Aker BP

Quarterly Report • Feb 11, 2020

Q UA RT E R LY R E P O RT Q 4 2 0 1 9

FOURTH QUARTER 2019 SUMMARY

Fourth quarter 2019 marked the end of a year of strong progress and value creation for Aker BP. For the first time, the company's quarterly income exceeded one billion dollars, driven by record high production following the successful start-up of the Johan Sverdrup field, combined with continued strong performance from other fields. The company paid a dividend of USD 187.5 million (USD 0.52 per share) in the quarter.

Aker BP reported total income of USD 1,003 (723) million for the fourth quarter 2019. The company's net production in the fourth quarter was 191.1 (146.1) thousand barrels of oil equivalents per day ("mboepd"). Net sold volume was 184.5 (143.3) mboepd. The main contribution to the increase in volumes was the start-up of production from the Johan Sverdrup field in October. Average realised liquids price was USD 64.2 (62.0) per barrel oil equivalents ("boe"), while the realised price for natural gas averaged USD 0.17 (0.16) per standard cubic metre ("scm"). For the full year 2019, the company's net production was 155.9 (155.7) mboepd, in line with previous guidance.

Production costs for the oil and gas sold in the quarter amounted to USD 154 (167) million. Production cost per boe produced in the quarter amounted to USD 9.1 (13.2). For the full year, production costs were USD 12.4 (12.1) per boe, in line with previous guidance. Exploration expenses amounted to USD 85 (70) million. For the full year, exploration spend totalled USD 501 (359) million, below the latest guidance of USD 550 million. Depreciation amounted to USD 255 (206) million, equivalent to USD 14.5 (15.3) per boe. Operating profit was USD 491 (196) million.

Net financial expenses were USD 67 (53) million in the quarter. Profit before taxes amounted to USD 424 (143) million. Tax expense was USD 312 (186) million. Overall, the company reported a net profit of USD 112 million for the quarter, compared to a net loss of USD 43 million in the previous quarter.

Investments in fixed assets amounted to USD 490 (435) million in the quarter, driven by field development activities across the company's portfolio. All major field development projects progressed according to plan, and first oil from both Johan Sverdrup and Valhall Flank West was achieved during the quarter. Total capex for 2019 was USD 1,667 (1,202) million, in line with the latest guidance of USD 1.6-1.7 billion.

Net interest-bearing debt was USD 3.5 (3.3) billion at the end of 2019, including USD 0.3 (0.3) billion in lease debt. Total available liquidity was USD 2.7 (2.9) billion as at 31 December 2019.

In November, the company paid a quarterly dividend of USD 187.5 million or USD 0.5207 per share. The Board has resolved to pay a quarterly dividend of USD 212.5 million, equivalent to USD 0.5901 per share, in February 2020.

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.

Summary of financial results

	UNIT	Q4 2019	Q3 2019	Q4 2018*	2019	2018*
Total income	USDm	1 003	723	916	3 347	3 752
EBITDA	USDm	745	480	658	2 286	2 745
Net profit/loss	USDm	112	-43	63	141	476
Earnings per share (EPS)	USD	0.31	-0.12	0.17	0.39	1.32
Capex	USDm	506	421	380	1 667	1 202
Exploration spend	USDm	79	144	84	501	359
Abandonment spend	USDm	10	37	16	109	243
Production cost	USD/boe	9.1	13.2	13.0	12.4	12.1
Taxes paid	USDm	199	106	340	619	606
Net interest-bearing debt**	USDm	3 493	3 276	1 973	3 493	1 973
Leverage ratio		1.2	1.2	0.6	1.2	0.6

*Total income, EBITDA, EPS and net profit figures for 2018 are restated, see note 1.

**The definition of net interest-bearing debt includes Lease debt, which is recognized from Q1 2019 following the implementation of IFRS 16 Leases. The comparative figures for previous periods have not been restated. See also the description of "Alternative performance measures" at the end of this report for definitions.

Summary of production

	UNIT	Q4 2019	Q3 2019	Q4 2018	2019	2018
Alvheim area	mboepd	56.4	51.4	58.4	54.4	59.5
Ivar Aasen	mboepd	23.1	22.5	23.3	21.8	23.5
Johan Sverdrup	mboepd	31.5	-	-	7.9	-
Skarv	mboepd	22.1	21.7	23.5	22.3	25.3
Ula area	mboepd	11.1	8.6	8.4	8.5	9.4
Valhall area	mboepd	45.4	40.3	39.6	39.0	36.0
Other	mboepd	1.4	1.7	2.6	1.9	1.9
Net production	mboepd	191.1	146.1	155.7	155.9	155.7
Over/underlift	mboepd	-6.6	-2.9	-4.2	1.8	-1.1
Net sold volume	mboepd	184.5	143.3	151.5	157.6	154.6
- liquids	mboepd	151.4	113.4	119.8	126.6	121.5
- natural gas	mboepd	33.1	29.8	31.8	31.0	33.1
Realized price liquids	USD/boe	64.2	62.0	67.8	64.8	70.8
Realized price natural gas	USD/scm	0.17	0.16	0.30	0.18	0.29

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q4 2019	Q3 2019	Q4 2018*	2019	2018*
Total income	1 003	723	916	3 347	3 752
EBITDA	745	480	658	2 286	2 745
EBIT	491	196	442	1 327	1 972
Pre-tax profit	424	143	398	1 084	1 802
Net profit/loss	112	-43	63	141	476
EPS (USD)	0.31	-0.12	0.17	0.39	1.32

*Restated, see note 1.

Total income in the fourth quarter 2019 amounted to USD 1,003 (723) million. The increase compared to the previous quarter was driven by a significant increase in sold volumes to 184.5 (143.3) mboepd following the start-up of production from the Johan Sverdrup field. Realized prices increased marginally for both liquids and natural gas.

Production costs related to oil and gas sold in the quarter amounted to USD 154 (167) million. The reduction was mainly driven by partial insurance recovery related to the Alvheim Mid Water Arch repairs. Production cost per produced unit in the quarter amounted to USD 9.1 (13.2) per boe, reflecting the positive contribution of low-cost production from Johan Sverdrup.

The company participated in three exploration wells in the quarter, resulting in discoveries at Shrek and Busta. Exploration expenses amounted to USD 85 (70) million, and reflected the dry well at the Kark prospect in addition to costs related to seismic, area fees, field evaluation etc.

Depreciation amounted to USD 255 (206) million. The increase was solely driven by higher production volume, as the depreciation per produced boe declined to USD 14.5 (15.3) due to low depreciation per boe on Johan Sverdrup.

Operating profit was USD 491 (196) million.

Net financial expenses amounted to USD 67 (53) million. The main change from the previous quarter was a USD 29 million reduction in capitalized interest cost related to development projects, following the start-up of Johan Sverdrup.

Profit before taxes amounted to USD 424 (143) million. Taxes amounted to USD 312 (186) million for the fourth quarter, representing an effective tax rate of 74 (130) percent.

This resulted in a net profit for the fourth quarter 2019 of USD 112 million, compared to a net loss of USD 43 million in the previous quarter.

Statement of financial position

(USD MILLION)	Q4 2019	Q3 2019	Q4 2018*
Total non-current assets	11 508	11 149	10 088
Total current assets	719	578	622
Total assets	12 227	11 727	10 709
Total equity	2 368	2 444	2 977
Bank and bond debt	3 287	2 940	2 018
Total abandonment provisions	2 788	2 642	2 553
Deferred taxes	2 235	2 279	1 753
Other liabilities	1 549	1 422	1 409
Total equity and liabilities	12 227	11 727	10 709
Net interest-bearing debt	3 493	3 276	1 973
*Restated, see note 1.

At the end of fourth quarter 2019, total assets amounted to USD 12,227 (11,727) million, of which current assets were USD 719 (578) million.

Equity amounted to USD 2,368 (2,444) million at the end of the quarter, corresponding to an equity ratio of 19 (21) percent.

Deferred tax liabilities amounted to USD 2,235 (2,279) million and are detailed in note 9 to the financial statements.

Gross bank and bond debt totalled USD 3,287 (2,940) million, of which bonds made up 57 percent.

At the end of the fourth quarter, the company had total available liquidity of USD 2.7 (2.9) billion, comprising USD 107 (5) million in cash and cash equivalents, and USD 2.55 (2.90) billion in undrawn credit facilities.

Cash flow

(USD MILLION)	Q4 2019	Q3 2019	Q4 2018	2019	2018
Cash flow from operations	525	382	1 889	1 885	3 800
Cash flow from investments	-541	-585	-910	-2 178	-2 147
Cash flow from financing	117	106	-1 063	356	-1 838
Net change in cash & cash equivalents	101	-96	-83	62	-185
Cash and cash equivalents	107	5	45	107	45

Net cash flow from operating activities was USD 525 (382) million in the quarter. Revenues were USD 1,003 million, up from USD 723 million in the third quarter mainly driven by increased volume as the Johan Sverdrup field started production. Taxes paid were USD 199 (106) million.

Net cash used for investment activities was USD 541 (585) million, of which investments in fixed assets amounted to USD 490 (435) million for the quarter. Investments in capitalized exploration were USD 42 (115) million, and payments for decommissioning activities amounted to USD 9 (35) million in the quarter.

Net cash flow from financing activities totalled USD 117 (106) million, of which USD 335 million came from net drawdown of debt, partly offset by dividend disbursements of USD 188 (188) million and payments related to lease debt of USD 30 (32) 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.

At the end of the fourth quarter 2019, the company's inventory of oil put options covers approximately 60 percent of the expected oil production for the first half of 2020 (after tax) at an average strike price of USD ~54 per barrel. The average premium paid for these options is USD ~1.3 per barrel. No longer-dated options had been purchased at the time of this report.

Dividends

At the Annual General Meeting in April 2019, the Board was authorized to approve the distribution of dividends based on the company's annual accounts for 2018 pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.

The Board has proposed a dividend of USD 750 million in 2019 and stated a clear ambition to increase this by USD 100 million per year until 2023. Dividends are paid quarterly.

On 8 November 2019, the company disbursed dividends of USD 187.5 million, corresponding to USD 0.5207 per share. Total dividend distributions in 2019 have thus amounted to USD 750 million.

On 10 February 2020, the Board of Directors declared a dividend of USD 0.5901 per share, to be disbursed on or around 24 February 2020.

OPER ATIONAL RE VIE W

Aker BP's net production was 17.6 (13.4) mmboe in the fourth quarter of 2019, corresponding to 191.1 (146.1) mboepd. Due to underlift in the quarter, net sold volume represented 184.5 (143.3) mboepd. The average realized liquids price was USD 64.2 (62.0) per barrel, while the average realized gas price was USD 0.17 (0.16) per scm.

Alvheim Area

Key figures	Aker BP interest	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Alvheim	65 %	36 588	36 826	39 943	43 478
Bøyla	65 %	7 534	4 490	2 364	1 829
Vilje	46.904 %	3 279	-	2 300	3 756
Volund	65 %	9 040	10 088	8 518	7 757
Total production		56 441	51 403	53 125	56 820
Production efficiency		98 %	96 %	97 %	97 %

Fourth quarter production from the Alvheim area was 56.4 mboepd net to Aker BP, an increase of 10 percent from the previous quarter. This increase was mainly due to the reinstatement of the MWA system which had caused production from certain areas shut in for most of the third quarter. The production for fourth quarter was very stable, helped by a slight increase in gas handling capacity. The production efficiency increased to 98 percent in the fourth quarter.

Through the fourth quarter Alvheim delivered stable operations and excellent HSSE performance with no reported incidents or spills. The repairs and testing of the MWA system were finalized and production from Vilje and East Kameleon resumed in October. The drilling at Skogul has been completed and the project is on track to commence production during the first quarter 2020.

Drilling of the Kameleon Infill Mid well (KIM) is planned to commence during the first quarter 2020, which may be followed by an additional infill well in the second half of the year.

The Frosk test production continues and a pressure build-up test has been completed, acquiring valuable reservoir connectivity information which will help optimize overall development of the Frosk area.

Ivar Aasen

Key figures	Aker BP interest	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Total production	34.7862 %	23 139	22 481	19 069	22 539
Production efficiency		97 %	94 %	87 %	98 %

Fourth quarter production from Ivar Aasen was 23.1 mboepd net to Aker BP, up three percent from the previous quarter. The two new wells that started production in the third quarter contributed positively in the period. Planned maintenance on Ivar Aasen during the fourth quarter did not impact the production, thus production efficiency increased to 97 percent.

The platform is prepared for subsea tie-in of nearby discoveries, and during the quarter the company has evaluated and selected a possible development concept for the Hanz discovery with startup in 2022.

Johan Sverdrup

Key figures	Aker BP interest	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Total production	11.5733 %	31 521	-	-	-
Production efficiency		99 %	-	-	-

The production from Phase 1 of the Johan Sverdrup development project started safely on 5 October, more than two months ahead of the schedule in the Plan for Development and Operations and NOK 40 billion below budget. After only five weeks all the eight pre-drilled oil production wells were on stream and producing according to expectations at above 350 mboepd gross. The production efficiency was impressive at 99 percent including a planned emergency shutdown test. Average daily production net to Aker BP in the fourth quarter 2019 amounted to 31.5 mboepd.

Drilling of the next production well (no 9) started late in January 2020 from the fixed rig drilling platform, which will drill continuously for the next 3-4 years. It is expected that the Phase 1 gross oil production capacity of 440,000 barrels per day will be reached during the summer of 2020.

Phase 2 of the Johan Sverdrup development is progressing well and was approximately 23 percent complete by the end of the fourth quarter.

The power capacity from shore to the Johan Sverdrup field center will increase from 100 MW in Phase 1 to 300 MW as part of Phase 2. This will enable Johan Sverdrup to also serve a number of surrounding fields in the greater Utsira High area (including the Edvard Grieg, Ivar Aasen, Gina Krog, Gudrun and Sleipner fields) by 2022, and contribute to reductions of approximately 1.2 million tonnes of CO2 emissions annually.

Skarv Area

Key figures	Aker BP interest	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Total production	23.835 %	22 119	21 717	22 657	22 558
Production efficiency		100 %	98 %	98 %	91 %

Fourth quarter production from the Skarv area was 22.1 mboepd net to Aker BP, up two percent from the previous quarter. The slight increase in production was caused by an annual emergency shutdown test in the third quarter and high gas exports in October following a reservoir behaviour test. Second half of 2019 was characterized by stable production with very high uptime. Production efficiency in the fourth quarter was 99.8 percent.

The Shrek exploration well was successfully completed during the quarter as a discovery, and preliminary estimates place the size of the discovery between 19 to 38 mmboe. Shrek is located around five kilometres southeast of the Skarv installation.

Phase 1 of the Ærfugl development project is progressing according to plan. Offshore modifications are ongoing, and the drilling campaign commenced in the fourth quarter 2019. Final testing of the technology qualification has been successfully completed. Fabrication of the electrical heat traced flowline and pipeline structures are ongoing. Pipelaying is scheduled for summer 2020, and production start-up is planned for the fourth quarter 2020.

Ærfugl phase 2 entered the execution phase after final investment decision and partner approval in November 2019. The development is progressing according to plan. Drilling of the first well is scheduled as part of the ongoing Ærfugl phase 1 drilling campaign, with production start expected in the summer of 2020. For the two remaining satellite wells, production start is expected in the fourth quarter 2021.

Ula Area

Key figures	Aker BP interest	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Ula	80 %	4 339	4 751	2 811	6 185
Tambar	55 %	3 054	2 531	1 455	1 916
Oda	15 %	3 713	1 280	1 949	102
Total production		11 106	8 562	6 214	8 203
Production efficiency*		78 %	76 %	46 %	75 %

*Oda not included.

Fourth quarter production from the Ula area was 11.1 mboepd net to Aker BP, up 30 percent from the previous quarter. Production volume from the Ula area include production from the Oda field.

The Maersk Integrator drilling rig has been in operation at Ula since mid-July and has now completed the first of six planned wells. The rig programme is planned to continue until third quarter 2020.

Ula and Tambar production remained stable despite several planned temporary well closures related to the drilling of new wells at Ula, and intervention activities at Tambar. Production from Oda increased following start-up of water injection.

The company is continuing to mature the opportunity set in the Ula area, which is a complex process involving a broad set of technical and commercial disciplines.

Valhall Area

Key figures	Aker BP interest	Q4 2019	Q3 2019	Q2 2019	Q1 2019
Production, boepd
Valhall	90 %	44 205	39 403	23 896	45 156
Hod	90 %	1 176	880	618	677
Total production		45 381	40 283	24 514	45 833
Production efficiency		90 %	87 %	53 %	94 %

Fourth quarter production from the Valhall area was 45.4 mboepd net to Aker BP. This was 13 percent higher than the previous quarter mainly driven by improved production efficiency and new wells brought on stream. On one of these wells, the "Single-Trip-Multi-Frac" technology was successfully applied. This represents a world-first for a new method of well stimulation offshore, with significant time and cost savings potential.

On 16 December the V-9 well was brought onstream thus marking successful first oil for the Valhall Flank West ("VFW") project. By the end of 2019, four VFW wells had been completed. The drilling operations are continuing in 2020 with the Maersk Invincible drilling rig, and the scope has been expanded to nine wells in total. The wells will be successively brought onstream as they are stimulated.

At the field center drilling operations commenced as part of the development of the lower Hod formation where a total of seven wells are sanctioned. The F-18 water injection well which is due to be brought onstream in Q1 2020, will test waterflooding efficiency in lower Hod, and if successful may trigger a second development phase of lower Hod.

In line with the strategy of maximizing recovery and value from the Valhall area, a concept selection has been made for the Hod Field Development ("HFD") project which represents a re-development of the Hod field. Building on the success of VFW, the selected concept and execution model for HFD is planned based on a VFW copy and calls for a 12-slot normally unmanned wellhead installation ("NUI") to be tied back to the Valhall central complex. In 2020 the company will continue the work towards final investment decision and submission of the plan for development and operations ("PDO").

North of Alvheim and Krafla-Askja (NOAKA)

The North of Alvheim and Krafla-Askja ("NOAKA") area consists of the discoveries Frigg Gamma Delta, Langfjellet, Frøy, Fulla, Frigg, Rind and Krafla-Askja. Gross resources in the area are estimated to be more than 500 mmboe, with further upside potential from exploration and appraisal.

Aker BP and the other partners have performed detailed studies of different development solutions for the NOAKA area. The premise has been that a development should capture all discovered resources in the area and facilitate future tie-ins of new discoveries.

E XPLOR ATION

The partners in the NOAKA area are currently in constructive dialogue on how to develop the area.

Total exploration spend in the fourth quarter was USD 79 (144) million, while USD 85 million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees, field evaluation and G&G costs.

Drilling of the Shrek prospect in the Skarv area started in August and was concluded to be an oil and gas discovery in early October. The preliminary estimated size of the discovery is 19-38 mmboe. The licensees will assess the discovery as a possible tie back to the Skarv FPSO. Aker BP is partner in the licence with a 30 percent interest.

The Busta prospect in licence 782S was drilled during the fourth quarter and resulted in a discovery with a preliminary volume estimate of 6-63 mmboe. Aker BP is partner in the licence with a 20 percent interest.

The Kark well in licence 019C in the Ula area was also completed in the quarter. The well resulted in a minor oil discovery and is considered as not commercial. Aker BP is operator of the licence with 80 percent interest.

On 14 January 2020, Aker BP was offered interests in 15 new production licences in Norway through the Awards in Pre-defined Areas (APA 2019) licensing round. Of these licences, 11 are located in the North Sea (7 as operator), 3 in the Norwegian Sea (1 as operator) and 1 in the Barents Sea (as operator).

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 2019	Q3 2019	Q2 2019	Q1 2019
Total recordable injury frequency (TRIF)	Per mill. exp. hours	2.0	2.7	4.0	3.1
Serious incident frequency (SIF)	Per mill. exp. hours	0.8	0.4	0.8	0.4
Loss of primary containment (LOPC)	Count	0	0	0	0
Process safety events Tier 1 and 2	Count	0	0	0	0
CO2 emissions intensity*	Kg CO2/boe	7.9	8.1	8.1	7.6

*Operated barrels.

Aker BP's response to the Norwegian Environment Agency ("NEA") concerning the discrepancy regarding Ivar Aasen's reported discharge was submitted during the fourth quarter in accordance with the request.

In January 2020 the NEA granted the company a new discharge permit which means that there is no longer any discrepancy between Ivar Aasen's reported discharge and the discharge permit.

OUTLOOK

Aker BP continues to build on a strong platform for further value creation through safe operations, an effective business model built on lean principles, technological competence and innovation and industrial cooperation to secure long term competitiveness.

The company has a strong balance sheet and opportunity set with ample financial flexibility to pursue both organic and inorganic growth opportunities as well as increasing dividend distributions to its shareholders.

For 2020, the company's financial plan consists of the following main items1:

• Production of 205-220 mboepd
• Capex of USD ~1.5 billion
• Exploration spend of USD ~0.5 billion
• Abandonment spend of USD ~0.2 billion
• Production cost of around USD ~10 per boe

The Board has proposed to pay USD 850 million in dividends in 2020, corresponding to a quarterly dividend of approximately USD 0.59 per share.

¹ The majority 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
		Q4	Q3	Q4	01.01.-31.12.
				Restated		Restated
(USD 1 000)	Note	2019	2019	2018	2019	2018
Petroleum revenues		979 561	720 930	890 914	3 338 667	3 713 022
Other operating income		23 112	2 408	25 286	8 421	38 600
Total income	2	1 002 673	723 338	916 200	3 347 088	3 751 622
Production costs	3	154 272	167 267	177 683	720 321	693 585
Exploration expenses	4	84 683	70 213	72 458	305 516	295 908
Depreciation	6	255 015	205 867	195 962	811 874	752 437
Impairments	5, 6	-509	78 376	20 172	146 808	20 172
Other operating expenses		18 550	6 038	7 739	35 328	17 037
Total operating expenses		512 011	527 760	474 015	2 019 848	1 779 140
Operating profit		490 661	195 578	442 185	1 327 241	1 972 481
Interest income		338	3 353	7 157	16 490	25 976
Other financial income		51 341	52 846	72 625	35 255	141 823
Interest expenses		37 762	9 464	28 511	76 587	120 033
Other financial expenses		80 580	99 445	95 175	218 145	218 272
Net financial items	8	-66 663	-52 710	-43 905	-242 986	-170 505
Profit before taxes		423 998	142 868	398 280	1 084 254	1 801 976
Taxes (+)/tax income (-)	9	312 448	186 291	335 403	943 204	1 326 198
Net profit/loss		111 550	-43 423	62 876	141 051	475 778
Weighted average no. of shares outstanding basic and diluted		360 113 509	359 772 534	360 113 509	360 014 176	360 113 509
Basic and diluted earnings/loss USD per share		0.31	-0.12	0.17	0.39	1.32

STATEMENT OF COMPREHENSIVE INCOME

		Group
	Q4	Q3	Q4		01.01.-31.12.
			Restated		Restated
(USD 1 000) Note	2019	2019	2018	2019	2018
Profit/loss for the period	111 550	-43 423	62 876	141 051	475 778
Items which will not be reclassified over profit and loss (net of taxes) Actuarial gain/loss pension plan	-4	-	8	-4	8
Items which may be reclassified over profit and loss (net of taxes)
Currency translation adjustment	-	-	-81 981	-	-72 612
Reclassification to profit and loss	-	-	47 504	-	47 504
Total comprehensive income in period	111 546	-43 423	28 407	141 046	450 678

STATEMENT OF FINANCIAL POSITION

			Group
				Restated
(USD 1 000)	Note	31.12.2019	30.09.2019	31.12.2018
ASSETS
Intangible assets
Goodwill	6	1 712 809	1 712 809	1 860 126
Capitalized exploration expenditures	6	621 315	626 995	427 439
Other intangible assets	6	1 915 968	1 943 898	2 005 885
Tangible fixed assets
Property, plant and equipment	6	7 023 276	6 613 597	5 746 275
Right-of-use assets	6	194 328	215 328	-
Financial assets
Long-term receivables		27 418	25 826	37 597
Other non-current assets		10 364	10 279	10 388
Long-term derivatives	13	2 706	-	-
Total non-current assets		11 508 183	11 148 732	10 087 710
Inventories
Inventories		87 539	94 626	93 179
Receivables
Accounts receivable		193 444	125 511	162 798
Tax receivables	9	-	-	11 082
Other short-term receivables	10	330 516	352 143	292 405
Short-term derivatives	13	-	728	17 253
Cash and cash equivalents
Cash and cash equivalents	11	107 104	5 066	44 944
Total current assets		718 603	578 073	621 661
TOTAL ASSETS		12 226 786	11 726 805	10 709 371

STATEMENT OF FINANCIAL POSITION

		Group
				Restated
(USD 1 000)	Note	31.12.2019	30.09.2019	31.12.2018
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		-1 326 767	-1 250 813	-717 814
Total equity		2 367 585	2 443 539	2 976 539
Non-current liabilities
Deferred taxes	9	2 235 357	2 279 415	1 752 757
Long-term abandonment provision	17	2 645 420	2 496 791	2 447 558
Provisions for other liabilities	12	403	741	107 519
Long-term bonds	15	1 630 936	1 629 890	1 110 488
Long-term derivatives	13	-	45 292	26 275
Long-term lease debt	7	202 592	223 616	-
Other interest-bearing debt	16	1 429 132	1 077 485	907 954
Current liabilities
Trade creditors		144 942	135 115	105 567
Short-term bonds	15	226 700	217 170	-
Accrued public charges and indirect taxes		25 974	16 829	25 061
Tax payable	9	361 157	194 991	551 942
Short-term derivatives	13	42 994	42 199	8 783
Short-term abandonment provision	17	142 798	145 229	105 035
Short-term lease debt	7	110 664	117 455	-
Short-term interest-bearing debt	16	-	15 000	-
Other current liabilities	14	660 132	646 049	583 894
Total liabilities		9 859 201	9 283 266	7 732 833
TOTAL EQUITY AND LIABILITIES		12 226 786	11 726 805	10 709 371

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)	reserves*	earnings	equity	Total equity
Equity as of 31.12.2017	57 056	3 637 297	573 083	-89	-90 383	-1 188 366	-705 756	2 988 596
Change of accounting principle**	-	-	-	-	-	-12 736	-12 736	-12 736
Restated equity as of 01.01.2018	57 056	3 637 297	573 083	-89	-90 383	-1 201 102	-718 492	2 975 860
Dividends distributed	-	-	-	-	-	-450 000	-450 000	-450 000
Restated profit/loss for the period	-	-	-	-	-	475 778	475 778	475 778
Other comprehensive income for the period	-	-	-	8	-25 108	-	-25 100	-25 100
Restated 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	-	-	-	-	-	-562 500	-562 500	-562 500
Profit/loss for the period	-	-	-	-	-	29 500	29 500	29 500
Equity as of 30.09.2019	57 056	3 637 297	573 083	-81	-115 491	-1 708 324	-1 250 813	2 443 539
Dividend distributed	-	-	-	-	-	-187 500	-187 500	-187 500
Profit/loss for the period	-	-	-	-	-	111 550	111 550	111 550
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

* The amount arose mainly as a result of the change in functional currency in Q4 2014.

** Relates to change in accounting principle for revenue recognition, as described in note 1.

STATEMENT OF CASH FLOW

		Group
		Q4	Q3	Q4		01.01.-31.12.
				Restated		Restated
(USD 1 000)	Note	2019	2019	2018	2019	2018
CASH FLOW FROM OPERATING ACTIVITIES
Profit before taxes		423 998	142 868	398 280	1 084 254	1 801 976
Taxes paid	9	-198 663	-105 561	-339 609	-618 593	-606 082
Tax refund	9	-	-	1 513 394	-	1 513 394
Depreciation	6	255 015	205 867	195 962	811 874	752 437
Net impairment losses	5, 6	-509	78 376	20 172	146 808	20 172
Accretion expenses	8, 17	31 210	30 511	32 082	121 723	128 737
Interest expenses	8	48 011	48 832	56 739	199 569	200 524
Interest paid		-41 908	-52 702	-59 703	-194 033	-195 659
Changes in derivatives	2, 8	-46 474	57 214	4 624	22 484	11 558
Amortized loan costs	8	4 463	4 454	6 856	21 705	29 722
Amortization of fair value of contracts	14	-	-	14 195	-	56 775
Expensed capitalized dry wells	4, 6	47 277	41 905	4 424	176 419	65 852
Changes in inventories, accounts payable and receivables		-51 019	59 735	-9 908	14 369	-7 800
Changes in other current balance sheet items		54 061	-129 012	51 520	98 567	27 964
NET CASH FLOW FROM OPERATING ACTIVITIES		525 463	382 487	1 889 029	1 885 146	3 799 570
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields		-9 295	-35 279	-16 069	-104 890	-242 545
Disbursements on investments in fixed assets		-490 457	-434 580	-414 861	-1 703 213	-1 312 697
Disbursements on investments in capitalized exploration		-41 597	-115 099	-15 764	-370 185	-128 795
Disbursements on investments in licenses		-	-	-463 049	-143	-463 049
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-541 348	-584 958	-909 743	-2 178 431	-2 147 085
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment of short-term debt		-15 000	15 000	-1 500 000	-	-1 500 000
Net drawdown/repayment of revolving credit facility		350 000	299 908	-	1 425 222	-
Net drawdown/repayment of reserve-based lending facility		-	-	550 000	-950 000	-380 252
Net proceeds from bond issue		-	-	-	740 159	492 423
Payments on lease debt related to investments in fixed assets		-25 278	-25 665	-	-88 718	-
Payments on other lease debt		-5 156	-5 947	-	-20 880	-
Paid dividend		-187 500	-187 500	-112 500	-750 000	-450 000
Net purchase/sale of treasury shares		-	10 665	-	-	-
NET CASH FLOW FROM FINANCING ACTIVITIES		117 065	106 462	-1 062 500	355 782	-1 837 829
Net change in cash and cash equivalents		101 180	-96 009	-83 214	62 498	-185 344
Cash and cash equivalents at start of period		5 066	101 828	126 608	44 944	232 504
Effect of exchange rate fluctuation on cash held		859	-753	1 550	-338	-2 216
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	107 104	5 066	44 944	107 104	44 944

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 annual financial statements as at 31 December 2018. 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 10 February 2020.

Note 1 Accounting principles

IFRS 16

As described in the group's annual financial statements for 2018, IFRS 16 Leases entered into force from 1 January 2019. The standard introduces a single on-balance sheet accounting model for all leases, which results in the recognition of a lease liability and a right-of-use asset in the balance sheet. The accounting principles applied are in line with the description provided in the group's annual financial statements for 2018. The impact on the balance sheet is presented on separate balance sheet items, and further details are provided in the notes, in particular note 6 and 7. The group has applied the modified retrospective approach with no restatement of comparative figures.

Change in accounting principles for revenue recognition

Prior to 2019, the group recognized revenue on the basis of the proportionate share of production during the period, regardless of actual sales (entitlement method). Due to recent development in IFRIC discussions, the group decided to change to the sales method from 1 January 2019. This means that changes in over/underlift balances are valued at production cost including depreciation and presented as an adjustment to cost. See note 3 for further details. Comparative figures have been restated in line with IAS 8.

Except for the changes described above, the accounting principles used for this interim report are consistent with the principles used in the group's annual financial statements as at 31 December 2018.

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 respect the same as those that applied to the annual financial statements as at 31 December 2018.

Note 2 Income

	Group
	Q4	Q3	Q4	01.01.-31.12.
			Restated		Restated
Breakdown of petroleum revenues (USD 1 000)	2019	2019	2018	2019	2018
Sales of liquids	894 926	646 837	747 439	2 993 456	3 139 350
Sales of gas	80 047	69 864	139 062	328 816	554 248
Tariff income	4 588	4 229	4 413	16 395	19 423
Total petroleum revenues	979 561	720 930	890 914	3 338 667	3 713 022
Sales of liquids (boe 1 000)	13 930	10 437	11 018	46 224	44 331
Sales of gas (boe 1 000)	3 046	2 743	2 921	11 317	12 083
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-2 215	-1 841	-4 111	-12 824	-16 242
Unrealized gain/loss (-) on oil derivatives	-2 533	944	28 087	-19 058	24 944
Other income*	27 860	3 305	1 310	40 303	29 898
Total other operating income	23 112	2 408	25 286	8 421	38 600

* Includes insurance settlement during Q4 2019 relating to prior years, in addtion 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.
			Restated		Restated
(USD 1 000)	2019	2019	2018	2019	2018
Total produced volumes (boe 1 000)	17 578	13 443	14 326	56 886	56 815
Production cost based on produced volumes	160 293	177 142	186 530	706 308	689 102
Adjustment for over/underlift (-)	-6 021	-9 876	-8 847	14 014	4 483
Production cost based on sold volumes	154 272	167 267	177 683	720 321	693 585

Note 4 Exploration expenses

	Group
	Q4	Q3	Q4	01.01.-31.12.
Breakdown of exploration expenses (USD 1 000)	2019	2019	2018	2019	2018
Seismic	12 644	5 932	21 306	28 875	95 458
Area fee	3 578	2 668	5 149	15 537	13 822
Field evaluation	9 723	9 987	27 782	42 532	79 323
Dry well expenses*	47 277	41 905	4 424	176 419	65 852
Other exploration expenses	11 461	9 721	13 798	42 153	41 453
Total exploration expenses	84 683	70 213	72 458	305 516	295 908

* Dry well expenses in Q4 2019 are mainly related to the Kark well.

Note 5 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment triggers are identified, and for goodwill impairment is tested at least annually. In Q4 2019, two categories of impairment tests have been performed:

• Impairment test of fixed assets and related intangible assets, other than goodwill

• Impairment test of goodwill

Impairment is recognized when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. For assets and goodwill in the group prior to the acquisition of BP Norge AS, the impairment testing has been based on value in use, consistent with the impairment testing prior to the acquisition of BP Norge AS. For assets and goodwill recognized in relation to the acquisition of BP Norge AS and Hess Norge AS, the impairment testing has been based on fair value (level 3 in fair value hierarchy). For both value in use and fair value, the impairment testing is performed 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. If not specifically stated otherwise, the same assumptions have been applied for value in use and fair value testing.

For producing licences and licences 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 2019.

Prices

The nominal oil price applied in the impairment test is as follows:

Year	USD/BOE
2020	64.2
2021	59.4
2022	57.3
From 2023 (in real terms)	65.0

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

Year	GBP/therm
2020	0.32
2021	0.42
2022	0.44
2023	0.52
From 2024 (in real terms)	0.53

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

For both value in use and fair value testing the post tax nominal discount rate used is 7.8 percent. This represents a change from 7.9 percent applied in previous quarters in 2019 for value in use testing, and a change from 10.0 percent applied in previous quarters in 2019 for fair value testing.

Currency rates
Year	USD/NOK
2020	8.79
2021	8.80
2022	8.82
From 2023	7.50

Inflation

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

Impairment testing of assets other than goodwill

The impairment test of assets other than goodwill has been performed prior to the quarterly goodwill impairment test. If these assets are found to be impaired, their carrying value will be written down before the impairment test of goodwill. The carrying value of the assets is the sum of tangible assets and intangible assets as of the assessment date.

Below is an overview of the reversal of impairment charge and the carrying value per cash generating unit where impairment reversal has been recognized in Q4 2019:

	Impairment charge/reversal		Recoverable amount/
Cash-generating unit (USD 1 000)	Intangible	Tangible	carrying value as of 31.12.2019
Other CGU's	-	-509		-
Total	-	-509		-

The reversal of impairment charge for other CGU's with no carrying value is related to changes in the ARO liability.

Impairment testing of technical goodwill

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. We have tested the Alvheim, Valhall/Hod, Skarv/Ærfugl and Ula/Tambar CGUs, and the calculation shows that no impairment charge of technical goodwill is needed.

Sensitivity analysis

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

	Change in goodwill impairment after
Assumption (USD 1 000)	Change	Increase in assumptions	Decrease in assumptions
Oil and gas price	+/- 20 %	-	130 888
Production profile (reserves)	+/- 5 %	-	-
Discount rate	+/- 1 % point	-	-
Currency rate USD/NOK	+/- 1.0 NOK	-	32 730
Inflation	+/- 1 % point	-	-

As the illustrative impairment sensitivity assumes no changes to other input factors, a price reduction of 20 % is likely to result in changes in business plans as well as other factors used when estimating an asset's recoverable amount. Changes in such input factors would likely significantly reduce the actual impairment amount compared to the illustrative sensitivity above.

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 31.12.2018	2 283 602	3 385 005	77 669	5 746 275
Acquisition cost 31.12.2018	2 283 602	6 086 362	135 061	8 505 025
Additions	1 125 404	164 762	17 866	1 308 031
Disposals	-	-	-	-
Reclassification	-250 942	287 356	4 880	41 294
Acquisition cost 30.09.2019	3 158 063	6 538 480	157 807	9 854 350
Accumulated depreciation and impairments 31.12.2018	-	2 701 357	57 392	2 758 750
Depreciation	-	462 155	19 849	482 003
Impairment	-	-	-	-
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 30.09.2019	-	3 163 512	77 241	3 240 753
Book value 30.09.2019	3 158 063	3 374 968	80 566	6 613 597
Acquisition cost 30.09.2019	3 158 063	6 538 480	157 807	9 854 350
Additions	403 132	197 572	12 767	613 472
Disposals	-	-	-	-
Reclassification*	-2 310 830	2 329 970	-163	18 977
Acquisition cost 31.12.2019	1 250 365	9 066 022	170 411	10 486 798
Accumulated depreciation and impairments 30.09.2019	-	3 163 512	77 241	3 240 753
Depreciation	-	215 062	8 217	223 279
Impairment	-	-509	-	-509
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 31.12.2019	-	3 378 065	85 458	3 463 522
Book value 31.12.2019	1 250 365	5 687 957	84 954	7 023 276

* The reclassification is mainly relating to the Johan Sverdrup field and Valhall Flank West, which entered into production phase during Q4 2019.

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
Right-of-use assets at initial recognition 01.01.2019	132 270	76 628	29 593	2 303	240 795
Additions	31 899	-	-	-	31 899
Abandonment activity	2 048	692	-	-	2 741
Reclassification	-39 167	-2 734	-	-	-41 901
Acquisition cost 30.09.2019	122 954	73 202	29 593	2 303	228 052
Accumulated depreciation and impairments 31.12.2018	-	-	-	-	-
Depreciation	4 390	2 337	5 865	132	12 724
Impairment	-	-	-	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2019	4 390	2 337	5 865	132	12 724
Book value 30.09.2019	118 564	70 865	23 729	2 171	215 328
Acquisition cost 30.09.2019	122 954	73 202	29 593	2 303	228 052
Additions	2 486	-	-	-	2 486
Abandonment activity*	657	44	-	-	701
Reclassification**	-17 926	-1 051	-	-	-18 978
Acquisition cost 31.12.2019	106 856	72 106	29 593	2 303	210 859
Accumulated depreciation and impairments 30.09.2019	4 390	2 337	5 865	132	12 724
Depreciation	979	829	1 955	44	3 807
Impairment	-	-	-	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 31.12.2019	5 369	3 166	7 820	177	16 531
Book value 31.12.2019	101 487	68 941	21 774	2 127	194 328

* This represents the share of right-of-use assets used in abandonment activity, and thus booked against the abandonment provision.

** 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)	Licences etc.	Software	Total	Exploration wells	Goodwill
Book value 31.12.2018	2 005 885	-	2 005 885	427 439	1 860 126
Acquisition cost 31.12.2018	2 396 290	7 501	2 403 791	427 439	2 738 973
Additions	143	-	143	328 588	-
Disposals/expensed dry wells	-	-	-	129 638	-
Reclassification	-	-	-	607	-
Acquisition cost 30.09.2019	2 396 433	7 501	2 403 934	626 995	2 738 973
Accumulated depreciation and impairments 31.12.2018	390 404	7 501	397 906	-	878 847
Depreciation	62 131	-	62 131	-	-
Impairment	-	-	-	-	147 317
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2019	452 535	7 501	460 036	-	1 026 165
Book value 30.09.2019	1 943 898	-	1 943 898	626 995	1 712 809
Acquisition cost 30.09.2019	2 396 433	7 501	2 403 934	626 995	2 738 973
Additions	-	-	-	41 597	-
Disposals/expensed dry wells	-	-	-	47 277	-
Reclassification	-	-	-		-
Acquisition cost 31.12.2019	2 396 433	7 501	2 403 934	621 315	2 738 973
Accumulated depreciation and impairments 30.09.2019	452 535	7 501	460 036	-	1 026 165
Depreciation	27 930	-	27 930	-	-
Impairment	-	-	-	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 31.12.2019	480 465	7 501	487 966	-	1 026 165
Book value 31.12.2019	1 915 968	-	1 915 968	621 315	1 712 809

Licences 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)	2019	2019	2018	2019	2018
Depreciation of tangible fixed assets Depreciation of right-of-use assets	223 279 3 807	178 077 4 355	176 829 -	705 282 16 531	678 751 -
Depreciation of intangible assets	27 930	23 435	19 133	90 060	73 686
Total depreciation in the income statement	255 015	205 867	195 962	811 874	752 437
Impairment in the income statement (USD 1 000)
Impairment/reversal of tangible fixed assets	-509	-	19 657	-509	19 657
Impairment/reversal of intangible assets	-	-	516	-	516
Impairment of goodwill	-	78 376	-	147 317	-
Total impairment in the income statement	-509	78 376	20 172	146 808	20 172

Note 7 Leasing

The group has applied the modified retrospective approach with no restatement of comparative figures. Refer to the accounting principles in the 2018 financial statements for description of impact and changes in accounting. The difference between the operating lease commitments, as disclosed in note 25 in the 2018 financial statements and the lease debt recognized at initial application is reconciled in the table below. The incremental borrowing rate applied in discounting of the nominal lease debt is between 4.16 percent and 6.67 percent, dependent on the duration of the lease and when it was intially recognized.

	Group
(USD 1 000)	2019
Operating lease obligation 31.12.2018	1 100 753
Short-term and low value leases	-403 720
Non-lease components excluded	-223 551
Other	-8 574
Nominal lease debt 01.01.2019	464 907
Discounting	-75 075
Lease debt 01.01.2019	389 833
New lease debt recognized in the period	34 385
Payments of lease debt*	-134 253
Interest expense on lease debt	23 897
Currency exchange differences	-606
Total lease debt 31.12.2019	313 256

Break down of the lease debt to short-term and long-term liabilities

Short-term	110 664
Long-term	202 592
Total lease debt	313 256

* Payments of lease debt split by activities (USD 1 000):	Q4	01.01.-31.12.
Investments in fixed assets	30 441	108 587
Abandonment activity	949	4 444
Operating expenditures	3 135	15 278
Exploration expenditures	-98	1 384
Other income	2 224	4 561
Total	36 651	134 253

Nominal lease debt maturity breakdown (USD 1 000):

Within one year	127 747
Two to five years	175 947
After five years	61 518
Total	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
(USD 1 000)	Q4 Q3		Q4	01.01.-31.12.
	2019	2019	2018	2019	2018
Interest income	338	3 353	7 157	16 490	25 976
Realized gains on derivatives	2 334	1 960	72 625	11 261	141 823
Change in fair value of derivatives	49 007	-	-	7 316	-
Net currency gains	-	50 886	-	16 677	-
Total other financial income	51 341	52 846	72 625	35 255	141 823
Interest expenses	42 552	43 068	56 739	175 672	200 524
Interest on lease debt	5 458	5 764	-	23 897	-
Capitalized interest cost, development projects*	-14 712	-43 822	-35 085	-144 686	-110 213
Amortized loan costs	4 463	4 454	6 856	21 705	29 722
Total interest expenses	37 762	9 464	28 511	76 587	120 033
Net currency loss/gain (-) before reclassification from OCI	24 592	-	-47 453	-	-43 592
Reclassification from OCI	-	-	47 504	-	47 504
Realized loss on derivatives	23 860	9 619	28 824	46 751	45 993
Change in fair value of derivatives	-	58 158	32 710	10 742	36 503
Accretion expenses	31 210	30 511	32 082	121 723	128 737
Other financial expenses	919	1 156	1 509	38 929	3 128
Total other financial expenses	80 580	99 445	95 175	218 145	218 272
Net financial items	-66 663	-52 710	-43 905	-242 986	-170 505

* The decrease in capitalized interest cost is mainly caused by the Johan Sverdrup field, which entered into production phase in October 2019.

Note 9 Tax

	Group
	Q4	Q3	Q4	01.01.-31.12.
			Restated		Restated
Tax for the period (USD 1 000)	2019	2019	2018	2019	2018
Current year tax payable	346 791	-91 745	133 275	461 984	803 396
Current year deferred tax change	-44 863	274 427	181 873	463 106	524 645
Prior period adjustments	10 521	3 609	20 255	18 113	-1 843
Total tax (+)/tax income (-)	312 448	186 291	335 403	943 204	1 326 198

		Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	31.12.2019	31.12.2018
Tax receivable/payable at 01.01.	-540 860	1 234 850
Current year tax (-)/tax receivable (+)	-461 984	-803 396
Taxes receivable/payable related to acquisitions/sales	520	4 387
Net tax payment (+)/tax refund (-)	618 593	-907 312
Prior period adjustments and change in estimate of uncertain tax positions	16 955	-30 269
Currency movements of tax receivable/payable	5 619	-39 119
Total net tax receivable (+)/tax payable (-)	-361 157	-540 860
Tax receivable included as current assets (+)	-	11 082
Tax payable included as current liabilities (-)	-361 157	-551 942

		Group
		Restated
Deferred tax (-)/deferred tax asset (+) (USD 1 000)	31.12.2019	31.12.2018
Deferred tax/deferred tax asset 31.12.	-1 752 757	-1 307 148
Effect of change in accounting principle*	-	45 155
Deferred tax/deferred tax asset 01.01.	-1 752 757	-1 261 993
Change in deferred tax in the income statement	-463 106	-524 645
Prior period adjustment	-19 509	33 912
Deferred tax charged to OCI and equity	15	-30
Net deferred tax (-)/deferred tax asset (+)	-2 235 357	-1 752 757

	Group
	Q4	Q3	Q4	01.01.-31.12.
			Restated		Restated
Reconciliation of tax expense (USD 1 000)	2019	2019	2018	2019	2018
78 % tax rate on profit before tax	330 719	111 437	310 658	845 718	1 405 541
Tax effect of uplift	-33 642	-31 901	-33 532	-129 619	-130 767
Change in tax rates	-	-	-2 047	-	-2 047
Permanent difference on impairment	-	61 133	-	114 907	-
Tax effect on OCI reclassification	-	-	37 053	-	37 053
Foreign currency translation of NOK monetary items	18 487	-38 200	-37 014	-12 535	-34 002
Foreign currency translation of USD monetary items	88 763	-131 447	-121 121	-16 006	-111 806
Tax effect of financial and other 22 %/23 % items	-25 576	78 165	41 678	81 593	50 578
Currency movements of tax balances**	-76 648	135 025	123 541	34 297	113 147
Other permanent differences, prior period adjustments and change in estimate of uncertain tax positions	10 347	2 078	16 187	24 848	-1 498
Total tax (+)/tax income (-)	312 448	186 291	335 403	943 204	1 326 198

* Relates to change in deferred tax as a result of the change in accounting principle for revenue recognition as described in note 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).

The tax rate for general corporation tax changed from 23 to 22 percent from 1 January 2019. The rate for special tax changed from the same date from 55 to 56 percent.

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
			Restated
(USD 1 000)	31.12.2019	30.09.2019	31.12.2018
Prepayments	65 813	64 344	64 004
VAT receivable	8 904	7 698	8 871
Underlift of petroleum*	46 515	29 966	54 924
Accrued income from sale of petroleum products	80 514	142 692	52 825
Other receivables, mainly from licences	128 770	107 443	111 781
Total other short-term receivables	330 516	352 143	292 405

* Comparable figure has been restated to reflect the valuation of underlift to production cost, in line with the sales method as described in note 1.

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
31.12.2019	30.09.2019	31.12.2018
107 104	5 066	44 944
107 104	5 066	44 944
2 550 000	2 900 000	3 050 000

Note 12 Provisions for other liabilities

	Group
Breakdown of provisions for other liabilities (USD 1 000)	31.12.2019	30.09.2019	31.12.2018
Fair value of contracts assumed in acquisitions*	-	-	106 040
Other long term liabilities	403	741	1 480
Total provisions for other liabilities	403	741	107 519

* The negative contract values are mainly related to rig contracts entered into by companies acquired by Aker BP, which differed from current market terms at the time of the acquisitions. The fair value is based on the difference between market price and contract price at the time of the acquisitions. In 2019, the amount is netted against the right-of-use asset as described in note 1 to the 2018 financial statements.

Note 13 Derivatives

	Group
(USD 1 000)	31.12.2019	30.09.2019	31.12.2018
Unrealized gain currency contracts	2 706	-	-
Long-term derivatives included in assets	2 706	-	-
Unrealized gain on commodity derivatives	-	728	17 253
Short-term derivatives included in assets	-	728	17 253
Total derivatives included in assets	2 706	728	17 253
Unrealized losses interest rate swaps	-	45 292	26 275
Long-term derivatives included in liabilities	-	45 292	26 275
Unrealized losses commodity derivatives	1 805	-	-
Unrealized losses interest rate swaps	37 017	-	-
Unrealized losses currency contracts	4 172	42 199	8 783
Short-term derivatives included in liabilities	42 994	42 199	8 783
Total derivatives included in liabilities	42 994	87 491	35 058

The group has various types of economic hedging instruments. Commodity derivatives are used to hedge the risk of oil price reduction. The group manages its interest rate exposure using interest rate derivatives, including interest rate swap and a cross currency interest rate swap. 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 2018.

Note 14 Other current liabilities

		Group
			Restated
Breakdown of other current liabilities (USD 1 000)	31.12.2019	30.09.2019	31.12.2018
Current liabilities against JV partners	67 199	55 588	22 779
Share of other current liabilities in licences	379 787	406 884	309 260
Overlift of petroleum*	15 660	5 132	10 055
Fair value of contracts assumed in acquisitions**	-	-	42 998
Other current liabilities***	197 486	178 445	198 801
Total other current liabilities	660 132	646 049	583 894

* Comparable figure has been restated to reflect the valuation of overlift to production cost, in line with the sales method as described in note 1.

** As described in note 12, the fair value of contracts has in 2019 been netted against the right-of-use assets.

*** Other current liabilities include unpaid wages and vacation pay, accrued interest and other provisions.

Note 15 Bonds

(USD 1 000)	31.12.2019	30.09.2019	31.12.2018
DETNOR02 Senior unsecured bond*	-	-	223 839
AKERBP – Senior Notes (17/22)**	395 046	394 635	393 301
AKERBP – Senior Notes (18/25)***	494 470	494 206	493 349
AKERBP – Senior Notes (19/24)****	741 421	741 048	-
Long-term bonds	1 630 936	1 629 890	1 110 488
DETNOR02 Senior unsecured bond*	226 700	217 170	-
Short-term bonds	226 700	217 170	-

* The bond is denominated in NOK and runs from July 2013 to July 2020 and carries an interest rate of 3 month Nibor + 6.5 percent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The bond is unsecured. The bond has been swapped into USD using a cross currency interest rate swap whereby the group pays Libor + 6.81 percent quarterly. The financial covenants for this bond are consistent with the RCF as described in note 16.

** The bond was established in July 2017 and carries an interest of 6.0 percent. The principal falls due in July 2022 and interest is paid on a semi annual basis. The bond is senior unsecured and has no financial covenants.

*** The bond was established in March 2018 and carries an interest of 5.875 percent. The principal falls due in March 2025 and interest is paid on a semi annual basis. The bond is senior unsecured and has no financial covenants.

**** The bond was established in June 2019 and carries an interest of 4.75 percent. The principal falls due in June 2024 and interest is paid on a semi annual basis. The bond is senior unsecured and has no financial covenants.

Note 16 Other interest-bearing debt

	Group
(USD 1 000)	31.12.2019	30.09.2019	31.12.2018
Reserve-based lending facility	-	-	907 954
Revolving credit facility	1 429 132	1 077 485	-
Long-term interest-bearing debt	1 429 132	1 077 485	907 954
Money market loan*	-	15 000	-
Short-term interest-bearing debt	-	15 000	-

* Money market loan is a bilateral bank loan used to cover short term working capital needs. These loans will normally have tenor shorter than 1 week.

In May 2019, the group refinanced the Reserve-based lending facility (RBL) with a USD 4.0 billion senior unsecured Revolving Credit Facility (RCF). The RCF 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. 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 Working Capital 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 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.

Note 17 Provision for abandonment liabilities

		Group
(USD 1 000)	31.12.2019	31.12.2018
Provisions as of 1 January	2 552 592	3 043 884
Incurred cost removal	-108 332	-201 227
Accretion expense - present value calculation	121 723	128 737
Changed net present value from changed discount rate	238 053	-277 081
Change in estimates and incurred liabilities on new drilling and installations	-15 818	-141 721
Total provision for abandonment liabilities	2 788 218	2 552 592
Break down of the provision to short-term and long-term liabilities
Short-term	142 798	105 035
Long-term	2 645 420	2 447 558
Total provision for abandonment liabilities	2 788 218	2 552 592

The estimate is 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 per cent and a nominal discount rate before tax of between 3.77 per cent and 4.59 per cent. For previous quarters in 2019 and year end 2018 the inflation rate was 2.0 per cent and the discount rate was between 4.46 per cent and 5.01 per cent. The credit margin included in the discount rate is 2.20 per cent. For previous quarters in 2019 and year end 2018 the credit margin was 2.00 per cent.

Note 18 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 19 Subsequent events

On 15th January 2020, Aker BP closed a bond offering for 500 million 3 percent Senior Notes due 2025 and \$1 billion 3.75 percent Senior Notes due 2030. Interest will be payable semi-annually. The bonds are senior unsecured and have no financial covenants. The gross proceeds from the issue were mainly used to repay outstanding amounts under the Revolving Credit Facility.

Note 20 Investments in joint operations

Fields operated:	31.12.2019	30.09.2019
Alvheim	65.000%	65.000 %
Bøyla	65.000%	65.000 %
Hod	90.000%	90.000 %
Ivar Aasen Unit	34.786%	34.786 %
Jette Unit	70.000%	70.000 %
Valhall	90.000%	90.000 %
Vilje	46.904%	46.904 %
Volund	65.000%	65.000 %
Tambar	55.000%	55.000 %
Tambar Øst	46.200%	46.200 %
Ula	80.000%	80.000 %
Skarv	23.835%	23.835 %

Production licences in which Aker BP is the operator:
Licence:	31.12.2019	30.09.2019 Licence:		31.12.2019	30.09.2019
PL 001B	35.000%		35.000 % PL 777D	40.000%	40.000 %
PL 006B	90.000%	90.000 % PL 784		40.000%	40.000 %
PL 019	80.000%	80.000 % PL 814		40.000%	40.000 %
PL 019C	80.000%	80.000 % PL 818		40.000%	40.000 %
PL 019E	80.000%		80.000 % PL 818B	40.000%	40.000 %
PL 019H	80.000%		80.000 % PL 822S	60.000%	60.000 %
PL 026	92.130%	92.130 % PL 839		23.835%	23.835 %
PL 026B	90.260%	90.260 % PL 843		40.000%	40.000 %
PL 027D*	0.000%	100.000 % PL 858		40.000%	40.000 %
PL 028B	35.000%	35.000 % PL 867		40.000%	40.000 %
PL 033	90.000%	90.000 % PL 868		60.000%	60.000 %
PL 033B	90.000%	90.000 % PL 869		60.000%	60.000 %
PL 036C	65.000%	65.000 % PL 873		40.000%	40.000 %
PL 036D	46.904%	46.904 % PL 874		90.260%	90.260 %
PL 036E	64.000%	64.000 % PL 893		60.000%	60.000 %
PL 065	55.000%	55.000 % PL 906		60.000%	60.000 %
PL 065B	55.000%	55.000 % PL 907		60.000%	60.000 %
PL 088BS	65.000%		65.000 % PL 914S	34.786%	34.786 %
PL 102D	50.000%	50.000 % PL 915		35.000%	35.000 %
PL 102F	50.000%	50.000 % PL 916		40.000%	40.000 %
PL 102G	50.000%	50.000 % PL 919		65.000%	65.000 %
PL 102H	50.000%	50.000 % PL 932		60.000%	60.000 %
PL 127C	100.000%	100.000 % PL 941		50.000%	50.000 %
PL 146	77.800%	77.800 % PL 948		40.000%	40.000 %
PL 150	65.000%	65.000 % PL 951		40.000%	40.000 %
PL 159D	23.835%	23.835 % PL 963		70.000%	70.000 %
PL 169C*	0.000%	50.000 % PL 964		40.000%	40.000 %
PL 203	65.000%	65.000 % PL 977		60.000%	60.000 %
PL 212	30.000%	30.000 % PL 978		60.000%	60.000 %
PL 212B	30.000%	30.000 % PL 979		60.000%	60.000 %
PL 212E	30.000%	30.000 % PL 986		30.000%	30.000 %
PL 242	35.000%	35.000 % PL 1005		60.000%	60.000 %
PL 261	50.000%	50.000 % PL 1008		60.000%	60.000 %
PL 262	30.000%	30.000 % PL 1022		40.000%	40.000 %
PL 300	55.000%	55.000 % PL 1026		40.000%	40.000 %
	77.800%			50.000%
PL 333	65.000%	77.800 % PL 1028		50.000%	50.000 %
PL 340	65.000%	65.000 % PL 1030			50.000 %
PL 340BS	90.260%	65.000 %
PL 364	90.260%	90.260 %
PL 442	90.260%	90.260 %
PL 442B		90.260 %
PL 460	65.000% 0.000%	65.000 %
PL 504*		47.593 %
PL 685	40.000%	40.000 %
PL 762	20.000%	20.000 %
PL 777	40.000%	40.000 %
PL 777B	40.000%	40.000 %
PL 777C	40.000%	40.000 %
Number of licences in which Aker BP is the operator				82	85

* Relinquished licence or Aker BP has withdrawn from the licence

Fields non-operated:	31.12.2019	30.09.2019
Atla	10.000%	10.000 %
Enoch	2.000%	2.000 %
Gina Krog	3.300%	3.300 %
Johan Sverdrup	11.573%	11.573 %
Oda	15.000%	15.000 %

Production licences in which Aker BP is a partner:
Licence:	31.12.2019	30.09.2019 Licence:	31.12.2019	30.09.2019
PL 006C	15.000%	15.000 % PL 782SB	20.000%	20.000 %
PL 006E	15.000%	15.000 % PL 782SC	20.000%	20.000 %
PL 006F	15.000%	15.000 % PL 782SD	20.000%	20.000 %
PL 029B	20.000%	20.000 % PL 811	20.000%	20.000 %
PL 035	50.000%	50.000 % PL 838	30.000%	30.000 %
PL 035C	50.000%	50.000 % PL 838B	30.000%	30.000 %
PL 048D	10.000%	10.000 % PL 844	20.000%	20.000 %
PL 102C	10.000%	10.000 % PL 852	40.000%	40.000 %
PL 127	50.000%	50.000 % PL 852B	40.000%	40.000 %
PL 127B	50.000%	50.000 % PL 852C	40.000%	40.000 %
PL 220	15.000%	15.000 % PL 857	20.000%	20.000 %
PL 265	20.000%	20.000 % PL 862	50.000%	50.000 %
PL 272	50.000%	50.000 % PL 863	40.000%	40.000 %
PL 272B	50.000%	50.000 % PL 863B	40.000%	40.000 %
PL 405	15.000%	15.000 % PL 864	20.000%	20.000 %
PL 457BS	40.000%	40.000 % PL 892	30.000%	30.000 %
PL 492	60.000%	60.000 % PL 902	30.000%	30.000 %
PL 502	22.222%	22.222 % PL 902B	30.000%	30.000 %
PL 533	35.000%	35.000 % PL 942	30.000%	30.000 %
PL 533B	35.000%	35.000 % PL 954	20.000%	20.000 %
PL 554	30.000%	30.000 % PL 955	30.000%	30.000 %
PL 554B	30.000%	30.000 % PL 961	30.000%	30.000 %
PL 554C	30.000%	30.000 % PL 962	20.000%	20.000 %
PL 554D	30.000%	30.000 % PL 966	30.000%	30.000 %
PL 615	4.000%	4.000 % PL 968	20.000%	20.000 %
PL 615B	4.000%	4.000 % PL 981	40.000%	40.000 %
PL 719	20.000%	20.000 % PL 982	40.000%	40.000 %
PL 722	20.000%	20.000 % PL 985	20.000%	20.000 %
PL 780*	40.000%	0.000 % PL 1031	20.000%	20.000 %
PL 782S	20.000%	20.000 %
Number of licences in which Aker BP is the partner			59	58

* Aker BP has acquired a 40 percent share of PL 780

Note 21 Results from previous interim reports

	2019				2018
(USD 1 000)	Q4	Q3	Q2	Q1	Restated Q4
Total income	1 002 673	723 338	784 816	836 262	916 200
Production costs	154 272	167 267	198 320	200 462	177 683
Exploration expenses	84 683	70 213	60 261	90 359	72 458
Depreciation	255 015	205 867	167 889	183 102	195 962
Impairments	-509	78 376	-	68 941	20 172
Other operating expenses	18 550	6 038	3 882	6 859	7 739
Total operating expenses	512 011	527 760	430 352	549 724	474 015
Operating profit/loss	490 661	195 578	354 464	286 538	442 185
Net financial items	-66 663	-52 710	-86 232	-37 381	-43 905
Profit/loss before taxes	423 998	142 868	268 232	249 157	398 280
Taxes (+)/tax income (-)	312 448	186 291	205 734	238 731	335 403
Net profit/loss	111 550	-43 423	62 498	10 425	62 876

	2019				2018
(boe 1 000)	Q4	Q3	Q2	Q1	Q4
Sold volumes
Liquids Gas	13 930 3 046	10 437 2 743	10 264 2 541	11 594 2 988	11 018 2 921

	2019				2018
					Restated
(USD 1 000)	Q4	Q3	Q2	Q1	Q4
Assets
Goodwill	1 712 809	1 712 809	1 791 185	1 791 185	1 860 126
Other intangible assets	2 537 283	2 570 893	2 521 625	2 483 080	2 433 324
Property, plant and equipment	7 023 276	6 613 597	6 299 710	5 953 972	5 746 275
Right-of-use asset	194 328	215 328	238 879	225 244	-
Receivables and other assets	651 986	609 112	521 934	533 949	613 620
Calculated tax receivables (short)	-	-	17 418	15 473	11 082
Cash and cash equivalents	107 104	5 066	101 828	113 680	44 944
Total assets	12 226 786	11 726 805	11 492 580	11 116 582	10 709 371
Equity and liabilities
Equity	2 367 585	2 443 539	2 663 797	2 799 464	2 976 539
Other provisions for liabilities incl. P&A (long)	2 645 823	2 542 824	2 560 005	2 504 723	2 581 352
Deferred tax	2 235 357	2 279 415	1 991 371	1 867 333	1 752 757
Bonds and bank debt	3 286 768	2 939 545	2 634 585	2 225 589	2 018 443
Lease debt	313 256	341 071	374 595	368 553	-
Other current liabilities incl. P&A	1 016 841	985 421	828 958	784 164	828 340
Tax payable	361 157	194 991	439 270	566 755	551 942
Total equity and liabilities	12 226 786	11 726 805	11 492 580	11 116 582	10 709 371

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