QUARTERLY REPORT Q1 2019

FIRST QUARTER 2019 SUMMARY

Aker BP delivered strong operational performance and exploration success in the first quarter. The company's field developments progressed as planned and remain on track for first oil from Johan Sverdrup and Valhall Flank West later this year. The company paid a dividend of USD 187.5 million (USD 0.52 per share) in the quarter.

The company's net production in the first quarter was 158.7 (158.6) thousand barrels of oil equivalents per day ("mboepd"). Net sold volume was 162.0 (167.3) mboepd. Total income amounted to USD 836 (944) million for the quarter. Petroleum revenues and production costs for the comparative period have been restated following a change in accounting principle as described in Note 1 to the interim financial statements.

Average realised liquids price was USD 63.9 (67.4) per barrel, while the realised price for natural gas averaged USD 0.24 (0.28) per standard cubic metre ("scm"). Total income was negatively affected by USD 26 million in value adjustments on the company's oil price hedging positions.

Production costs for the oil and gas sold in the quarter amounted to USD 200 (195) million. Production cost per produced barrel oil equivalents ("boe") amounted to USD 13.4 (12.1). Exploration expenses amounted to USD 90 (55) million. Total cash spend on exploration was USD 159 (80) million. The company participated in three exploration wells in the quarter, of which the Froskelår well was a discovery.

Depreciation was USD 183 (185) million, equivalent to USD 12.8 (13.0) per boe. Impairments amounted to USD 69 (0) million related to technical goodwill, driven by changes in expected cost and production profiles for future developments in the Ula area.

Profit before taxes amounted to USD 249 (458) million. Tax expense was USD 239 (290) million, representing an effective tax rate of 96 per cent. The main reason for the high effective tax rate was the impairment of technical goodwill which is not deductible for tax purposes. Net profit was USD 10 (169) million.

Investments in fixed assets amounted to USD 364 (257) million in first quarter. All field development projects, including Johan Sverdrup, Valhall Flank West and Ærfugl, progressed according to plans.

Net interest-bearing debt was USD 2.5 (3.0) billion at the end of the quarter, including USD 0.4 billion in lease debt recognized in the financial statement due to implementation of IFRS 16 Leases. Total available liquidity at the end of the quarter was USD 3.0 (3.5) billion.

In February, the company paid a quarterly dividend of USD 0.5207 (NOK 4.41) per share. The Board has resolved to pay a quarterly dividend of USD 187.5 million (USD 0.5207 per share) in May 2019.

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 will occur in the future.

All figures are presented in USD unless otherwise stated, and figures in brackets apply to the corresponding period in the previous year. The figures related to previous periods have been restated due to changes in accounting principles, see note 1.

Summary of financial results

	UNIT	Q1 2019	Q4 2018*	Q1 2018*
Total income	USDm	836	916	944
EBITDA	USDm	539	658	691
Net profit	USDm	10	63	169
Earnings per share (EPS)	USD	0.03	0.17	0.47
Capex	USDm	329	380	237
Exploration spend	USDm	158	84	80
Abandonment spend	USDm	22	16	62
Production cost	USD/boe	13.4	13.0	12.1
Taxes paid	USDm	106	340	34
Net interest-bearing debt**	USDm	2 480	1 973	3 048
Leverage ratio		0.72	0.65	1.27

*Restated 2018 numbers due to the change in accounting principle for revenue recognition as described in note 1 to the interim financial statements. **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	Q1 2019	Q4 2018	Q1 2018
Alvheim area	mboepd	56.8	58.4	62.9
Ivar Aasen	mboepd	22.5	23.3	24.4
Skarv	mboepd	22.6	23.5	27.1
Ula area	mboepd	8.1	8.4	8.1
Valhall area	mboepd	45.8	39.6	34.5
Other	mboepd	2.8	2.6	1.6
Net production	mboepd	158.7	155.7	158.6
Over/underlift	mboepd	3.3	-4.2	8.7
Net sold volume	mboepd	162.0	151.5	167.3
- liquids	mboepd	128.8	119.7	132.3
- natural gas	mboepd	33.2	31.8	35.0
Realized price liquids	USD/boe	63.9	67.8	67.4
Ralized price natural gas	USD/scm	0.24	0.30	0.28

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q1 2019	Q1 2018*
Total income	836	944
EBITDA	539	691
EBIT	287	505
Pre-tax profit	249	458
Net profit	10	169
EPS (USD)	0.03	0.47

*restated

As described in note 1 to the interim financial statements, the accounting principle for revenue has been changed to now reflect revenue on lifted volumes, and the comparative periods have been restated accordingly.

Total income in first quarter 2019 amounted to USD 836 (944) million. The decrease was driven by lower sales volume and realized prices, and by non-cash losses on oil price hedging. Oil and gas production was nearly unchanged at 158.7 (158.6), however the sold volume decreased to 162.0 (167.3) mboepd due to lifting schedules. Realized oil and gas prices were six per cent lower in the first quarter 2019 than in the same period last year.

Other income included a loss of USD 26 million related to the company's oil price hedging programme. This programme consists of put options to provide downside protection. As oil prices increased during the quarter, the value of these options was reduced.

Production costs related to oil and gas sold in the quarter amounted to USD 200 (195) million. Production cost per produced unit in the quarter amounted to USD 13.4 (12.1) per boe. The increase was mainly caused by high maintenance activity particularly at Valhall and Ula.

Exploration expenses amounted to USD 90 (55) million, and reflected two dry exploration wells in addition to costs related to seismic, area fees, field evaluation etc. The company participated in three exploration wells in the quarter. The Froskelår well resulted in a discovery, while the Gjøkåsen and Hod Deep wells were dry.

Depreciation amounted to USD 183 (185) million, corresponding to USD 12.8 (13.0) per boe. Impairments amounted to USD 69 (0) million related to technical goodwill, driven by changes in expected cost and production profiles for future developments in the Ula area (see note 5).

Operating profit was USD 287 (505) million. Net financial expenses amounted to USD 37 (47) million.

Profit before taxes amounted to USD 249 (458) million. Taxes amounted to USD 239 (290) million for the first quarter, representing an effective tax rate of 96 (63) per cent. The high tax rate was mainly driven by the impairment of technical goodwill, which does not carry deferred tax.

This resulted in a net profit for the first quarter 2019 of USD 10 (169) million.

Statement of financial position

(USD MILLION)	Q1 2019	Q1 2018*
Goodwill	1 791	1 860
Other intangible assets	1 987	1 601
PP&E	5 954	5 665
Cash & cash equivalents	114	38
Total assets	11 117	11 943
Equity	2 799	3 105
Net interest-bearing debt	2 480	3 048

*restated

At the end of first quarter 2019, total intangible assets amounted to USD 4,274 (3,852) million, of which goodwill was USD 1,791 (1,860) million.

Property, plant and equipment increased to USD 5,954 (5,665) million, driven by investments in development projects, net of depreciation. Due to the implementation of IFRS 16 Leases, Right-of-use assets were recognized for the first time this quarter at a net value of USD 225 million at quarter end.

Current tax receivables decreased to USD 15 (1,666) as the tax loss acquired with Hess Norge was refunded in fourth quarter 2018.

Cash and cash equivalents were USD 114 (38) million at the end of the quarter. Total assets were USD 11,117 (11,943) million.

Equity amounted to USD 2,799 (3,105) million at the end of the first quarter, corresponding to an equity ratio of 25 (26) per cent.

Deferred tax liabilities amounted to USD 1,867 (1,337) million and are detailed in note 9 to the financial statements.

Gross bank and bond debt was USD 2,226 (3,086) million, consisting of the DETNOR02 bond of USD 226 million, the AKERBP Senior Notes (17/22) of USD 394 million, the AKERBP Senior Notes (18/25) of USD 494 million, and the Reserve Based Lending ("RBL") facility of USD 1,112 million. A bank term loan of USD 1,500 million was repaid in fourth quarter 2018 following the refund of the previously mentioned tax loss related to the Hess Norge acquisition.

At the end of the first quarter, the company had total available liquidity of USD 3.0 (3.5) billion, comprising USD 114 (38) million in cash and cash equivalents, and USD 2,850 (3,485) million in undrawn credit facilities.

Cash flow

(USD MILLION)	Q1 2019	Q1 2018
Cash flow from operations	591	600
Cash flow from investments	-511	-378
Cash flow from financing	-9	-435
Net change in cash & cash equivalents	71	-213
Cash and cash equivalents	114	38

Net cash flow from operating activities was USD 591 (600) million. Revenues were USD 858 million, down from USD 947 million in first quarter 2018 due to lower realized oil and gas prices, and taxes paid were USD 106 (34) million. These deviations were mitigated by changes in working capital and other current balance sheet items.

Net cash flow from investment activities was USD -511 (-378) million, of which investments in fixed assets amounted to USD 364 (257) million for the quarter, mainly related to the Valhall and Johan Sverdrup fields. Investments in intangible assets including capitalized exploration were USD 127 (39) million, and payments for decommissioning activities amounted to USD 21 (82) million in the quarter.

Net cash flow from financing activities totalled USD -9 (-435) million, reflecting USD 200 million in proceeds from issuance of debt, USD 21 million in payments on lease debt and USD 188 million in dividend disbursements.

Risk management

The company seeks to reduce the risk related to foreign exchange rates, 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 end of the first quarter 2019:

OIL PUT OPTIONS	Q2 2019	Q3 2019	Q4 2019
Volume (million bbl)	2.6	0.8	0.8
Share of after tax value of oil pro	100 %	25 %	21 %
duction covered (per cent)
Average strike (USD/bbl)	55	57	57
Average premium (USD/bbl)	1.76	1.44	1.44

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 19 February 2019, the company disbursed dividends of USD 187.5 million, corresponding to USD 0.5207 per share.

On 25 April 2019, the Board of Directors declared a dividend of USD 0.5207 per share, to be disbursed on or about 16 May 2019.

OPERATIONAL REVIEW

Aker BP's net production was 14.3 (14.3) mmboe in the first quarter of 2019, corresponding to 158.7 (158.6) mboepd. Due to overlift in the quarter, net sold volume represented 162.0 (167.3) mboepd. The average realized liquids price was USD 63.9 (67.4) per barrel, while the average realized gas price was USD 0.24 (0.28) per scm.

Alvheim Area

Key figures	Aker BP interest	Q1 2019	Q4 2018	Q3 2018	Q2 2018
Production, boepd
Alvheim	65 %	43 478	43 406	38 872	40 091
Bøyla	65 %	1 829	2 039	3 125	3 265
Vilje	46.904 %	3 756	3 257	3 716	4 098
Volund	65 %	7 757	9 655	11 016	12 646
Total production		56 820	58 356	56 729	60 100
Production efficiency		96.8 %	98.3 %	96.0 %	95.3 %

First quarter production from the Alvheim area was 56.8 mboepd net to Aker BP, representing a decrease of three per cent from the previous quarter. The main driver was natural decline and planned maintenance in February.

The Skogul project is progressing according to plan. Production start is planned for the first quarter of 2020. Skogul will be developed with a single multilateral production well tied back to the Vilje field, utilizing the existing pipeline from Vilje to the Alvheim FPSO.

Aker BP is planning to drill a new sidetrack from the Volund field (subsea tie-back to Alvheim) in the second quarter to continue the strategy of increased oil recovery from the area.

Following from last year's Frosk oil discovery near the Bøyla field a new well is now being drilled. This well will gather more information about the reservoir and will be completed as a production well which will be used for test production from mid-2019. In connection with the drilling of the Frosk test-producer, the Froskelår North-East prospect will be tested with aim of proving up additional resources in the area.

As previously announced, the Froskelår Main discovery is estimated to contain 60-130 mmboe. A comprehensive data collection program was carried out as part of the drilling operation, and further analysis will be performed to determine the size and quality of the discovery.

As a part of the company's strategy to develop the resource base in the Alvheim area, the Rumpetroll prospect will be drilled in the third quarter.

Valhall Area

Key figures	Aker BP interest	Q1 2019	Q4 2018	Q3 2018	Q2 2018
Production, boepd
Valhall	90 %	45 156	38 816	35 120	32 670
Hod	90 %	677	802	872	1 063
Total production		45 833	39 618	35 993	33 733
Production efficiency		94.3 %	91.1 %	87.6 %	84.5 %

First quarter production from the Valhall area was 45.8 mboepd net to Aker BP, representing a 16 per cent increase from the previous quarter, driven by a ramp-up of production from new wells and continued high production efficiency.

The Valhall IP drilling campaign continued with the G10 well. During the drilling of this well, valuable core samples and data was gathered on the shallower Miocene play which may represent a significant development potential if economically extractable. One section of the G11 well was completed with Fishbone technology and successfully put on test production. This test will continue until the remainder of the well is stimulated and put on production later this year.

The Valhall partnership made a final investment decision for the first phase of the Wellhead Platform Production Recovery ("WPPR") project. The WPPR project consists of a water injection test and six infill producers in the Lower Hod formation and represents a continuation of drilling in the Valhall central area following the successful IP campaign.

The Maersk Invincible rig was deployed to Flank South to drill two infill targets, where the first target did not find economic volumes. The rig will now drill the second infill target.

During the first quarter a combined appraisal and exploration well was drilled at the Hod field. Both targets were dry. These results will inform future concept work for the Hod Field Development project which is currently in early phase.

The Valhall Flank West development project is progressing as planned, with excellent HSE performance. The project is preparing for the upcoming offshore installation campaign this summer and is on schedule for first oil in the fourth quarter.

Ula Area

Key figures	Aker BP interest	Q1 2019	Q4 2018	Q3 2018	Q2 2018
Production, boepd
Ula	80 %	6 185	5 784	6 498	5 361
Tambar	55 %	1 916	2 572	4 008	5 398
Oda	15 %	102	-	-	-
Total production		8 203	8 356	10 506	10 759
Production efficiency		74.6 %	64.9 %	72.5 %	65.4 %

First quarter production from the Ula area was 8.2 mboepd net to Aker BP. Production was impacted by further reduced productivity from Tambar wells, and low availability on Ula due to the high ongoing activity in the area.

A flotel is in operation at the field to provide additional accommodation capacity to support the ongoing maintenance and upgrade activities at Ula. The flotel will be kept on location until mid-May.

The Oda field started production mid-March 2019, five months ahead of original schedule.

The company is working diligently to mature the opportunity set in the Ula area, which is a complex process involving a broad set of technical and commercial disciplines. This could eventually lead to the addition of a new platform at Ula in the mid-2020s.

During the first quarter, the company updated certain assumptions on production and cost profiles. This resulted in a reduction in the valuation of Ula, which triggered an impairment charge of technical goodwill of USD 69 million.

Skarv Area

Key figures	Aker BP interest	Q1 2019	Q4 2018	Q3 2018	Q2 2018
Production, boepd
Total production	23.835 %	22 558	23 454	23 313	27 579
Production efficiency		90.6 %	92.6 %	90.0 %	88.4 %

First quarter production from the Skarv area was 22.6 mboepd net to Aker BP, down four per cent from the previous quarter. Gas injection and oil production was shut in from late January to mid-March due to failure of the gas injection compressor motor. Higher gas export and strong performance and uptime of the gas production wells partially compensated for the temporary shut in oil production. The compressor motor was replaced with a new one and oil production was re-established in late March 2019.

Phase 1 of the Ærfugl development project is progressing on plan. Currently there is high activity on engineering, procurement and fabrication of the subsea system structure, the wellheads and the vertical Xmas tree system. Offshore modification work has commenced, and subsea installation is scheduled to begin in the third quarter. The drilling campaign is planned to start by the fourth quarter.

The remaining technology qualification activities for the trace heated pipe in pipe system and the new generation of vertical Xmas trees are on plan and well underway to be ready for assembly and construction in 2019. Production start is planned for fourth quarter 2020.

Ærfugl phase 2 is progressing as planned, awaiting formal concept selection in the second quarter. The final investment decision is planned by the end of the fourth quarter this year.

Ivar Aasen

Key figures	Aker BP interest	Q1 2019	Q4 2018	Q3 2018	Q2 2018
Production, boepd
Total production	34.7862 %	22 539	23 343	22 651	23 699
Production efficiency		98.3 %	93.2 %	93.2 %	90.4 %

The production from Ivar Aasen was 22.5 mboepd net to Aker BP, down three per cent from the previous quarter. Production efficiency was 98 per cent in the period, a significant improvement compared to 93 per cent in the previous quarter, mainly driven by improved export availability and adequate power supply. Overall production was negatively impacted by effects of prior period adjustments and slightly lower GOR due to good pressure support.

Johan Sverdrup

Phase 1 of the Johan Sverdrup development project is progressing steadily towards planned production start in November 2019. Offshore hook-up, commissioning and completion of the two platforms installed at the field centre last summer continued throughout the first quarter.

On the drilling platform the tie-back operations of the eight pre-drilled oil production wells continued. In March the 26,000 tonnes processing platform was successfully installed offshore at the Johan Sverdrup field centre in a single lift by the world's largest ship, Pioneering Spirit. This was the heaviest single lift ever executed offshore.

Subsequently the living quarter was also installed in a single lift, together with two bridges and a flare tower. This successful major marine operation completed the Phase 1 field centre building block installations and was an important 2019 milestone for meeting the planned production start-up.

Phase 2 of the Johan Sverdrup development is also pro¬gressing well. Detailed engineering is ongoing, and construction of the Main Support Frame (MSF) started in Thailand in March. The contract for subsea production system (SPS) was awarded to Technip-FMC.

North of Alvheim and Krafla-Askja (NOAKA)

The North of Alvheim and Askja-Krafla («NOAKA») area consists of the discoveries Frigg Gamma Delta, Langfjellet, Frøy, Fulla, Frigg, Rind and Askja-Krafla. Gross resources in the area are estimated to be more than 500 mmboe.

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

These studies have resulted in two alternative development solutions. One solution involves two unmanned production platforms («UPP») or similar concepts, supported from an existing host in the area. The other solution involves a new hub platform in the central part of the area, with processing and living quarters («PQ»).

Aker BP's recommendation is to develop the area with the PQ concept. This concept is the only alternative that allows for economic recovery of all discovered resources in the area, and provides higher resource recovery and socio-economic benefits than the alternative. The PQ concept is also the better alternative with regards to exploiting additional resources that may be discovered through future exploration.

Discussions are still ongoing between the partners on how to develop the NOAKA area.

HEALTH, SAFETY, SECURITY AND THE ENVIRONMENT

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

KEY HSSE INDICATORS	UNIT	Q1 2019	Q4 2018	Q3 2018	Q2 2018
Total recordable injury frequency (TRIF)	Per mill. exp. hours	3.3	3.4	4.1	4.2
Serious incident frequency (SIF)	Per mill. exp. hours	0.5	0.5	0.6	0.6
Loss of primary containment (LOPC)	Count	0	0	1	0
Process safety events Tier 1 and 2	Count	0	0	1	1
CO2 emissions intensity	Kg CO2/boe	7.7	7.6	7.5	6.8

Aker BP received a notice of order for Ula from the PSA related to the audit "Risk, barrier and maintenance management" in 2018. Aker BP complied with the order by the deadline 1 March 2019. In addition, Aker BP is conducting a large work program to rejuvenate the facilities at Ula in order for it to continue to be a safe and reliable operating hub for the coming decades.

EXPLORATION

Total exploration spend in the first quarter was USD 159 (55) million. Of this, USD 90 million was recognized as exploration expenses in the period, relating to dry wells, area fees, field evaluation and G&G costs.

In the Alvheim area, the Froskelår Main exploration well proved oil and gas. The well was successfully completed in the first quarter and the gross resources were estimated at 60-130 mmboe. A part of the discovery may straddle the UK-Norwegian border in the North Sea. The Froskelår Main well is part of a drilling campaign in the Alvheim area launched on the back of the exploration success at Frosk in 2018. More exploration and appraisal wells in the area will follow.

During the quarter the company also completed an appraisal and exploration well southwest of the Hod Field in Central Graben. The main objective of the appraisal well was to evaluate the chalk reservoir in Hod west and secondarily test the Miocene reservoir potential. The primary exploration target in the sidetrack was the Upper Jurassic succession. The secondary target was to test the potential in the Permian succession. Both wells were classified as dry.

Drilling of the first well on the Gjøkåsen prospect in the Barents Sea was completed in February 2019. Aker BP is partner in this licence with a 20 per cent interest. The first well explored a shallow target and was classified as dry. The Gjøkåsen Deep well was completed in March 2019, and also was classified as dry.

On 15 January 2019, the Norwegian Ministry of Petroleum and Energy announced the results of the APA 2018 licensing round. Aker BP was awarded 21 new exploration licenses, of which 11 as operator.

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 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 2019, the company's financial plan consists of the following main items1:

Production of 155-160,000 boe per day
Capex USD 1.6 billion of which the main drivers are Valhall and Johan Sverdrup
Exploration spend of USD 500 million, to cater for an extensive exploration program comprising of 15 exploration wells targeting net prospective resources of 500 mmboe
Abandonment spend of USD 150 million, related to plugging of depleted wells and removal of the old living quarters platform at Valhall
Production cost of around USD 12.5 per boe, slightly above 2018 due to high maintenance and modifications activity particularly at Valhall and Ula

1 The majority of the company's cost elements are denominated in NOK. The estimated USD amounts are based on an USDNOK exchange rate of 8.5.

The Board has proposed to pay USD 750 million in dividends in 2019, with an intention to increase the dividend level by USD 100 million per year until 2023. The company pays dividends each quarter. For 2019, the quarterly dividend is expected to be approximately USD 0.52 per share.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT (Unaudited)

		Group
		Q1		01.01.-31.03.
			Restated		Restated
(USD 1 000)	Note	2019	2018	2019	2018

Petroleum revenues		858 105	946 503	858 105	946 503
Other operating income		-21 843	-2 045	-21 843	-2 045
Total income	2	836 262	944 458	836 262	944 458
Production costs	3	200 462	195 296	200 462	195 296
Exploration expenses	4	90 359	54 661	90 359	54 661
Depreciation	6	183 102	185 421	183 102	185 421
Impairments	5, 6	68 941	-	68 941	-
Other operating expenses		6 859	3 640	6 859	3 640
Total operating expenses		549 724	439 018	549 724	439 018
Operating profit		286 538	505 439	286 538	505 439
Interest income		6 064	4 904	6 064	4 904
Other financial income		9 719	52 544	9 719	52 544
Interest expenses		13 830	32 675	13 830	32 675
Other financial expenses		39 335	71 727	39 335	71 727
Net financial items	8	-37 381	-46 954	-37 381	-46 954
Profit before taxes		249 157	458 486	249 157	458 486
Taxes (+)/tax income (-)	9	238 731	289 972	238 731	289 972
Net profit		10 425	168 514	10 425	168 514
Weighted average no. of shares outstanding basic and diluted Basic and diluted earnings USD per share		360 113 509 0.03	360 113 509 0.47	360 113 509 0.03	360 113 509 0.47

STATEMENT OF FINANCIAL POSITION (Unaudited)

ASSETS

Intangible assets

Tangible fixed assets

Financial assets

Inventories

Receivables

Cash and cash equivalents

(USD 1 000) Note 31.03.2019 31.03.2018 31.12.2018

Goodwill 6 1 791 185 1 860 126 1 860 126 Capitalized exploration expenditures 6 496 094 391 212 427 439 Other intangible assets 6 1 986 986 1 600 736 2 005 885

Property, plant and equipment 6 5 953 972 5 664 761 5 746 275 Right-of-use assets 6 225 244 - -

Long-term receivables 34 002 42 319 37 597 Long-term derivatives 13 - 3 848 - Other non-current assets 10 392 8 707 10 388

Total non-current assets 10 497 874 9 571 710 10 087 710

Inventories 98 910 80 713 93 179

Accounts receivable 45 271 109 471 162 798 Tax receivables 9 15 473 1 666 497 11 082 Other short-term receivables 10 345 374 469 391 292 405 Short-term derivatives 13 - 7 241 17 253

Cash and cash equivalents 11 113 680 37 999 44 944

Total current assets 618 708 2 371 312 621 661

TOTAL ASSETS 11 116 582 11 943 022 10 709 371

Restated Restated

Group

STATEMENT OF COMPREHENSIVE INCOME

		Group
		Q1			01.01.-31.03.
			Restated		Restated
(USD 1 000)	Note	2019	2018	2019	2018

Profit for the period		10 425	168 514	10 425	168 514
Items which may be reclassified over profit and loss (net of taxes)
Currency translation adjustment		-	73 132	-	73 132

Total comprehensive income in period		10 425	241 646	10 425	241 646

STATEMENT OF FINANCIAL POSITION (Unaudited)

Restated Restated

Q1 01.01.-31.03. Group

Restated Restated

Q1 01.01.-31.03.

Group

(USD 1 000) Note 2019 2018 2019 2018

Petroleum revenues 858 105 946 503 858 105 946 503 Other operating income -21 843 -2 045 -21 843 -2 045

Total income 2 836 262 944 458 836 262 944 458

Production costs 3 200 462 195 296 200 462 195 296 Exploration expenses 4 90 359 54 661 90 359 54 661 Depreciation 6 183 102 185 421 183 102 185 421 Impairments 5, 6 68 941 - 68 941 - Other operating expenses 6 859 3 640 6 859 3 640

Total operating expenses 549 724 439 018 549 724 439 018

Operating profit 286 538 505 439 286 538 505 439

Interest income 6 064 4 904 6 064 4 904 Other financial income 9 719 52 544 9 719 52 544 Interest expenses 13 830 32 675 13 830 32 675 Other financial expenses 39 335 71 727 39 335 71 727

Net financial items 8 -37 381 -46 954 -37 381 -46 954

Profit before taxes 249 157 458 486 249 157 458 486

Taxes (+)/tax income (-) 9 238 731 289 972 238 731 289 972

Net profit 10 425 168 514 10 425 168 514

Weighted average no. of shares outstanding basic and diluted 360 113 509 360 113 509 360 113 509 360 113 509 Basic and diluted earnings USD per share 0.03 0.47 0.03 0.47

(USD 1 000) Note 2019 2018 2019 2018

Profit for the period 10 425 168 514 10 425 168 514

Currency translation adjustment - 73 132 - 73 132

Total comprehensive income in period 10 425 241 646 10 425 241 646

INCOME STATEMENT (Unaudited)

STATEMENT OF COMPREHENSIVE INCOME

Items which may be reclassified over profit and loss (net of taxes)

		Group
			Restated	Restated
(USD 1 000)	Note	31.03.2019	31.03.2018	31.12.2018

ASSETS
Intangible assets
Goodwill	6	1 791 185	1 860 126	1 860 126
Capitalized exploration expenditures	6	496 094	391 212	427 439
Other intangible assets	6	1 986 986	1 600 736	2 005 885
Tangible fixed assets
Property, plant and equipment	6	5 953 972	5 664 761	5 746 275
Right-of-use assets	6	225 244	-	-
Financial assets
Long-term receivables		34 002	42 319	37 597
Long-term derivatives	13	-	3 848	-
Other non-current assets		10 392	8 707	10 388
Total non-current assets		10 497 874	9 571 710	10 087 710
Inventories
Inventories		98 910	80 713	93 179
Receivables
Accounts receivable		45 271	109 471	162 798
Tax receivables	9	15 473	1 666 497	11 082
Other short-term receivables	10	345 374	469 391	292 405
Short-term derivatives	13	-	7 241	17 253
Cash and cash equivalents
Cash and cash equivalents	11	113 680	37 999	44 944
Total current assets		618 708	2 371 312	621 661
TOTAL ASSETS		11 116 582	11 943 022	10 709 371

STATEMENT OF FINANCIAL POSITION (Unaudited)

		Group
			Restated	Restated
(USD 1 000)	Note	31.03.2019	31.03.2018	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		-894 888	-589 345	-717 814
Total equity		2 799 464	3 105 007	2 976 539
Non-current liabilities
Deferred taxes	9	1 867 333	1 337 694	1 752 757
Long-term abandonment provision	17	2 475 388	2 814 235	2 447 558
Provisions for other liabilities	12	1 389	141 228	107 519

Long-term bonds	15	1 113 285	1 127 838	1 110 488
Long-term derivatives	13	27 945	-	26 275
Long-term lease debt	7	275 818	-	-
Other interest-bearing debt	16	1 112 304	459 906	907 954
Current liabilities
Trade creditors		112 033	123 521	105 567
Accrued public charges and indirect taxes		17 254	17 608	25 061
Tax payable	9	566 755	553 574	551 942
Short-term derivatives	13	10 354	10 630	8 783
Short-term abandonment provision	17	85 212	194 087	105 035
Short-term lease debt	7	92 735	-	-
Short-term interest-bearing debt	16	-	1 498 159	-
Other current liabilities	14	559 310	559 534	583 894
Total liabilities		8 317 118	8 838 015	7 732 833
TOTAL EQUITY AND LIABILITIES		11 116 582	11 943 022	10 709 371

STATEMENT OF CHANGES IN EQUITY - GROUP (Unaudited)

Restated Restated

Group

STATEMENT OF FINANCIAL POSITION (Unaudited)

EQUITY AND LIABILITIES

Non-current liabilities

Current liabilities

Equity

(USD 1 000) Note 31.03.2019 31.03.2018 31.12.2018

Share capital 57 056 57 056 57 056 Share premium 3 637 297 3 637 297 3 637 297 Other equity -894 888 -589 345 -717 814

Total equity 2 799 464 3 105 007 2 976 539

Deferred taxes 9 1 867 333 1 337 694 1 752 757 Long-term abandonment provision 17 2 475 388 2 814 235 2 447 558 Provisions for other liabilities 12 1 389 141 228 107 519

Long-term bonds 15 1 113 285 1 127 838 1 110 488 Long-term derivatives 13 27 945 - 26 275 Long-term lease debt 7 275 818 - - Other interest-bearing debt 16 1 112 304 459 906 907 954

Trade creditors 112 033 123 521 105 567 Accrued public charges and indirect taxes 17 254 17 608 25 061 Tax payable 9 566 755 553 574 551 942 Short-term derivatives 13 10 354 10 630 8 783 Short-term abandonment provision 17 85 212 194 087 105 035 Short-term lease debt 7 92 735 - - Short-term interest-bearing debt 16 - 1 498 159 - Other current liabilities 14 559 310 559 534 583 894

Total liabilities 8 317 118 8 838 015 7 732 833

TOTAL EQUITY AND LIABILITIES 11 116 582 11 943 022 10 709 371

				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
Dividend 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	-25 108	-1 175 324	-717 814	2 976 539

Dividend distributed	-	-	-	-	-	-187 500	-187 500	-187 500
Profit for the period	-	-	-	-	-	10 425	10 425	10 425
Equity as of 31.03.2019	57 056	3 637 297	573 083	-81	-25 108	-1 352 399	-894 888	2 799 464

* 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 i note 1.

STATEMENT OF CASH FLOW (Unaudited)

			Group
		Q1		01.01.-31.03.
			Restated		Restated
(USD 1 000)	Note	2019	2018	2019	2018
CASH FLOW FROM OPERATING ACTIVITIES
Profit before taxes		249 157	458 486	249 157	458 486
Taxes paid	9	-105 930	-34 381	-105 930	-34 381
Depreciation	6	183 102	185 421	183 102	185 421
Net impairment losses	5, 6	68 941	-	68 941	-
Accretion expenses	8, 17	29 584	32 146	29 584	32 146
Interest expenses	8	49 150	44 550	49 150	44 550

Interest paid		-45 843	-51 156	-45 843	-51 156
Changes in derivatives	2, 8	20 495	-6 706	20 495	-6 706
Amortized loan costs	8	6 676	8 124	6 676	8 124
Amortization of fair value of contracts	14	-	14 195	-	14 195
Expensed capitalized dry wells	4, 6	58 074	13 665	58 074	13 665
Changes in inventories, accounts payable and receivables		118 262	75 947	118 262	75 947
Changes in other current balance sheet items		-41 108	-139 898	-41 108	-139 898
NET CASH FLOW FROM OPERATING ACTIVITIES		590 560	600 394	590 560	600 394
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields		-20 762	-81 903	-20 762	-81 903
Disbursements on investments in fixed assets		-363 982	-256 757	-363 982	-256 757
Disbursements on investments in capitalized exploration		-126 334	-39 460	-126 334	-39 460
Disbursements on investments in licenses		-143	-	-143	-
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-511 222	-378 119	-511 222	-378 119

CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment of long-term debt		200 000	-815 000	200 000	-815 000
Net proceeds from issuance of debt		-	492 423	-	492 423
Payments on lease debt		-21 302	-	-21 302	-
Paid dividend		-187 500	-112 500	-187 500	-112 500
NET CASH FLOW FROM FINANCING ACTIVITIES		-8 802	-435 077	-8 802	-435 077

Net change in cash and cash equivalents		70 537	-212 802	70 537	-212 802

Cash and cash equivalents at start of period		44 944	232 504	44 944	232 504
Effect of exchange rate fluctuation on cash held		-1 801	18 297	-1 801	18 297
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	113 680	37 999	113 680	37 999

SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits and cash		113 680	37 999	113 680	37 999
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	113 680	37 999	113 680	37 999

NOTES

Restated Restated

Group Q1 01.01.-31.03.

STATEMENT OF CASH FLOW (Unaudited)

CASH FLOW FROM OPERATING ACTIVITIES

CASH FLOW FROM INVESTMENT ACTIVITIES

CASH FLOW FROM FINANCING ACTIVITIES

SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD

(USD 1 000) Note 2019 2018 2019 2018

Profit before taxes 249 157 458 486 249 157 458 486 Taxes paid 9 -105 930 -34 381 -105 930 -34 381 Depreciation 6 183 102 185 421 183 102 185 421 Net impairment losses 5, 6 68 941 - 68 941 - Accretion expenses 8, 17 29 584 32 146 29 584 32 146 Interest expenses 8 49 150 44 550 49 150 44 550 Interest paid -45 843 -51 156 -45 843 -51 156 Changes in derivatives 2, 8 20 495 -6 706 20 495 -6 706 Amortized loan costs 8 6 676 8 124 6 676 8 124 Amortization of fair value of contracts 14 - 14 195 - 14 195 Expensed capitalized dry wells 4, 6 58 074 13 665 58 074 13 665 Changes in inventories, accounts payable and receivables 118 262 75 947 118 262 75 947 Changes in other current balance sheet items -41 108 -139 898 -41 108 -139 898 NET CASH FLOW FROM OPERATING ACTIVITIES 590 560 600 394 590 560 600 394

Payment for removal and decommissioning of oil fields -20 762 -81 903 -20 762 -81 903 Disbursements on investments in fixed assets -363 982 -256 757 -363 982 -256 757 Disbursements on investments in capitalized exploration -126 334 -39 460 -126 334 -39 460 Disbursements on investments in licenses -143 - -143 - NET CASH FLOW FROM INVESTMENT ACTIVITIES -511 222 -378 119 -511 222 -378 119

Net drawdown/repayment of long-term debt 200 000 -815 000 200 000 -815 000 Net proceeds from issuance of debt - 492 423 - 492 423 Payments on lease debt -21 302 - -21 302 - Paid dividend -187 500 -112 500 -187 500 -112 500 NET CASH FLOW FROM FINANCING ACTIVITIES -8 802 -435 077 -8 802 -435 077

Net change in cash and cash equivalents 70 537 -212 802 70 537 -212 802

Cash and cash equivalents at start of period 44 944 232 504 44 944 232 504 Effect of exchange rate fluctuation on cash held -1 801 18 297 -1 801 18 297 CASH AND CASH EQUIVALENTS AT END OF PERIOD 11 113 680 37 999 113 680 37 999

Bank deposits and cash 113 680 37 999 113 680 37 999 CASH AND CASH EQUIVALENTS AT END OF PERIOD 11 113 680 37 999 113 680 37 999 (All figures in USD 1 000 unless otherwise stated)

These 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 25 April 2019.

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 is 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

The group has previously 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 has 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
	Q1		01.01.-31.03.
		Restated		Restated
Breakdown of petroleum revenues (USD 1 000)	2019	2018	2019	2018

Sales of liquids	740 780	802 054	740 780	802 054
Sales of gas	113 927	139 470	113 927	139 470
Tariff income	3 397	4 979	3 397	4 979
Total petroleum revenues	858 105	946 503	858 105	946 503
Sales of liquids (barrels of oil equivalent)	11 593 578	11 907 579	11 593 578	11 907 579
Sales of gas (barrels of oil equivalent)	2 987 607	3 152 497	2 987 607	3 152 497
Other income (USD 1 000)

Realized gain/loss (-) on oil derivatives	-2 058	-3 487	-2 058	-3 487
Unrealized gain/loss (-) on oil derivatives	-24 123	1 109	-24 123	1 109
Other income*	4 338	332	4 338	332
Total other operating income	-21 843	-2 045	-21 843	-2 045

* Includes 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
	Q1		01.01.-31.03.
(USD 1 000)	2019	2018	2019	2018

Total produced volumes (barrels of oil equivalent)	14 280 083	14 278 426	14 280 083	14 278 426
Production cost based on produced volumes	190 998	173 481	190 998	173 481
Adjustment for over/underlift (-)	9 464	21 814	9 464	21 814
Production cost based on sold volumes	200 462	195 296	200 462	195 296

Note 4 Exploration expenses

		Group
	Q1		01.01.-31.03.
Breakdown of exploration expenses (USD 1 000)	2019	2018	2019	2018

Seismic	532	13 479	532	13 479
Area fee	4 574	4 246	4 574	4 246
Field evaluation	15 925	14 458	15 925	14 458
Dry well expenses*	58 074	13 665	58 074	13 665
Other exploration expenses	11 254	8 814	11 254	8 814
Total exploration expenses	90 359	54 661	90 359	54 661

* Dry well expenses are mainly related to the Gjøkåsen well and a combined appraisal and exploration well on Hod.

Note 5 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment triggers are identified. Goodwill is tested for impairment at least annually. In Q1 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 licenses and licenses in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 March 2019.

Oil and gas prices

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

Year	USD/BOE

2019	67.0
2020	65.0
2021	62.9
2022	67.2
From 2023 (in real terms)	65.0

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

Year	GBP/therm

2019	0.61
2020	0.54
2021	0.51
2022	0.52
From 2023 (in real terms)	0.49

Oil and gas reserves

Note 3 Produced volumes and over/underlift adjustment

Note 4 Exploration expenses

Note 5 Impairments

Impairment test of goodwill

categories of impairment tests have been performed:

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

* Dry well expenses are mainly related to the Gjøkåsen well and a combined appraisal and exploration well on Hod.

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

assumptions have been applied for value in use and fair value testing.

assumptions applied for impairment testing purposes as of 31 March 2019.

Impairment testing

Oil and gas prices

(USD 1 000) 2019 2018 2019 2018

Breakdown of exploration expenses (USD 1 000) 2019 2018 2019 2018

Seismic 532 13 479 532 13 479 Area fee 4 574 4 246 4 574 4 246 Field evaluation 15 925 14 458 15 925 14 458 Dry well expenses* 58 074 13 665 58 074 13 665 Other exploration expenses 11 254 8 814 11 254 8 814 Total exploration expenses 90 359 54 661 90 359 54 661

Impairment tests of individual cash-generating units are performed when impairment triggers are identified. Goodwill is tested for impairment at least annually. In Q1 2019, two

Year USD/BOE

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

2019 67.0 2020 65.0 2021 62.9 2022 67.2 From 2023 (in real terms) 65.0

Total produced volumes (barrels of oil equivalent) 14 280 083 14 278 426 14 280 083 14 278 426 Production cost based on produced volumes 190 998 173 481 190 998 173 481 Adjustment for over/underlift (-) 9 464 21 814 9 464 21 814 Production cost based on sold volumes 200 462 195 296 200 462 195 296

Group Q1 01.01.-31.03.

Group

01.01.-31.03.

Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves. The recoverable amount is sensitive to changes in 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 value in use testing, the post tax nominal discount rate used is 7.9 per cent, which is the same discount rate as applied in Q4 2018. For fair value testing, the discount rate used is 10.0 per cent (unchanged from 2018).

Currency rates
Year	USD/NOK

2019	8.63
2020	8.53
2021	8.48
2022	7.66
From 2023	7.50

Inflation

The long-term inflation rate is assumed to be 2.0 per cent, unchanged from Q4 2018.

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. No impairment/reversal of impairment of assets other than goodwill has been recognized in Q1 2019.

Impairment testing of technical goodwill

For the CGUs Alvheim, Valhall/Hod, Skarv/Ærfugl no impairment is recognized during Q1. For the CGU Ula/Tambar, the impairment charge has been calculated as follows:

(USD 1 000)	Ula/Tambar

Net carrying value	506 793
Recoverable amount	437 852
Impairment charge Q1	68 941

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. In Q1 2019, the reduced deferred tax, together with updated cost and production profiles are the main reason for the impairment.

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. The only impacted CGU is Ula/Tambar.

		Change in goodwill impairment after
Assumption (USD 1 000)	Change	Increase in assumptions	Decrease in assumptions
Oil and gas price	+/- 20%	-68 941	76 455
Production profile (reserves)	+/- 5%	-34 781	34 781
Discount rate	+/- 1% point	22 997	-24 750
Currency rate USD/NOK	+/- 1.0 NOK	-47 850	61 526
Inflation	+/- 1% point	-31 713	28 153

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 31.12.2017	1 480 689	4 032 797	69 007	5 582 493

Acquisition cost 31.12.2017	1 480 689	6 057 801	104 346	7 642 835
Additions	1 011 222	-172 615	22 662	861 269
Disposals	-	-	-	-
Reclassification	-208 309	201 176	8 053	921
Acquisition cost 31.12.2018	2 283 602	6 086 362	135 061	8 505 025
Accumulated depreciation and impairments 31.12.2017	-	2 025 004	35 338	2 060 342
Depreciation	-	656 697	22 054	678 751
Impairment	-	19 657	-	19 657
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 31.12.2018	-	2 701 357	57 392	2 758 750
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	343 368	8 156	6 415	357 939
Disposals	-	-	-	-
Reclassification*	-138 081	144 963	2 402	9 284
Acquisition cost 31.03.2019	2 488 888	6 239 482	143 878	8 872 248
Accumulated depreciation and impairments 31.12.2018	-	2 701 357	57 392	2 758 750
Depreciation	-	153 501	6 025	159 527
Impairment	-	-	-	-
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 31.03.2019	-	2 854 859	63 418	2 918 276
Book value 31.03.2019	2 488 888	3 384 623	80 460	5 953 972

*The reclassification is mainly relating to the Oda field, which entered into production phase in March 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
(USD 1 000)	Vessels and
	Drilling Rigs	Boats	Office	Other	Total

Right-of-use assets at initial recognition 01.01.2019	-	-	-	-	-
Additions	132 270	76 628	29 593	2 303	240 795
Abandonment activity*	-871	-284	-	-	-1 155
Reclassification**	-9 046	-817	-	-	-9 863
Acquisition cost 31.03.2019	122 353	75 528	29 593	2 303	229 777
Accumulated depreciation and impairments	-	-	-	-	-
Depreciation	1 723	835	1 955	20	4 533
Impairment	-	-	-	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 31.03.2019	1 723	835	1 955	20	4 533
Book value 31.03.2019	120 630	74 693	27 639	2 283	225 244

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

** Of which 9 284 reclassified to tangible fixed assets and 579 reclassified to capitalized exploration in line with the actitivy of the right-of-use asset.

Right-of-use assets are depreciated linearly over the lifetime of the related lease contract.

INTANGIBLE ASSETS - GROUP

Note 6 Tangible fixed assets and intangible assets

Book value 31.12.2017 1 480 689 4 032 797 69 007 5 582 493

Assets under development

Production facilities including wells

Fixtures and fittings, office

machinery Total

Acquisition cost 31.12.2017 1 480 689 6 057 801 104 346 7 642 835 Additions 1 011 222 -172 615 22 662 861 269 Disposals - - - - Reclassification -208 309 201 176 8 053 921 Acquisition cost 31.12.2018 2 283 602 6 086 362 135 061 8 505 025

Accumulated depreciation and impairments 31.12.2017 - 2 025 004 35 338 2 060 342 Depreciation - 656 697 22 054 678 751 Impairment - 19 657 - 19 657 Retirement/transfer depreciations - - - - Accumulated depreciation and impairments 31.12.2018 - 2 701 357 57 392 2 758 750

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 343 368 8 156 6 415 357 939 Disposals - - - - Reclassification* -138 081 144 963 2 402 9 284 Acquisition cost 31.03.2019 2 488 888 6 239 482 143 878 8 872 248

Accumulated depreciation and impairments 31.12.2018 - 2 701 357 57 392 2 758 750 Depreciation - 153 501 6 025 159 527 Impairment - - - - Retirement/transfer depreciations - - - - Accumulated depreciation and impairments 31.03.2019 - 2 854 859 63 418 2 918 276

Book value 31.03.2019 2 488 888 3 384 623 80 460 5 953 972

Production facilities, including wells, are depreciated in accordance with the unit-of-production method. Office machinery, fixtures and fittings etc. are depreciated using the straight-

line method over their useful life, i.e. 3 - 5 years. Removal and decommissioning costs are included as production facilities or fields under development.

*The reclassification is mainly relating to the Oda field, which entered into production phase in March 2019.

TANGIBLE FIXED ASSETS - GROUP

Property, plant and equipment

(USD 1 000)

	Other intangible assets
(USD 1 000)	Licences etc.	Software	Total	Exploration wells	Goodwill
Book value 31.12.2017	1 617 005	34	1 617 039	365 417	1 860 126
Acquisition cost 31.12.2017	1 933 241	7 501	1 940 742	365 417	2 738 973
Additions	463 049	-	463 049	128 795	-
Disposals/expensed dry wells	-	-	-	65 852	-
Reclassification	-	-	-	-921	-
Acquisition cost 31.12.2018	2 396 290	7 501	2 403 791	427 439	2 738 973
Accumulated depreciation and impairments 31.12.2017	316 236	7 467	323 703	-	878 847
Depreciation	73 653	34	73 686	-	-
Impairment	516	-	516	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 31.12.2018	390 404	7 501	397 906	-	878 847
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	126 150	-
Disposals/expensed dry wells	-	-	-	58 074	-
Reclassification	-	-	-	579	-
Acquisition cost 31.03.2019	2 396 433	7 501	2 403 934	496 094	2 738 973
Accumulated depreciation and impairments 31.12.2018	390 404	7 501	397 906	-	878 847
Depreciation	19 043	-	19 043	-	-
Impairment	-	-	-	-	68 941
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 31.03.2019	409 447	7 501	416 948	-	947 789
Book value 31.03.2019	1 986 986	-	1 986 986	496 094	1 791 185

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

	Group
	Q1		01.01.-31.03.
Depreciation in the income statement (USD 1 000)	2019	2018	2019	2018

Depreciation of tangible fixed assets	159 527	169 119	159 527	169 119
Depreciation of right-of-use assets	4 533	-	4 533	-
Depreciation of intangible assets	19 043	16 302	19 043	16 302
Total depreciation in the income statement	183 102	185 421	183 102	185 421
Impairment in the income statement (USD 1 000)

Impairment of goodwill	68 941	-	68 941	-
Total impairment in the income statement	68 941	-	68 941	-

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 weighted average of the incremental borrowing rate applied in discounting of the nominal lease debt is 6.7 per cent.

	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	-
Payments of lease debt	-27 760
Interest expense on lease debt	6 459
Currency exchange differences	22
Total lease debt 31.03.2019	368 553

Break down of the lease debt to short-term and long-term liabilities
Short-term	92 735
Long-term	275 818
Total lease debt	368 553

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 it, based on the managements judgement, is reasonably certain that an extension will be exercised.

Nominal lease debt maturity breakdown (USD 1 000):
Within one year	115 454
Two to five years	273 461
After five years	75 992
Total	464 907

Note 8 Financial items

Depreciation in the income statement (USD 1 000) 2019 2018 2019 2018

Impairment in the income statement (USD 1 000)

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

Nominal lease debt maturity breakdown (USD 1 000):

Note 7 Leasing

per cent.

Depreciation of tangible fixed assets 159 527 169 119 159 527 169 119 Depreciation of right-of-use assets 4 533 - 4 533 - Depreciation of intangible assets 19 043 16 302 19 043 16 302 Total depreciation in the income statement 183 102 185 421 183 102 185 421

Impairment of goodwill 68 941 - 68 941 - Total impairment in the income statement 68 941 - 68 941 -

(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 - Payments of lease debt -27 760 Interest expense on lease debt 6 459 Currency exchange differences 22 Total lease debt 31.03.2019 368 553

Short-term 92 735 Long-term 275 818 Total lease debt 368 553

Within one year 115 454 Two to five years 273 461 After five years 75 992 Total 464 907

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 it, based on the managements judgement, is reasonably certain that an extension will be exercised.

		Group
(USD 1 000)		Q1		01.01.-31.03.
	2019	2018	2019	2018
Interest income	6 064	4 904	6 064	4 904
Realized gains on derivatives	4 420	32 295	4 420	32 295
Change in fair value of derivatives	5 299	20 250	5 299	20 250
Total other financial income	9 719	52 544	9 719	52 544

Interest expenses	42 691	44 550	42 691	44 550
Interest on lease debt	6 459	-	6 459	-
Capitalized interest cost, development projects	-41 997	-20 000	-41 997	-20 000
Amortized loan costs	6 676	8 124	6 676	8 124
Total interest expenses	13 830	32 675	13 830	32 675
Net currency loss/gain (-)	605	20 792	605	20 792
Realized loss on derivatives	6 694	4 046	6 694	4 046
Change in fair value of derivatives	1 671	14 652	1 671	14 652
Accretion expenses	29 584	32 146	29 584	32 146
Other financial expenses	782	90	782	90
Total other financial expenses	39 335	71 727	39 335	71 727
Net financial items	-37 381	-46 954	-37 381	-46 954

Note 9 Tax

Group

Q1 01.01.-31.03. Group

	Group
	Q1		01.01.-31.03.
		Restated		Restated
Tax for the period (USD 1 000)	2019	2018	2019	2018

Current year tax payable	129 282	225 730	129 282	225 730
Current year deferred tax change	110 686	85 471	110 686	85 471
Prior period adjustments	-1 237	-21 229	-1 237	-21 229
Total tax (+)/tax income (-)	238 731	289 972	238 731	289 972

		Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	31.03.2019	31.03.2018	31.12.2018

Tax receivable/payable at 01.01.	-540 860	1 234 850	1 234 850
Current year tax (-)/tax receivable (+)	-129 282	-225 730	-803 396
Taxes receivable/payable related to acquisitions/sales	520	-	4 387
Net tax payment (+)/tax refund (-)	105 930	34 381	-907 312
Prior period adjustments and change in estimate of uncertain tax positions	13 278	11 458	-30 269
Currency movements of tax receivable/payable	-868	57 964	-39 119
Total net tax receivable (+)/tax payable (-)	-551 282	1 112 923	-540 860
Tax receivable included as current assets (+)	15 473	1 666 497	11 082
Tax payable included as current liabilities (-)	-566 755	-553 574	-551 942

		Group
		Restated	Restated
Deferred tax (-)/deferred tax asset (+) (USD 1 000)	31.03.2019	31.03.2018	31.12.2018

Deferred tax/deferred tax asset 31.12.	-1 752 757	-1 307 148	-1 307 148
Effect of change in accounting principle*	-	45 155	45 155
Deferred tax/deferred tax asset 01.01.	-1 752 757	-1 261 993	-1 261 993
Change in deferred tax in the income statement	-110 686	-85 471	-524 645
Prior period adjustment	-3 891	9 770	33 912
Deferred tax charged to OCI and equity	-	-	-30
Net deferred tax (-)/deferred tax asset (+)	-1 867 333	-1 337 694	-1 752 757

	Group
	Q1		01.01.-31.03.
		Restated		Restated
Reconciliation of tax expense (USD 1 000)	2019	2018	2019	2018

78% tax rate on profit before tax	194 342	357 619	194 342	357 619
Tax effect of uplift	-31 063	-31 627	-31 063	-31 627
Permanent difference on impairment	53 774	-	53 774	-
Foreign currency translation of NOK monetary items	472	16 218	472	16 218
Foreign currency translation of USD monetary items	1 138	110 572	1 138	110 572
Tax effect of financial and other 22%/23% items	17 519	-61 469	17 519	-61 469
Currency movements of tax balances**	-323	-84 993	-323	-84 993
Other permanent differences, prior period adjustments and change in estimate of	2 873	-16 347	2 873	-16 347
uncertain tax positions
Total tax (+)/tax income (-)	238 731	289 972	238 731	289 972

* 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 (vice versa).

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

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	Restated
(USD 1 000)	31.03.2019	31.03.2018	31.12.2018

Prepayments	66 662	47 597	64 004
VAT receivable	7 082	14 863	8 871
Underlift of petroleum*	39 170	36 004	54 924
Accrued income from sale of petroleum products	136 882	247 637	52 825
Other receivables, mainly from licenses	95 578	123 290	111 781
Total other short-term receivables	345 374	469 391	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

Group

Restated Restated

Group

2 873 -16 347 2 873 -16 347

Group

Restated Restated

Deferred tax (-)/deferred tax asset (+) (USD 1 000) 31.03.2019 31.03.2018 31.12.2018

Deferred tax/deferred tax asset 31.12. -1 752 757 -1 307 148 -1 307 148 Effect of change in accounting principle* - 45 155 45 155 Deferred tax/deferred tax asset 01.01. -1 752 757 -1 261 993 -1 261 993 Change in deferred tax in the income statement -110 686 -85 471 -524 645 Prior period adjustment -3 891 9 770 33 912 Deferred tax charged to OCI and equity - - -30 Net deferred tax (-)/deferred tax asset (+) -1 867 333 -1 337 694 -1 752 757

Reconciliation of tax expense (USD 1 000) 2019 2018 2019 2018

78% tax rate on profit before tax 194 342 357 619 194 342 357 619 Tax effect of uplift -31 063 -31 627 -31 063 -31 627 Permanent difference on impairment 53 774 - 53 774 - Foreign currency translation of NOK monetary items 472 16 218 472 16 218 Foreign currency translation of USD monetary items 1 138 110 572 1 138 110 572 Tax effect of financial and other 22%/23% items 17 519 -61 469 17 519 -61 469 Currency movements of tax balances** -323 -84 993 -323 -84 993

Total tax (+)/tax income (-) 238 731 289 972 238 731 289 972

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

** 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

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

* Relates to change in deferred tax as a result of the change in accounting principle for revenue recognition as described in note 1.

Other permanent differences, prior period adjustments and change in estimate of

(USD 1 000) 31.03.2019 31.03.2018 31.12.2018

Prepayments 66 662 47 597 64 004 VAT receivable 7 082 14 863 8 871 Underlift of petroleum* 39 170 36 004 54 924 Accrued income from sale of petroleum products 136 882 247 637 52 825 Other receivables, mainly from licenses 95 578 123 290 111 781 Total other short-term receivables 345 374 469 391 292 405

* 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 10 Other short-term receivables

company's functional currency is USD.

depreciation measured in USD (vice versa).

uncertain tax positions

Restated Restated

01.01.-31.03.

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

		Group
Breakdown of cash and cash equivalents (USD 1 000)	31.03.2019	31.03.2018	31.12.2018

Bank deposits	113 680	37 999	44 944
Cash and cash equivalents	113 680	37 999	44 944

Unused reserve-based lending facility (see note 16)	2 850 000	3 485 000	3 050 000

Note 12 Provisions for other liabilities

	Group
Breakdown of provisions for other liabilities (USD 1 000)	31.03.2019	31.03.2018	31.12.2018

Fair value of contracts assumed in acquisitions*	-	138 282	106 040
Other long term liabilities	1 389	2 947	1 480
Total provisions for other liabilities	1 389	141 228	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)	31.03.2019	31.03.2018	31.12.2018

Unrealized gain interest rate swaps	-	1 613	-
Unrealized gain currency contracts	-	2 236	-
Long-term derivatives included in assets	-	3 848	-
Unrealized gain on commodity derivatives	-	-	17 253
Unrealized gain currency contracts	-	7 241	-
Short-term derivatives included in assets	-	7 241	17 253
Total derivatives included in assets	-	11 090	17 253
Unrealized losses interest rate swaps	27 945	-	26 275
Long-term derivatives included in liabilities	27 945	-	26 275
Unrealized losses commodity derivatives	6 870	4 048	-
Unrealized losses currency contracts	3 484	6 582	8 783
Short-term derivatives included in liabilities	10 354	10 630	8 783
Total derivatives included in liabilities	38 300	10 630	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	Restated
Breakdown of other current liabilities (USD 1 000)	31.03.2019	31.03.2018	31.12.2018

Current liabilities against JV partners	25 723	77 484	22 779
Share of other current liabilities in licences	357 645	277 739	309 260
Overlift of petroleum*	3 766	7 202	10 055
Fair value of contracts assumed in acquisitions**	-	57 322	42 998
Other current liabilities***	172 177	139 786	198 801
Total other current liabilities	559 310	559 534	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

	Group
(USD 1 000)	31.03.2019	31.03.2018	31.12.2018

DETNOR02 Senior unsecured bond *	225 843	243 316	223 839
AKERBP – Senior Notes (17/22) **	393 763	392 099	393 301
AKERBP – Senior Notes (18/25) ***	493 680	492 423	493 349
Long-term bonds	1 113 285	1 127 838	1 110 488

* 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 per cent. 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 per cent quarterly. The financial covenants for this bond are consistent with the RBL as described in note 16.

** The bond was established in July 2017 and carries an interest of 6.0 per cent. 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 per cent. 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.

Note 16 Other interest-bearing debt

Group

Breakdown of other current liabilities (USD 1 000) 31.03.2019 31.03.2018 31.12.2018

Current liabilities against JV partners 25 723 77 484 22 779 Share of other current liabilities in licences 357 645 277 739 309 260 Overlift of petroleum* 3 766 7 202 10 055 Fair value of contracts assumed in acquisitions** - 57 322 42 998 Other current liabilities*** 172 177 139 786 198 801 Total other current liabilities 559 310 559 534 583 894

(USD 1 000) 31.03.2019 31.03.2018 31.12.2018

DETNOR02 Senior unsecured bond * 225 843 243 316 223 839 AKERBP – Senior Notes (17/22) ** 393 763 392 099 393 301 AKERBP – Senior Notes (18/25) *** 493 680 492 423 493 349 Long-term bonds 1 113 285 1 127 838 1 110 488

** The bond was established in July 2017 and carries an interest of 6.0 per cent. The principal falls due in July 2022 and interest is paid on a semi annual basis. The bond is senior

*** The bond was established in March 2018 and carries an interest of 5.875 per cent. The principal falls due in March 2025 and interest is paid on a semi annual basis. The bond is

* 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.

per cent quarterly. The financial covenants for this bond are consistent with the RBL as described in note 16.

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

Restated Restated

Note 14 Other current liabilities

Note 15 Bonds

unsecured and has no financial covenants.

senior unsecured and has no financial covenants.

	Group
(USD 1 000)	31.03.2019	31.03.2018	31.12.2018

Reserve-based lending facility	1 112 304	459 906	907 954
Long-term interest-bearing debt	1 112 304	459 906	907 954

Bridge facility	-	1 498 159	-
Short-term interest-bearing debt	-	1 498 159	-

The RBL facility was established in 2014 and is a senior secured seven-year facility. The facility size amounts to USD 4.0 billion, with an uncommitted accordion option of USD 1.0 billion. The interest rate is from 1 - 6 months LIBOR plus a margin of 2 - 3 per cent based on drawn amount. In addition, a commitment fee is paid on unused credit. The financial covenants are as follows:

Leverage Ratio shall be maximum 4 until the production start of Johan Sverdrup, thereafter maximum 3.5
Interest Coverage Ratio shall be minimum 3.5

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.

In relation to the acquisition of Hess Norge AS, the company obtained a new USD 1.5 billion bank facility ("Bridge facility"). The terms of the facility included a mandatory repayment clause triggered by the refund of tax losses in Hess Norge. The refund took place in November 2018 and the facility was repaid and cancelled at the same time.

Note 17 Provision for abandonment liabilities

		Group
(USD 1 000)	31.03.2019	31.03.2018	31.12.2018

Provisions as of 1 January	2 552 592	3 043 884	3 043 884
Incurred cost removal	-21 575	-67 707	-201 227
Accretion expense - present value calculation	29 584	32 146	128 737
Changed net present value from changed discount rate	-	-	-277 081
Change in estimates and incurred liabilities on new drilling and installations	-	-	-141 721
Total provision for abandonment liabilities	2 560 601	3 008 323	2 552 592
Break down of the provision to short-term and long-term liabilities
Short-term	85 212	194 087	105 035
Long-term	2 475 388	2 814 235	2 447 558
Total provision for abandonment liabilities	2 560 601	3 008 323	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 4.46 per cent and 5.01 per cent. The credit margin included in the discount rate is 2.00 per cent.

Note 18 Contingent liabilities

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

The company has not identified any events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report.

Note 20 Investments in joint operations

Fields operated:	31.03.2019	31.12.2018
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:	31.03.2019	31.12.2018 Licence:		31.03.2019	31.12.2018
PL 001B	35.000%	35.000 % PL 777		40.000%	40.000 %
PL 006B	90.000%		90.000 % PL 777B	40.000%	40.000 %
PL 019	80.000%		80.000 % PL 777C	40.000%	40.000 %
PL 019C	80.000%		80.000 % PL 777D	40.000%	40.000 %
PL 019E	80.000%	80.000 % PL 784		40.000%	40.000 %
PL 019H*	80.000%	0.000 % PL 790		30.000%	30.000 %
PL 026	92.130%	92.130 % PL 814		40.000%	40.000 %
PL 026B	90.260%	90.260 % PL 818		40.000%	40.000 %
PL 027D	100.000%	100.000 % 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 839		23.835%	23.835 %
PL 033B	90.000%	90.000 % PL 843		40.000%	40.000 %
PL 036C	65.000%	65.000 % PL 858		40.000%	40.000 %
PL 036D	46.904%	46.904 % PL 861		50.000%	50.000 %
PL 036E	64.000%	64.000 % PL 867		40.000%	40.000 %
PL 065	55.000%	55.000 % PL 868		60.000%	60.000 %
PL 065B	55.000%	55.000 % PL 869		60.000%	60.000 %
PL 088BS	65.000%		65.000 % PL 872**	0.000%	40.000 %
PL 102D	50.000%	50.000 % PL 873		40.000%	40.000 %
PL 102F	50.000%	50.000 % PL 874		90.260%	90.260 %
PL 102G	50.000%	50.000 % PL 893		60.000%	60.000 %
PL 102H	50.000%		50.000 % PL 895**	0.000%	60.000 %
PL 127C	100.000%	100.000 % PL 906		60.000%	60.000 %
PL 146	77.800%	77.800 % PL 907		60.000%	60.000 %
PL 150	65.000%		65.000 % PL 914S	34.786%	34.786 %
PL 159D	23.835%	23.835 % PL 915		35.000%	35.000 %
PL 169C	50.000%	50.000 % PL 916		40.000%	40.000 %
PL 203	65.000%	65.000 % PL 919		65.000%	65.000 %
PL 203B**	0.000%	65.000 % PL 932		60.000%	60.000 %
PL 212	30.000%	30.000 % PL 941		50.000%	50.000 %
PL 212B	30.000%	30.000 % PL 948		40.000%	40.000 %
	30.000%			40.000%
PL 212E	35.000%	30.000 % PL 951		70.000%	40.000 %
PL 242	50.000%	35.000 % PL 963		40.000%	70.000 %
PL 261	30.000%	50.000 % PL 964		60.000%	40.000 %
PL 262	55.000%	30.000 % PL 977*		60.000%	0.000 %
PL 300	77.800%	55.000 % PL 978*		60.000%	0.000 %
PL 333		77.800 % PL 979*			0.000 %
PL 340	65.000%	65.000 % PL 986*		30.000%	0.000 %
PL 340BS	65.000%		65.000 % PL 1005*	60.000%	0.000 %
PL 364	90.260%		90.260 % PL 1008*	60.000%	0.000 %
PL 442	90.260%		90.260 % PL 1022*	40.000%	0.000 %
PL 442B	90.260%		90.260 % PL 1026*	40.000%	0.000 %
PL 460	65.000%		65.000 % PL 1028*	50.000%	0.000 %
PL 504	47.593%		47.593 % PL 1030*	50.000%	0.000 %
PL 626**	0.000%	60.000 %
PL 659**	0.000%	50.000 %
PL 685	40.000%	40.000 %
PL 748	50.000%	50.000 %
PL 748B	50.000%	50.000 %
PL 762	20.000%	20.000 %
Number of licenses in which Aker BP is the operator				89	83

Fields non-operated: 31.03.2019 31.12.2018 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 %

PL 722 20.000% 20.000 % PL 782S 20.000% 20.000 % PL 782SB 20.000% 20.000 % PL 782SC 20.000% 20.000 % PL 782SD* 20.000% 0.000 % PL 810 30.000% 30.000 % PL 810B 30.000% 30.000 %

* Interest awarded in the APA Licensing round (Application in Predefined Areas) in 2018. The awards were announced in 2019.

** Relinquished license or Aker BP has withdrawn from the license.

Licence: 31.03.2019 31.12.2018 Licence: 31.03.2019 31.12.2018 PL 006C 15.000% 15.000 % PL 811 20.000% 20.000 % PL 006E 15.000% 15.000 % PL 813** 0.000% 3.300 % PL 006F* 15.000% 0.000 % PL 838 30.000% 30.000 % PL 018DS** 0.000% 13.338 % PL 838B* 30.000% 0.000 % PL 029B 20.000% 20.000 % PL 842 30.000% 30.000 % PL 035 50.000% 50.000 % PL 844 20.000% 20.000 % PL 035C 50.000% 50.000 % PL 852 40.000% 40.000 % PL 048D 10.000% 10.000 % PL 852B 40.000% 40.000 % PL 102C 10.000% 10.000 % PL 852C 40.000% 40.000 % PL 127 50.000% 50.000 % PL 857 20.000% 20.000 % PL 127B 50.000% 50.000 % PL 862 50.000% 50.000 % PL 220 15.000% 15.000 % PL 863 40.000% 40.000 % PL 265 20.000% 20.000 % PL 863B 40.000% 40.000 % PL 272 50.000% 50.000 % PL 864 20.000% 20.000 % PL 272B* 50.000% 0.000 % PL 891 30.000% 30.000 % PL 405 15.000% 15.000 % PL 892 30.000% 30.000 % PL 457BS 40.000% 40.000 % PL 902 30.000% 30.000 % PL 492 60.000% 60.000 % PL 902B* 30.000% 0.000 % PL 502 22.222% 22.222 % PL 942 30.000% 30.000 % PL 533 35.000% 35.000 % PL 954 20.000% 20.000 % PL 533B 35.000% 35.000 % PL 955 30.000% 30.000 % PL 554 30.000% 30.000 % PL 961 30.000% 30.000 % PL 554B 30.000% 30.000 % PL 962 20.000% 20.000 % PL 554C 30.000% 30.000 % PL 966 30.000% 30.000 % PL 554D 30.000% 30.000 % PL 968* 20.000% 0.000 % PL 615 4.000% 4.000 % PL 981* 40.000% 0.000 % PL 615B 4.000% 4.000 % PL 982* 40.000% 0.000 % PL 719 20.000% 20.000 % PL 985* 20.000% 0.000 % PL 721 40.000% 40.000 % PL 1031* 20.000% 0.000 %

Number of licenses in which Aker BP is the partner 63 55

Production licences in which Aker BP is a partner:

* Interest awarded in the APA Licensing round (Application in Predefined Areas) in 2018. The awards were announced in 2019.

** Relinquished license or Aker BP has withdrawn from the license.

31.03.2019	31.12.2018
10.000%	10.000 %
2.000%	2.000 %
3.300%	3.300 %
11.573%	11.573 %
15.000%	15.000 %

Note 20 Investments in joint operations

Production licences in which Aker BP is the operator:

Fields operated: 31.03.2019 31.12.2018 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 %

PL 626** 0.000% 60.000 % PL 659** 0.000% 50.000 % PL 685 40.000% 40.000 % PL 748 50.000% 50.000 % PL 748B 50.000% 50.000 % PL 762 20.000% 20.000 %

* Interest awarded in the APA Licensing round (Application in Predefined Areas) in 2018. The awards were announced in 2019.

** Relinquished license or Aker BP has withdrawn from the license.

Licence: 31.03.2019 31.12.2018 Licence: 31.03.2019 31.12.2018 PL 001B 35.000% 35.000 % PL 777 40.000% 40.000 % PL 006B 90.000% 90.000 % PL 777B 40.000% 40.000 % PL 019 80.000% 80.000 % PL 777C 40.000% 40.000 % PL 019C 80.000% 80.000 % PL 777D 40.000% 40.000 % PL 019E 80.000% 80.000 % PL 784 40.000% 40.000 % PL 019H* 80.000% 0.000 % PL 790 30.000% 30.000 % PL 026 92.130% 92.130 % PL 814 40.000% 40.000 % PL 026B 90.260% 90.260 % PL 818 40.000% 40.000 % PL 027D 100.000% 100.000 % 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 839 23.835% 23.835 % PL 033B 90.000% 90.000 % PL 843 40.000% 40.000 % PL 036C 65.000% 65.000 % PL 858 40.000% 40.000 % PL 036D 46.904% 46.904 % PL 861 50.000% 50.000 % PL 036E 64.000% 64.000 % PL 867 40.000% 40.000 % PL 065 55.000% 55.000 % PL 868 60.000% 60.000 % PL 065B 55.000% 55.000 % PL 869 60.000% 60.000 % PL 088BS 65.000% 65.000 % PL 872** 0.000% 40.000 % PL 102D 50.000% 50.000 % PL 873 40.000% 40.000 % PL 102F 50.000% 50.000 % PL 874 90.260% 90.260 % PL 102G 50.000% 50.000 % PL 893 60.000% 60.000 % PL 102H 50.000% 50.000 % PL 895** 0.000% 60.000 % PL 127C 100.000% 100.000 % PL 906 60.000% 60.000 % PL 146 77.800% 77.800 % PL 907 60.000% 60.000 % PL 150 65.000% 65.000 % PL 914S 34.786% 34.786 % PL 159D 23.835% 23.835 % PL 915 35.000% 35.000 % PL 169C 50.000% 50.000 % PL 916 40.000% 40.000 % PL 203 65.000% 65.000 % PL 919 65.000% 65.000 % PL 203B** 0.000% 65.000 % PL 932 60.000% 60.000 % PL 212 30.000% 30.000 % PL 941 50.000% 50.000 % PL 212B 30.000% 30.000 % PL 948 40.000% 40.000 % PL 212E 30.000% 30.000 % PL 951 40.000% 40.000 % PL 242 35.000% 35.000 % PL 963 70.000% 70.000 % PL 261 50.000% 50.000 % PL 964 40.000% 40.000 % PL 262 30.000% 30.000 % PL 977* 60.000% 0.000 % PL 300 55.000% 55.000 % PL 978* 60.000% 0.000 % PL 333 77.800% 77.800 % PL 979* 60.000% 0.000 % PL 340 65.000% 65.000 % PL 986* 30.000% 0.000 % PL 340BS 65.000% 65.000 % PL 1005* 60.000% 0.000 % PL 364 90.260% 90.260 % PL 1008* 60.000% 0.000 % PL 442 90.260% 90.260 % PL 1022* 40.000% 0.000 % PL 442B 90.260% 90.260 % PL 1026* 40.000% 0.000 % PL 460 65.000% 65.000 % PL 1028* 50.000% 0.000 % PL 504 47.593% 47.593 % PL 1030* 50.000% 0.000 %

Number of licenses in which Aker BP is the operator 89 83

Production licences in which Aker BP is a partner:
Licence:	31.03.2019	31.12.2018 Licence:	31.03.2019	31.12.2018
PL 006C	15.000%	15.000 % PL 811	20.000%	20.000 %
PL 006E	15.000%	15.000 % PL 813**	0.000%	3.300 %
PL 006F*	15.000%	0.000 % PL 838	30.000%	30.000 %
PL 018DS**	0.000%	13.338 % PL 838B*	30.000%	0.000 %
PL 029B	20.000%	20.000 % PL 842	30.000%	30.000 %
PL 035	50.000%	50.000 % PL 844	20.000%	20.000 %
PL 035C	50.000%	50.000 % PL 852	40.000%	40.000 %
PL 048D	10.000%	10.000 % PL 852B	40.000%	40.000 %
PL 102C	10.000%	10.000 % PL 852C	40.000%	40.000 %
PL 127	50.000%	50.000 % PL 857	20.000%	20.000 %
PL 127B	50.000%	50.000 % PL 862	50.000%	50.000 %
PL 220	15.000%	15.000 % PL 863	40.000%	40.000 %
PL 265	20.000%	20.000 % PL 863B	40.000%	40.000 %
PL 272	50.000%	50.000 % PL 864	20.000%	20.000 %
PL 272B*	50.000%	0.000 % PL 891	30.000%	30.000 %
PL 405	15.000%	15.000 % PL 892	30.000%	30.000 %
PL 457BS	40.000%	40.000 % PL 902	30.000%	30.000 %
PL 492	60.000%	60.000 % PL 902B*	30.000%	0.000 %
PL 502	22.222%	22.222 % PL 942	30.000%	30.000 %
PL 533	35.000%	35.000 % PL 954	20.000%	20.000 %
PL 533B	35.000%	35.000 % PL 955	30.000%	30.000 %
PL 554	30.000%	30.000 % PL 961	30.000%	30.000 %
PL 554B	30.000%	30.000 % PL 962	20.000%	20.000 %
PL 554C	30.000%	30.000 % PL 966	30.000%	30.000 %
PL 554D	30.000%	30.000 % PL 968*	20.000%	0.000 %
PL 615	4.000%	4.000 % PL 981*	40.000%	0.000 %
PL 615B	4.000%	4.000 % PL 982*	40.000%	0.000 %
PL 719	20.000%	20.000 % PL 985*	20.000%	0.000 %
PL 721	40.000%	40.000 % PL 1031*	20.000%	0.000 %
PL 722	20.000%	20.000 %
PL 782S	20.000%	20.000 %
PL 782SB	20.000%	20.000 %
PL 782SC	20.000%	20.000 %
PL 782SD*	20.000%	0.000 %
PL 810	30.000%	30.000 %
PL 810B	30.000%	30.000 %
Number of licenses in which Aker BP is the partner			63	55

* Interest awarded in the APA Licensing round (Application in Predefined Areas) in 2018. The awards were announced in 2019.

** Relinquished license or Aker BP has withdrawn from the license.

Note 21 Results from previous interim reports

	2019		2018 Restated
(USD 1 000)	Q1	Q4	Q3	Q2	Q1
Total income	836 262	916 200	965 799	925 166	944 458
Production costs	200 462	177 683	170 090	150 517	195 296
Exploration expenses	90 359	72 458	93 519	75 270	54 661
Depreciation	183 102	195 962	188 526	182 528	185 421
Impairments	68 941	20 172	-	-	-
Other operating expenses	6 859	7 739	4 334	1 324	3 640
Total operating expenses	549 724	474 015	456 468	409 639	439 018
Operating profit/loss	286 538	442 185	509 331	515 526	505 439
Net financial items	-37 381	-43 905	-57 869	-21 778	-46 954
Profit/loss before taxes	249 157	398 280	451 462	493 748	458 486
Taxes (+)/tax income (-)	238 731	335 403	335 052	365 771	289 972
Net profit/loss	10 425	62 876	116 410	127 977	168 514

	2019			2018
(barrels of oil equivalent)	Q1	Q4	Q3	Q2	Q1
Sold volumes
Liquids Gas	11 593 578 2 987 607	11 018 340 2 921 380	10 816 266 2 826 946	10 588 527 3 182 150	11 907 579 3 152 497

	2019	2018
		Restated
(USD 1 000)	Q1	Q4	Q3	Q2	Q1
Assets
Goodwill	1 791 185	1 860 126	1 860 126	1 860 126	1 860 126
Other intangible assets	2 483 080	2 433 324	1 978 583	1 986 427	1 991 949
Property, plant and equipment	5 953 972	5 746 275	6 038 954	5 835 137	5 664 761
Right-of-use asset	225 244	-	-	-	-
Receivables and other assets	533 949	613 620	627 882	738 909	721 690
Calculated tax receivables (short)	15 473	11 082	1 607 118	1 595 916	1 666 497
Cash and cash equivalents	113 680	44 944	126 608	49 245	37 999
Total assets	11 116 582	10 709 371	12 239 271	12 065 760	11 943 022
Equity and liabilities
Equity	2 799 464	2 976 539	3 060 631	3 050 214	3 105 007
Other provisions for liabilities incl. P&A (long)	2 504 723	2 581 352	3 023 870	2 992 329	2 955 464
Deferred tax	1 867 333	1 752 757	1 593 074	1 477 175	1 337 694
Bonds and bank debt	2 225 589	2 018 443	2 975 518	3 017 362	3 085 903
Lease debt	368 553	-	-	-	-
Other current liabilities incl. P&A	784 164	828 340	831 834	841 352	905 380
Tax payable	566 755	551 942	754 344	687 328	553 574
Total equity and liabilities	11 116 582	10 709 371	12 239 271	12 065 760	11 943 022

Alternative performance measures

Note 21 Results from previous interim reports

Sold volumes

Assets

Equity and liabilities

2019

(USD 1 000) Q1 Q4 Q3 Q2 Q1

Total income 836 262 916 200 965 799 925 166 944 458

Production costs 200 462 177 683 170 090 150 517 195 296 Exploration expenses 90 359 72 458 93 519 75 270 54 661 Depreciation 183 102 195 962 188 526 182 528 185 421 Impairments 68 941 20 172 - - - Other operating expenses 6 859 7 739 4 334 1 324 3 640

Total operating expenses 549 724 474 015 456 468 409 639 439 018

Operating profit/loss 286 538 442 185 509 331 515 526 505 439

Net financial items -37 381 -43 905 -57 869 -21 778 -46 954

Profit/loss before taxes 249 157 398 280 451 462 493 748 458 486 Taxes (+)/tax income (-) 238 731 335 403 335 052 365 771 289 972

Net profit/loss 10 425 62 876 116 410 127 977 168 514

(barrels of oil equivalent) Q1 Q4 Q3 Q2 Q1

Liquids 11 593 578 11 018 340 10 816 266 10 588 527 11 907 579 Gas 2 987 607 2 921 380 2 826 946 3 182 150 3 152 497

(USD 1 000) Q1 Q4 Q3 Q2 Q1

Goodwill 1 791 185 1 860 126 1 860 126 1 860 126 1 860 126 Other intangible assets 2 483 080 2 433 324 1 978 583 1 986 427 1 991 949 Property, plant and equipment 5 953 972 5 746 275 6 038 954 5 835 137 5 664 761 Right-of-use asset 225 244 - - - - Receivables and other assets 533 949 613 620 627 882 738 909 721 690 Calculated tax receivables (short) 15 473 11 082 1 607 118 1 595 916 1 666 497 Cash and cash equivalents 113 680 44 944 126 608 49 245 37 999

Total assets 11 116 582 10 709 371 12 239 271 12 065 760 11 943 022

Equity 2 799 464 2 976 539 3 060 631 3 050 214 3 105 007 Other provisions for liabilities incl. P&A (long) 2 504 723 2 581 352 3 023 870 2 992 329 2 955 464 Deferred tax 1 867 333 1 752 757 1 593 074 1 477 175 1 337 694 Bonds and bank debt 2 225 589 2 018 443 2 975 518 3 017 362 3 085 903 Lease debt 368 553 - - - - Other current liabilities incl. P&A 784 164 828 340 831 834 841 352 905 380 Tax payable 566 755 551 942 754 344 687 328 553 574

Total equity and liabilities 11 116 582 10 709 371 12 239 271 12 065 760 11 943 022

2019

Restated

2018

Restated

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 fields

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 cost

EBIT is short for earnings before interest and other financial items and taxes

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 expenses

Leverage ratio is calculated as Net interest-bearing debt (excluding leasing debt) divided by twelve months rolling EBITDAX

Net interest-bearing debt is book value of current and non-current interest-bearing debt less cash and cash equivalents*

Production cost per boe is production cost basd on produced volumes (see note 3), divided by number of barrels of oil equivalents produced in the corresponding period**

* Includes leasing debt from Q1 2019

** Definition is changed in Q1 2019 as production cost in the income statement includes adjustment for over/underlift, while this APM still applies to produced volumes.

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: [email protected]

AI Terminal

Aker BP

3528_rns_2019-04-26_b1af9e11-fda0-4bec-ab47-8f19a3f0ed38.pdf

FIRST QUARTER 2019 SUMMARY

Summary of financial results

Summary of production

FINANCIAL REVIEW

Income statement

Statement of financial position

Cash flow

Risk management

Dividends

OPERATIONAL REVIEW

Alvheim Area

Valhall Area

Ula Area

Skarv Area

Ivar Aasen

Johan Sverdrup

North of Alvheim and Krafla-Askja (NOAKA)

HEALTH, SAFETY, SECURITY AND THE ENVIRONMENT

EXPLORATION

Total exploration spend in the first quarter was USD 159 (55) million. Of this, USD 90 million was recognized as exploration expenses in the period, relating to dry wells, area fees, field evaluation and G&G costs.

OUTLOOK

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT (Unaudited)

STATEMENT OF COMPREHENSIVE INCOME

STATEMENT OF FINANCIAL POSITION (Unaudited)

STATEMENT OF FINANCIAL POSITION (Unaudited)

STATEMENT OF CHANGES IN EQUITY - GROUP (Unaudited)

STATEMENT OF CASH FLOW (Unaudited)

NOTES

Note 1 Accounting principles

IFRS 16

Change in accounting principles for revenue recognition

Note 2 Income

Note 3 Produced volumes and over/underlift adjustment

Note 4 Exploration expenses

Note 5 Impairments

Impairment testing

Oil and gas prices

Oil and gas reserves

Future expenditure

Discount rate

Inflation

Impairment testing of assets other than goodwill

Impairment testing of technical goodwill

Sensitivity analysis

Note 6 Tangible fixed assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

INTANGIBLE ASSETS - GROUP

Note 7 Leasing

Note 8 Financial items

Note 9 Tax

Note 10 Other short-term receivables

Note 11 Cash and cash equivalents

Note 12 Provisions for other liabilities

Note 13 Derivatives

Note 14 Other current liabilities

Note 15 Bonds

Note 16 Other interest-bearing debt

Note 17 Provision for abandonment liabilities

Note 18 Contingent liabilities

Note 19 Subsequent events

Note 20 Investments in joint operations

Note 21 Results from previous interim reports

Alternative performance measures

AKER BP ASA

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