Aker BP

Quarterly Report • Jul 12, 2019

QUARTERLY AND HALF YEAR REPORT Q2 2019

SECOND QUARTER 2019 SUMMARY

Aker BP reported total income of USD 785 million and operating profit of USD 354 million for the second quarter 2019. Net profit was 62 million USD. All field developments are progressing as planned, and the company's exploration program has been highly successful so far this year. The company paid a dividend of USD 187.5 (USD 0.52 per share) in the quarter.

The company's net production in the second quarter was 127.3 (158.7) thousand barrels of oil equivalents per day ("mboepd"). The decrease was primarily driven by planned maintenance. Net sold volume was 140.7 (162.0) mboepd. The company maintains its full-year production estimate of 155-160 mboepd.

Average realised liquids price was USD 69.3 (63.9) per barrel, while the realised price for natural gas averaged USD 0.16 (0.24) per standard cubic metre ("scm").

Production costs for the oil and gas sold in the quarter amounted to USD 198 (200) million. Production cost per produced barrel oil equivalents ("boe") increased to USD 15.4 (13.4) driven by the lower volume and high maintenance activity. The company expects lower production cost per boe in the second half of 2019, and maintains its guidance of around USD 12.5 per boe on average for the full year.

Exploration expenses amounted to USD 60 (90) million. Total cash spend on exploration was USD 119 (159) million. The company completed four exploration wells in the quarter, of which the Froskelår NE well was classified as a discovery. The Liatårnet well has been completed as a discovery after the end of the quarter. The company has also added two new wells to the 2019 exploration program and has consequently increased its expected exploration spend for the year to around USD 550 (500) million.

Depreciation was USD 168 (183) million, equivalent to USD 14.5 (12.8) per boe. Profit before taxes amounted to USD 268 (249) million. Tax expense was USD 206 (239) million, representing an effective tax rate of 77 (96) per cent. Net profit was USD 62 (10) million.

Investments in fixed assets amounted to USD 414 (364) million in the second quarter. All field development projects, including Johan Sverdrup, Valhall Flank West and Ærfugl progressed according to plan. Abandonment expenditures were USD 40 (21) million, driven by removal of the Valhall QP and plugging of two wells at the abandoned Jette field.

The company successfully put in place a new capital structure in the second quarter. The previous USD 4 billion secured bank facility was replaced with a new USD 4 billion senior unsecured facility at lower cost and extended maturity. The company also issued a new USD 750 million bond. Net interest-bearing debt was USD 2.9 (2.5) billion at the end of the quarter, including USD 0.4 billion in lease debt. Total available liquidity at the end of the quarter was USD 3.3 (3.0) billion.

In May, the company paid a quarterly dividend of USD 0.5207 (NOK 4.52) per share. The Board has resolved to pay a quarterly dividend of USD 187.5 million (USD 0.5207 per share) in August 2019. The Board expects an additional quarterly dividend of USD 187.5 million to be paid in the fourth quarter, implying total annual dividends of USD 750 million. The Board's ambition is to increase the annual dividends by USD 100 million per year until 2023.

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	Q2 2019	Q1 2019	Q2 2018*	2019 YTD	2018 YTD*
Total income	USDm	785	836	925	1 621	1 870
EBITDA	USDm	522	539	698	1 061	1 389
Net profit	USDm	62	10	128	72	296
Earnings per share (EPS)	USD	0.17	0.03	0.36	0.20	0.82
Capex	USDm	397	343	276	740	812
Exploration spend	USDm	119	159	86	278	167
Abandonment spend	USDm	41	21	72	62	154
Production cost	USD/boe	15.4	13.4	11.4	14.3	11.8
Taxes paid	USDm	208	106	69	314	103
Net interest-bearing debt**	USDm	2 907	2 480	2 968	2 907	2 968
Leverage ratio		0.9	0.7	1.1	0.9	1.1

*Total income, EBITDA 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	Q2 2019	Q1 2019	Q2 2018	2019 YTD	2018 YTD
Alvheim area	mboepd	53.1	56.8	60.1	55.0	61.5
Ivar Aasen	mboepd	19.1	22.5	23.7	20.8	24.1
Skarv	mboepd	22.7	22.6	27.6	22.6	27.3
Ula area	mboepd	6.2	8.2	10.8	7.2	9.4
Valhall area	mboepd	24.5	45.8	33.7	35.1	34.1
Other	mboepd	1.7	2.7	1.9	2.2	1.7
Net production	mboepd	127.3	158.7	157.8	142.9	158.2
Over/underlift	mboepd	13.4	3.3	-6.5	8.4	1.1
Net sold volume	mboepd	140.7	162.0	151.3	151.3	159.3
- liquids	mboepd	112.8	128.8	116.4	120.8	124.3
- natural gas	mboepd	27.9	33.2	35.0	30.5	35.0
Realized price liquids	USD/boe	69.3	63.9	73.9	66.4	70.5
Ralized price natural gas	USD/scm	0.16	0.24	0.28	0.20	0.28

FINANCIAL REVIEW

Income statement

(USD MILLION)	Q2 2019	Q1 2019	Q2 2018*	2019 YTD	2018 YTD*
Total income	785	836	925	1 621	1 870
EBITDA	522	539	698	1 061	1 389
EBIT	354	287	516	641	1 021
Pre-tax profit	268	249	494	517	952
Net profit	62	10	128	73	296
EPS (USD)	0.17	0.03	0.36	0.20	0.82

*Restated, see note 1.

Total income in the second quarter 2019 amounted to USD 785 (836) million. The decrease compared to the previous quarter was driven by lower sales volume and lower gas prices, partly mitigated by higher realized liquids prices. Oil and gas production decreased to 127.3 (158.7) due to high maintenance activity in the quarter. Sold volume decreased to 140.7 (162.0) mboepd. Average realized liquids prices were eight per cent higher than in the previous quarter, while realized natural gas prices were down 33 per cent.

Production costs related to oil and gas sold in the quarter amounted to USD 198 (200) million. Production cost per produced unit in the quarter amounted to USD 15.4 (13.4) per boe. The increase was mainly caused by lower production volume due to the high maintenance activity.

Exploration expenses amounted to USD 60 (90) million, and reflected three dry exploration wells in addition to costs related to seismic, area fees, field evaluation etc. The company completed four exploration wells in the quarter. The Froskelår NE well resulted in a discovery, while the wells on JK, Freke-Garm and Hornet were dry. In addition, the Liatårnet well has been completed as a discovery after the end of the quarter.

Depreciation amounted to USD 168 (183) million, corresponding to USD 14.5 (12.8) per boe. No impairment charge was recognized in the quarter.

Operating profit was USD 354 (287) million. During the second quarter, the company replaced its previous Reserve Based Lending facility ("RBL") with a new Senior Unsecured Revolving Credit Facilities ("RCF"). The unamortized portion of the cost related to the RBL, amounting to approximately USD 35 million, was expensed in the second quarter. Net financial expenses amounted to USD 86 (37) million.

Profit before taxes amounted to USD 268 (249) million. Taxes amounted to USD 206 (239) million for the second quarter, representing an effective tax rate of 77 (96) per cent.

This resulted in a net profit for the second quarter 2019 of USD 62 (10) million.

Statement of financial position

(USD MILLION)	Q2 2019	Q1 2019	Q4 2018*	Q2 2018*
Total non-current assets	10 889	10 498	10 088	9 728
Total current assets	603	619	622	2 338
Total assets	11 493	11 117	10 709	12 066
Total equity	2 664	2 799	2 977	3 050
Bank and bond debt	2 635	2 226	2 018	3 017
Total abandonment provisions	2 607	2 561	2 553	3 022
Deferred taxes	1 991	1 867	1 753	1 477
Other liabilities	1 596	1 664	1 409	1 499
Total equity and liabilities	11 493	11 117	10 709	12 066
Net interest-bearing debt	2 907	2 480	1 973	2 968

*Restated, see note 1.

At the end of second quarter 2019, total assets amounted to USD 11,493 (11,117) million, of which current assets were USD 603 (619) million.

Equity amounted to USD 2,664 (2,799) million at the end of the second quarter, corresponding to an equity ratio of 23 (25) per cent.

Deferred tax liabilities amounted to USD 1,991 (1,867) million and are detailed in note 9 to the financial statements.

Gross bank and bond debt totalled USD 2,635 (2,226) million, consisting of the DETNOR02 bond of USD 230 million, the AKERBP Senior Notes (17/22) of USD 394 million, the AKERBP Senior Notes (18/25) of USD 494 million, the AKERBP Senior Notes (19/24) of USD 740 million and the RCF bank facility of USD 776 million, all net of unamortised fees.

At the end of the second quarter, the company had total available liquidity of USD 3.3 (3.0) billion, comprising USD 102 (114) million in cash and cash equivalents, and USD 3.2 (2.9) billion in undrawn credit facilities.

Cash flow

(USD MILLION)	Q2 2019	Q1 2019	Q2 2018	2019 YTD	2018 YTD
Cash flow from operations	387	591	613	977	1 214
Cash flow from investments	-541	-511	-403	-1 052	-780
Cash flow from financing	141	-9	-178	132	-613
Net change in cash & cash equivalents	-13	71	33	57	-180
Cash and cash equivalents	102	114	49	102	49

Net cash flow from operating activities was USD 387 (591) million. Revenues were USD 785 million, down from USD 836 million in the first quarter due to lower volume sold and lower gas prices, partly mitigated by higher realized liquids prices. Taxes paid were USD 208 (106) million.

Net cash flow from investment activities was USD -541 (-511) million, of which investments in fixed assets amounted to USD 414 (364) million for the quarter, mainly related to the Valhall

Financing

On 24 May, Aker BP closed a new USD 4.0 billion Senior Unsecured Revolving Credit Facilities with a syndicate of 17 banks. The facilities 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. These facilities replaced the previous USD 4.0 billion Reserve Based Lending facility.

On 12 June 2019, the company priced a notes offering of USD 750 million aggregate principal amount of 4.75 per cent senior unsecured notes due 2024 at par. Interest will be payable semi-annually. The offering was closed on 19 June 2019.

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 second quarter 2019:

OIL PUT OPTIONS	Q3 2019	Q4 2019	Q1 2020
Volume (million bbl)	1.7	1.7	0
Share of after tax value of oil pro	~ 50 %	~ 45 %	-
duction covered (per cent)
Average strike (USD/bbl)	58	58	-
Average premium (USD/bbl)	1.53	1.53	-

Flank West, Ærfugl and Johan Sverdrup development. Investments in capitalized exploration were USD 87 (126) million, and payments for decommissioning activities amounted to USD 40 (21) million in the quarter.

Net cash flow from financing activities totalled USD 141 (-9) million, reflecting USD 740 million in proceeds from issuance of debt, repayment of long-term debt, dividend disbursements, payments on lease debt and purchase of treasury shares.

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

On 11 July 2019, the Board of Directors declared a dividend of USD 0.5207 per share, to be disbursed on or about 9 August 2019.

OPERATIONAL REVIEW

Aker BP's net production was 11.6 (14.3) mmboe in the second quarter of 2019, corresponding to 127.3 (158.7) mboepd. Due to overlift in the quarter, net sold volume represented 140.7 (162.0) mboepd. The average realized liquids price was USD 69.3 (63.9) per barrel, while the average realized gas price was USD 0.16 (0.24) per scm.

Alvheim Area

Key figures	Aker BP interest	Q2 2019	Q1 2019	Q4 2018	Q3 2018
Production, boepd
Alvheim	65 %	39 943	43 478	43 406	38 872
Bøyla	65 %	2 364	1 829	2 039	3 125
Vilje	46.904 %	2 300	3 756	3 257	3 716
Volund	65 %	8 518	7 757	9 655	11 016
Total production		53 125	56 820	58 357	56 729
Production efficiency		97 %	97 %	98 %	96 %

Second quarter production from the Alvheim area was 53.1 mboepd net to Aker BP, representing a decrease of seven percent from the previous quarter. The reduction was driven by natural decline and by the shut-in of some wells due to a technical issue with the riser support system.

The activity level at Alvheim was high during the quarter, with several wells drilled and completed. The Volund Sidetrack well was drilled and completed within 23 days, 12 days ahead of plan. The well began producing on 28 May and production is in accordance with expectations. The Skogul development project continued according to plan. The subsea installation campaign was successfully completed in June, and drilling operations are scheduled to start in the third quarter.

Drilling of the Frosk Test producer well was completed in June, and the well is expected to begin producing during the third quarter. The Froskelår NE prospect was also drilled as a sidetrack from the Frosk Test well and resulted in a small discovery of 2-10 mmboe. The Rumpetroll exploration well south of Bøyla and Frosk was spudded in June and was not yet completed at the time of this report.

The Alvheim riser configuration consists of three buoyant Mid Water Assemblies ("MVA"). During an annual ROV inspection on 5 June it was discovered that one of the tether frame connections on the eastern MWA had failed. This MWA supports several risers and umbilicals, including the production risers for Vilje and East Kameleon. The MWA has been secured in vertical position, and production from the corresponding wells has been shut in pending repairs. This production effect has largely been mitigated by increased production from other wells.

Valhall Area

Key figures	Aker BP interest	Q2 2019	Q1 2019	Q4 2018	Q3 2018
Production, boepd
Valhall	90 %	23 896	45 156	38 816	35 120
Hod	90 %	618	677	802	872
Total production		24 514	45 833	39 618	35 992
Production efficiency		53 %	94 %	91 %	88 %

Second quarter production from the Valhall area was 24.5 mboepd net to Aker BP. This was 47 per cent lower than previous quarter, which was driven by a planned one-month maintenance shutdown in June.

The IP drilling campaign continued with the G-10 well on the field center. On the Flank South the Maersk Invincible (MINV) rig successfully drilled and completed the S-16B well. A second back-up target S-6A was sanctioned, planned and successfully executed in only two months to safeguard production and reserves from South Flank after the first S-16A target failed to find economic volumes. The MINV rig has now moved to Flank West to commence drilling during the third quarter.

The Flank West facilities have been successfully installed. The topsides were lifted into place on 20 June by the Thialf heavy lift vessel, just 14 months after the first steel was cut at Kværner's yard in Verdal. Both the topsides and the jacket were delivered ahead of schedule, below budget and with excellent HSSE performance.

The original accommodation platform at Valhall (QP) was safely removed in June by Pioneering Spirit. This was the first of the original structures at Valhall to be removed as part of the modernization of the Valhall field centre.

Ula Area

Key figures	Aker BP interest	Q2 2019	Q1 2019	Q4 2018	Q3 2018
Production, boepd
Ula	80 %	2 811	6 185	5 784	6 498
Tambar	55 %	1 455	1 916	2 572	4 008
Oda	15 %	1 949	102	-	-
Total production		6 215	8 203	8 356	10 506
Production efficiency		46 %	75 %	66 %	72 %

Second quarter production from the Ula area was 6.2 mboepd net to Aker BP, down 24 per cent from the previous quarter. Production was primarily impacted by a planned one-month maintenance shutdown towards the end of the quarter. This was partly mitigated by the ramp-up of production from Oda. Tambar productivity has not yet improved, and one Ula producing well ceased to flow in April and will remain shut-in until re-drilled in 2020.

The modification work scope progressed as planned and the flotel has been demobilized. The original Ula drilling derrick was removed as part of preparation for the upcoming infill

drilling campaign. Maersk Integrator (MING) is now located at the Ula D platform and drilling operations are scheduled to commence shortly.

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. This could lead to further development of the Ula area in the mid-2020s.

Skarv Area

Key figures	Aker BP interest	Q2 2019	Q1 2019	Q4 2018	Q3 2018
Production, boepd
Total production	23.835 %	22 657	22 558	23 454	23 313
Production efficiency		98 %	91 %	93 %	90 %

Second quarter production from the Skarv area was 22.7 mboepd net to Aker BP, marginally higher than in the previous quarter. The production efficiency for the quarter was a record high at 98 per cent. The gas injection rates were increased, and accelerated oil production was initiated in the Skarv C reservoir segment in May.

Phase 1 of the Ærfugl development project is progressing in line with the plan. Current activities involve engineering, procurement and fabrication of the subsea system structure, the wellheads and the vertical Xmas tree system. System Integration Test (SIT) for the subsea system is ongoing according to plan, without any significant findings so far. Offshore modification work is ongoing and progressing according to plan. Offshore vessel campaign started in June with rock installation followed by subsea installation in the second half of 2019. 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 close to completion. Production start is planned for fourth quarter 2020.

Ærfugl phase 2 is progressing as planned. The selected development concept has been approved by the partnership, and the final investment decision is planned by the end of this year.

Ivar Aasen

Key figures	Aker BP interest	Q2 2019	Q1 2019	Q4 2018	Q3 2018
Production, boepd
Total production	34.7862 %	19 069	22 539	23 343	22 651
Production efficiency		87 %	98 %	94 %	94 %

The production from Ivar Aasen was 19 mboepd net to Aker BP, down 15 per cent from the previous quarter. Production efficiency was 87 per cent in the period, compared to 98 per cent in the previous quarter. The main reasons for the reduced production efficiency were turbine challenges on Edvard Grieg which led to approximately one week with no production or water injection.

Further, planned activities such as an emergency shutdown test, rig intake and work related to the 2019 drilling campaign contributed to reduced production efficiency in the quarter. The first of two wells in the 2019 drilling campaign was successfully started 21 June. The second well is planned to start production by the end of third quarter.

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 four bridge-linked field center platforms continued throughout the second quarter. On the drilling platform the tie-back operations of the eight pre-drilled oil production wells continued. Tie in of the oil and gas export pipelines continued as planned.

Phase 2 of the Johan Sverdrup development is also progressing well. The plan for development and operation (PDO) was formally approved by Norwegian authorities on 15 May. The contract for subsea pipelines and associated marine operations was awarded to Subsea 7. This will increase the share of contracts awarded to Norwegian suppliers in Phase 2 of the Johan Sverdrup project to 85 percent.

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. 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-eco¬nomic 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.

Aker BP is planning to drill a new exploration well in the third quarter on the Nipa prospect in licence PL 986 (Aker BP 30 per cent), with a pre-drill unrisked volume estimate of 35-115 mmboe.

EXPLORATION

Total exploration spend in the second quarter was USD 119 (159) million. Of this, USD 60 million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees, field evaluation and G&G costs.

In the Alvheim area, the Froskelår NE exploration well proved oil and gas. The well was drilled as a part of the Frosk appraisal and test producer campaign and was successfully completed during the quarter. The gross resources are estimated at 2-10 mmboe. Exploration drilling in the area continued with the Rumpetroll prospect which was spud in June and was not been completed at the time of this report.

Drilling of the Liatårnet prospect in licence PL 442 in the NOAKA area started in June and has been concluded as an oil discovery. The preliminary estimated size of the discovery is 80-200 mmboe.

Further data acquisition and analysis will be undertaken to determine the drainage strategy and recovery factor for the discovery.

During the second quarter the company also drilled and completed three exploration wells on the JK, Freke-Garm and Hornet prospects. These wells were concluded as dry. The drilling was performed with the Deepsea Stavanger rig with high efficiency, utilizing the rig's dual drilling capabilities for the first time ever.

The company has added two new wells to the 2019 exploration program. These wells are Nipa (PL 986, Aker BP 30 per cent) in the NOAKA area and Nidhogg (PL 1008, Aker BP 60 per cent) in the Norwegian sea. Drilling of Nipa and Nidhogg is scheduled for third and fourth quarter respectively.

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	Q2 2019	Q1 2019	Q4 2018	Q3 2018
Total recordable injury frequency (TRIF)	Per mill. exp. hours	4.5	3.3	3.4	4.1
Serious incident frequency (SIF)	Per mill. exp. hours	0.9	0.5	0.5	0.6
Loss of primary containment (LOPC)	Count	0	0	0	1
Process safety events Tier 1 and 2	Count	0	0	0	1
CO2 emissions intensity	Kg CO2/boe	8.7	7.7	7.6	7.5

Both Total Recordable Injuries Frequency (TRIF) and Serious Incident Frequency (SIF) are higher compared to the first quarter 2019. This is mainly due to an increase in personal injuries with low potential, which is addressed through a safety campaign initiated in the second quarter for all Aker BP operated assets.

Following an audit on logistics and health risk management at Ula in April, Aker BP received an improvement order from the Petroleum Safety Authority (PSA). The company is working systematically to address the issues raised by the PSA.

REPORT FOR THE FIRST HALF 2019

	UNIT	PER 30 JUNE 2019	PER 30 JUNE 2018
Oil and gas production	mboepd	142.9	158.2
Realized price liquids	USD/boe	66.4	70.5
Total income	USDm	1 621	1 870
EBITDA	USDm	1 061	1 389
Net profit	USDm	73	296
Net interest-bearing debt	USDm	2 907	2 968

During the first six months of 2019, the company reported consolidated revenues of USD 1,621 (1,870) million. Production in the period was 142.9 (158.2) thousand barrels of oil equivalent per day ("mboepd"). Average realised liquids prices were USD 66 (70) per barrel of oil equivalents and USD 0.20 (0.28) per standard cubic metre of natural gas. The decrease in production compared to first half last year was mainly due to planned maintenance at Valhall and Ula.

Production costs were USD 399 (346) million, or USD 14.3 (11.8) per boe. The increase per boe was driven by lower production due to higher maintenance activity.

Exploration expenses amounted to USD 151 (130) million. Aker BP spudded 10 exploration wells during the first half of 2019. Three of these wells resulted in discoveries, including the Liatårnet well which was completed in July.

EBITDA amounted to USD 1,061 (1,389) million in the period and EBIT was USD 641 (1,021) million. Net profit for the first half of 2019 was USD 73 (296) million, translating into an EPS of USD 0.20 (0.82).

Net cash flow to investment activities amounted to USD 1,052 (781) million. The Johan Sverdrup, Valhall Flank West and Ærfugl field developments progressed as planned and remains on track for first oil. The company also made significant investments in other development projects across its portfolio.

The company refinanced its USD 4 billion RBL bank facility with a new senior unsecured revolving credit facility, extending the maturity and reducing the interest cost compared to the RBL. The company also issued a new USD 750 million bond.

As at 30 June 2019, the company had net interest-bearing debt of USD 2,907 (2,968) million. Available liquidity was USD 3.3 (3.6) billion comprising of cash and cash equivalents of USD 102 (49) million and undrawn credit facilities of USD 3.2 (3.6) billion.

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.

* On this page, all figures in brackets apply to first-half 2018.

RISKS AND UNCERAINTY

Investment in Aker BP involves risks and uncertainties as described in the company's annual report for 2018.

As an oil and gas company operating on the Norwegian Continental Shelf, exploration results, reserve and resource estimates and estimates for capital and operating expenditures are associated with uncertainty. The production performance of oil and gas fields may be variable over time.

The company is exposed to various forms of financial risks, including, but not limited to, fluctuation in oil prices, exchange rates, interest rates and capital requirements; these are described in the company's annual report and accounts, and in note 27 to the accounts for 2018. The company is also exposed to uncertainties relating to the international capital markets and access to capital and this may influence the speed with which development projects can be brought on stream.

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 of USD 1.6-1.7 billion of which the main drivers are Valhall and Johan Sverdrup (the estimate has been increased from USD 1.6 billion due to rig reallocation from abandonment to capex-related activities)
• Exploration spend of USD ~550 million, to cater for an extensive exploration program comprising of 17 exploration wells (increased from USD ~500 million following the addition of two wells to the program)
• Abandonment spend of USD ~100 million (reduced from USD ~150 million due to rig reallocation from abandonment to capex-related activities)
• Production cost of around USD 12.5 per boe

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.

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

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT (Unaudited)

		Group
		Q2 Q1		Q2		01.01.-30.06.
				Restated		Restated
(USD 1 000)	Note	2019	2019	2018	2019	2018
Petroleum revenues		780 071	858 105	928 353	1 638 176	1 874 856
Other operating income		4 744	-21 843	-3 187	-17 098	-5 233
Total income	2	784 816	836 262	925 166	1 621 077	1 869 623
Production costs	3	198 320	200 462	150 517	398 783	345 812
Exploration expenses	4	60 261	90 359	75 270	150 621	129 931
Depreciation	6	167 889	183 102	182 528	350 991	367 950
Impairments	5, 6	-	68 941	-	68 941	-
Other operating expenses		3 882	6 859	1 324	10 740	4 965
Total operating expenses		430 352	549 724	409 639	980 076	848 657
Operating profit		354 464	286 538	515 526	641 002	1 020 966
Interest income		6 735	6 064	6 001	12 799	10 905
Other financial income		6 872	9 719	50 777	16 591	56 970
Interest expenses		15 532	13 830	30 651	29 361	63 326
Other financial expenses		84 307	39 335	47 905	123 642	73 280
Net financial items	8	-86 232	-37 381	-21 778	-123 613	-68 732
Profit before taxes		268 232	249 157	493 748	517 388	952 234
Taxes (+)/tax income (-)	9	205 734	238 731	365 771	444 465	655 743
Net profit		62 498	10 425	127 977	72 923	296 491
Weighted average no. of shares outstanding basic and diluted Basic and diluted earnings USD per share		360 059 807 0.17	360 113 509 0.03	360 113 509 0.36	360 086 510 0.20	360 113 509 0.82

STATEMENT OF COMPREHENSIVE INCOME

				Group
		Q2	Q1	Q2 01.01.-30.06.
				Restated		Restated
(USD 1 000)	Note	2019	2019	2018	2019	2018
Profit for the period		62 498	10 425	127 977	72 923	296 491
Items which may be reclassified over profit and loss (net of taxes) Currency translation adjustment		-	-	-70 269	-	2 863
Total comprehensive income in period		62 498	10 425	57 708	72 923	299 354

		Group
				Restated	Restated
(USD 1 000)	Note	30.06.2019	31.03.2019	31.12.2018	30.06.2018
ASSETS
Intangible assets
Goodwill	6	1 791 185	1 791 185	1 860 126	1 860 126
Capitalized exploration expenditures	6	554 293	496 094	427 439	401 069
Other intangible assets	6	1 967 332	1 986 986	2 005 885	1 585 358
Tangible fixed assets
Property, plant and equipment	6	6 299 710	5 953 972	5 746 275	5 835 137
Right-of-use assets	6	238 879	225 244	-	-
Financial assets
Long-term receivables		27 333	34 002	37 597	37 849
Other non-current assets		10 416	10 392	10 388	8 612
Total non-current assets		10 889 148	10 497 874	10 087 710	9 728 151
Inventories
Inventories		99 205	98 910	93 179	80 438
Receivables
Accounts receivable		124 623	45 271	162 798	134 629
Tax receivables	9	17 418	15 473	11 082	1 595 916
Other short-term receivables	10	259 518	345 374	292 405	448 004
Short-term derivatives	13	840	-	17 253	29 377
Cash and cash equivalents
Cash and cash equivalents	11	101 828	113 680	44 944	49 245
Total current assets		603 432	618 708	621 661	2 337 609
TOTAL ASSETS		11 492 580	11 116 582	10 709 371	12 065 760

STATEMENT OF FINANCIAL POSITION (Unaudited)

		Group
				Restated	Restated
(USD 1 000)	Note	30.06.2019	31.03.2019	31.12.2018	30.06.2018
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		-1 030 555	-894 888	-717 814	-644 138
Total equity		2 663 797	2 799 464	2 976 539	3 050 214
Non-current liabilities
Deferred taxes	9	1 991 371	1 867 333	1 752 757	1 477 175
Long-term abandonment provision	17	2 528 672	2 475 388	2 447 558	2 852 795
Provisions for other liabilities	12	1 161	1 389	107 519	130 240
Long-term bonds	15	1 858 665	1 113 285	1 110 488	1 119 027
Long-term derivatives	13	30 173	27 945	26 275	9 295
Long-term lease debt	7	252 467	275 818	-	-
Other interest-bearing debt	16	775 920	1 112 304	907 954	399 255
Current liabilities
Trade creditors		79 071	112 033	105 567	82 148
Accrued public charges and indirect taxes		24 702	17 254	25 061	21 324
Tax payable	9	439 270	566 755	551 942	687 328
Short-term derivatives	13	216	10 354	8 783	10 012
Short-term abandonment provision	17	78 410	85 212	105 035	168 956
Short-term lease debt	7	122 127	92 735	-	-
Short-term interest-bearing debt	16	-	-	-	1 499 079
Other current liabilities	14	646 559	559 310	583 894	558 912
Total liabilities		8 828 783	8 317 118	7 732 833	9 015 546
TOTAL EQUITY AND LIABILITIES		11 492 580	11 116 582	10 709 371	12 065 760

STATEMENT OF CHANGES IN EQUITY - GROUP (Unaudited)

			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
Dividend distributed	-	-	-	-	-	-187 500	-187 500	-187 500
Profit for the period	-	-	-	-	-	62 498	62 498	62 498
Purchase of treasury shares***	-	-	-	-	-	-10 665	-10 665	-10 665
Equity as of 30.06.2019	57 056	3 637 297	573 083	-81	-25 108	-1 488 066	-1 030 555	2 663 797

* 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.

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

		Group
		Q2	Q1	Q2		01.01.-30.06.
				Restated		Restated
(USD 1 000)	Note	2019	2019	2018	2019	2018
CASH FLOW FROM OPERATING ACTIVITIES
Profit before taxes		268 232	249 157	493 748	517 388	952 234
Taxes paid	9	-208 440	-105 930	-69 086	-314 370	-103 466
Depreciation Net impairment losses	6 5, 6	167 889 -	183 102 68 941	182 529 -	350 991 68 941	367 950 -
Accretion expenses	8, 17	30 419	29 584	33 006	60 002	65 152
Interest expenses	8	53 576	49 150	48 956	102 726	93 507
Interest paid Changes in derivatives	2, 8	-53 580 -8 751	-45 843 20 495	-36 381 -9 611	-99 423 11 744	-87 537 -16 317
Amortized loan costs	8	6 112	6 676	7 594	12 788	15 719
Amortization of fair value of contracts	14	-	-	14 189	-	28 384
Expensed capitalized dry wells	4, 6	29 163	58 074	17 997	87 237	31 662
Changes in inventories, accounts payable and receivables		-112 609	118 262	-66 256	5 654	9 691
Changes in other current balance sheet items		214 626	-41 108	-3 309	173 518	-143 207
NET CASH FLOW FROM OPERATING ACTIVITIES		386 636	590 560	613 376	977 196	1 213 770
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields		-39 554	-20 762	-72 307	-60 316	-154 210
Disbursements on investments in fixed assets		-414 194	-363 982	-301 508	-778 176	-558 265
Disbursements on investments in capitalized exploration		-87 155	-126 334	-28 775	-213 489	-68 235
Disbursements on investments in licenses		-	-143	-	-143	-
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-540 903	-511 222	-402 591	-1 052 125	-780 710
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment of long-term debt		-374 686	200 000	-65 252	-174 686	-880 252
Net proceeds from bond issue		740 159	-	-	740 159	492 423
Payments on lease debt related to investments in fixed assets		-21 492	-16 283	-	-37 775	-
Payments on other lease debt		-4 758	-5 018	-	-9 777	-
Paid dividend		-187 500	-187 500	-112 500	-375 000	-225 000
Purchase of treasury shares		-10 665	-	-	-10 665	-
NET CASH FLOW FROM FINANCING ACTIVITIES		141 057	-8 802	-177 752	132 256	-612 829
Net change in cash and cash equivalents		-13 209	70 537	33 033	57 327	-179 769
Cash and cash equivalents at start of period		113 680	44 944	37 999	44 944	232 504
Effect of exchange rate fluctuation on cash held		1 358	-1 801	-21 787	-443	-3 491
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	101 828	113 680	49 245	101 828	49 245
SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits and cash		101 828	113 680	49 245	101 828	49 245
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	101 828	113 680	49 245	101 828	49 245

NOTES

(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 11 July 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
	Q2	Q1	Q2	01.01.-30.06.
			Restated		Restated
Breakdown of petroleum revenues (USD 1 000)	2019	2019	2018	2019	2018
Sales of liquids	710 913	740 780	782 805	1 451 693	1 584 859
Sales of gas	64 978	113 927	140 926	178 905	280 395
Tariff income	4 181	3 397	4 622	7 578	9 602
Total petroleum revenues	780 071	858 105	928 353	1 638 176	1 874 856
Sales of liquids (barrels of oil equivalent)	10 264 006	11 593 578	10 588 527	21 857 584	22 496 106
Sales of gas (barrels of oil equivalent)	2 540 664	2 987 607	3 182 150	5 528 271	6 334 646
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-6 710	-2 058	-3 946	-8 768	-7 432
Unrealized gain/loss (-) on oil derivatives	6 654	-24 123	-3 429	-17 469	-2 320
Other income*	4 801	4 338	4 188	9 139	4 520
Total other operating income	4 744	-21 843	-3 187	-17 098	-5 233

* 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
	Q2	Q1	Q2	01.01.-30.06.
(USD 1 000)	2019	2019	2018	2019	2018
Total produced volumes (barrels of oil equivalent)	11 585 465	14 280 083	14 358 356	25 865 548	28 636 782
Production cost based on produced volumes	177 874	190 998	163 625	368 872	337 106
Adjustment for over/underlift (-)	20 446	9 464	-13 108	29 910	8 706
Production cost based on sold volumes	198 320	200 462	150 517	398 783	345 812

Note 4 Exploration expenses

	Group
	Q2	Q1	Q2		01.01.-30.06.
Breakdown of exploration expenses (USD 1 000)	2019	2019	2018	2019	2018
Seismic	9 767	532	30 033	10 299	43 512
Area fee	4 717	4 574	2 330	9 291	6 576
Field evaluation	6 898	15 925	14 580	22 823	29 038
Dry well expenses*	29 163	58 074	17 997	87 237	31 662
Other exploration expenses	9 716	11 254	10 329	20 971	19 143
Total exploration expenses	60 261	90 359	75 270	150 621	129 931

* Dry well expenses in Q2 2019 are mainly related to the wells Freke/Garm, JK and Hornet.

Note 5 Impairments

Impairment testing

Based on an assessment of impairment triggers, no impairment charge has been recognized during the quarter.

Note 6 Tangible fixed assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

Property, plant and equipment		Production	Fixtures and
(USD 1 000)	Assets under development	facilities including wells	fittings, office 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	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
Acquisition cost 31.03.2019	2 488 888	6 239 482	143 878	8 872 248
Additions	399 519	71 207	5 351	476 077
Disposals	-	-	-	-
Reclassification	-2 965	15 789	1 236	14 060
Acquisition cost 30.06.2019	2 885 443	6 326 478	150 465	9 362 385
Accumulated depreciation and impairments 31.03.2019	-	2 854 859	63 418	2 918 276
Depreciation	-	137 883	6 516	144 399
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

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	-	-	-	-	-
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
Acquisition cost 31.03.2019	122 353	75 528	29 593	2 303	229 777
Additions	31 899	-	-	-	31 899
Abandonment activity*	188	157	-	-	345
Reclassification**	-13 095	-988	-	-	-14 084
Acquisition cost 30.06.2019	140 970	74 382	29 593	2 303	247 249
Accumulated depreciation and impairments 31.03.2019	1 723	835	1 955	20	4 533
Depreciation	1 052	761	1 955	68	3 836
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

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

** Of which 14 061 reclassified to tangible fixed assets and 23 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	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
Acquisition cost 31.03.2019	2 396 433	7 501	2 403 934	496 094	2 738 973
Additions	-	-	-	87 339	-
Disposals/expensed dry wells	-	-	-	29 163	-
Reclassification	-	-	-	23	-
Acquisition cost 30.06.2019	2 396 433	7 501	2 403 934	554 293	2 738 973
Accumulated depreciation and impairments 31.03.2019	409 447	7 501	416 948	-	947 789
Depreciation	19 654	-	19 654	-	-
Impairment	-	-	-	-	-
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

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
	Q2	Q1	Q2	01.01.-30.06.
Depreciation in the income statement (USD 1 000)	2019	2019	2018	2019	2018
Depreciation of tangible fixed assets	144 399	159 527	167 150	303 926	336 269
Depreciation of right-of-use assets	3 836	4 533	-	8 369	-
Depreciation of intangible assets	19 654	19 043	15 378	38 696	31 681
Total depreciation in the income statement	167 889	183 102	182 529	350 991	367 950

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 incremental borrowing rate applied in discounting of the nominal lease debt is between 4.16% and 6.67%, 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*	-60 226
Interest expense on lease debt	12 674
Currency exchange differences	415
Total lease debt 30.06.2019	374 595
Break down of the lease debt to short-term and long-term liabilities
Short-term	122 127
Long-term	252 467
Total lease debt	374 595
* Payments of lease debt split on activities (USD 1 000): Q2	01.01.-30.06.
Investments in fixed assets 26 581	47 801
Abandonment activity 497	1 963
Operating expenditures 3 917	7 651
Exploration expenditures 468	1 260
Other income 1 003	1 552
Total 32 466	60 226
Nominal lease debt maturity breakdown (USD 1 000):
Within one year	145 486
Two to five years	223 473
After five years	68 677
Total	437 636

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
	Q2		Q2	01.01.-30.06.
(USD 1 000)	2019	2019	2018	2019	2018
Interest income	6 735	6 064	6 001	12 799	10 905
Realized gains on derivatives	2 547	4 420	4 148	6 967	36 442
Change in fair value of derivatives	4 324	5 299	23 947	9 623	18 638
Net currency gains	-	-	22 682	-	1 890
Total other financial income	6 872	9 719	50 777	16 591	56 970
Interest expenses	47 360	42 691	48 956	90 052	93 507
Interest on lease debt	6 216	6 459	-	12 674	-
Capitalized interest cost, development projects	-44 156	-41 997	-25 899	-86 152	-45 899
Amortized loan costs	6 112	6 676	7 594	12 788	15 719
Total interest expenses	15 532	13 830	30 651	29 361	63 326
Net currency loss	9 011	605	-	9 616	-
Realized loss on derivatives	6 578	6 694	2 691	13 272	6 737
Change in fair value of derivatives	2 227	1 671	10 907	3 898	-
Accretion expenses	30 419	29 584	33 006	60 002	65 152
Other financial expenses*	36 072	782	1 301	36 854	1 392
Total other financial expenses	84 307	39 335	47 905	123 642	73 280
Net financial items	-86 232	-37 381	-21 778	-123 613	-68 732

* Other financial expenses include USD 34.8 million in remaining unamortized fees in relation to the refinancing of the RBL facility as described in note 16.

Note 9 Tax

	Group
	Q2		Q2	01.01.-30.06.
			Restated		Restated
Tax for the period (USD 1 000)	2019	2019	2018	2019	2018
Current year tax payable	77 657	129 282	224 905	206 939	450 635
Current year deferred tax change	122 856	110 686	141 402	233 542	226 873
Prior period adjustments	5 221	-1 237	-536	3 984	-21 765
Total tax (+)/tax income (-)	205 734	238 731	365 771	444 465	655 743

		Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	30.06.2019	30.06.2018	31.12.2018
Tax receivable/payable at 01.01.	-540 860	1 234 850	1 234 850
Current year tax (-)/tax receivable (+)	-206 939	-450 635	-803 396
Taxes receivable/payable related to acquisitions/sales	520	-	4 387
Net tax payment (+)/tax refund (-)	314 370	103 466	-907 312
Prior period adjustments and change in estimate of uncertain tax positions	17 083	11 115	-30 269
Currency movements of tax receivable/payable	-6 025	9 792	-39 119
Total net tax receivable (+)/tax payable (-)	-421 851	908 588	-540 860
Tax receivable included as current assets (+)	17 418	1 595 916	11 082
Tax payable included as current liabilities (-)	-439 270	-687 328	-551 942

	Group
		Restated	Restated
Deferred tax (-)/deferred tax asset (+) (USD 1 000)	30.06.2019	30.06.2018	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	-233 542	-226 873	-524 645
Prior period adjustment	-5 072	11 691	33 912
Deferred tax charged to OCI and equity	-	-	-30
Net deferred tax (-)/deferred tax asset (+)	-1 991 371	-1 477 175	-1 752 757

	Group
	Q2	Q1	Q2		01.01.-30.06.
			Restated		Restated
Reconciliation of tax expense (USD 1 000)	2019	2019	2018	2019	2018
78% tax rate on profit before tax	209 221	194 342	385 124	403 563	742 743
Tax effect of uplift	-33 012	-31 063	-33 226	-64 076	-64 853
Permanent difference on impairment	-	53 774	-	53 774	-
Foreign currency translation of NOK monetary items	6 706	472	-17 692	7 177	-1 474
Foreign currency translation of USD monetary items	25 541	1 138	-103 404	26 679	7 168
Tax effect of financial and other 22%/23% items	11 486	17 519	56 454	29 005	-5 016
Currency movements of tax balances**	-23 757	-323	83 378	-24 080	-1 615
Other permanent differences, prior period adjustments and change in estimate of	9 550	2 873	-4 862	12 423	-21 209
uncertain tax positions	-
Total tax (+)/tax income (-)	205 734	238 731	365 771	444 465	655 743

* 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)	30.06.2019	31.03.2019	30.06.2018	31.12.2018
Prepayments	64 682	66 662	77 311	64 004
VAT receivable	6 086	7 082	7 271	8 871
Underlift of petroleum*	26 409	39 170	47 897	54 924
Accrued income from sale of petroleum products	60 066	136 882	198 688	52 825
Other receivables, mainly from licenses	102 275	95 578	116 837	111 781
Total other short-term receivables	259 518	345 374	448 004	292 405

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

Note 11 Cash and cash equivalents

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

		Group
Breakdown of cash and cash equivalents (USD 1 000)	30.06.2019	31.03.2019	30.06.2018	31.12.2018
Bank deposits	101 828	113 680	49 245	44 944
Cash and cash equivalents	101 828	113 680	49 245	44 944
Unused RCF/RBL facility (see note 16)	3 200 000	2 850 000	3 550 000	3 050 000

Note 12 Provisions for other liabilities

	Group
Breakdown of provisions for other liabilities (USD 1 000)	30.06.2019	31.03.2019	30.06.2018	31.12.2018
Fair value of contracts assumed in acquisitions*	-	-	127 539	106 040
Other long term liabilities	1 161	1 389	2 701	1 480
Total provisions for other liabilities	1 161	1 389	130 240	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)	30.06.2019	31.03.2019	30.06.2018	31.12.2018
Unrealized gain on commodity derivatives	-	-	-	17 253
Unrealized gain currency contracts	840	-	29 377	-
Short-term derivatives included in assets	840	-	29 377	17 253
Unrealized losses interest rate swaps	30 173	27 945	9 295	26 275
Long-term derivatives included in liabilities	30 173	27 945	9 295	26 275
Unrealized losses commodity derivatives	216	6 870	10 012	-
Unrealized losses currency contracts	-	3 484	-	8 783
Short-term derivatives included in liabilities	216	10 354	10 012	8 783
Total derivatives included in liabilities	30 389	38 300	19 306	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)	30.06.2019	31.03.2019	30.06.2018	31.12.2018
Current liabilities against JV partners	49 242	25 723	39 472	22 779
Share of other current liabilities in licences	412 322	357 645	320 862	309 260
Overlift of petroleum*	11 450	3 766	5 536	10 055
Fair value of contracts assumed in acquisitions**	-	-	52 548	42 998
Other current liabilities***	173 545	172 177	140 495	198 801
Total other current liabilities	646 559	559 310	558 912	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)	30.06.2019	31.03.2019	30.06.2018	31.12.2018
DETNOR02 Senior unsecured bond*	230 296	225 843	233 713	223 839
AKERBP – Senior Notes (17/22)**	394 225	393 763	392 535	393 301
AKERBP – Senior Notes (18/25)***	493 943	493 680	492 779	493 349
AKERBP – Senior Notes (19/24)****	740 201	-	-	-
Long-term bonds	1 858 665	1 113 285	1 119 027	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 RCF 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.

**** The bond was established in June 2019 and carries an interest of 4.75 per cent. 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)	30.06.2019	31.03.2019	30.06.2018	31.12.2018
Reserve-based lending facility	-	1 112 304	399 255	907 954
Revolving credit facility	775 920	-	-	-
Long-term interest-bearing debt	775 920	1 112 304	399 255	907 954
Bridge facility	-	-	1 499 079	-
Short-term interest-bearing debt	-	-	1 499 079	-

In May 2019, the group refinanced the RBL facility 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 per cent based on drawn amount. In addition, a commitment fee of 35% 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)	30.06.2019	30.06.2018	31.12.2018
Provisions as of 1 January	2 552 592	3 043 884	3 043 884
Incurred cost removal	-61 815	-125 826	-201 227
Accretion expense - present value calculation	60 002	65 152	128 737
Changed net present value from changed discount rate	-	-	-277 081
Change in estimates and incurred liabilities on new drilling and installations	56 303	38 541	-141 721
Total provision for abandonment liabilities	2 607 082	3 021 751	2 552 592
Break down of the provision to short-term and long-term liabilities
Short-term	78 410	168 956	105 035
Long-term	2 528 672	2 852 795	2 447 558
Total provision for abandonment liabilities	2 607 082	3 021 751	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:	30.06.2019	31.03.2019
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:	30.06.2019	31.03.2019 Licence:	30.06.2019	31.03.2019
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	30.000%	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	50.000%	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 %
PL 261	50.000%	50.000 % PL 986	30.000%	30.000 %
PL 262	30.000%	30.000 % PL 1005	60.000%	60.000 %
PL 300	55.000%	55.000 % PL 1008	60.000%	60.000 %
PL 333	77.800%	77.800 % PL 1022	40.000%	40.000 %
PL 340	65.000%	65.000 % PL 1026	40.000%	40.000 %
PL 340BS	65.000%	65.000 % PL 1028	50.000%	50.000 %
PL 364	90.260%	90.260 % PL 1030	50.000%	50.000 %
PL 442	90.260%	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	50.000%	50.000 %
PL 748B	50.000%	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			89	89

Fields non-operated:	30.06.2019	31.03.2019
Atla	10.000%	10.000 %
Enoch	2.000%	2.000 %
Gina Krog	3.300%	3.300 %
Johan Sverdrup	11.573%	11.573 %
Oda	15.000%	15.000 %

Production licences in which Aker BP is a partner:
Licence:	30.06.2019	31.03.2019 Licence:	30.06.2019	31.03.2019
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 842*	0.000%	30.000 %
PL 029B	20.000%	20.000 % PL 844	20.000%	20.000 %
PL 035	50.000%	50.000 % PL 852	40.000%	40.000 %
PL 035C	50.000%	50.000 % PL 852B	40.000%	40.000 %
PL 048D	10.000%	10.000 % PL 852C	40.000%	40.000 %
PL 102C	10.000%	10.000 % PL 857	20.000%	20.000 %
PL 127	50.000%	50.000 % PL 862	50.000%	50.000 %
PL 127B	50.000%	50.000 % PL 863	40.000%	40.000 %
PL 220	15.000%	15.000 % PL 863B	40.000%	40.000 %
PL 265	20.000%	20.000 % PL 864	20.000%	20.000 %
PL 272	50.000%	50.000 % PL 891**	0.000%	30.000 %
PL 272B	50.000%	50.000 % PL 892	30.000%	30.000 %
PL 405	15.000%	15.000 % PL 902	30.000%	30.000 %
PL 457BS	40.000%	40.000 % PL 902B	30.000%	30.000 %
PL 492	60.000%	60.000 % PL 942	30.000%	30.000 %
PL 502	22.222%	22.222 % PL 954	20.000%	20.000 %
PL 533	35.000%	35.000 % PL 955	30.000%	30.000 %
PL 533B	35.000%	35.000 % PL 961	30.000%	30.000 %
PL 554	30.000%	30.000 % PL 962	20.000%	20.000 %
PL 554B	30.000%	30.000 % PL 966	30.000%	30.000 %
PL 554C	30.000%	30.000 % PL 968	20.000%	20.000 %
PL 554D	30.000%	30.000 % PL 981	40.000%	40.000 %
PL 615	4.000%	4.000 % PL 982	40.000%	40.000 %
PL 615B	4.000%	4.000 % PL 985	20.000%	20.000 %
PL 719	20.000%	20.000 % PL 1031	20.000%	20.000 %
PL 721	40.000%	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	30.000%	30.000 %
PL 810B	30.000%	30.000 %
PL 811	20.000%	20.000 %
Number of licenses in which Aker BP is the partner			61	63

* Aker BP has farmed out from the license.

** Aker BP has withdrawn from the license.

Note 21 Results from previous interim reports

	2019			2018 Restated
(USD 1 000)	Q2	Q1	Q4	Q3	Q2
Total income	784 816	836 262	916 200	965 799	925 166
Production costs	198 320	200 462	177 683	170 090	150 517
Exploration expenses	60 261	90 359	72 458	93 519	75 270
Depreciation	167 889	183 102	195 962	188 526	182 528
Impairments	-	68 941	20 172	-	-
Other operating expenses	3 882	6 859	7 739	4 334	1 324
Total operating expenses	430 352	549 724	474 015	456 468	409 639
Operating profit/loss	354 464	286 538	442 185	509 331	515 526
Net financial items	-86 232	-37 381	-43 905	-57 869	-21 778
Profit/loss before taxes	268 232	249 157	398 280	451 462	493 748
Taxes (+)/tax income (-)	205 734	238 731	335 403	335 052	365 771
Net profit/loss	62 498	10 425	62 876	116 410	127 977

	2019			2018
(barrels of oil equivalent)	Q2	Q1	Q4	Q3	Q2
Sold volumes
Liquids Gas	10 264 006 2 540 664	11 593 578 2 987 607	11 018 340 2 921 380	10 816 266 2 826 946	10 588 527 3 182 150

	2019		2018
				Restated
(USD 1 000)	Q2	Q1	Q4	Q3	Q2
Assets
Goodwill	1 791 185	1 791 185	1 860 126	1 860 126	1 860 126
Other intangible assets	2 521 625	2 483 080	2 433 324	1 978 583	1 986 427
Property, plant and equipment	6 299 710	5 953 972	5 746 275	6 038 954	5 835 137
Right-of-use asset	238 879	225 244	-	-	-
Receivables and other assets	521 934	533 949	613 620	627 882	738 909
Calculated tax receivables (short)	17 418	15 473	11 082	1 607 118	1 595 916
Cash and cash equivalents	101 828	113 680	44 944	126 608	49 245
Total assets	11 492 580	11 116 582	10 709 371	12 239 271	12 065 760
Equity and liabilities
Equity	2 663 797	2 799 464	2 976 539	3 060 631	3 050 214
Other provisions for liabilities incl. P&A (long)	2 560 005	2 504 723	2 581 352	3 023 870	2 992 329
Deferred tax	1 991 371	1 867 333	1 752 757	1 593 074	1 477 175
Bonds and bank debt	2 634 585	2 225 589	2 018 443	2 975 518	3 017 362
Lease debt	374 595	368 553	-	-	-
Other current liabilities incl. P&A	828 958	784 164	828 340	831 834	841 352
Tax payable	439 270	566 755	551 942	754 344	687 328
Total equity and liabilities	11 492 580	11 116 582	10 709 371	12 239 271	12 065 760

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

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 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.

STATEMENT BY THE BOARD OF DIRECTORS AND CHIEF EXECUTIVE OFFICER

Pursuant to the Norwegian Securities Trading Act section § 5-5 with pertaining regulations, we hereby confirm that, to the best of our knowledge, the company's interim financial statements for the period 1 January to 30 June 2019 have been prepared in accordance with IFRS, as provided for by the EU, and in accordance with the requirements for additional information provided for by the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair picture of the company's liabilities, financial position and results overall.

To the best of our knowledge, the Board of Directors' half-yearly report together with the yearly report, gives a true and fair picture of the development, performance and financial position of the company, and includes a description of the principal risk and uncertainty factors facing the company.

Øyvind Eriksen, Chair of the Board Kjell Inge Røkke, Board member Anne Marie Cannon, Deputy Chair Trond Brandsrud, Board member Gro Kielland, Board member Bernard Looney, Board member Ingard Haugeberg, Board member Terje Solheim, Board member Anette Hoel Helgesen, Board member Kate Thomson, Board member The Board of Directors and the CEO of Aker BP ASA Akerkvartalet, 11 July 2019

Karl Johnny Hersvik, Chief Executive Officer Ørjan Holstad, Board member

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