Aker BP

Quarterly Report • Oct 22, 2019

QUARTERLY REPORT Q3 2019

THIRD QUARTER 2019 SUMMARY

Aker BP delivered strong operational performance and exploration success during the third quarter. The company's field developments progressed as planned, paving the way for a significant increase in production in the coming months. Johan Sverdrup was brought on stream early October, and Valhall Flank West remains on track for first oil later this year. The company paid a dividend of USD 187.5 million (USD 0.52 per share) in the quarter.

Aker BP reported total income of USD 723 (785) million and operating profit of USD 196 (354) million for the third quarter 2019. Net loss was USD 43 million, compared to a net profit of USD 62 million in the previous quarter.

The company's net production in the third quarter was 146.1 (127.3) thousand barrels of oil equivalents per day ("mboepd"). Net sold volume was 143.3 (140.7) mboepd. The production volumes were below plan mainly due to delays in the stimulation program at Valhall following the planned maintenance shutdown in June. Average realized liquids price was USD 62.0 (69.3) per barrel, while the realized price for natural gas averaged USD 0.16 (0.16) per standard cubic metre ("scm").

Production costs for the oil and gas sold in the quarter amounted to USD 167 (198) million. Production cost per produced unit in the quarter amounted to USD 13.2 (15.4) per boe, negatively impacted by the costs of approximately USD 14 million related to an incident with the Mid Water Arch (MWA) at Alvheim. Any related insurance recoveries will be recognized in future periods.

Exploration expenses amounted to USD 70 (60) million. Total cash spend on exploration was USD 144 (119) million. The company completed six exploration wells in the quarter, of which the Liatårnet and Ørn wells were classified as discoveries. The Shrek well was completed and classified as a discovery after the end of the quarter.

Depreciation amounted to USD 206 (168) million, equivalent to USD 15.3 (14.5) per produced boe. Impairments amounted to USD 78 (0) million related to technical goodwill on Ula/Tambar, mainly triggered by decreased near-term oil and gas prices and updated cost and production profiles.

Profit before taxes amounted to USD 143 (268) million. Tax expense was USD 186 (206) million, representing an effective tax rate of 130 (77) percent. The tax rate was negatively impacted by impairment of technical goodwill with no tax impact, and an increase in deferred tax primarily driven by currency movements. Overall, the company reported a net loss of USD 43 million for the quarter.

Investments in fixed assets amounted to USD 435 (414) million in the third quarter. All field development projects, including Johan Sverdrup, Valhall Flank West and Ærfugl progressed according to plan. Abandonment expenditures in the quarter were USD 35 (40) million.

Net interest-bearing debt was USD 3.3 (2.9) billion at the end of the quarter, including USD 0.3 billion in lease debt. Total available liquidity at the end of the quarter was USD 2.9 (3.3) billion.

In August, the company paid a quarterly dividend of USD 0.5207 (NOK 4.44) per share. The Board has resolved to pay a quarterly dividend of USD 187.5 million (USD 0.5207 per share) in November 2019, implying total annual dividends of USD 750 million.

Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future and may not be within our control. All figures are presented in USD unless otherwise stated, and figures in brackets apply to the previous quarter.

Summary of financial results

	UNIT	Q3 2019	Q2 2019	Q3 2018*	2019 YTD	2018 YTD*
Total income	USDm	723	785	966	2 344	2 835
EBITDA	USDm	480	522	698	1 541	2 087
Net profit/loss	USDm	-43	62	116	30	413
Earnings per share (EPS)	USD	-0.12	0.17	0.32	0.08	1.15
Capex	USDm	421	397	343	1 161	823
Exploration spend	USDm	144	119	159	422	275
Abandonment spend	USDm	37	41	21	99	226
Production cost	USD/boe	13.2	15.4	11.9	13.9	11.8
Taxes paid	USDm	106	208	163	420	266
Net interest-bearing debt**	USDm	3 276	2 907	2 849	3 276	2 849
Leverage ratio		1.2	0.9	1.0	1.2	1.0

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

**The definition of net interest-bearing debt includes Lease debt, which is recognized from Q1 2019 following the implementation of IFRS 16 Leases. The comparative figures for

previous periods have not been restated. See also the description of "Alternative performance measures" at the end of this report for definitions.

Summary of production

	UNIT	Q3 2019	Q2 2019	Q3 2018	2019 YTD	2018 YTD
Alvheim area	mboepd	51.4	53.1	56.7	53.8	59.9
Ivar Aasen	mboepd	22.5	19.1	22.7	21.4	23.6
Skarv	mboepd	21.7	22.7	23.3	22.3	26.0
Ula area	mboepd	8.6	6.2	10.5	7.7	9.8
Valhall area	mboepd	40.3	24.5	36.0	36.9	34.8
Other	mboepd	1.7	1.7	1.4	2.0	1.6
Net production	mboepd	146.1	127.3	150.6	144.0	155.7
Over/underlift	mboepd	-2.9	13.4	-2.3	4.6	-0.1
Net sold volume	mboepd	143.3	140.7	148.3	148.6	155.6
- liquids	mboepd	113.4	112.8	117.6	118.3	122.0
- natural gas	mboepd	29.8	27.9	30.7	30.3	33.6
Realized price liquids	USD/boe	62.0	69.3	74.6	65.0	71.8
Ralized price natural gas	USD/scm	0.16	0.16	0.30	0.19	0.29

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q3 2019	Q2 2019	Q3 2018*	2019 YTD	2018 YTD*
Total income	723	785	966	2 344	2 835
EBITDA	480	522	698	1 541	2 087
EBIT	196	354	509	837	1 530
Pre-tax profit	143	268	451	660	1 404
Net profit/loss	-43	62	116	30	413
EPS (USD)	-0.12	0.17	0.32	0.08	1.15

*Restated, see note 1.

Total income in the third quarter 2019 amounted to USD 723 (785) million. The decrease compared to the previous quarter was driven by lower oil prices, partly mitigated by an increase in sold volumes. Sold volume increased to 143.3 (140.7) mboepd. Oil and gas production increased to 146.1 mboepd in the third quarter, compared to 127.3 mboepd in the previous quarter which was a quarter impacted by planned maintenance shutdowns.

Average realized liquids prices were 11 percent lower than in the previous quarter, while realized natural gas prices were unchanged.

Production costs related to oil and gas sold in the quarter amounted to USD 167 (198) million. The decrease was mainly caused by changes in over/underlift positions as described in note 3 to the financial statements. Production cost per produced unit in the quarter amounted to USD 13.2 (15.4) per boe. The MWA incident at Alvheim increased production costs by USD 14 million during the quarter. The company is pursuing insurance recovery. Additional costs and any related insurance recoveries will be recognized in future periods.

Exploration expenses amounted to USD 70 (60) million, and reflected four dry exploration wells in addition to costs related to seismic, area fees, field evaluation etc. The company completed six exploration wells in the quarter. The Liatårnet and Ørn wells resulted in discoveries. In addition, the Shrek well was completed after the end of the quarter and resulted in a discovery.

Depreciation amounted to USD 206 (168) million, corresponding to USD 15.3 (14.5) per boe. The increase was driven by higher production and by relatively higher contribution from fields with above-average depreciation per unit of production. An impairment charge of USD 78 million was recognized in the quarter related to technical goodwill on Ula/Tambar, mainly triggered by decreased near-term oil and gas prices and updated cost and production profiles.

Operating profit was USD 196 (354) million. Net financial expenses amounted to USD 53 million, down from 86 million in the previous quarter which was a quarter impacted by costs triggered by the replacement of the previous Reserve Based Lending facility ("RBL").

Profit before taxes amounted to USD 143 (268) million. Taxes amounted to USD 186 (206) million for the third quarter, representing an effective tax rate of 130 (77) percent. The tax rate was negatively impacted by the impairment of technical goodwill, which is not tax deductible, in addition to currency movements during the quarter.

This resulted in a net loss for the third quarter 2019 of USD 43 million, compared to a net profit of USD 62 million in the previous quarter.

Statement of financial position

(USD MILLION)	Q3 2019	Q2 2019	Q1 2019	Q3 2018*
Total non-current assets	11 149	10 889	10 498	9 928
Total current assets	578	603	619	2 311
Total assets	11 727	11 493	11 117	12 239
Total equity	2 444	2 664	2 799	3 060
Bank and bond debt	2 940	2 635	2 226	2 976
Total abandonment provisions	2 642	2 607	2 561	3 024
Deferred taxes	2 279	1 991	1 867	1 593
Other liabilities	1 423	1 596	1 664	1 586
Total equity and liabilities	11 727	11 493	11 117	12 239
Net interest-bearing debt	3 276	2 907	2 480	2 849
*Restated, see note 1.

At the end of third quarter 2019, total assets amounted to USD 11,727 (11,493) million, of which current assets were USD 578 (603) million.

Equity amounted to USD 2,444 (2,664) million at the end of the third quarter, corresponding to an equity ratio of 21 (23) percent.

Deferred tax liabilities amounted to USD 2,279 (1,991) million and are detailed in note 9 to the financial statements. The increase in deferred taxes was primarily driven by currency movements in the quarter.

Gross bank and bond debt totalled USD 2,940 (2,635) million, consisting of the DETNOR02 bond of USD 217 million, the AK-ERBP Senior Notes (17/22) of USD 395 million, the AKERBP Senior Notes (18/25) of USD 494 million, the AKERBP Senior Notes (19/24) of USD 741 million, a short term bank loan of USD 15 million and the RCF bank facility of USD 1,077 million, all net of unamortised fees.

At the end of the third quarter, the company had total available liquidity of USD 2.9 (3.3) billion, comprising USD 5 (102) million in cash and cash equivalents, and USD 2.9 (3.2) billion in undrawn credit facilities.

Cash flow

(USD MILLION)	Q3 2019	Q2 2019	Q3 2018	2019 YTD	2018 YTD
Cash flow from operations	382	387	697	1 360	1 911
Cash flow from investments	-585	-541	-457	-1 637	-1 237
Cash flow from financing	106	141	-163	239	-775
Net change in cash & cash equivalents	-96	-13	78	-39	-102
Cash and cash equivalents	5	102	127	5	127

Net cash flow from operating activities was USD 382 (387) million. Revenues were USD 723 million, down from USD 785 million in the second quarter due to lower oil and gas prices, partly mitigated by an increase in sold volumes. Taxes paid were USD 106 (208) million.

Net cash flow from investment activities was USD -585 (-541) million, of which investments in fixed assets amounted to USD 435 (414) million for the quarter, mainly related to the Valhall Flank West and Johan Sverdrup developments.

Investments in capitalized exploration were USD 115 (87) million, and payments for decommissioning activities amounted to USD 35 (40) million in the quarter.

Net cash flow from financing activities totalled USD 106 (141) million, reflecting USD 315 million of drawdown on debt, dividend disbursements, payments on lease debt and sale of treasury shares as part of the company's annual share saving plan.

Risk management

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

At the end of the third quarter 2019, the company's inventory of oil put options amounted to 1.7 million barrels, covering approximately 45 percent of the expected oil production in the fourth quarter, after tax, at an average strike price of USD 58 per barrel. The average premium paid for these options is USD 1.53 per barrel. No longer-dated options had been purchased at the time of this report.

Dividends

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

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

On 9 August 2019, the company disbursed dividends of USD 187.5 million, corresponding to USD 0.5207 per share. So far in 2019, USD 562.5 million in dividends have been distributed.

On 21 October 2019, the Board of Directors declared a dividend of USD 0.5207 per share, to be disbursed on or around 8 November 2019, implying total annual dividends of USD 750 million.

OPERATIONAL REVIEW

Aker BP's net production was 13.4 (11.6) mmboe in the third quarter of 2019, corresponding to 146.1 (127.3) mboepd. Due to underlift in the quarter, net sold volume represented 143.3 (140.7) mboepd. The average realized liquids price was USD 62.0 (69.3) per barrel, while the average realized gas price was USD 0.16 (0.16) per scm.

Alvheim Area

Key figures	Aker BP interest	Q3 2019	Q2 2019	Q1 2019	Q4 2018
Production, boepd
Alvheim	65 %	36 826	39 943	43 478	43 406
Bøyla	65 %	4 490	2 364	1 829	2 039
Vilje	46.904 %	-	2 300	3 756	3 257
Volund	65 %	10 088	8 518	7 757	9 655
Total production		51 403	53 125	56 820	58 357
Production efficiency		96 %	97 %	97 %	98 %

Third quarter production from the Alvheim area was 51.4 mboepd net to Aker BP, down three percent from the previous quarter. This reduction was mainly due to the MWA incident which was discovered early June and described in the second quarter report. This caused a slightly lower production efficiency at 96 percent as Vilje and East Kameleon were kept shutin during the quarter. In addition, the base production natural decline continued, but was partly offset by the Frosk Test well start-up late August.

The Skogul drilling activity started in July and was suspended after setting the multi-lateral liner into the reservoir, due to the uncertain availability of the Vilje flowline in time for a clean-up of the Skogul well after drilling. The rig will return to Skogul during the fourth quarter 2019. The project is on track to commence production in the first quarter 2020.

The Rumpetroll exploration well resulted in a non-commercial gas discovery with preliminary estimated volumes between 4 and 11 mmboe. In addition, three geo pilot wells were drilled in the Alvheim core area; Kameleon and Kneler. These wells are used to de-risk future infill opportunities in the field.

In the third quarter, Alvheim delivered stable operations and excellent HSSE performance with no reported incidents or spills. The main focus area was the repairs and testing of the MWA system. All the risers have now been successfully tested for leakages. No changes have been identified through leak, flow and electrical testing of the dynamical umbilical and the Mid Water Arch has been placed in a level position. Permanent tether and connection installation is now well under way.

Valhall Area

Key figures	Aker BP interest	Q3 2019	Q2 2019	Q1 2019	Q4 2018
Production, boepd
Valhall	90 %	39 403	23 896	45 156	38 816
Hod	90 %	880	618	677	802
Total production		40 283	24 514	45 833	39 618
Production efficiency		87 %	53 %	94 %	91 %

Third quarter production from the Valhall area was 40.3 mboepd net to Aker BP. This was 64 percent higher than the previous quarter, however below plan mainly due to delays in the stimulation program and consequently start of production from new wells at Valhall following the planned maintenance shutdown in June. The delay has no impact on reserves. These stimulation activities, as well as the startup of new wells at Valhall, are expected to contribute to significant production growth from the field over the coming quarters.

Stimulation operations have been performed at the southern flank and the field center in order to bring new wells on stream. A second stimulation vessel was contracted in order to mitigate delays in the stimulation program. Slot recovery commenced on the field center in preparation for drilling operations and development of the lower Hod formation.

At Valhall Flank West, the first two wells were successfully drilled and completed during the quarter. These wells are now awaiting stimulation before the start-up of production. As a part of the Valhall strategy to continuously identify and mature new targets in order to maximize recovery and value from the field, the partnership has sanctioned two infill wells on the Valhall Flank West which will be drilled back-to-back with the six wells originally planned.

Ula Area

Key figures	Aker BP interest	Q3 2019	Q2 2019	Q1 2019	Q4 2018
Production, boepd
Ula	80 %	4 751	2 811	6 185	5 784
Tambar	55 %	2 531	1 455	1 916	2 572
Oda	15 %	1 280	1 949	102	-
Total production		8 562	6 214	8 203	8 356
Production efficiency		76 %	46 %	75 %	66 %

Third quarter production from the Ula area was 8.6 mboepd net to Aker BP, up almost 40 percent from the previous quarter. Production returned to normal following the planned onemonth maintenance shutdown in June and has increased further due to re-start of the multiphase pump on Tambar at the end of August.

The Ula producer that ceased to flow in April has been scheduled for re-drill during the first half of 2020. The drilling rig Maersk Integrator has been in operation at Ula since mid-July and has completed slot recovery on one well and is progressing slot recovery on another. The rig programme continues until third quarter next year.

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

Skarv Area

Key figures	Aker BP interest	Q3 2019	Q2 2019	Q1 2019	Q4 2018
Production, boepd
Total production	23.835 %	21 717	22 657	22 558	23 454
Production efficiency		98 %	98 %	91 %	93 %

Third quarter production from the Skarv area was 21.7 mboepd net to Aker BP, down four percent from the previous quarter. Production efficiency for the quarter was 98 percent. The third quarter was characterized by stable operations and production. An annual emergency shutdown test was conducted in late September.

The Ørn exploration well, located 20 kilometers northwest of the Skarv installation, was successfully completed during the quarter. Preliminary estimates place the size of the discovery between 50-88 mmboe. Drilling of the Shrek prospect, also in the Skarv area, started in August and has in early October been concluded as an oil and gas discovery. The preliminary estimated size of the discovery is 19-38 mmboe.

Phase 1 of the Ærfugl development project is progressing according to plan. Offshore modification work is ongoing, and the structure installation campaign was completed during the quarter. The drilling campaign is scheduled to start in 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 close to completion. Production start is planned for the fourth quarter 2020.

Ærfugl phase 2 is also progressing as planned, with ongoing detailed engineering (FEED). The final investment decision is planned by the end of this year.

Ivar Aasen

Key figures	Aker BP interest	Q3 2019	Q2 2019	Q1 2019	Q4 2018
Production, boepd
Total production	34.7862 %	22 481	19 069	22 539	23 343
Production efficiency		94 %	87 %	98 %	94 %

The production from Ivar Aasen was 22.5 mboepd net to Aker BP, up 18 percent from the previous quarter. Production efficiency was negatively impacted by the failure of pumps in the produced water treatment system and the repair of the Edvard Grieg gas turbine, but still increased from 87 percent in the second quarter to 94 percent in the third quarter.

Start-up of a new well contributed positively to production during the quarter. In addition, a second well in the 2019 drilling campaign was successfully finalised and commenced production on 25 September.

Johan Sverdrup

The production from Phase 1 of the Johan Sverdrup development project started safely on 5 October, more than two months ahead of the schedule in the Plan for Development and Operations and NOK 40 billion below budget.

Tie-back operations of the eight pre-drilled oil production wells was nearly completed during the quarter. These predrilled wells will be put into production one by one after startup. The first new production well will be drilled late in the fourth quarter.

Phase 2 of the Johan Sverdrup development is also progressing well and was approximately 15 percent complete by the end of the third quarter. All planned preparatory work on the riser and utilities platform at the field centre was completed safely and on schedule prior to production start.

North of Alvheim and Krafla-Askja (NOAKA)

The North of Alvheim and Krafla-Askja ("NOAKA") area consists of the discoveries Frigg Gamma Delta, Langfjellet, Liatårnet, Frøy, Fulla, Frigg, Rind and Krafla-Askja. Including the preliminary volume estimates from the recent Liatårnet discovery, the gross resources in the area are estimated to be in the order of 700 mmboe.

The recent Liatårnet discovery is estimated to hold 80-200 mmboe of recoverable resources. Further data acquisition and analysis will be undertaken to determine the drainage strategy and recovery factor for the discovery, and the company is aiming for an appraisal well in 2020. Aker BP's ambition is to include Liatårnet in the resource base for an area development.

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

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 NOAKA area with the PQ concept. This concept 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.

EXPLORATION

Total exploration spend in the third quarter was USD 144 (119) million. Of this, USD 70 million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees, field evaluation and G&G costs.

As previously reported in the second quarter report, the Liatårnet exploration well in the NOAKA area proved oil with a gross resource estimate of 80-200 mmboe. Further data acquisition and analysis will be undertaken to determine the drainage strategy and recovery factor for the discovery. An appraisal well is planned to be drilled early in 2020. Aker BP is the operator and holds 90.26 percent interest in the licence.

The Ørn exploration well was successfully completed during the third quarter. The well encountered a total gas column of 40 meters. Preliminary estimates place the size of the discovery between 50-88 mmboe. The discovery is located 20 kilometers northwest of the Skarv installation. Aker BP is partner in the licence with a 30 percent interest.

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

In the Alvheim area, the Rumpetroll exploration well was completed in July. The well encountered gas and traces of petroleum. Preliminary estimates suggest the size of the discovery to be between 4-11 mmboe. The gas discovery is considered non-commercial, however extensive data acquisition and sampling have been conducted in order to increase the understanding of the injectite play in the area. Aker BP is the operator and holds 60 percent interest in the licence.

The Klaff exploration well was drilled about one kilometer west of the Johan Sverdrup field in the North Sea. Pending new information and interpretation of collected data, the preliminary classification is that the well is dry. Aker BP is partner in the licence with 22 percent interest.

During the third quarter the company also drilled and completed two exploration wells on the Vågar and Nipa prospects, both concluded as dry.

HEALTH, SAFETY, SECURITY AND THE ENVIRONMENT

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

KEY HSSE INDICATORS	UNIT	Q3 2019	Q2 2019	Q1 2019	Q4 2018
Total recordable injury frequency (TRIF)	Per mill. exp. hours	2.9	4.0	3.1	3.4
Serious incident frequency (SIF)	Per mill. exp. hours	0.4	0.8	0.4	0.5
Loss of primary containment (LOPC)	Count	0	0	0	0
Process safety events Tier 1 and 2	Count	0	0	0	0
CO2 emissions intensity	Kg CO2/boe	8.1	8.2	7.8	7.6

A discrepancy between Ivar Aasen's reported discharge and the field discharge permit was identified during an inspection from the Norwegian Environment Agency (NEA) in September 2019. The company has received an improvement order from the NEA to investigate the environmental consequences of the discharge volumes in the updated Application for Discharge, submitted by the company in July 2019, and to describe corrective measures to reduce discharge from the sea water system.

Aker BP is working systematically to address the issues raised by the NEA. The company has also initiated an internal investigation to look at the monitoring and follow-up of discharge permits.

OUTLOOK

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

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

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

• Production of ~155mboepd, around the low end of the previously communicated range of 155-160 mboepd mainly due to the delays in the stimulation of new wells at Valhall (described above)
• Capex of USD 1.6-1.7 billion
• Exploration spend of USD ~550 million
• Abandonment spend of USD ~100 million
• Production cost of around USD 12.5 per boe²
• 1 The majority of the company's cost elements (both capex and production cost) are denominated in NOK. The estimated USD amounts are based on an USDNOK exchange rate of 8.5.
• 2 Excluding costs related to repairs of the Alvheim MWA.

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. So far in 2019, USD 562.5 million in dividends has been distributed.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT

		Group
		Q3 Q2		Q3	01.01.-30.09.
				Restated		Restated
(USD 1 000)	Note	2019	2019	2018	2019	2018
Petroleum revenues		720 930	780 071	947 252	2 359 106	2 822 108
Other operating income		2 408	4 744	18 547	-14 690	13 314
Total income	2	723 338	784 816	965 799	2 344 416	2 835 422
Production costs	3	167 267	198 320	170 090	566 049	515 902
Exploration expenses	4	70 213	60 261	93 519	220 833	223 450
Depreciation	6	205 867	167 889	188 525	556 858	556 475
Impairments	5, 6	78 376	-	-	147 317	-
Other operating expenses		6 038	3 882	4 334	16 778	9 299
Total operating expenses		527 760	430 352	456 468	1 507 836	1 305 125
Operating profit		195 578	354 464	509 331	836 579	1 530 297
Interest income		3 353	6 735	7 914	16 152	18 820
Other financial income		52 846	6 872	34 130	50 197	74 982
Interest expenses		9 464	15 532	28 196	38 825	91 522
Other financial expenses		99 445	84 307	71 717	203 847	128 880
Net financial items	8	-52 710	-86 232	-57 869	-176 323	-126 601
Profit before taxes		142 868	268 232	451 462	660 256	1 403 696
Taxes (+)/tax income (-)	9	186 291	205 734	335 052	630 756	990 795
Net profit/loss		-43 423	62 498	116 410	29 500	412 902
Weighted average no. of shares outstanding basic and diluted		359 772 534	360 059 807	360 113 509	359 980 701	360 113 509
Basic and diluted earnings/loss USD per share		-0.12	0.17	0.32	0.08	1.15

STATEMENT OF COMPREHENSIVE INCOME

		Group
	Q3	Q2	Q3 01.01.-30.09.
			Restated		Restated
(USD 1 000)	Note 2019	2019	2018	2019	2018
Profit/loss for the period	-43 423	62 498	116 410	29 500	412 902
Items which may be reclassified over profit and loss (net of taxes) Currency translation adjustment		- -	6 506	-	9 369
Total comprehensive income in period	-43 423	62 498	122 917	29 500	422 271

STATEMENT OF FINANCIAL POSITION

		Group
				Restated	Restated
(USD 1 000)	Note	30.09.2019	30.06.2019	31.12.2018	30.09.2018
ASSETS
Intangible assets
Goodwill	6	1 712 809	1 791 185	1 860 126	1 860 126
Capitalized exploration expenditures	6	626 995	554 293	427 439	416 097
Other intangible assets	6	1 943 898	1 967 332	2 005 885	1 562 486
Tangible fixed assets
Property, plant and equipment	6	6 613 597	6 299 710	5 746 275	6 038 954
Right-of-use assets	6	215 328	238 879	-	-
Financial assets
Long-term receivables		25 826	27 333	37 597	39 608
Other non-current assets		10 279	10 416	10 388	10 506
Total non-current assets		11 148 732	10 889 148	10 087 710	9 927 777
Inventories
Inventories		94 626	99 205	93 179	82 891
Receivables
Accounts receivable		125 511	124 623	162 798	144 231
Tax receivables	9	-	17 418	11 082	1 607 118
Other short-term receivables	10	352 143	259 518	292 405	345 072
Short-term derivatives	13	728	840	17 253	5 574
Cash and cash equivalents
Cash and cash equivalents	11	5 066	101 828	44 944	126 608
Total current assets		578 073	603 432	621 661	2 311 493
TOTAL ASSETS		11 726 805	11 492 580	10 709 371	12 239 271

STATEMENT OF FINANCIAL POSITION

		Group
			Restated		Restated
(USD 1 000)	Note	30.09.2019	30.06.2019	31.12.2018	30.09.2018
EQUITY AND LIABILITIES
Equity
Share capital		57 056	57 056	57 056	57 056
Share premium		3 637 297	3 637 297	3 637 297	3 637 297
Other equity		-1 250 813	-1 030 555	-717 814	-633 721
Total equity		2 443 539	2 663 797	2 976 539	3 060 631
Non-current liabilities
Deferred taxes	9	2 279 415	1 991 371	1 752 757	1 593 074
Long-term abandonment provision	17	2 496 791	2 528 672	2 447 558	2 887 356
Provisions for other liabilities	12	741	1 161	107 519	119 344
Long-term bonds	15	1 629 890	1 858 665	1 110 488	1 122 220
Long-term derivatives	13	45 292	30 173	26 275	17 169
Long-term lease debt	7	223 616	252 467	-	-
Other interest-bearing debt	16	1 077 485	775 920	907 954	353 605
Current liabilities
Trade creditors		135 115	79 071	105 567	86 620
Short-term bonds	15	217 170	-	-	-
Accrued public charges and indirect taxes		16 829	24 702	25 061	14 582
Tax payable	9	194 991	439 270	551 942	754 344
Short-term derivatives	13	42 199	216	8 783	1 587
Short-term abandonment provision	17	145 229	78 410	105 035	140 875
Short-term lease debt	7	117 455	122 127	-	-
Short-term interest-bearing debt	16	15 000	-	-	1 499 693
Other current liabilities	14	646 049	646 559	583 894	588 170
Total liabilities		9 283 266	8 828 783	7 732 833	9 178 640
TOTAL EQUITY AND LIABILITIES		11 726 805	11 492 580	10 709 371	12 239 271

STATEMENT OF CHANGES IN EQUITY - GROUP

			Other equity
				Other comprehensive income
					Foreign currency
		Share	Other paid-in	Actuarial	translation	Retained	Total other
(USD 1 000)	Share capital	premium	capital	gains/(losses)	reserves*	earnings	equity	Total equity
Equity as of 31.12.2017	57 056	3 637 297	573 083	-89	-90 383	-1 188 366	-705 756	2 988 596
Change of accounting principle**	-	-	-	-	-	-12 736	-12 736	-12 736
Restated equity as of 01.01.2018	57 056	3 637 297	573 083	-89	-90 383	-1 201 102	-718 492	2 975 860
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	-115 491	-1 175 324	-717 814	2 976 539
Dividend distributed	-	-	-	-	-	-375 000	-375 000	-375 000
Profit/loss for the period	-	-	-	-	-	72 923	72 923	72 923
Purchase of treasury shares***	-	-	-	-	-	-10 665	-10 665	-10 665
Equity as of 30.06.2019	57 056	3 637 297	573 083	-81	-115 491	-1 488 066	-1 030 555	2 663 797
Dividend distributed	-	-	-	-	-	-187 500	-187 500	-187 500
Profit/loss for the period	-	-	-	-	-	-43 423	-43 423	-43 423
Sale of treasury shares***	-	-	-	-	-	10 665	10 665	10 665
Equity as of 30.09.2019	57 056	3 637 297	573 083	-81	-115 491	-1 708 324	-1 250 813	2 443 539

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

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

*** The treasury shares are purchased/sold for use in the company's share saving plan.

STATEMENT OF CASH FLOW

		Group
		Q3	Q2	Q3	01.01.-30.09.
				Restated		Restated
(USD 1 000)	Note	2019	2019	2018	2019	2018
CASH FLOW FROM OPERATING ACTIVITIES
Profit before taxes		142 868	268 232	451 462	660 256	1 403 696
Taxes paid	9	-105 561	-208 440	-163 007	-419 931	-266 473
Depreciation	6	205 867	167 889	188 525	556 858	556 475
Net impairment losses	5, 6	78 376	-	-	147 317	-
Accretion expenses	8, 17	30 511	30 419	31 504	90 513	96 656
Interest expenses	8	48 832	53 576	50 278	151 558	143 785
Interest paid		-52 702	-53 580	-48 419	-152 125	-135 956
Changes in derivatives	2, 8	57 214	-8 751	23 252	68 958	6 935
Amortized loan costs	8	4 454	6 112	7 147	17 242	22 866
Amortization of fair value of contracts	14	-	-	14 195	-	42 580
Expensed capitalized dry wells	4, 6	41 905	29 163	29 766	129 142	61 428
Changes in inventories, accounts payable and receivables		59 735	-112 609	-7 584	65 389	2 107
Changes in other current balance sheet items		-129 012	214 626	119 651	44 507	-23 556
NET CASH FLOW FROM OPERATING ACTIVITIES		382 487	386 636	696 772	1 359 684	1 910 542
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields		-35 279	-39 554	-72 266	-95 595	-226 476
Disbursements on investments in fixed assets		-434 580	-414 194	-339 571	-1 212 756	-897 837
Disbursements on investments in capitalized exploration		-115 099	-87 155	-44 795	-328 588	-113 030
Disbursements on investments in licenses		-	-	-	-143	-
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-584 958	-540 903	-456 633	-1 637 083	-1 237 343
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment of short-term debt		15 000	-	-	15 000	-
Net drawdown/repayment of revolving credit facility		299 908	775 314	-	1 075 222	-
Net drawdown/repayment of reserve-based lending facility		-	-1 150 000	-50 000	-950 000	-930 252
Net proceeds from bond issue		-	740 159	-	740 159	492 423
Payments on lease debt related to investments in fixed assets		-25 665	-21 492	-	-63 440	-
Payments on other lease debt		-5 947	-4 758	-	-15 724	-
Paid dividend		-187 500	-187 500	-112 500	-562 500	-337 500
Net purchase/sale of treasury shares		10 665	-10 665	-	-	-
NET CASH FLOW FROM FINANCING ACTIVITIES		106 462	141 057	-162 500	238 717	-775 329
Net change in cash and cash equivalents		-96 009	-13 209	77 639	-38 682	-102 130
Cash and cash equivalents at start of period		101 828	113 680	49 245	44 944	232 504
Effect of exchange rate fluctuation on cash held		-753	1 358	-276	-1 196	-3 766
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	5 066	101 828	126 608	5 066	126 608

NOTES

(All figures in USD 1 000 unless otherwise stated)

These condensed consolidated interim financial statements ("interim financial statements") have been prepared in accordance with the International Financial Reporting Standards as adopted by the EU ("IFRS") IAS 34 "Interim Financial Reporting", thus the interim financial statements do not include all information required by IFRS and should be read in conjunction with the group's annual financial statements as at 31 December 2018. The interim financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the financial position, results of operations and cash flows for the dates and interim periods presented. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. These interim financial statements have been subject to a review in accordance with the Intenational Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity.

These interim financial statements were authorised for issue by the company's Board of Directors on 21 October 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 are in line with the description provided in the group's annual financial statements for 2018. The impact on the balance sheet is presented on separate balance sheet items, and further details are provided in the notes, in particular note 6 and 7. The group has applied the modified retrospective approach with no restatement of comparative figures.

Change in accounting principles for revenue recognition

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

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

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

The significant judgements made by management in applying the group's accounting policies and the key sources of estimation uncertainty are in all material respect the same as those that applied to the annual financial statements as at 31 December 2018.

Note 2 Income

	Group
	Q3	Q2 Q3			01.01.-30.09.
			Restated		Restated
Breakdown of petroleum revenues (USD 1 000)	2019	2019	2018	2019	2018
Sales of liquids	646 837	710 913	807 052	2 098 530	2 391 911
Sales of gas	69 864	64 978	134 791	248 769	415 187
Tariff income	4 229	4 181	5 408	11 807	15 010
Total petroleum revenues	720 930	780 071	947 252	2 359 106	2 822 108
Sales of liquids (boe 1 000)	10 437	10 264	10 816	32 294	33 312
Sales of gas (boe 1 000)	2 743	2 541	2 827	8 272	9 162
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-1 841	-6 710	-4 698	-10 609	-12 131
Unrealized gain/loss (-) on oil derivatives	944	6 654	-822	-16 525	-3 143
Gain on license transactions	-	-	404	-	404
Other income*	3 305	4 801	23 664	12 443	28 183
Total other operating income	2 408	4 744	18 547	-14 690	13 314

* 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

	Q3	Group Q2 Q3			01.01.-30.09.
			Restated		Restated
(USD 1 000)	2019	2019	2018	2019	2018
Total produced volumes (boe 1 000)	13 443	11 585	13 852	39 308	42 489
Production cost based on produced volumes	177 142	177 874	165 466	546 015	502 573
Adjustment for over/underlift (-)	-9 876	20 446	4 623	20 035	13 329
Production cost based on sold volumes	167 267	198 320	170 090	566 049	515 902

Note 4 Exploration expenses

	Group
	Q3	Q2	Q3		01.01.-30.09.
Breakdown of exploration expenses (USD 1 000)	2019	2019	2018	2019	2018
Seismic	5 932	9 767	30 639	16 231	74 151
Area fee	2 668	4 717	2 097	11 959	8 673
Field evaluation	9 987	6 898	22 503	32 809	51 541
Dry well expenses*	41 905	29 163	29 766	129 142	61 428
Other exploration expenses	9 721	9 716	8 512	30 692	27 655
Total exploration expenses	70 213	60 261	93 519	220 833	223 450

* Dry well expenses in Q3 2019 are mainly related to the wells Rumpetroll, Vågar, Klaff and Nipa.

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 Q3 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 30 September 2019. Assumptions regarding oil and gas reserves and future expenditure are made on a consistent basis as described in the 2018 annual financial statements. Discount rate and inflation assumptions are unchanged from Q4 2018.

Oil and gas prices

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

Year	USD/BOE
2019	60.3
2020	56.9
2021	55.6
2022	58.9
From 2023 (in real terms)	65.0

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

Year	GBP/therm
2019	0.45
2020	0.48
2021	0.50
2022	0.49
From 2023 (in real terms)	0.49

Oil and gas reserves

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 percent. For fair value testing, the discount rate used is 10.0 percent.

Currency rates

Year	USD/NOK
2019	9.10
2020	9.09
2021	9.10
2022	8.71
From 2023	7.50

Inflation

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

Impairment testing of assets other than goodwill

The impairment test of assets other than goodwill has been performed prior to the quarterly goodwill impairment test. No impairment/reversal of impairment of assets other than goodwill has been recognized in Q3 2019.

Impairment testing of technical goodwill

For the CGUs Alvheim, Valhall/Hod, Skarv/Ærfugl no impairment is recognized during Q3. For the CGU Ula/Tambar, the impairment charge has been calculated as follows:

(USD 1 000)	Ula/Tambar
Net carrying value	641 279
Recoverable amount	562 903
Impairment charge Q3	78 376

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 Q3 2019, the reduced deferred tax, together with updated cost and production profiles and decrease in the near term oil and gas prices 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.

	Change in goodwill impairment after
Assumption (USD 1 000)	Change	Increase in assumptions	Decrease in assumptions
Oil and gas price	+/- 20%	-78 376	156 867
Production profile (reserves)	+/- 5%	-29 464	29 464
Discount rate	+/- 1% point	17 345	-18 331
Currency rate USD/NOK	+/- 1.0 NOK	-21 937	27 793
Inflation	+/- 1% point	-24 336	21 686

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

Note 6 Tangible fixed assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

Property, plant and equipment		Production	Fixtures and
	Assets under	facilities	fittings, office
(USD 1 000)	development	including wells	machinery	Total
Book value 31.12.2018	2 283 602	3 385 005	77 669	5 746 275
Acquisition cost 31.12.2018	2 283 602	6 086 362	135 061	8 505 025
Additions	742 887	79 363	11 766	834 016
Disposals	-	-	-	-
Reclassification	-141 046	160 753	3 638	23 344
Acquisition cost 30.06.2019	2 885 443	6 326 478	150 465	9 362 385
Accumulated depreciation and impairments 31.12.2018	-	2 701 357	57 392	2 758 750
Depreciation	-	291 384	12 542	303 926
Impairment	-	-	-	-
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 30.06.2019	-	2 992 742	69 934	3 062 676
Book value 30.06.2019	2 885 443	3 333 736	80 531	6 299 710
Acquisition cost 30.06.2019	2 885 443	6 326 478	150 465	9 362 385
Additions	382 517	85 399	6 099	474 015
Disposals	-	-	-	-
Reclassification	-109 896	126 603	1 242	17 949
Acquisition cost 30.09.2019	3 158 063	6 538 480	157 807	9 854 350
Accumulated depreciation and impairments 30.06.2019	-	2 992 742	69 934	3 062 676
Depreciation	-	170 770	7 307	178 077
Impairment	-	-	-	-
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 30.09.2019	-	3 163 512	77 241	3 240 753
Book value 30.09.2019	3 158 063	3 374 968	80 566	6 613 597

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

Right-of-use assets
	Vessels and
(USD 1 000)	Drilling Rigs	Boats	Office	Other	Total
Right-of-use assets at initial recognition 01.01.2019	132 270	76 628	29 593	2 303	240 795
Additions	31 899	-	-	-	31 899
Abandonment activity	1 058	441	-	-	1 499
Reclassification Acquisition cost 30.06.2019	-22 141 140 970	-1 805 74 382	- 29 593	- 2 303	-23 946 247 249
Accumulated depreciation and impairments 31.12.2018	-	-	-	-	-
Depreciation	2 775	1 596	3 910	88	8 369
Impairment	-	-	-	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 30.06.2019	2 775	1 596	3 910	88	8 369
Book value 30.06.2019	138 195	72 786	25 684	2 215	238 879
Acquisition cost 30.06.2019	140 970	74 382	29 593	2 303	247 249
Additions	-	-	-	-	-
Abandonment activity*	990	252	-	-	1 242
Reclassification**	-17 026	-929	-	-	-17 955
Acquisition cost 30.09.2019	122 954	73 202	29 593	2 303	228 052
Accumulated depreciation and impairments 30.06.2019	2 775	1 596	3 910	88	8 369
Depreciation	1 616	741	1 955	44	4 355
Impairment	-	-	-	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2019	4 390	2 337	5 865	132	12 724
Book value 30.09.2019	118 564	70 865	23 729	2 171	215 328

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

** Of which 17 949 reclassified to tangible fixed assets and 5 reclassified to capitalized exploration in line with the activity of the right-of-use asset.

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

INTANGIBLE ASSETS - GROUP

	Other intangible assets
(USD 1 000)	Licences etc.	Software	Total	Exploration wells	Goodwill
Book value 31.12.2018	2 005 885	-	2 005 885	427 439	1 860 126
Acquisition cost 31.12.2018	2 396 290	7 501	2 403 791	427 439	2 738 973
Additions	143	-	143	213 489	-
Disposals/expensed dry wells	-	-	-	87 237	-
Reclassification	-	-	-	602	-
Acquisition cost 30.06.2019	2 396 433	7 501	2 403 934	554 293	2 738 973
Accumulated depreciation and impairments 31.12.2018	390 404	7 501	397 906	-	878 847
Depreciation	38 696	-	38 696	-	-
Impairment	-	-	-	-	68 941
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 30.06.2019	429 101	7 501	436 602	-	947 789
Book value 30.06.2019	1 967 332	-	1 967 332	554 293	1 791 185
Acquisition cost 30.06.2019	2 396 433	7 501	2 403 934	554 293	2 738 973
Additions	-	-	-	115 099	-
Disposals/expensed dry wells	-	-	-	42 401	-
Reclassification	-	-	-	5	-
Acquisition cost 30.09.2019	2 396 433	7 501	2 403 934	626 995	2 738 973
Accumulated depreciation and impairments 30.06.2019	429 101	7 501	436 602	-	947 789
Depreciation	23 435	-	23 435	-	-
Impairment	-	-	-	-	78 376
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2019	452 535	7 501	460 036	-	1 026 165
Book value 30.09.2019	1 943 898	-	1 943 898	626 995	1 712 809

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
	Q3	Q2	Q3	01.01.-30.09.
Depreciation in the income statement (USD 1 000)	2019	2019	2018	2019	2018
Depreciation of tangible fixed assets	178 077	144 399	165 653	482 003	501 922
Depreciation of right-of-use assets	4 355	3 836	-	12 724	-
Depreciation of intangible assets	23 435	19 654	22 872	62 131	54 553
Total depreciation in the income statement	205 867	167 889	188 525	556 858	556 475
Impairment in the income statement (USD 1 000)

Impairment of goodwill	78 376	-	-	147 317	-
Total impairment in the income statement	78 376	-	-	147 317	-

Note 7 Leasing

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

	Group
(USD 1 000)	2019
Operating lease obligation 31.12.2018	1 100 753
Short-term and low value leases	-403 720
Non-lease components excluded	-223 551
Other	-8 574
Nominal lease debt 01.01.2019	464 907
Discounting	-75 075
Lease debt 01.01.2019	389 833
New lease debt recognized in the period	31 899
Payments of lease debt*	-97 602
Interest expense on lease debt	18 438
Currency exchange differences	-1 497
Total lease debt 30.09.2019	341 071

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

Short-term	117 455
Long-term	223 616
Total lease debt	341 071

* Payments of lease debt split by activities (USD 1 000):	Q3	01.01.-30.09.
Investments in fixed assets	30 344	78 146
Abandonment activity	1 532	3 495
Operating expenditures	4 492	12 143
Exploration expenditures	223	1 482
Other income	785	2 336
Total	37 376	97 602

Nominal lease debt maturity breakdown (USD 1 000):

Within one year	136 434
Two to five years	197 124
After five years	64 762
Total	398 319

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

Note 8 Financial items

	Group
	Q3 Q2		Q3	01.01.-30.09.
(USD 1 000)	2019	2019	2018	2019	2018
Interest income	3 353	6 735	7 914	16 152	18 820
Realized gains on derivatives	1 960	2 547	32 757	8 927	69 199
Change in fair value of derivatives	-	4 324	1 373	-	5 783
Net currency gains	50 886	-	-	41 269	-
Total other financial income	52 846	6 872	34 130	50 197	74 982
Interest expenses	43 068	47 360	50 278	133 119	143 785
Interest on lease debt	5 764	6 216	-	18 438	-
Capitalized interest cost, development projects	-43 822	-44 156	-29 229	-129 975	-75 129
Amortized loan costs	4 454	6 112	7 147	17 242	22 866
Total interest expenses	9 464	15 532	28 196	38 825	91 522
Net currency loss	-	9 011	5 752	-	3 861
Realized loss on derivatives	9 619	6 578	10 432	22 891	17 169
Change in fair value of derivatives	58 158	2 227	23 803	52 433	9 575
Accretion expenses	30 511	30 419	31 504	90 513	96 656
Other financial expenses	1 156	36 072	227	38 010	1 619
Total other financial expenses	99 445	84 307	71 717	203 847	128 880
Net financial items	-52 710	-86 232	-57 869	-176 323	-126 601

Note 9 Tax

	Group
	Q3	Q2	Q3	01.01.-30.09.
			Restated		Restated
Tax for the period (USD 1 000)	2019	2019	2018	2019	2018
Current year tax payable	-91 745	77 657	219 486	115 194	670 121
Current year deferred tax change	274 427	122 856	115 899	507 969	342 772
Prior period adjustments	3 609	5 221	-333	7 593	-22 098
Total tax (+)/tax income (-)	186 291	205 734	335 052	630 756	990 795

		Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	30.09.2019	30.09.2018	31.12.2018
Tax receivable/payable at 01.01.	-540 860	1 234 850	1 234 850
Current year tax (-)/tax receivable (+)	-115 194	-670 121	-803 396
Taxes receivable/payable related to acquisitions/sales	520	-	4 387
Net tax payment (+)/tax refund (-)	419 931	266 473	-907 312
Prior period adjustments and change in estimate of uncertain tax positions	26 948	12 131	-30 269
Currency movements of tax receivable/payable	13 663	9 441	-39 119
Total net tax receivable (+)/tax payable (-)	-194 991	852 774	-540 860
Tax receivable included as current assets (+)	-	1 607 118	11 082
Tax payable included as current liabilities (-)	-194 991	-754 344	-551 942

	Group
		Restated	Restated
Deferred tax (-)/deferred tax asset (+) (USD 1 000)	30.09.2019	30.09.2018	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	-507 969	-342 772	-524 645
Prior period adjustment	-18 689	11 691	33 912
Deferred tax charged to OCI and equity	-	-	-30
Net deferred tax (-)/deferred tax asset (+)	-2 279 415	-1 593 074	-1 752 757

			Group
	Q3	Q2	Q3	01.01.-30.09.
			Restated		Restated
Reconciliation of tax expense (USD 1 000)	2019	2019	2018	2019	2018
78% tax rate on profit before tax	111 437	209 221	352 141	515 000	1 094 883
Tax effect of uplift	-31 901	-33 012	-32 382	-95 977	-97 236
Permanent difference on impairment	61 133	-	-	114 907	-
Foreign currency translation of NOK monetary items	-38 200	6 706	4 486	-31 022	3 012
Foreign currency translation of USD monetary items	-131 447	25 541	2 148	-104 768	9 315
Tax effect of financial and other 22%/23% items	78 165	11 486	13 916	107 169	8 900
Currency movements of tax balances**	135 025	-23 757	-8 779	110 945	-10 394
Other permanent differences, prior period adjustments and change in estimate of	2 078	9 550	3 524	14 501	-17 685
uncertain tax positions	-	-	-	-	-
Total tax (+)/tax income (-)	186 291	205 734	335 052	630 756	990 795

* 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 percent from 1 January 2019. The rate for special tax changed from the same date from 55 to 56 percent.

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

Note 10 Other short-term receivables

	Group
			Restated	Restated
(USD 1 000)	30.09.2019	30.06.2019	31.12.2018	30.09.2018
Prepayments	64 344	64 682	64 004	56 607
VAT receivable	7 698	6 086	8 871	10 228
Underlift of petroleum*	29 966	26 409	54 924	51 354
Accrued income from sale of petroleum products	142 692	60 066	52 825	103 718
Other receivables, mainly from licenses	107 443	102 275	111 781	123 164
Total other short-term receivables	352 143	259 518	292 405	345 072

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

Note 11 Cash and cash equivalents

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

	Group
Breakdown of cash and cash equivalents (USD 1 000)	30.09.2019	30.06.2019	31.12.2018	30.09.2018
Bank deposits	5 066	101 828	44 944	126 608
Cash and cash equivalents	5 066	101 828	44 944	126 608
Unused RCF/RBL facility (see note 16)	2 900 000	3 200 000	3 050 000	3 600 000

Note 12 Provisions for other liabilities

	Group
Breakdown of provisions for other liabilities (USD 1 000)	30.09.2019	30.06.2019	31.12.2018	30.09.2018
Fair value of contracts assumed in acquisitions*	-	-	106 040	116 789
Other long term liabilities	741	1 161	1 480	2 555
Total provisions for other liabilities	741	1 161	107 519	119 344

* 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)	30.09.2019	30.06.2019	31.12.2018	30.09.2018
Unrealized gain on commodity derivatives	728	-	17 253	-
Unrealized gain currency contracts	-	840	-	5 574
Short-term derivatives included in assets	728	840	17 253	5 574
Unrealized losses on commodity derivatives	-	-	-	9 247
Unrealized losses interest rate swaps	45 292	30 173	26 275	7 922
Long-term derivatives included in liabilities	45 292	30 173	26 275	17 169
Unrealized losses commodity derivatives	-	216	-	1 587
Unrealized losses currency contracts	42 199	-	8 783	-
Short-term derivatives included in liabilities	42 199	216	8 783	1 587
Total derivatives included in liabilities	87 491	30 389	35 058	18 756

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)	30.09.2019	30.06.2019	31.12.2018	30.09.2018
Current liabilities against JV partners	55 588	49 242	22 779	29 052
Share of other current liabilities in licences	406 884	412 322	309 260	338 791
Overlift of petroleum*	5 132	11 450	10 055	15 369
Fair value of contracts assumed in acquisitions**	-	-	42 998	47 773
Other current liabilities***	178 445	173 545	198 801	157 186
Total other current liabilities	646 049	646 559	583 894	588 170

* 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)	30.09.2019	30.06.2019	31.12.2018	30.09.2018
DETNOR02 Senior unsecured bond*	-	230 296	223 839	236 259
AKERBP – Senior Notes (17/22)**	394 635	394 225	393 301	392 918
AKERBP – Senior Notes (18/25)***	494 206	493 943	493 349	493 044
AKERBP – Senior Notes (19/24)****	741 048	740 201	-	-
Long-term bonds	1 629 890	1 858 665	1 110 488	1 122 220
DETNOR02 Senior unsecured bond*	217 170	-	-	-
Short-term bonds	217 170	-	-	-

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

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

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

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

Note 16 Other interest-bearing debt

		Group
(USD 1 000)	30.09.2019	30.06.2019	31.12.2018	30.09.2018
Reserve-based lending facility	-	-	907 954	353 605
Revolving credit facility	1 077 485	775 920	-	-
Long-term interest-bearing debt	1 077 485	775 920	907 954	353 605
Money market loan*	15 000	-	-	-
Bridge facility	-	-	-	1 499 693
Short-term interest-bearing debt	15 000	-	-	1 499 693

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

In May 2019, the group refinanced the Reserve-based lending facility (RBL) by closing a USD 4.0 billion senior unsecured Revolving Credit Facility (RCF). The RCF comprise a 3 year USD 2.0 billion Working Capital Facility and a USD 2.0 billion 5-year Liquidity Facility. The Liquidity Facility includes two 12-month extension options. The interest rate is LIBOR plus a margin of 1.25 - 1.70 percent based on drawn amount. In addition, a commitment fee of 35 percent of applicable margin is paid on the undrawn facility. The financial covenants are as follows:

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

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

The financial covenants in the group's current debt facilities exclude the effects from IFRS 16, and therefore cannot be directly derived from the group's financial statements.

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)	30.09.2019	30.09.2018	31.12.2018
Provisions as of 1 January	2 552 592	3 043 884	3 043 884
Incurred cost removal	-98 336	-185 158	-201 227
Accretion expense - present value calculation	90 513	96 656	128 737
Changed net present value from changed discount rate	-	-	-277 081
Change in estimates and incurred liabilities on new drilling and installations	97 251	72 850	-141 721
Total provision for abandonment liabilities	2 642 019	3 028 232	2 552 592
Break down of the provision to short-term and long-term liabilities
Short-term	145 229	140 875	105 035
Long-term	2 496 791	2 887 356	2 447 558
Total provision for abandonment liabilities	2 642 019	3 028 232	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 as at 30 September 2019 assume an inflation rate of 2.0 percent and a nominal discount rate before tax of between 4.46 percent and 5.01 percent. The credit margin included in the discount rate is 2.00 percent.

Note 18 Contingent liabilities and assets

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

The Alvheim riser configuration consists of three buoyant Mid Water Assemblies ("MWA"), and during an annual ROV inspection on 5 June it was discovered that one of the tether frame connections on the eastern MWA had failed. The company has initiated a process to pursue insurance recovery for the costs related to the repairs currently recorded as production cost. In the third quarter, costs related to repairs amounted to approximately USD 14 million net to Aker BP. The insurance recovery is considered a contingent asset that does not meet the recognition criteria under IAS 37.

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:	30.09.2019	30.06.2019
Alvheim	65.000%	65.000 %
Bøyla	65.000%	65.000 %
Hod	90.000%	90.000 %
Ivar Aasen Unit	34.786%	34.786 %
Jette Unit	70.000%	70.000 %
Valhall	90.000%	90.000 %
Vilje	46.904%	46.904 %
Volund	65.000%	65.000 %
Tambar	55.000%	55.000 %
Tambar Øst	46.200%	46.200 %
Ula	80.000%	80.000 %
Skarv	23.835%	23.835 %

Production licences in which Aker BP is the operator:
Licence:	30.09.2019	30.06.2019 Licence:	30.09.2019	30.06.2019
PL 001B	35.000%	35.000 % PL 777D	40.000%	40.000 %
PL 006B	90.000%	90.000 % PL 784	40.000%	40.000 %
PL 019	80.000%	80.000 % PL 790*	0.000%	30.000 %
PL 019C	80.000%	80.000 % PL 814	40.000%	40.000 %
PL 019E	80.000%	80.000 % PL 818	40.000%	40.000 %
PL 019H	80.000%	80.000 % PL 818B	40.000%	40.000 %
PL 026	92.130%	92.130 % PL 822S	60.000%	60.000 %
PL 026B	90.260%	90.260 % PL 839	23.835%	23.835 %
PL 027D	100.000%	100.000 % PL 843	40.000%	40.000 %
PL 028B	35.000%	35.000 % PL 858	40.000%	40.000 %
PL 033	90.000%	90.000 % PL 861*	0.000%	50.000 %
PL 033B	90.000%	90.000 % PL 867	40.000%	40.000 %
PL 036C	65.000%	65.000 % PL 868	60.000%	60.000 %
PL 036D	46.904%	46.904 % PL 869	60.000%	60.000 %
PL 036E	64.000%	64.000 % PL 873	40.000%	40.000 %
PL 065	55.000%	55.000 % PL 874	90.260%	90.260 %
PL 065B	55.000%	55.000 % PL 893	60.000%	60.000 %
PL 088BS	65.000%	65.000 % PL 906	60.000%	60.000 %
PL 102D	50.000%	50.000 % PL 907	60.000%	60.000 %
PL 102F	50.000%	50.000 % PL 914S	34.786%	34.786 %
PL 102G	50.000%	50.000 % PL 915	35.000%	35.000 %
PL 102H	50.000%	50.000 % PL 916	40.000%	40.000 %
PL 127C	100.000%	100.000 % PL 919	65.000%	65.000 %
PL 146	77.800%	77.800 % PL 932	60.000%	60.000 %
PL 150	65.000%	65.000 % PL 941	50.000%	50.000 %
PL 159D	23.835%	23.835 % PL 948	40.000%	40.000 %
PL 169C	50.000%	50.000 % PL 951	40.000%	40.000 %
PL 203	65.000%	65.000 % PL 963	70.000%	70.000 %
PL 212	30.000%	30.000 % PL 964	40.000%	40.000 %
PL 212B	30.000%	30.000 % PL 977	60.000%	60.000 %
PL 212E	30.000%	30.000 % PL 978	60.000%	60.000 %
PL 242	35.000%	35.000 % PL 979	60.000%	60.000 %
	50.000%		30.000%
PL 261	30.000%	50.000 % PL 986	60.000%	30.000 %
PL 262	55.000%	30.000 % PL 1005	60.000%	60.000 %
PL 300	77.800%	55.000 % PL 1008	40.000%	60.000 %
PL 333	65.000%	77.800 % PL 1022	40.000%	40.000 %
PL 340	65.000%	65.000 % PL 1026	50.000%	40.000 %
PL 340BS	90.260%	65.000 % PL 1028	50.000%	50.000 %
PL 364	90.260%	90.260 % PL 1030		50.000 %
PL 442		90.260 %
PL 442B	90.260%	90.260 %
PL 460	65.000%	65.000 %
PL 504	47.593%	47.593 %
PL 685	40.000%	40.000 %
PL 748*	0.000%	50.000 %
PL 748B*	0.000%	50.000 %
PL 762	20.000%	20.000 %
PL 777	40.000%	40.000 %
PL 777B	40.000%	40.000 %
PL 777C	40.000%	40.000 %
Number of licenses in which Aker BP is the operator			85	89

* Relinquished license or Aker BP has withdrawn from the license

Fields non-operated:	30.09.2019	30.06.2019
Atla	10.000%	10.000 %
Enoch	2.000%	2.000 %
Gina Krog	3.300%	3.300 %
	11.573%
Oda	15.000%	15.000 %
Johan Sverdrup		11.573 %

Production licences in which Aker BP is a partner:
Licence:	30.09.2019	30.06.2019 Licence:	30.09.2019	30.06.2019
PL 006C	15.000%	15.000 % PL 838	30.000%	30.000 %
PL 006E	15.000%	15.000 % PL 838B	30.000%	30.000 %
PL 006F	15.000%	15.000 % PL 844	20.000%	20.000 %
PL 029B	20.000%	20.000 % PL 852	40.000%	40.000 %
PL 035	50.000%	50.000 % PL 852B	40.000%	40.000 %
PL 035C	50.000%	50.000 % PL 852C	40.000%	40.000 %
PL 048D	10.000%	10.000 % PL 857	20.000%	20.000 %
PL 102C	10.000%	10.000 % PL 862	50.000%	50.000 %
PL 127	50.000%	50.000 % PL 863	40.000%	40.000 %
PL 127B	50.000%	50.000 % PL 863B	40.000%	40.000 %
PL 220	15.000%	15.000 % PL 864	20.000%	20.000 %
PL 265	20.000%	20.000 % PL 892	30.000%	30.000 %
PL 272	50.000%	50.000 % PL 902	30.000%	30.000 %
PL 272B	50.000%	50.000 % PL 902B	30.000%	30.000 %
PL 405	15.000%	15.000 % PL 942	30.000%	30.000 %
PL 457BS	40.000%	40.000 % PL 954	20.000%	20.000 %
PL 492	60.000%	60.000 % PL 955	30.000%	30.000 %
PL 502	22.222%	22.222 % PL 961	30.000%	30.000 %
PL 533	35.000%	35.000 % PL 962	20.000%	20.000 %
PL 533B	35.000%	35.000 % PL 966	30.000%	30.000 %
PL 554	30.000%	30.000 % PL 968	20.000%	20.000 %
PL 554B	30.000%	30.000 % PL 981	40.000%	40.000 %
PL 554C	30.000%	30.000 % PL 982	40.000%	40.000 %
PL 554D	30.000%	30.000 % PL 985	20.000%	20.000 %
PL 615	4.000%	4.000 % PL 1031	20.000%	20.000 %
PL 615B	4.000%	4.000 %
PL 719	20.000%	20.000 %
PL 721*	0.000%	40.000 %
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%	20.000 %
PL 810*	0.000%	30.000 %
PL 810B*	0.000%	30.000 %
PL 811	20.000%	20.000 %
Number of licenses in which Aker BP is the partner			58	61

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

Note 21 Results from previous interim reports

	2019			2018
				Restated
(USD 1 000)	Q3	Q2	Q1	Q4	Q3
Total income	723 338	784 816	836 262	916 200	965 799
Production costs	167 267	198 320	200 462	177 683	170 090
Exploration expenses	70 213	60 261	90 359	72 458	93 519
Depreciation	205 867	167 889	183 102	195 962	188 526
Impairments	78 376	-	68 941	20 172	-
Other operating expenses	6 038	3 882	6 859	7 739	4 334
Total operating expenses	527 760	430 352	549 724	474 015	456 468
Operating profit/loss	195 578	354 464	286 538	442 185	509 331
Net financial items	-52 710	-86 232	-37 381	-43 905	-57 869
Profit/loss before taxes	142 868	268 232	249 157	398 280	451 462
Taxes (+)/tax income (-)	186 291	205 734	238 731	335 403	335 052
Net profit/loss	-43 423	62 498	10 425	62 876	116 410

	2019			2018
(boe 1 000)	Q3	Q2	Q1	Q4	Q3
Sold volumes
Liquids Gas	10 437 2 743	10 264 2 541	11 594 2 988	11 018 2 921	10 816 2 827

	2019 2018
				Restated
(USD 1 000)	Q3	Q2	Q1	Q4	Q3
Assets
Goodwill	1 712 809	1 791 185	1 791 185	1 860 126	1 860 126
Other intangible assets	2 570 893	2 521 625	2 483 080	2 433 324	1 978 583
Property, plant and equipment	6 613 597	6 299 710	5 953 972	5 746 275	6 038 954
Right-of-use asset	215 328	238 879	225 244	-	-
Receivables and other assets	609 112	521 934	533 949	613 620	627 882
Calculated tax receivables (short)	-	17 418	15 473	11 082	1 607 118
Cash and cash equivalents	5 066	101 828	113 680	44 944	126 608
Total assets	11 726 805	11 492 580	11 116 582	10 709 371	12 239 271
Equity and liabilities
Equity	2 443 539	2 663 797	2 799 464	2 976 539	3 060 631
Other provisions for liabilities incl. P&A (long)	2 542 824	2 560 005	2 504 723	2 581 352	3 023 870
Deferred tax	2 279 415	1 991 371	1 867 333	1 752 757	1 593 074
Bonds and bank debt	2 939 545	2 634 585	2 225 589	2 018 443	2 975 518
Lease debt	341 071	374 595	368 553	-	-
Other current liabilities incl. P&A	985 421	828 958	784 164	828 340	831 834
Tax payable	194 991	439 270	566 755	551 942	754 344
Total equity and liabilities	11 726 805	11 492 580	11 116 582	10 709 371	12 239 271

Alternative performance measures

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

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

Operating profit 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 divided by twelve months rolling EBITDAX, excluding impacts from IFRS 16*

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***

* The definition of Leverage ratio has been adjusted to comply with the financial covenants in the group's current debt facilities. Both leasing debt and IFRS 16 impacts on EBITDAX are thus excluded when calculating this ratio.

** Includes leasing debt from Q1 2019

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

KPMG AS Sørkedalsveien 6 Postboks 7000 Majorstuen 0306 Oslo

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

To the Board of Directors of Aker BP ASA

Report on Review of Interim Financial Information

Introduction

We have reviewed the accompanying condensed consolidated statements of financial position of Aker BP ASA as at 30 September 2019, 30 September 2018 and 30 June 2019, and the related condensed consolidated income statements and statements of comprehensive income, changes in equity and cash flows for the nine-month periods ended 30 September 2019 and 2018, and the threemonth periods ended 30 September 2019, 30 September 2018 and 30 June 2019, and notes to the condensed consolidated interim financial information (the "condensed consolidated interim financial information"). Management is responsible for the preparation and presentation of this condensed consolidated interim financial information in accordance with International Accounting Standard 34, Interim Financial Reporting as adopted by the EU. Our responsibility is to express a conclusion on this condensed consolidated interim financial information based on our review.

Scope of Review

We conducted our review in accordance with the International Standard on Review Engagements 2410, Review of Interim Financial Information Performed by the Independent Auditor of the Entity.

A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing, and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the accompanying condensed consolidated interim financial information as at 30 September 2019, 30 September 2018 and 30 June 2019 and for the nine-month periods ended 30 September 2019 and 2018, and the three-month periods ended 30 September 2019, 30 September 2018 and 30 June 2019, is not prepared, in all material respects, in accordance with International Accounting Standard 34, Interim Financial Reporting as adopted by the EU.

Other matters

Our report does not extend to the summary financial information for interim periods included in note 21 which is not a required disclosure under International Accounting Standard 34 Interim Financial Reporting.

Oslo, 21 October 2019 KPMG AS

Mona Irene Larsen State Authorised Public Accountant (Norway)

	ffices in:
--	------------	--

ffiliated	Oslo	Elverum	Mo i Rana	Stord
	Alta	Finnsnes	Molde	Straume
	Arendal	Hamar	Skien	Tromsø
	Bergen	Haugesund	Sandefjord	Trondheim
	Bodø	Knarvik	Sandnessjøen	Tynset
	Drammen	Kristiansand	Stavanger	Alesund

35 · Aker BP Quarterly Report Q3 2019

AKER BP ASA

Fornebuporten, Building B Oksenøyveien 10 1366 Lysaker

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

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

www.akerbp.com