Aker BP

Quarterly Report • Jun 14, 2017

Q1 2017 Restated QUARTERLY REPORT FOR AKER BP ASA

FORNEBU, 13 JUNE 2017

KEY EVENTS IN Q1 2017

16 January:	The company announced year-end 2016 preliminary P50 reserves of 711 million barrels of oil equivalents ("mmboe") and mean contingent resources of 600 mmboe
17 January:	The company was offered ownership in 21 new licenses, including 13 operatorship in the 2016 Awards in Pre-defined Areas ("APA")
7 February:	The company and its partners in the Johan Sverdrup development reported a decrease in estimated CAPEX for the project, resulting in break even price for the full field project below 25 USD/bbl
13 February:	The company and its partner announced an oil discovery at the Filicudi prospect in the Barents Sea
16 March:	Anne Marie Cannon and Kjell Inge Røkke were re-elected as board members with a term of office of up to two years. Murray Auchincloss, was elected as a deputy member of the board of directors in Aker BP ASA.
21 March:	The Johan Sverdrup partnership announced the decision to proceed with (DG2) Phase 2 of the Johan Sverdrup development
30 March:	The company and its partner announced redevelopement of Tambar, extending the production period by at least ten years
	KEY EVENTS AFTER THE QUARTER
5 April:	The Annual General Meeting approved an agreement to abolish the Corporate Assembly in Aker BP
7 April:	Following completion of a competitive process, Aker BP announced that the company had entered into long-term frame agreements with key suppliers of engineering services, construction, electro/ IT/ control room systems as well as transport and installation of fixed facilities offshore
27 April:	The Board declared a quarterly dividend of USD 0.185 per share to be paid out in May 2017. The dividend was disbursed on 19 May 2017
3 May:	The Norwegian Petroleum Directorate announced completion

SUMMARY OF FINANCIAL RESULTS

	Unit	Q1 2017	Q1 2016	2017 YTD	2016 YTD
Operating income	USDm	646	205	646	205
EBITDA	USDm	487	129	487	129
Net result	USDm	69	32	69	32
Earnings per share (EPS)	USD	0.20	0.16	0.20	0.16
Production cost per barrel	USD/boe	9	6	9	6
Depreciation per barrel	USD/boe	14	21	14	21
Cash flow from operations	USDm	438	189	438	189
Cash flow from investments	USDm	-270	-232	-270	-232
Total assets	USDm	9 337	5 387	9 337	5 387
Net interest-bearing debt (book value)	USDm	2 330	2 584	2 330	2 584
Cash and cash equivalents	USDm	183	155	183	155

SUMMARY OF PRODUCTION

	Unit	Q1 2017	Q1 2016	2017 YTD	2016 YTD
Alvheim (65%)	boepd	64 383	38 416	64 383	38 416
Bøyla (65%)	boepd	4 545	9 084	4 545	9 084
Hod (37.5%)	boepd	568	-	568	-
Ivar Aasen (34.8%)	boepd	15 003	-	15 003	-
Skarv (23.8%)	boepd	31 608	-	31 608	-
Tambar / Tambar East (55.0%/46.2%)	boepd	2 059	-	2 059	-
Ula (80%)	boepd	6 183	-	6 183	-
Valhall (36.0%)	boepd	14 796	-	14 796	-
Vilje (46.9%)	boepd	5 604	5 177	5 604	5 177
Volund (65%)	boepd	526	6 445	526	6 445
Other (Jette, Jotun, Varg, Atla, Enoch)	boepd	65	1 494	65	1 494
SUM	boepd	145 338	60 615	145 338	60 615
Oil price	USD/bbl	54	37	54	37
Gas price	USD/scm	0.21	0.18	0.21	0.18

3

This report replaces the first quarter financial reporting announced by Aker BP ASA ("Aker BP" or "the company") 28 April 2017. The reissuance of these condensed consolidated interim financial statements has been triggered by a Notes offering involving the preparation of a prospectus, including an ISRE 2410 limited review performed by the Company's independent auditor. As a result, the Company evaluated events subsequent to the original approval date of 27 April 2017 by the board of directors of the Q1 2017 interim financial statements for new information that, if known at the original approval date, would have resulted in adjustment to the financial statements and for other information that would have resulted in additional disclosures. These events have been considered through the date of this report and have been disclosed in Note 17.

SUMMARY OF THE QUARTER

Aker BP ASA ("the company" or "Aker BP") reported total income of USD 646 (205) million in the first quarter of 2017. Production in the period was 145.3 (60.6) thousand barrels of oil equivalent per day ("mboepd"), realizing an average oil price of USD 54 (37) per barrel, while gas revenues were recognized at market value of USD 0.21 (0.18) per standard cubic metre (scm).

EBITDA amounted to USD 487 (129) million in the quarter and EBIT was USD 273 (-23) million. Net profit for the quarter was USD 69 (32) million, translating into an EPS of USD 0.20 (0.16). Net interest-bearing debt amounted to USD 2,330 (2,584) million per March 31, 2017.

Production from the Alvheim area has been both stable and high in the first quarter, positively impacted by a full quarter of production from Viper-Kobra, which commenced production in November last year. The Transocean Arctic drilling rig has completed one infill well at Volund and is currently drilling a second infill well.

Production from the Skarv area remained high and stable during the quarter. Drilling from the Valhall injection platform commenced in the first quarter after a drilling pause of approximately two years.

Production performance at Ivar Aasen has been strong and ahead of expectations in the first quarter as production levels ramp up towards plateau. The Johan Sverdrup project is progressing according to plan and the pre-drilling of injector wells started in February. Concept selection (DG2) was approved for the full field development in March.

An oil discovery was made at the Filicudi prospect in the Barents Sea and drilling of the Gohta 3 well is ongoing.

In February, the company paid a quarterly dividend of USD 0.185 per share.

Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future.

All figures are presented in USD unless otherwise stated, and figures in brackets apply to the corresponding period in the previous year, and is for 2016 not directly comparable as they represent Aker BP ASA prior to the merger with BP Norge AS.

FINANCIAL REVIEW

(USD million)	Q1 2017	Q1 2016
Operating income	646	205
EBITDA	487	129
EBIT	273	-23
Pre-tax profit/loss	227	-16
Net profit	69	32
EPS (USD)	0,20	0,16

Income statement Statement of financial position

(USD million)	Q1 2017	Q1 2016
Goodwill	1 818	739
PP&E	4 600	3 090
Cash & cash equivalents	183	155
Total assets	9 337	5 387
Equity	2 455	371
Interest-bearing debt	2 513	2 739

Total income in the first quarter was USD 646 (205) million, higher than the first quarter 2016 mainly due to inclusion of BP Norge AS activities. Petroleum revenues accounted for USD 647 (201) million, while other income was USD -1 (4) million, primarily relating to realized and unrealized gains and losses on commodity hedges.

Exploration expenses amounted to USD 30 (36) million in the quarter, reflecting dry hole costs, seismic costs, area fees and G&G activities. Production costs were USD 121 (34) million, equating to 9.2 (6.2) USD/boe, including shipping and handling of 2.7 USD/boe. The increase from the first quarter 2016 is mainly due to inclusion of BP Norge fields and production from Ivar Aasen, which have a higher production cost per boe compared to the Alvheim area. Other operating expenses amounted to USD 8 (5) million, a slight increase from the first quarter 2016 following the inclusion of BP Norge AS activities.

Depreciation amounted to USD 184 (114) million, corresponding to 14 (21) USD/boe, which represents a decrease from first quarter 2016 mainly due to the inclusion of the BP Norge assets. During the quarter, an impairment of USD 30 (38) million mainly related to technical goodwill from the BP Norge assets, was recognized.

The company recorded an operating profit of USD 273 (-23) million in the first quarter, higher than the first quarter 2016 primarily due to the merger with BP Norge and higher oil prices. The net profit for the period was USD 69 (32) million after net financial items of USD 47 (-8) million and a tax expense of USD 158 (-48) million. Earnings per share were USD 0.20 (0.16).

Total intangible assets amounted to USD 3,482 (1,664) million, of which goodwill was USD 1,818 (739) million. The increase from the first quarter 2016 is mainly related to the merger with BP Norge AS.

Property, plant and equipment increased to USD 4,600 (3,090) million, reflecting the increase related to the acquisition of BP Norge AS and investments in development projects less depreciation. Current tax receivables amounted to USD 395 (215) million at the end of the quarter relating to exploration spend and anticipated payout of historical tax losses from BP Norge.

The group's cash and cash equivalents were USD 183 (155) million as of 31 March. Total assets were USD 9,337 (5,387) million at the end of the quarter.

Equity amounted to USD 2,455 (371) million at the end of the quarter, corresponding to an equity ratio of 26 (7) percent. The increase is mainly related to the share issue in relation to the merger with BP Norge AS in the third quarter 2016.

Deferred tax liabilities decreased to USD 1,164 (1,384) million and are detailed in note 7 to the financial statements.

Gross interest-bearing debt decreased to USD 2,513 (2,739) million, consisting of the DETNOR02 bond of USD 217 million, the DETNOR03 bond of USD 296 million and the Reserve Based Lending ("RBL") facility of USD 2,000 million.

Statement of cash flow

(USD million)	Q1 2017	Q1 2016
Cash flow from operations	438	189
Cash flow from investments	-270	-232
Cash flow from financing	-98	100
Net change in cash & cash eq.	70	57
Cash and cash eq. EOQ	183	155

Net cash flow from operating activities was USD 438 (189) million. The change is mainly caused by increased profit before tax following the acquisition of BP Norge AS.

Net cash flow from investment activities was USD -270 (-232) million. Investments in fixed assets amounted to USD 232 (209) million for the quarter, mainly reflecting CAPEX on Ivar Aasen, Alvheim and Johan Sverdrup. Investments in intangible assets including capitalized exploration were USD 30 (21) million in the quarter.

Net cash flow from financing activities totaled USD -98 (100) million, reflecting the amount repaid on the group's RBL facility in the quarter and dividend disbursements of USD 62.5 million during the quarter.

Funding

At the end of the first quarter, the company had total available liquidity of USD 2.6 (1.2) billion, comprising of cash and cash equivalents of USD 183 (155) million and undrawn credit facilities of USD 2,416 (1,078) million.

Bondholders representing NOK 0.3 million nominal worth of DETNOR02 bonds exercised the distribution put option following the dividend payment in February. Aker BP consequently owns DETNOR02 bonds equal to NOK 3.8 million.

Going forward, the company will continue to assess its capital structure and debt composition with the aim to improve flexibility and support further organic and inorganic growth.

Hedging

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

During the fourth quarter 2016, the company entered into new commodity hedges for 2017. These include put options with a strike price of 50 USD/bbl for approximately 15 percent of estimated 2017 oil production, corresponding to approximately 50 percent of the undiscounted after-tax value.

Dividends

A quarterly dividend of USD 62.5 million, corresponding to USD 0.185 per share was disbursed on February 17, 2017.

At the Annual General Meeting in April 2017, the Board was authorized to approve the distribution of dividends based on the company's annual accounts for 2016 pursuant to section 8-2 (2) of the Norwegian Public Limited Companies Act.

On April 27, 2017 the Board of Directors declared a quarterly dividend of USD 0.185 per share, to be dispursed on or about May 19, 2017.

HEALTH, SAFETY AND THE ENVIRONMENT

HSE is always the number one priority in all Aker BP's activities. The company ensures that all its operations and projects are carried out under the highest HSE standards.

During first quarter, there were two notifications to the PSA. One high potential incident (HIPO) was recorded, which was a dropped object on Valhall IP drilling platform. The second incident involved a dropped object on Maersk Interceptor. Both incidents have been thoroughly investigated and learnings distributed throughout the entire company and implemented.

In the quarter, one acute spill to sea from Skarv of 200 litres crude oil leaked from the offloading hose. The incident was investigated, and the root causes has been identified and the integrity of the system reinstated.

There has been three lost time work incidents and two medical treatment cases. Two of the lost time incidents have been connected to onshore activity. There has

been an increase of injuries at the end of the quarter, and measures has been taken in order to reverse the negative trend by "Time Out for Safety" stand-downs offshore and onshore in order to reduce risk potential.

The Enterprise Risk Management (ERM) process has been rolled out in the organisation and a comprehensive build up of the new risk matrix has been established. The company is managing the risk picture in all business units and regular risk meetings are taking place in accordance with the governing structure.

A new emergency preparedness room have been completed at the company's offices in Jåttåvågveien 10 in Stavanger, enabling a new, efficient and state of the art environment for the emergency response teams. Emergency response training and exercises will be conducted frequently in order to continue to improve the organisation's emergency preparedness.

OPERATIONAL REVIEW

Aker BP produced 13.1 (5.5) mmboe in the first quarter of 2017, corresponding to 145.3 (60.6) mboepd. The average realized oil price was USD 54 (37) per barrel, while gas revenues were recognized at market value of USD 0.21 (0.18) per standard cubic metre (scm).

Alvheim Area

PL203/088BS/036C/036D/150 (operator)

The producing fields Alvheim (65 percent), Volund (65 percent), Bøyla (65 percent) and Vilje (46.9 percent) are all tied back to the Alvheim FPSO.

Production from the Alvheim area has been both stable and high in the first quarter, with a total operational efficiency of 97 percent. In November, the production from the Viper Kobra wells started on schedule and within budget. The wells have been performing very well since the start-up and are a major contributor to the increased production from the Alveim area compared to the previous quarter.

Re-entry to drill and complete the Volund West and South infill wells using the Transocean Arctic rig commenced in December. The Volund West well was completed mid March, and Transocean Arctic is currently drilling the Volund South tri-lateral infill well.

Valhall Area PL006B/033/033B (operator)

The Valhall area consists of the producing fields Valhall (35.95 percent) and Hod (37.5 percent).

Production from the Valhall area decreased in the first quarter compared to the previous quarter, mainly driven by reservoir depletion. Overall operational efficiency in the quarter was 88 percent.

During the quarter, coiled tubing activity to prepare wells for plug and abandonment (P&A) took place. Maersk Invincible has arrived in Norway, and will shortly continue the P&A campaign at Valhall.

Ula Area PL019/019B/065/300 (operator)

The Ula area consists of the producing fields Ula (80.0 percent), Tambar (55.0 percent) and Tambar East (46.2 percent). Tambar and Tambar East are tied back to the Ula facilities, together with the Repsol operated Blane field and the Dong operated Oselvar field.

Production from the Ula area increased in the first quarter, mainly due to an increased effect of the water altering gas injection (WAG) and two wells available on Tambar rather than one.

The operational efficiency averaged at 74 percent in the quarter because of the issues described above.

Skarv Area PL159/212/212B/262 (operator)

The Skarv area consists of the Skarv producing field (23.84 percent). In addition, production from the Snadd test producer is reported as Skarv volumes.

Production from the Skarv area was high and stable during the first quarter. A successful well intervention on well A04 brought this well back from a hydraulic leakage, which contributed to the good production rate in the quarter.

The operational efficiency ended at 98 percent in the quarter.

PROJECTS

Johan Sverdrup Unit PL265/501/502 (partner)

Phase 1 of the Johan Sverdrup development project is progressing according to plan towards production start-up in the fourth quarter 2019. Phase 1 consists of a field centre with four fixed platforms, three subsea templates, oil and gas export pipelines, power from shore and 36 production and injection wells. Most major contracts have been awarded and engineering and construction are ongoing on 22 sites internationally. At the end of the first quarter, approximately 50 percent of the Phase 1 facilities construction has been completed.

A four-well pilot/appraisal campaign for further improvement of reservoir definition was completed according to plan in February, before the planned predrilling of 10 water injection wells started.

Ivar Aasen PL001B/242/457 (operator)

Operations at Ivar Aasen were very good in the first quarter of 2017 with production ramp-up ahead of plan. Operational efficiency in the quarter was 91 percent.

Focus for the Ivar Aasen operations going forward is to start water injection and bring one more compressor into operation.

The Maersk Interceptor drilling rig resumed drilling in March, drilling the remaining production and water injector wells at Ivar Aasen. The rig is expected to move on to exploration drilling in the third quarter.

In March, concept selection (DG2) for Phase 2 (full field development) was approved according to plan. The final investment decision and Plan for Development and Operation (PDO) for Phase 2 is scheduled for the second half of 2018 and Phase 2 production start is expected in 2022. Phase 2 includes 28 new production and injection wells in the peripheral parts of the Johan Sverdrup oil field (increasing the total number of wells from 36 to 64). Phase 2 also includes an increased production capacity on a 5th platform at the field centre (increasing the production capacity from 440 000 to 660 000 barrels of oil per day). Phase 2 increases the power from shore capacity that will also supply the surrounding fields Ivar Aasen, Edvard Grieg and Gina Krog with power.

The cost estimate of the Johan Sverdrup development continues on a positive downward trend. The Operator's latest Phase 1 CAPEX estimate is NOK 97 billion (nominal at Project FX), which is more than 20 percent lower than at PDO in 2015. The CAPEX estimate for Phase 2 is now NOK 40 – 55 billion, which is approximately half the cost estimated for Phase 2 when the PDO for Phase 1 was submitted in 2015.

The Operator estimates the Johan Svedrup reserves at between 2.0 and 3.0 billion barrels of oil equivalents (boe) and the full field break even oil price lower than 25 USD/boe.

Valhall Flank West PL006B/033/033B (operator)

The Valhall Flank West project will be developed out of the Tor Formation at the western flank of the Valhall field. Valhall is a chalk type reservoir located in the southern area of the Norwegian North Sea. The project passed concept selection gate (DG2) on April 1, 2017 and plans to pass DG3 towards the end of 2017.

The development concept is a Normally Unmanned Installation (NUI), with 12 well slots, tied back to Valhall Field Center. Six of the 12 slots are planned as producers, with option to convert two producers into water injectors. Hence, there is spare capacity for additional future wells.

The project is planned to be executed through long-term strategic frame agreements and alliances. On April 7, Aker BP announced it entered into frame agreements with key suppliers of engineering services, construction, electro/ IT/ control room. The framework agreements will be used as part of an alliance for the Valhall Flank West development.

Valhall Flank North Water Injection PL006B/033/033B (operator)

The Valhall Flank North platform is located to the north of the Valhall complex in 72 meter water depth. A project is currently being matured to expand capability for water injection to the northern basin drainage area, thus securing the Valhall base production through enabling water injection to existing depleted producers and offering a potential for increased reserves recovery from Valhall of 6-8 mmboe gross.

The project has been accelerated and is currently in concept selection phase with a decision gate (DG2) scheduled for the second quarter this year.

North of Alvheim (NoA) PL442/026B/364 (operator)

The North of Alvheim (NoA) area consists of Frigg Gamma Delta, Langfjellet and Frøy. With limited infrastructure available in the area, Aker BP's goal is to develop an area hub, which can tie-in neighbouring licenses and open up for new exploration upsides.

The area is planned to be developed with either a floating or a permanent installation as the hub, with subsea structures or unmanned wellhead platforms on the individual reservoirs based on their size and complexity.

The project is expected to be further matured towards a planned concept selection decision in the fourth quarter 2017.

Storklakken PL460 (operator)

Storklakken is planned to be developed as a stand-alone development with a single multilateral production well tied back to the Vilje field, utilizing existing pipeline from Vilje to Alvheim FPSO. A concept selection (DG2) was internally approved the first quarter 2017 and first oil is planned for 2020.

Snadd

PL162/159/212/212B (operator)

Snadd is planned as a tie-in to Skarv FPSO in a phased development. Phase 1 is planned with three subsea wells tied in to Skarv A template, with first gas scheduled for 2020.

The key activities include the execution of the FEED scopes during 2017 with focus on the technical qualification of the electrical trace heated pipe-inpipe flowline system and selection of optimal subsea production system. The project passed through concept selection (DG2) during the first quarter, and the focus now is to prepare the project for sanctioning (DG3) in the fourth quarter of 2017.

Tambar Re-development PL065 (operator)

Tambar is located 16 kilometres southeast of Ula in 68m water depth. During the first quarter, the Tambar license approved the Tambar-development, consisting of two additional wells and gas lift. This is a major milestone for Tambar, and the production period will be extended from 2018 to 2028 with potential further upsides.

Around NOK 1.7 billion (gross) will be invested targeting gross reserves of 27 million barrels of oil equivalent

(boe), of which Aker BP's share is 15 million boe. The expectation is that this will give additional 4,000-6,000 boepd (gross) production over several years.

The drilling rig Maersk Interceptor will drill two production wells scheduled to start in the fourth quarter this year. Drilling will also test the oil-water contact in the northern part of the Tambar field, which will contribute to increased understanding of the Tambar- reservoir.

Oda

PL405 (partner)

Oda will be developed with a subsea template tied back to the Ula field centre via the Oselvar infrastructure. Recoverable reserves is estimated at 48 mmboe (gross) and the project is planned to be developed with two production wells and one water injector well. Estimated first oil is in 2019.

The PDO was submitted to the Ministry of Petroleum and Energy on November 30, 2016. Total investment for Oda are estimated to NOK 5.4 billion.

EXPLORATION

During the quarter, the company's cash spending on exploration was USD 59 (40) million. USD 30 (36) million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees and G&G costs.

Drilling on the Filicudi prospect in PL533 in the Barents Sea was completed during the first quarter. The well encountered a gross 129 meters hydrocarbon column of high quality sandstone reservoir characteristics, with 63 meters of oil and 66 meters gas in the Jurassic and Triassic targets.

Preliminary volume estimates for the oil and gas discovery are in the range of 35 to 100 million barrels of oil equivalent. Multiple additional prospects have been identified on the Filicudi trend within PL533 with total gross unrisked prospective resource potential for the trend of up to 700 mmboe. The partnership is considering the drilling of up to two additional prospects in 2017. There are two independent high graded prospects within PL533, Hufsa containing gross unrisked prospective resources of 285 mmboe and Hurri with gross unrisked prospective resources of 218 mmboe. The success at Filicudi has reduced the risk of these prospects.

Hanz PL028B (operator)

The discovery at Hanz is part of the development of the Ivar Aasen field. Hanz will be developed by a subsea installation tied back to the Ivar Aasen platform by means of a flow line and umbilical system.

Gina Krog PL029B/029C/048/303 (partner)

The Gina Krog field is being developed with a fixed platform with living quarters and processing facilities. Oil from Gina Krog will be exported to the markets with shuttle tankers while gas will be exported via the Sleipner platform.

The project is progressing towards a planned production start-up in the second quarter this year.

Drilling of the Gohta 3 appraisal well in PL492 in the Barents Sea commenced in March and the well is currently drilling. Appraisal well 7120/1-5 was drilled approximately 4 km north of the original discovery well and is the second appraisal well drilled on the Gohta discovery. The main objective of well was to delineate the northeastern extent of the discovery and to provide a calibration point for the drilling of a horizontal well for a possible extended well test.

The well encountered about 300 metres of carbonates in the Røye formation with poor reservoir quality. Pressure gradients were not established and the forecasted Permian-Triassic conglomerates were not encountered. The well is classified as dry, with traces of hydrocarbons. The resource estimate for the discovery will be reduced as a result of the well. An updated resource estimate will be prepared together with the operator during the year based on all new data.

In January 2017, the company was awarded 21 licenses in the 2016 APA (Awards in predefined areas) round, 13 as operator. The majority of the licenses are close to the company's existing core areas.

BUSINESS DEVELOPMENT

In January, the company sold 9.74 percent of its interest in PL364, including the Frøy discovery in the North Sea to LOTOS Exploration and Production Norge AS. Following this transaction, Aker BP holds 90.26 percent in PL364. The transaction is subject to regulatory approval.

In March, the company sold 35 percent of its interest in PL460, including the Storklakken discovery in the North Sea to PGNiG Upstream Norway AS. Following this transaction, Aker BP holds 65 percent in PL460. The transaction is subject to regulatory approval.

OUTLOOK

The company continues to build on a strong platform for further value creation through an effective business model built on lean principles, technological competence and industrial cooperation to secure longterm competitiveness.

Going forward, the company will continue to pursue growth opportunities which will enhance production and increase dividend capacity. A dividend of USD 0.185 per share is scheduled to be paid out in May and the ambition to sustain a dividend level of minimum USD 250 million per year in the medium term and to increase this level once Johan Sverdrup is in production is reiterated.

The company will have four rigs in operation in the second quarter. Operations include completion of the PDO scope at Ivar Aasen, drilling infill and exploration targets in the Alvheim area, new production wells at Valhall and conducting P&A activity at Valhall.

Aker BP is on track to to submit three PDO's during 2017, relating to the Valhall West Flank, Snadd and Storklakken projects.

The company has a robust balance sheet with USD 2.6 billion in available liquidity, providing the company with ample financial flexibility. Going forward, the company will continue to assess its capital structure and debt composition with the aim to improve flexibility and support further organic and inorganic growth.

The company makes no changes to its 2017 guidance as presented at the Capital Markets Day in January. Aker BP expects to produce between 128 and 135 mboepd in 2017 with a production cost of approximately 11 USD/boe. The full year 2017 CAPEX is expected to be between USD 900 – 950 million, exploration expenditures are expected to be USD 280 – 300 million and decommissioning costs between USD 100 – 110 million.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT

		Group
		Q1		01.01.-31.03.
(USD 1 000)	Note	2017	2016	2017	2016
Petroleum revenues	2	647 171	200 768	647 171	200 768
Other income	2	-922	4 080	-922	4 080
Total income		646 250	204 848	646 250	204 848
Exploration expenses	3	30 259	36 115	30 259	36 115
Production costs Depreciation	5	120 874 184 004	34 374 114 318	120 874 184 004	34 374 114 318
Impairments	4, 5	29 782	37 964	29 782	37 964
Other operating expenses		8 051	5 330	8 051	5 330
Total operating expenses		372 969	228 101	372 969	228 101
Operating profit/loss		273 280	-23 253	273 280	-23 253
Interest income		1 074	817	1 074	817
Other financial income		17 272	49 521	17 272	49 521
Interest expenses		30 008	20 701	30 008	20 701
Other financial expenses		34 846	22 018	34 846	22 018
Net financial items	6	-46 508	7 620	-46 508	7 620
Profit/loss before taxes		226 772	-15 633	226 772	-15 633
Taxes (+)/tax income (-)	7	157 955	-47 866	157 955	-47 866
Net profit/loss		68 818	32 233	68 818	32 233
Weighted average no. of shares outstanding basic and diluted Basic and diluted earnings/(loss) per share		337 737 071 0.20	202 618 602 0.16	337 737 071 0.20	202 618 602 0.16

STATEMENT OF COMPREHENSIVE INCOME

		Group
			Q1	01.01.-31.03.
(USD 1 000)	Note	2017	2016	2017	2016
Profit/loss for the period		68 818	32 233	68 818	32 233
Items which may be reclassified over profit and loss (net of taxes)
Currency translation adjustment		-356	-59	-356	-59
Total comprehensive income in period		68 461	32 174	68 461	32 174

13

STATEMENT OF FINANCIAL POSITION

			Group
(USD 1 000)	Note	31.03.2017	31.03.2016	31.12.2016
ASSETS
Intangible assets
Goodwill	5	1 817 810	739 383	1 846 971
Capitalized exploration expenditures	5	355 910	294 161	395 260
Other intangible assets	5	1 308 011	630 105	1 332 813
Tangible fixed assets
Property, plant and equipment	5	4 599 627	3 089 831	4 441 796
Financial assets
Long-term receivables		43 138	2 935	47 171
Other non-current assets		12 313	12 142	12 894
Long-term derivatives	11	745	6 222	-
Total non-current assets		8 137 553	4 774 778	8 076 905
Inventories
Inventories		68 552	31 018	69 434
Receivables
Accounts receivable		93 142	44 795	170 000
Other short-term receivables	8	459 865	129 894	422 932
Other current financial assets		-	2 989	-
Tax receivables	7	394 669	215 141	400 638
Short-term derivatives	11	209	33 349	-
Cash and cash equivalents
Cash and cash equivalents	9	182 795	154 618	115 286
Total current assets		1 199 232	611 804	1 178 290
TOTAL ASSETS		9 336 785	5 386 582	9 255 196

STATEMENT OF FINANCIAL POSITION

		Group
(USD 1 000) Note	31.03.2017	31.03.2016	31.12.2016
EQUITY AND LIABILITIES
Equity Share capital	54 349	37 530	54 349
Share premium	3 150 567	1 029 617	3 150 567
Other equity	-749 748	-695 947	-755 709
Total equity	2 455 169	371 200	2 449 207
Non-current liabilities
Deferred taxes 7	1 164 113	1 384 031	1 045 542
Long-term abandonment provision 15	2 084 584	425 853	2 080 940
Provisions for other liabilities 10	212 862	1 648	218 562
Long-term bonds 13	512 729	518 142	510 337
Other interest-bearing debt 14	1 999 869	2 220 836	2 030 209
Long-term derivatives 11	27 685	33 776	35 659
Current liabilities
Trade creditors	41 630	135 295	88 156
Accrued public charges and indirect taxes	19 485	6 105	39 048
Tax payable 7	120 114	-	92 661
Short-term derivatives 11	1 803	205	5 049
Short-term abandonment provision 15	96 365	13 785	75 981
Other current liabilities 12	600 376	275 707	583 844
Total liabilities	6 881 616	5 015 382	6 805 989
TOTAL EQUITY AND LIABILITIES	9 336 785	5 386 582	9 255 196

STATEMENT OF CHANGES IN EQUITY - GROUP

				Other equity
					Other comprehensive income
(USD 1 000)	Share capital	Share premium	Other paid-in capital	Actuarial gains/(losses)	Foreign currency translation reserves*	Retained earnings	Total other equity	Total equity
Equity as of 31.12.2015	37 530	1 029 617	573 083	-88	-115 491	-1 185 625	-728 121	339 026
Private placement	16 820	2 120 950	-	-	-	-	-	2 137 769
Dividend distributed	-	-	-	-	-	-62 500	-62 500	-62 500
Profit/loss for the period 01.01.2016 - 31.12.2016	-	-	-	-	-59	34 971	34 911	34 911
Equity as of 31.12.2016	54 349	3 150 567	573 083	-88	-115 550	-1 213 154	-755 709	2 449 207
Dividend distributed	-	-	-	-	-	-62 500	-62 500	-62 500
Profit/loss for the period 01.01.2017 - 31.03.2017	-	-	-	-	-356	68 818	68 461	68 461
Equity as of 31.03.2017	54 349	3 150 567	573 083	-88	-115 907	-1 206 836	-749 748	2 455 169

* The main part of the foreign currency translation reserve arose as a result of the change in functional currency in Q4 2014.

STATEMENT OF CASH FLOW

			Group
			Q1	Year
(USD 1 000)	Note	2017	2016	2016
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		226 772	-15 633	290 453
Taxes paid during the period		-	-	-1 419
Tax refund during the period		-	-	212 944
Depreciation	5	184 004	114 318	509 027
Net impairment losses	4, 5	29 782	37 964	71 375
Accretion expenses	6, 15	31 713	5 812	47 977
Interest expenses Interest paid	6	41 166 -41 156	37 635 -29 433	160 808 -161 634
Changes in derivatives	2, 6	-12 173	-35 890	10 408
Amortized loan costs	6	7 144	3 109	17 915
Gain on change of pension scheme		-	-	-115 616
Expensed capitalized dry wells	3, 6	1 059	16 451	51 669
Changes in inventories, accounts payable and receivables		-5 718	100 779	-317 488
Changes in abandonment liabilities through income statement		-	-	-1 131
Changes in other current balance sheet items		-24 488	-46 350	120 365
NET CASH FLOW FROM OPERATING ACTIVITIES		438 104	188 762	895 652
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	15	-7 684	-1 306	-12 237
Disbursements on investments in fixed assets	5	-232 407	-209 279	-935 755
Net of cash consideration paid for, and cash acquired from, BP Norge AS		-	-	423 990
Disbursements on investments in capitalized exploration expenditures and
other intangible assets	5	-29 905	-21 228	-181 492
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-269 996	-231 812	-705 494
CASH FLOW FROM FINANCING ACTIVITIES
Repayment of long-term debt		-35 470	-	-612 825
Net proceeds from issuance of long-term debt		-	100 000	512 013
Paid dividend		-62 500	-	-62 500
NET CASH FLOW FROM FINANCING ACTIVITIES		-97 970	100 000	-163 312
Net change in cash and cash equivalents		70 139	56 950	26 846
Cash and cash equivalents at start of period		115 286	90 599	90 599
Effect of exchange rate fluctuation on cash held		-2 630	7 069	-2 158
CASH AND CASH EQUIVALENTS AT END OF PERIOD	9	182 795	154 618	115 286
SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits and cash		173 830	149 812	106 369
Restricted bank deposits		8 965	4 806	8 917
CASH AND CASH EQUIVALENTS AT END OF PERIOD	9	182 795	154 618	115 286

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 statement as at 31 December 2016. 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 International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity. These condensed interim financial statements replace and restate the condensed interim financial statements as at and for the three months ended 31 March 2017 released on 27 April 2017.

The reissuance of these condensed interim financial statements has been triggered by a Notes offering involving the preparation of a prospectus, including an ISRE 2410 limited review performed by the Company's independent auditor. As a result, the Company evaluated events subsequent to the original approval date of 27 April 2017 by the board of directors of the Q1 2017 interim financial statements for new information that, if known at the original approval date, would have resulted in adjustment to the financial statements and for other information that would have resulted in additional disclosures. These events have been considered through the date of this report and have been disclosed in Note 17.

These interim financial statements were authorised for issue by the Company's Board of Directors on 13 June 2017.

The acquisition of BP Norge AS was completed on 30 September 2016. Corresponding figures for 2016 are therefore not directly comparable as they represent Aker BP prior to the acquisition of BP Norge AS.

Note 1 Accounting principles

The accounting principles used for this interim report are consistent with the principles used in the financial statements for 2016. There are no new standards effective from 1 January 2017.

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 were the same as those that applied to the consolidated financial statements as at and for the year ended 31 December 2016. Refer also to Note 4 Impairments.

Note 2 Income

			Group
		Q1	01.01.-31.03.
Breakdown of petroleum revenues (USD 1 000)	2017	2016	2017	2016
Recognized income liquids	547 311	180 388	547 311	180 388
Recognized income gas	94 206	18 103	94 206	18 103
Tariff income	5 654	2 277	5 654	2 277
Total petroleum revenues	647 171	200 768	647 171	200 768

Breakdown of produced volumes (barrels of oil equivalent)

Liquids	10 280 386	4 819 146	10 280 386	4 819 146
Gas	2 800 022	696 793	2 800 022	696 793
Total produced volumes	13 080 409	5 515 939	13 080 409	5 515 939

Other income (USD 1 000)

Realized gain/loss (-) on oil derivatives	-2 549	17 073	-2 549	17 073
Unrealized gain/loss (-) on oil derivatives	1 390	-13 131	1 390	-13 131
Other income	237	138	237	138
Total other income	-922	4 080	-922	4 080

Note 3 Exploration expenses

			Group
	Q1			01.01.-31.03.
Breakdown of exploration expenses (USD 1 000)	2017	2016	2017	2016
Seismic	10 389	1 024	10 389	1 024
Area fee	5 308	2 262	5 308	2 262
Dry well expenses	1 059	16 451	1 059	16 451
Other exploration expenses	13 504	16 378	13 504	16 378
Total exploration expenses	30 259	36 115	30 259	36 115

Note 4 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment triggers are identified, and for goodwill impairment is tested at least annually. In Q1 2017, 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, the impairment testing has been based on fair value. For both value in use and fair value, the impairment testing is done based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years. If not specifically stated otherwise, the same assumptions have been applied for value in use and fair value testing.

For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 March 2017.

Oil and gas prices

The nominal oil price based on the forward curve applied in the impairment test is as follows:

Year	USD/BOE
2017	55.0
2018	53.9
2019	53.4
From 2020 (in real terms) - fair value testing*	65.0
From 2020 (in real terms) - value in use testing	75.0

* In line with the fair value requirements in IAS 36, as defined by IFRS 13 definition of fair value, the long-term fair value oil price assumption reflects the view of market participants at the measurement date under current market conditions.

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.

Discount rate

The post tax nominal discount rate used is 7.5 per cent, which is the same discount rate as applied in Q4 2016.

Currency rates

Year	USD/NOK
2017	8.53
2018	8.46
2019	8.38
From 2020	7.50

Inflation

The long-term inflation rate is assumed to be 2.5 per cent.

Impairment testing of technical goodwill

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

(USD 1 000)	Ula/Tambar	Valhall/Hod
Net carrying value	242 635	1 096 104
Recoverable amount	229 588	1 079 904
Impairment charge Q1	13 047	16 200

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 from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable. In Q1 2017, the reduced deferred tax together with decreased forward prices are the main reasons for the impairment.

In addition to the impairment on the technical goodwill described above, there has been a minor adjustment of an impairment on a CGU with no recoverable amount. The total impairment on goodwill is thus USD 29 161 thousands. See note 5 for a summary of impairment charges.

Sensitivity analysis

The table below shows how the impairment of goodwill allocated to the Ula/Tambar and Valhall/Hod would be affected by changes in the various assumptions, given that the remainders of the assumptions are constant.

	Change in goodwill impairment after
Assumption (USD 1 000)	Change	Increase in assumption	Decrease in assumption
Oil and gas price	+/- 20%	-29 247	402 831
Production profiles (reserves)	+/- 5%	-29 247	102 045
Discount rate	+/- 1% point	59 720	-19 306
Currency rate USD/NOK	+/- 1.0 NOK	-29 247	96 240
Inflation	+/- 1% point	-29 247	84 159

Note 5 Tangible assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

	Assets under	Production facilities	Fixtures and fittings, office
(USD 1 000)	development	including wells	machinery	Total
Book value 31.12.2015	1 493 795	1 470 881	14 758	2 979 434
Acquisition cost 31.12.2015	1 505 779	2 514 487	35 506	4 055 772
Acquisition of BP Norge AS	-	921 081	-	921 081
Additions	752 795	177 144	12 603	942 542
Disposals	-	-	4 001	4 001
Reclassification	-1 349 900	1 337 853	12 028	-19
Acquisition cost 31.12.2016	908 674	4 950 566	56 137	5 915 377
Accumulated depreciation and impairments 31.12.2015 Depreciation	11 984 -	1 043 606 411 400	20 748 6 491	1 076 338 417 891
Impairment	-10 418	-6 191	-	-16 609
Retirement/transfer depreciations	-	-156	-3 882	-4 038
Accumulated depreciation and impairments 31.12.2016	1 566	1 448 659	23 357	1 473 582
Book value 31.12.2016	907 108	3 501 908	32 779	4 441 796
Acquisition cost 31.12.2016	908 674	4 950 566	56 137	5 915 377
Additions	184 124	62 658	2 676	249 458
Disposals	-	-	-	-
Reclassification*	67 326	-	665	67 991
Acquisition cost 31.03.2017	1 160 124	5 013 224	59 478	6 232 826
Accumulated depreciation and impairments 31.12.2016	1 566	1 448 659	23 357	1 473 582
Depreciation	-	157 555	2 070	159 625
Impairment	-6	-	-	-6
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 31.03.2017	1 560	1 606 213	25 427	1 633 200
Book value 31.03.2017	1 158 564	3 407 011	34 050	4 599 627

* The reclassification in this quarter is mainly related to Storklakken which was reclassified from exploration to development phase.

Capitalized exploration expenditures are reclassified to "Fields under development" when the field enters into the development phase. If development plans are subsequently reevaluated, the associated costs remain in assets under development and are not reclassified back to exploration assets. Fields under development are reclassified to "Production facilities" from the start of production. Production facilities, including wells, are depreciated in accordance with the Unit of Production Method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3-5 years. Removal and decommissioning costs are included as production facilities or fields under development.

See Note 4 for information regarding impairment charges.

INTANGIBLE ASSETS - GROUP

Other intangible assets				Exploration
(USD 1 000)	Licences etc.	Software	Total	wells	Goodwill
Book value 31.12.2015	646 487	1 543	648 030	289 980	767 571
Acquisition cost 31.12.2015	789 316	9 149	798 465	289 980	1 561 880
Acquisition of BP Norge AS	759 962	-	759 962	-	1 119 083
Additions	25 519	-1 383	24 137	157 337	39 871
Disposals/expensed dry wells	-	265	265	51 669	-
Reclassification	406	-	406	-388	-
Acquisition cost 31.12.2016	1 575 203	7 501	1 582 705	395 260	2 720 835
Accumulated depreciation and impairments 31.12.2015	142 829	7 606	150 435	-	794 309
Depreciation	91 254	-118	91 136	-	-
Impairment	8 429	-	8 429	-	79 555
Retirement/transfer depreciations	157	-265	-108	-	-
Accumulated depreciation and impairments 31.12.2016	242 670	7 223	249 892	-	873 864
Book value 31.12.2016	1 332 534	279	1 332 813	395 260	1 846 971
Acquisition cost 31.12.2016	1 575 203	7 501	1 582 705	395 260	2 720 835
Additions	205	-	205	29 699	-
Disposals/expensed dry wells	-	-	-	1 059	-
Reclassification*	-	-	-	-67 991	-
Acquisition cost 31.03.2017	1 575 409	7 501	1 582 910	355 910	2 720 835
Accumulated depreciation and impairments 31.12.2016	242 670	7 223	249 892	-	873 864
Depreciation	24 309	70	24 379	-	-
Impairment	627	-	627	-	29 161
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 31.03.2017	267 606	7 293	274 898	-	903 025
Book value 31.03.2017	1 307 803	208	1 308 011	355 910	1 817 810

* The reclassification in this quarter is mainly related to Storklakken which was reclassified from exploration to development phase.

See Note 4 for information regarding impairment charges.

	Group
		Q1		01.01.-31.03.
Depreciation in the Income statement (USD 1 000)	2017	2016	2017	2016
Depreciation of tangible fixed assets	159 625	95 798	159 625	95 798
Depreciation of intangible assets	24 379	18 519	24 379	18 519
Total depreciation in the Income statement	184 004	114 318	184 004	114 318
Impairment in the Income statement (USD 1 000)
Impairment/reversal of tangible fixed assets	-6	9 775	-6	9 775
Impairment/reversal of intangible assets	627	-	627	-
Impairment of goodwill	29 161	28 189	29 161	28 189
Total impairment in the Income statement	29 782	37 964	29 782	37 964

Note 6 Financial items

	Group
	Q1		01.01.-31.03.
(USD 1 000)	2017	2016	2017	2016
Interest income	1 074	817	1 074	817
Realized gains on derivatives	389	500	389	500
Change in fair value of derivatives	10 783	49 021	10 783	49 021
Net currency gains	6 100	-	6 100	-
Total other financial income	17 272	49 521	17 272	49 521
Interest expenses	41 166	37 635	41 166	37 635
Capitalized interest cost, development projects	-18 301	-20 043	-18 301	-20 043
Amortized loan costs	7 144	3 109	7 144	3 109
Total interest expenses	30 008	20 701	30 008	20 701
Net currency losses	-	10 996	-	10 996
Realised loss on derivatives	1 510	3 790	1 510	3 790
Accretion expenses	31 713	5 812	31 713	5 812
Other financial expenses	1 623	1 420	1 623	1 420
Total other financial expenses	34 846	22 018	34 846	22 018
Net financial items	-46 508	7 620	-46 508	7 620

Note 7 Taxes

	Group
	Q1		01.01.-31.03.
Taxes for the period appear as follows (USD 1 000)	2017	2016	2017	2016
Calculated current year tax/exploration tax refund	39 011	-6 090	39 011	-6 090
Change in deferred taxes in the Income statement	120 193	-41 577	120 193	-41 577
Prior period adjustments	-1 250	-200	-1 250	-200
Total taxes (+)/tax income (-)	157 955	-47 866	157 955	-47 866

		Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	31.03.2017	31.03.2016	31.12.2016
Tax receivable/payable at 01.01.	307 977	126 391	126 391
Current year tax (-)/tax receivable (+)	-39 011	6 090	131 488
Tax receivable related to acquisitions	-	60 379	255 873
Tax payment/tax refund	-	-	-211 525
Prior period adjustments	4 216	8 817	-1 681
Revaluation of tax receivable	1 373	13 465	7 430
Total tax receivable (+)/tax payable (-)	274 555	215 141	307 977
Tax receivable included as current assets (+)	394 669	215 141	400 638
Tax payable included as current liabilities (-)	-120 114	-	-92 661

		Group
Deferred taxes (-)/deferred tax asset (+) (USD 1 000)	31.03.2017	31.03.2016	31.12.2016
Deferred taxes/deferred tax asset 01.01.	-1 045 542	-1 356 114	-1 356 114
Change in deferred taxes in the Income statement	-120 193	41 577	-374 617
Reclassification of loss carried forward from Premier Oil Norge AS and BP Norge AS	-	-60 379	-238 866
Deferred tax related to acquisitions	-	-	942 611
Prior period adjustment	1 622	-9 115	-18 555
Deferred tax charged to OCI and equity	-	-	-1
Net deferred tax (-)/deferred tax asset (+)	-1 164 113	-1 384 031	-1 045 542

	Group
		Q1		01.01.-31.03.
Reconciliation of tax expense (USD 1 000)	2017	2016	2017	2016
78% tax rate on profit before tax	176 882	-12 194	176 882	-12 194
Tax effect on uplift	-30 489	-24 597	-30 489	-24 597
Permanent difference on impairment	22 813	21 987	22 813	21 987
Foreign currency translation of NOK monetary items	-3 371	8 674	-3 371	8 674
Foreign currency translation of USD monetary items	12 001	125 619	12 001	125 619
Tax effect of financial and other 24%/25% items	-3 917	-85 869	-3 917	-85 869
Revaluation of tax balances*	-12 177	-79 945	-12 177	-79 945
Other items (other permanent differences and prior period adjustment)	-3 788	-1 543	-3 788	-1 543
Total taxes (+)/tax income (-)	157 955	-47 866	157 955	-47 866

* 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).

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

The tax rate for general corporation tax changed from 25 to 24 per cent from 1 January 2017. The rate for special tax changed from the same date from 53 to 54 per cent.

Note 8 Other short-term receivables

		Group
(USD 1 000)	31.03.2017	31.03.2016	31.12.2016
Receivables related to deferred volume at Atla	-	4 371	-
Prepayments	28 922	33 594	40 730
VAT receivable	7 262	10 004	7 913
Underlift of petroleum	65 245	15 091	70 003
Accrued income from sale of petroleum products	132 165	-614	86 429
Other receivables, mainly from licenses	226 272	67 448	217 857
Total other short-term receivables	459 865	129 894	422 932

Note 9 Cash and cash equivalents

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

31.03.2017	31.03.2016	31.12.2016
173 830	149 812	106 369
8 965	4 806	8 917
182 795	154 618	115 286
550 000	550 000	550 000
1 866 000	528 000	1 805 000
		Group

Note 10 Provisions for other liabilities

		Group
Breakdown of provisions for other liabilities (USD 1 000)	31.03.2017	31.03.2016	31.12.2016
Fair value of contracts assumed in acquisition of BP Norge AS*	191 406	-	202 874
Other long term liabilities	21 456	1 648	15 688
Total provisions for other liabilities	212 862	1 648	218 562

* The negative contracts value are related to rig contracts entered into by BP Norge AS, which were different from current market terms at the time of the acquisition. The fair value was based on the difference between market price and contract price at the time of the acquisition. The balance is split between current and non-current liabilities based on the cash flow in the contracts, and amortized over the lifetime of the contracts.

Note 11 Derivatives

		Group
(USD 1 000)	31.03.2017	31.03.2016	31.12.2016
Unrealized gain currency contracts	745	6 222	-
Long-term derivatives included in assets	745	6 222	-
Unrealized gain on commodity derivatives	209	32 086	-
Unrealized gain currency contracts	-	1 263	-
Short-term derivatives included in assets	209	33 349	-
Total derivatives included in assets	954	39 571	-
Unrealized losses currency contracts	393	-	5 073
Unrealized losses interest rate swaps	27 292	33 776	30 586
Long-term derivatives included in liabilities	27 685	33 776	35 659
Unrealized losses currency contracts	1 803	205	3 868
Unrealized losses commodity derivatives	-	-	1 181
Short-term derivatives included in liabilities	1 803	205	5 049
Total derivatives included in liabilities	29 489	33 981	40 708

The group has different types of hedging instruments. The commodity derivatives are used to hedge the risk of oil price reduction. The group manages its interest rate exposure using interest rate derivatives, including a cross currency interest rate swap. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly 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 consolidated financial statements as at and for the year ended 31 December 2016.

Note 12 Other current liabilities

		Group
Breakdown of other current liabilities (USD 1 000)	31.03.2017	31.03.2016	31.12.2016
Current liabilities related to overcall in licences	97 487	25 880	81 686
Share of other current liabilities in licences	355 043	183 250	360 222
Overlift of petroleum	2 275	909	20 000
Fair value of contracts assumed in acquisition of BP Norge AS*	45 939	8 470	36 199
Other current liabilities**	99 631	57 198	85 737
Total other current liabilities	600 376	275 707	583 844

* Refer to note 10.

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

Note 13 Long-term bonds

		Group
(USD 1 000)	31.03.2017	31.03.2016	31.12.2016
DETNOR02 Senior unsecured bond1)	216 909	223 135	214 827
DETNOR03 Subordinated PIK toggle bond 2)	295 820	295 007	295 510
Total bond	512 729	518 142	510 337

1) The loan 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 loan is unsecured. The loan has been swapped into USD using a cross currency interest rate swap whereby the group pays LIBOR +6.81 per cent quarterly.

2) In May 2015, the group completed an issue of USD 300 million subordinated seven year PIK Toggle bonds with a fixed rate coupon of 10.25 per cent. The bonds are callable and includes an option to defer interest payments.

Note 14 Other interest-bearing debt

	Group
(USD 1 000)	31.03.2017	31.03.2016	31.12.2016
Reserve-based lending facility	1 999 869	2 220 836	2 030 209
Total other interest-bearing debt	1 999 869	2 220 836	2 030 209

The RBL facility was established in 2014 and is a senior secured seven-year facility. The facility was originally USD 3.0 billion, with an additional uncommitted accordion option of USD 1.0 billion. In connection with the acquisition of BP Norge AS, the facility size was increased to USD 4.0 billion. In addition a new, uncommitted, accordion option of USD 1.0 billion was added to the facility. After the inclusion of the BP Norge assets into the RBL facility and the semi-annual redetermination in December 2016, the borrowing base was increased to USD 3.9 billion as of 31 December 2016.

The interest rate is from 1 - 6 months LIBOR plus a margin of 2.75 per cent, with a utilization fee of 0.5 per cent on outstanding loan. In addition, a commitment fee of 1.1 per cent is paid on unused credit.

A revolving credit facility ("RCF") of USD 550 million was completed with a consortium of banks in June 2015. The loan has a tenor of four years with extension options of one plus one year at the lenders discretion. The loan carries a margin of 4 per cent, stepping up by 0.5 per cent annually after 3, 4 and 5 years, plus a utilization fee of 1.5 per cent. In addition, a commitment fee of 2.0 per cent is paid on unused credit. This facility is undrawn as of 31 March 2017.

Note 15 Provision for abandonment liabilities

		Group
(USD 1 000)	31.03.2017	31.03.2016	31.12.2016
Provisions as of 1 January	2 156 921	423 325	423 325
Abandonment liabilities from acquisition of BP Norge AS	-	-	1 680 206
Incurred cost removal	-7 684	-1 306	-12 237
Accretion expense - present value calculation	31 713	5 812	47 977
Change in estimates and incurred liabilities on new fields	-	11 807	17 650
Total provision for abandonment liabilities	2 180 950	439 638	2 156 921
Break down of the provision to short-term and long-term liabilities
Short-term	96 365	13 785	75 981
Long-term	2 084 584	425 853	2 080 940
Total provision for abandonment liabilities	2 180 950	439 638	2 156 921

The group's removal and decommissioning liabilities relate mainly to the producing fields.

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 2.5 per cent and a nominal discount rate before tax of between 4.14 per cent and 6.35 per cent.

Note 16 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 17 Subsequent events

Dividend

At the Annual General Meeting in April 2017, the Board was authorized to approve the distribution of dividends based on the company's annual accounts for 2016. On 27 April 2017 the Board of Directors declared a quarterly dividend of USD 62.5 million.The dividend was disbursed on 19 May 2017.

Exploration wells

The Gohta appraisal well 7120/1-5 was completed in the second quarter. The well is classified as dry, with traces of hydrocarbons, and the associated capitalized values will be expensed in Q2 2017.

Notes offering

On 13 June 2017, the Board of Directors approved the offering of Senior Notes amounting to USD 500 million due 2022. The Notes will be senior unsecured debt of the Company and will rank pari passu in right of payment with all of the Company's existing and future senior obligations and senior right of payment to all of the Company's future subordinated obligations. The interest rate of the Notes has not been determined as of the date of this report.

Note 18 Investments in joint operations

The company's investments in licences on the Norwegian Continental Shelf as of:

Tambar Øst 46.200 % 46.200 % Ula 80.000 % 80.000 %

Fields operated:	31.03.2017	31.12.2016	Fields non-operated:	31.03.2017	31.12.2016
Alvheim	65.000 %	65.000 % Atla		10.000 %	10.000 %
Bøyla	65.000 %	65.000 % Enoch		2.000 %	2.000 %
Hod	37.500 %		37.500 % Gina Krog	3.300 %	3.300 %
Ivar Aasen Unit	34.786 %		34.786 % Johan Sverdrup ***	11.573 %	11.573 %
Jette Unit	70.000 %	70.000 % Jotun		7.000 %	7.000 %
Valhall	35.953 %	35.953 % Varg		5.000 %	5.000 %
Vilje	46.904 %	46.904 %
Volund	65.000 %	65.000 %
Tambar	55.000 %	55.000 %

Skarv	23.835 %	23.835 %
Production licences in which Aker BP is the operator: Licence:	31.03.2017	31.12.2016	Production licences in which Aker BP is a partner: Licence:	31.03.2017	31.12.2016
PL 001B	35.000 %		35.000 % PL 006C	15.000 %	15.000 %
PL 006B	35.833 %		35.833 % PL 018DS	13.338 %	13.338 %
PL 019	80.000 %		80.000 % PL 019C	30.000 %	30.000 %
PL 026B	90.260 %	90.260 % PL 026		30.000 %	30.000 %
PL 027D	100.000 %	100.000 % PL 029B		20.000 %	20.000 %
PL 028B	35.000 %	35.000 % PL 035		50.000 %	50.000 %
PL 033	37.500 %		37.500 % PL 035C	50.000 %	50.000 %
PL 033B	37.500 %	37.500 % PL 038		5.000 %	5.000 %
PL 036C	65.000 %		65.000 % PL 048D	10.000 %	10.000 %
PL 036D	46.904 %		46.904 % PL 102C	10.000 %	10.000 %
PL 065	55.000 %		55.000 % PL 102D	10.000 %	10.000 %
PL 088BS	65.000 %		65.000 % PL 102F	10.000 %	10.000 %
PL 103B	70.000 %		70.000 % PL 102G	10.000 %	10.000 %
PL 150	65.000 %	65.000 % PL 265		20.000 %	20.000 %
PL 150B	65.000 %	65.000 % PL 272		50.000 %	50.000 %
PL 169C	50.000 %	50.000 % PL 405		15.000 %	15.000 %
PL 203	65.000 %	65.000 % PL 457*		0.000 %	40.000 %
PL 203B	65.000 %		65.000 % PL 457BS	40.000 %	40.000 %
PL 212	30.000 %	30.000 % PL 492		60.000 %	60.000 %
PL 212B	30.000 %	30.000 % PL 502		22.222 %	22.222 %
PL 212E	30.000 %	30.000 % PL 507		45.000 %	45.000 %
PL 242	35.000 %	35.000 % PL 533		35.000 %	35.000 %
PL 261	50.000 %	50.000 % PL 554		30.000 %	30.000 %
PL 262	30.000 %		30.000 % PL 554B	30.000 %	30.000 %
PL 300	55.000 %		55.000 % PL 554C	30.000 %	30.000 %
PL 340	65.000 %	65.000 % PL 610*		0.000 %	37.500 %
PL 340BS	65.000 %	65.000 % PL 613		20.000 %	20.000 %
PL 364	100.000 %	100.000 % PL 627		20.000 %	20.000 %
PL 407*	0.000 %		50.000 % PL 627B	20.000 %	20.000 %
PL 442	90.260 %	90.260 % PL 650*		0.000 %	25.000 %
PL 460	100.000 %	100.000 % PL 653*		0.000 %	30.000 %
PL 504	47.593 %	47.593 % PL 689*		0.000 %	20.000 %
PL 626	50.000 %		50.000 % PL 689B*	0.000 %	20.000 %
PL 659**	50.000 %	35.000 % PL 694*		0.000 %	20.000 %
PL 677	60.000 %	60.000 % PL 719		20.000 %	20.000 %
PL 715	40.000 %		40.000 % PL 721**	40.000 %	20.000 %
PL 724	40.000 %	40.000 % PL 722		20.000 %	20.000 %
PL 724B	40.000 %	40.000 % PL 778		20.000 %	20.000 %
PL 736S	65.000 %		65.000 % PL 782S	20.000 %	20.000 %
PL 748	50.000 %		50.000 % PL 782SB	20.000 %	20.000 %
PL 762	20.000 %	20.000 % PL 797*		0.000 %	25.000 %
PL 777	40.000 %	40.000 % PL 804*		0.000 %	30.000 %
PL 777B	40.000 %	40.000 % PL 811		20.000 %	20.000 %
PL 784	40.000 %	40.000 % PL 813		3.300 %	3.300 %
PL 790	30.000 %	30.000 % PL 838		30.000 %	30.000 %
PL 814	40.000 %	40.000 % PL 842		30.000 %	30.000 %
PL 818	40.000 %	40.000 % PL 844		20.000 %	20.000 %
PL 821	60.000 %	60.000 % PL 852		40.000 %	40.000 %
PL 822S	60.000 %	60.000 % PL 857		20.000 %	20.000 %
PL 839	23.835 %		23.835 % Number	40	49
PL 843	40.000 %	40.000 %
PL 858	40.000 %	40.000 %

* Relinquished licences or Aker BP has withdrawn from the licence. ** Acquired/changed through licence transactions or licence splits.

Number 51 52

Note 19 Results from previous interim reports

	2017	2016				2015
(USD 1 000)	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Total income	646 250	655 624	247 993	255 665	204 848	254 634	316 393	321 850
Exploration expenses	30 259	44 281	30 843	36 214	36 115	18 867	18 066	24 949
Production costs	120 874	121 139	32 188	39 116	34 374	24 077	26 888	50 686
Depreciation	184 004	159 796	114 649	120 264	114 318	111 590	129 790	117 354
Impairments	29 782	44 627	8 429	-19 644	37 964	191 939	185 756	-
Other operating expenses	8 051	5 029	6 223	5 410	5 330	3 228	11 433	22 550
Total operating expenses	372 969	374 872	192 333	181 360	228 101	349 701	371 932	215 539
Operating profit/loss	273 280	280 752	55 660	74 305	-23 253	-95 067	-55 539	106 311
Net financial items	-46 508	-70 572	-5 107	-28 951	7 620	-56 138	-51 205	-43 136
Profit/loss before taxes	226 772	210 180	50 553	45 353	-15 633	-151 205	-106 744	63 175
Taxes (+)/tax income (-)	157 955	277 183	-12 880	39 046	-47 866	4 980	59 441	55 897
Net profit/loss	68 818	-67 003	63 433	6 308	32 233	-156 184	-166 185	7 277

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.

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

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

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 divided by number of barrels of oil equivalents produced in the corresponding period

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