818 547	537 801	107 104	107 104
Net interest-bearing debt excluding lease debt		3 430 766	3 554 268	3 430 766	3 179 664	3 179 664
Twelve months rolling EBITDAX	20	2 301 830	2 467 269	2 301 830	2 591 439	2 591 439
Twelve months rolling EBITDAX, impacts from IFRS 16	7	-22 564	-25 005	-22 564	-19 839	-19 839
Twelve months rolling EBITDAX, excluding impacts from IFRS 16		2 279 266	2 442 263	2 279 266	2 571 600	2 571 600
Leverage ratio		1.51	1.46	1.51	1.24	1.24
Net interest-bearing debt
Long-term bonds	14	3 968 566	3 966 815	3 968 566	1 630 936	1 630 936
Long-term lease debt	7	131 856	136 074	131 856	202 592	202 592
Other interest-bearing debt	15	-	-	-	1 429 132	1 429 132
Short-term bonds	14	-	406 000	-	226 700	226 700
Short-term lease debt	7	83 904	81 075	83 904	110 664	110 664
Cash and cash equivalents	11	537 801	818 547	537 801	107 104	107 104
Net interest-bearing debt		3 646 526	3 771 416	3 646 526	3 492 920	3 492 920

Operating profit/loss see Income Statement

Production cost per boe see note 3

AKER BP ASA

Fornebuporten, Building B Oksenøyveien 10 1366 Lysaker

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

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

www.akerbp.com