Aker BP

Quarterly Report • Jul 14, 2017

Q2 2017 QUARTERLY REPORT FOR AKER BP ASA

KEY EVENTS IN Q2 2017

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
14 June:	The company announced that it had obtained credit ratings from S&P (BB+) and Moody's (Ba2)
28 June:	The company announced pricing of a 5-year USD 400 million senior notes offering at 6.0 percent
30 June:	The company announced that it had exercised a redemption right for the DETNOR03 bond

KEY EVENTS AFTER THE QUARTER

13 July: The Board declared a quarterly dividend of USD 0.185 per share to be paid out in August 2017

SUMMARY OF FINANCIAL RESULTS

	Unit	Q2 2017	Q2 2016	2017 YTD	2016 YTD
Operating income	USDm	595	256	1 241	461
EBITDA	USDm	395	175	882	304
Net result	USDm	60	6	129	39
Earnings per share (EPS)	USD	0.18	0.03	0.38	0.19
Production cost per barrel	USD/boe	9	7	9	7
Depreciation per barrel	USD/boe	14	21	14	21
Cash flow from operations	USDm	447	127	882	323
Cash flow from investments	USDm	-312	-325	-582	-556
Total assets	USDm	9 331	5 609	9 331	5 609
Net interest-bearing debt (book value)	USDm	2 302	2 783	2 302	2 783
Cash and cash equivalents	USDm	66	68	66	68

SUMMARY OF PRODUCTION

	Unit	Q2 2017	Q2 2016	2017 YTD	2016 YTD
Alvheim (65%)	boepd	61 788	39 923	63 078	39 170
Bøyla (65%)	boepd	4 935	7 923	4 741	8 504
Hod (37.5%)	boepd	580	-	574	-
Ivar Aasen (34.8%)	boepd	17 257	-	16 136	-
Skarv (23.8%)	boepd	29 326	-	30 461	-
Tambar / Tambar East (55.0%/46.2%)	boepd	2 621	-	2 341	-
Ula (80%)	boepd	7 232	-	6 710	-
Valhall (36.0%)	boepd	13 080	-	13 933	-
Vilje (46.9%)	boepd	5 795	7 615	5 700	6 396
Volund (65%)	boepd	4	6 033	264	6 239
Other (Jette, Jotun, Varg, Atla, Enoch)	boepd	95	946	80	1 219
SUM	boepd	142 713	62 440	144 018	61 527
Oil price	USD/bbl	51	49	53	44
Gas price	USD/scm	0.18	0.17	0.20	0.18

3

SUMMARY OF THE QUARTER

Aker BP ASA ("the company" or "Aker BP") reported total income of USD 595 (256) million in the second quarter of 2017. Production in the period was 142.7 (62.4) thousand barrels of oil equivalent per day ("mboepd"), realising an average oil price of USD 51 (49) per barrel, while gas revenues were recognized at market value of USD 0.18 (0.17) per standard cubic metre (scm). Production cost per barrel of oil equivalents ("boe") was USD 9.3 (6.9).

EBITDA amounted to USD 395 (175) million in the quarter and EBIT was USD 210 (74) million. Net profit for the quarter was USD 60 (6) million, translating into an EPS of USD 0.18 (0.03). Net interest-bearing debt amounted to USD 2,302 (2,783) million per 30 June 2017.

Production from the Alvheim area remained both stable and high in the second quarter. The Transocean Arctic drilling rig has completed the infill wells at Volund and has commenced drilling of the first of two infill wells at Boa.

Production from the Skarv area remained high and stable during the quarter. Drilling from the Valhall injection platform continued and P&A activity commenced with the Maersk Invincible drilling rig.

Production at Ivar Aasen has continued to ramp-up during the second quarter. The Gina Krog field started producing at the end of the quarter. The Johan Sverdrup project is progressing according to plan and pre-drilling of injector wells is ongoing.

Drilling of the Gohta 3 appraisal well in the Barents Sea and the Volund West exploration well in the Alvheim area were completed in the quarter, both dry.

In May, 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)	Q2 2017	Q2 2016
Operating income	595	256
EBITDA	395	175
EBIT	210	74
Pre-tax profit/loss	127	45
Net profit	60	6
EPS (USD)	0.18	0.03

Income statement Statement of financial position

(USD million)	Q2 2017	Q2 2016
Goodwill	1 817	739
PP&E	4 725	3 305
Cash & cash equivalents	66	68
Total assets	9 331	5 609
Equity	2 453	378
Interest-bearing debt	2 368	2 852

Total income in the second quarter was USD 595 (256) million, higher than the second quarter 2016 mainly due to inclusion of BP Norge AS activities. Petroleum revenues accounted for USD 590 (271) million, while other income was USD 4 (-16) million, primarily relating to realized and unrealized gains and losses on commodity hedges.

Exploration expenses amounted to USD 75 (36) million in the quarter, reflecting dry hole costs, seismic costs, area fees and G&G activities. Production costs were USD 121 (39) million, equating to 9.3 (6.9) USD/boe, including shipping and handling of 2.5 USD/boe. The increase from the second 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 3 (5) million, a decrease from the second quarter 2016 following certain one-off items.

Depreciation amounted to USD 184 (120) million, corresponding to 14 (21) USD/boe, which represents a decrease from second quarter 2016 mainly due to the inclusion of the BP Norge assets.

The company recorded an operating profit of USD 210 (74) million in the second quarter, higher than the second quarter 2016 primarily due to the merger with BP Norge. The net profit for the period was USD 60 (6) million after net financial items of USD 84 (29) million, including a redemption fee for the DETNOR03 bond of USD 30 million and a tax expense of USD 67 (39) million. Earnings per share were USD 0.18 (0.03).

Total intangible assets amounted to USD 3,444 (1,666) million, of which goodwill was USD 1,817 (739) million. The increase from the second quarter 2016 is related to the merger with BP Norge AS.

Property, plant and equipment increased to USD 4,725 (3,305) 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 402 (207) million at the end of the quarter relating to exploration spend and payout of tax refunds.

The group's cash and cash equivalents were USD 66 (68) million as of 30 June. Total assets were USD 9,331 (5,609) million at the end of the quarter.

Equity amounted to USD 2,453 (378) 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, offset by a quarterly dividend payment in the fourth quarter 2016.

Deferred tax liabilities decreased to USD 1,125 (1,440) million and are detailed in note 7 to the financial statements.

Gross interest-bearing debt decreased to USD 2,368 (2,852) million, consisting of the DETNOR02 bond of USD 224 million, the DETNOR03 bond of USD 330 million (inclusive of the call premium) and the Reserve Based Lending ("RBL") facility of USD 1,814 million.

Statement of cash flow

(USD million)	Q2 2017	Q2 2016
Cash flow from operations	447	127
Cash flow from investments	-312	-325
Cash flow from financing	-253	112
Net change in cash & cash eq.	-118	-85
Cash and cash eq. EOQ	66	68

Net cash flow from operating activities was USD 447 (127) 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 -312 (-325) million. Investments in fixed assets amounted to USD 271 (279) million for the quarter, mainly reflecting capital expenditures ("CAPEX") on Ivar Aasen, Alvheim and Johan Sverdrup. Investments in intangible assets including capitalized exploration were USD 21 (44) million in the quarter and payment for decommissioning activities were USD 20 (2) million in the quarter.

Net cash flow from financing activities totaled USD -253 (112) million, reflecting a repayment of USD 190 million 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 second quarter, the company had total available liquidity of USD 2.7 (1.0) billion, comprising of cash and cash equivalents of USD 66 (68) million and undrawn credit facilities of USD 2,605 (953) million.

No bondholders exercised the distribution put option following the dividend payment in May. Aker BP consequently owns DETNOR02 bonds equal to NOK 3.8 million.

On 28 June, the company priced a notes offering of USD 400 million aggregate principal amount of 6.00% senior notes due 2022 at par. Interest will be payable semi-annually. The offering was closed on 5 July 2017.

On 30 June, the company notified Nordic Trustee ASA of its intention to exercise its redemption right for bond issue DETNOR03 (ISIN NO 001073638.2) as per Clause 10.3 of the Bond Agreement. The entire bond issue will be repaid at 110 per cent of par value (plus accrued interest), with settlement date 31 July 2017. The balance of the high yield bond proceeds will be used to repay (without cancelling) drawn commitments under the company's RBL credit facility and pay the costs, fees and expenses related to the offering.

Ahead of the notes offering, Aker BP obtained credit ratings from S&P and Moody's. S&P assigned a BB+ long-term corporate credit rating with stable outlook. Moody's assigned a Ba2 corporate family rating with stable outlook.

In their ratings reports the agencies note Aker BP's strong financial profile, the low cost profile of assets as well as the supportive and predictable fiscal regime.

The Company is currently in advanced discussions with the lenders in the RBL syndicate about amending this facility. The aim is to achieve a cost effective structure with flexibility and ease of administration. As part of this process, the company intends to cancel its second lien RCF facility which was established in June 2015.

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 19 May 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 13 July 2017 the Board of Directors declared a quarterly dividend of USD 0.185 per share, to be disbursed on or about 9 August 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 second quarter, one High Potential Incident (HIPO) involving a dropped object was recorded on the Skarv FPSO. The incident is being thoroughly investigated and learnings will be distributed throughout the organisation. There was one recordable injury (LTI) in the second quarter. A series of initiatives have been launched to increase safety awareness within the offshore population.

Most of the activities in an offshore operation are conducted by contractors, hence working with contractors is an important part of the safety agenda

in Aker BP. A HSE Contractor day event was conducted in June. More than forty contractors were present to discuss leadership approach in order to understand the barriers to prevent major accidents.

During the quarter, extensive work has been undertaken to build the HSE governing processes which will be a part of the new business management system. An extensive effort has been conducted in order to establish new and harmonized processes.

The Aker BP research and development projects portfolio within HSE has been developed and much attention has been given to the Arctic regions in order to create a deeper understanding of the environmental aspects of the area.

OPERATIONAL REVIEW

Aker BP produced 13.0 (5.7) mmboe in the second quarter of 2017, corresponding to 142.7 (62.4) mboepd. The average realized oil price was USD 51 (49) per barrel, while gas revenues were recognized at market value of USD 0.18 (0.17) 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 stable and high in the second quarter. Production from the Viper Kobra wells has been higher than anticipated, but started to decline during the quarter. The wells still perform very well and continue to be the main contributor to the increased production from the Alveim area.

The Volund West and South infill wells have been completed and one well was hooked up and commenced production in July.

The production efficiency in the quarter was 98 percent.

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 second quarter partly driven by normal reservoir depletion, and partly by temporary shutdowns related to drilling and well operations.

During the quarter, four parallel drilling and wells operations have been in progress. Maersk Invincible continue the P&A campaign at Valhall while IP rig drilling is progressing very well and two wireline crews run production and abandonment well interventions.

Overall production efficiency in the quarter was 85 percent.

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 Faroe operated Oselvar field.

Production from the Ula area increased in the second quarter, with the increase largely coming from a few cyclic wells. The alternating water and gas injection mode of these wells is expected to cause fluctuation in production volumes going forward.

The production efficiency averaged at 69 percent in the quarter.

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 second quarter. Two wells at Skarv are currently shut in due to technical issues. Due to ample capacity from the other wells, the impact of these shutins on production has been insignificant. The wells are

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 second quarter, approximately 60 percent of the Phase 1 facilities construction has been completed.

After a successful completion of the eight pre-drilled production wells and a four well pilot/appraisal campaign for further improvement of reservoir definition, the planned pre-drilling of 10 water injection wells has had good progress.

likely to be recompleted, and the company is taking steps to prevent similar problems elsewhere.

The production efficiency ended at 96 percent in the quarter.

Ivar Aasen PL001B/242/457 (operator)

Operations at Ivar Aasen (34.786 percent) were very good in the second quarter of 2017 continuing the production ramp-up according to the processing agreement. The full agreed throughput was reached in the quarter. Some production losses arose during the quarter from power availability issues, with mitigating actions being implemented.

The production efficiency ended at 90 percent in the quarter.

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

The Gina Krog field (3.3 percent) started production on 30 June. The field has been 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 field is operated by Statoil.

The front end engineering and design ("FEED") has progressed well for the Phase 2 installations, aiming for a high engineering maturity level prior to the final investment decision and Plan for Development and Operation (PDO) for Phase 2 scheduled for the second half of 2018. 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 fifth platform at the field centre (increasing the production capacity from 440 000 to 660 000 barrels of oil per day). Phase 2 includes 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 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 Sverdrup 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 1 April.

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 being executed through long-term strategic frame agreements and alliances. PDO preparation is also progressing according to plan. The NUI fixed facilities alliance is set up and progressing well on FEED.

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.

North of Alvheim and Askja-Krafla (NOAKA) PL442/026B/364 (operator) and PL272 (partner)

The North of Alvheim and Askja-Krafla (NOAKA) area consists of the discoveries Frigg Gamma Delta, Langfjellet, Frøy, Fulla and Askja-Krafla. The area development is a shared initiative between the partners in the licences.

With limited infrastructure available in the area, the goal is to develop an economically robust area solution, which can tie-in neighbouring licenses and open up for new exploration upsides.

The area development solution is likely to include subsea structures and unmanned/ normally unmanned installations on the individual reservoirs based on their size and complexity.

The project is expected to be further matured towards a planned concept selection (DG2) decision in 2018.

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 in 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 km southeast of Ula. In the first quarter, the Tambar license approved a development project which will add two production wells to the field plus modify facilities to provide gas lift from Ula field to new and existing Tambar wells. Drilling will also test the oil-water contact in the northern part of the field, and thus contribute to increased understanding of the Tambar reservoir.

During the second quarter, key project activities involved procurement, engineering and prefabrication in preparation for offshore facility modifications. Drilling with the Maersk Interceptor is expected to start in the fourth quarter.

Oda

PL405 (partner)

The Oda field is being developed with a subsea template tied back to the Aker BP operated Ula field centre via the existing Oselvar infrastructure. The project involves two production wells and one water injector well. Aker BP performs the required facilty modifications to receive production from and provide injection water to Oda. Oda's recoverable reserves are estimated at 48

EXPLORATION

During the quarter, the company's cash spending on exploration was USD 61 million. USD 75 million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees and G&G costs.

Drilling of the Gohta 3 appraisal well in PL492 in the Barents Sea commenced in March and was finalised in early May. 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 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 was classified as dry, with traces of hydrocarbons.

mmboe (gross). Natural gas from Oda will support Ula development strategy in provision of gas for the water alternating gas (WAG) injection regime.

The PDO was submitted to the Ministry of Petroleum and Energy on 30 November 2016 and was approved in May 2017. Total investments for Oda are estimated to NOK 5.4 billion. First oil from Oda is expected in second quarter of 2019.

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.

The Volund West prospect was drilled in May and June by Transocean Arctic in PL150B 11 km southwest of Alvheim, and was classified as dry. The well encountered a seven metres thick sandstone layer with very good reservoir properties, interpreted to be the prognosed injected sandstones from the Hermod Formation below, but the sandstones had weak shows of hydrocarbons.

BUSINESS DEVELOPMENT

In June, the company entered into an agreement to transfer its 7 percent participating interest in the Jotun Unit to ExxonMobil Exploration and Production Norway

AS. Following this transaction, Aker BP holds no interest in the Jotun Unit. The transaction is subject to regulatory approval.

REPORT FOR THE FIRST HALF 2017

(USD million)	Per 30 June 2017	Per 30 June 2016
Oil and gas production (mboepd)	144.0	61.5
Oil price (USD/bbl)	53	44
Operating income (USDm)	1 241	461
EBITDA (USDm)	882	304
Net result (USDm)	129	39
Net interest-bearing debt (USDm)	2 302	2 783

During the first six months, the company reported consolidated revenues of USD 1,241 (461) million. Production in the period was 144.0 (61.5) thousand barrels of oil equivalent per day ("mboepd"), realising an average oil price of USD 53 (44) per barrel.

EBITDA amounted to USD 882 (304) million in the period and EBIT was USD 484 (51) million. Net profit for the first half of 2017 were USD 129 (39) million, translating into an EPS of USD 0.38 (0.19).

Per 30 June 2017, the company had net interest-bearing debt of USD 2,302 million and cash and undrawn credit of about USD 2.7 billion.

The company had two high potential (HIPO) incidents during the first half of 2017, both are being thoroughly investigated and learnings distributed and embedded. With the continued high activity level, significant attention is paid to achieving and maintaining the highest HSE standards across all disciplines and preventing injuries and undesired events related to all activities.

The Alvheim fields have had stable and high operations and high uptime in the first half of 2017, primarily driven by increased production from Viper-Kobra. The Volund West and South infill wells have been completed and one well was hooked up and commenced production in July.

Production from the Valhall area has been characterised by reservoir depletion in the first half of 2017. The Marsk Invicible commenced a P&A campaign and the Valhall IP drilling program has progressed well.

Production from the Ula area has increased in the first half of 2017 caused by good results from water

alternating gas (WAG) injection and from cyclic wells.

Production from the Skarv area has been high and stable during the first half of 2017.

First oil at the Ivar Aasen field was achieved at the end of 2016 with solid operations during the first half of 2017. Production is expected to ramp-up during 2017 in line with the commercial agreement with the neighboring Edvard Grieg field. During the first half of 2017, the Maersk Interceptor rig continued to drill production and injection wells.

First oil at Gina Krog was achieved on 30 June 2017.

Phase 1 of the Johan Sverdrup development is progressing according to plan towards production start-up in the fourth quarter 2019. Most major contracts have been awarded and engineering and construction are ongoing on 22 sites internationally. At the end of the second quarter, approximately 60 percent of the Phase 1 facilities construction has been completed. After a successful completion of the eight pre-drilled production wells and a four well pilot/appraisal campaign for further improvement of reservoir definition, the planned pre-drilling of 10 water injection wells has had good progress.

The FEED has progressed well for the Phase 2 installations, aiming for a high engineering maturity level prior to the final investment decision and PDO for Phase 2 scheduled for the second half of 2018. Phase 2 production start is expected in 2022.

Aker BP participated in four exploration wells during the first half of 2017. Drilling of the Filicudi prospect in PL533 in the Barents Sea was successfully completed in the first quarter. Preliminary volume estimates for

the oil and gas discovery are in the range of 35 to 100 million barrels of oil equivalent. The Tonjer well in PL265, the Gohta 3 well in PL492 and the Volund West well in PL150B were dry.

In January 2017, Aker BP 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.

At the end of the second quarter, the company had total available liquidity of USD 2.7 (1.0) billion, comprising of cash and cash equivalents of USD 66 (68) million and undrawn credit facilities of USD 2,605 (953) million.

On 28 June, the company priced a notes offering of USD 400 million aggregate principal amount of 6.00% senior notes due 2022 at par. Interest will be payable semiannually. The offering was closed on 5 July 2017.

Ahead of the notes offering, Aker BP obtained credit ratings from S&P and Moody's. S&P assigned a BB+ long-term corporate credit rating with stable outlook. Moody's assigned a Ba2 corporate family rating with stable outlook.

On 30 June, the company notified Nordic Trustee ASA of its intention to exercise its redemption right for bond issue DETNOR03. The entire bond issue will be repaid at 110 per cent of par value (plus accrued interest).

RISKS AND UNCERTAINTY

Investment in Aker BP involves risks and uncertainties as described in the company's annual report for 2016.

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 field's production performance may be uncertain 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 28 to the accounts for 2016. 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 accomplished.

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 selectively pursues 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 August 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 third quarter. Operations include completion of the PDO scope at Ivar Aasen, new production wells and P&A activity at Valhall, plus drilling of the operated Hyrokkin and Nordfjellet/Delta prospects in the North Sea.

Aker BP is in the process of preparing to submit three PDOs during 2017, relating to the Valhall West Flank, Snadd and Storklakken projects.

The company has a robust balance sheet, providing the company with ample financial flexibility. As part of the work to optimise the capital structure, the company expects to redeem its USD 300 million subordinated bond and to cancel its USD 550 million revolving credit facility.

The company updates its production guidance that was presented at the Capital Markets Day in January. Aker BP expects to produce between 135 and 140 mboepd in 2017 (previously 128 – 135 mboepd) with a production cost of approximately 10 USD/boe (previously approximately 11 USD/boe). The full year 2017 CAPEX guidance is unchanged and expected to be between USD 900 – 950 million, guidance for 2017 exploration expenditures is unchanged at USD 280 – 300 million and no change has been made to the expected 2017 decommissioning costs, between USD 100 – 110 million.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT (Unaudited)

		Group
		Q2		01.01.-30.06.
(USD 1 000)	Note	2017	2016	2017	2016
Petroleum revenues	2	590 471	271 272	1 237 642	472 040
Other income	2	4 031	-15 608	3 109	-11 527
Total income		594 501	255 665	1 240 751	460 513
Exploration expenses	3	75 375	36 214	105 634	72 329
Production costs		121 017	39 116	241 891	73 490
Depreciation	5	184 194	120 264	368 198	234 582
Impairments	4, 5	365	-19 644	30 147	18 319
Other operating expenses		3 113	5 410	11 164	10 741
Total operating expenses		384 065	181 360	757 034	409 461
Operating profit/loss		210 436	74 305	483 717	51 052
Interest income		1 085	1 523	2 159	2 340
Other financial income		15 384	10 437	30 230	41 194
Interest expenses		31 259	21 125	61 267	41 826
Other financial expenses		68 806	19 786	101 227	23 040
Net financial items	6	-83 597	-28 951	-130 105	-21 331
Profit/loss before taxes		126 840	45 353	353 612	29 720
Taxes (+)/tax income (-)	7	66 944	39 046	224 898	-8 821
Net profit/loss		59 896	6 308	128 714	38 541
Weighted average no. of shares outstanding basic and diluted Basic and diluted earnings/(loss) per share		337 737 071 0.18	202 618 602 0.03	337 737 071 0.38	202 618 602 0.19

STATEMENT OF COMPREHENSIVE INCOME (Unaudited)

		Group
		Q2		01.01.-30.06.
(USD 1 000)	Note	2017	2016	2017	2016
Profit/loss for the period		59 896	6 308	128 714	38 541
Items which may be reclassified over profit and loss (net of taxes)
Currency translation adjustment		-	-	-356	-59
Total comprehensive income in period		59 896	6 308	128 358	38 482

STATEMENT OF FINANCIAL POSITION (Unaudited)

		Group
(USD 1 000) Note	30.06.2017	30.06.2016	31.12.2016
ASSETS
Intangible assets
Goodwill 5	1 817 486	739 383	1 846 971
Capitalized exploration expenditures 5	344 268	316 913	395 260
Other intangible assets 5	1 282 600	609 943	1 332 813
Tangible fixed assets
Property, plant and equipment 5	4 724 803	3 305 081	4 441 796
Financial assets
Long-term receivables	44 107	1 724	47 171
Long-term tax receivable 7	-	28 090	-
Other non-current assets	23 643	13 545	12 894
Long-term derivatives 11	7 398	2 287	-
Total non-current assets	8 244 305	5 016 966	8 076 905
Inventories
Inventories	64 867	35 816	69 434
Receivables Accounts receivable	101 441	43 572	170 000
Other short-term receivables 8	446 493	227 306	422 932
Other current financial assets	-	2 951	-
Tax receivables 7	401 857	206 749	400 638
Short-term derivatives 11	6 149	6 774	-
Cash and cash equivalents
Cash and cash equivalents 9	65 569	68 393	115 286
Total current assets	1 086 377	591 561	1 178 290
TOTAL ASSETS	9 330 683	5 608 527	9 255 196

STATEMENT OF FINANCIAL POSITION (Unaudited)

		Group
(USD 1 000) Note	30.06.2017	30.06.2016	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	-752 351	-689 639	-755 709
Total equity	2 452 565	377 508	2 449 207
Non-current liabilities
Deferred taxes 7	1 124 750	1 439 940	1 045 542
Long-term abandonment provision 15	2 109 309	445 085	2 080 940
Provisions for other liabilities 10	196 541	1 204	218 562
Long-term bonds 13	223 523	515 486	510 337
Other interest-bearing debt 14	1 814 053	2 336 361	2 030 209
Long-term derivatives 11	24 315	38 117	35 659
Current liabilities
Short-term bonds 13	330 000	-	-
Trade creditors	75 090	74 879	88 156
Accrued public charges and indirect taxes	22 882	7 343	39 048
Tax payable 7	224 957	-	92 661
Short-term derivatives 11	-	230	5 049
Short-term abandonment provision 15	112 907	17 504	75 981
Other current liabilities 12	619 789	354 870	583 844
Total liabilities	6 878 117	5 231 019	6 805 988
TOTAL EQUITY AND LIABILITIES	9 330 683	5 608 527	9 255 196

STATEMENT OF CHANGES IN EQUITY - GROUP (Unaudited)

				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 31.12.2016	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 31.3.2017	54 349	3 150 567	573 083	-88	-115 907	-1 206 836	-749 748	2 455 169
Dividend distributed	-	-	-	-	-	-62 500	-62 500	-62 500
Profit/loss for the period 01.04.2017 - 30.06.2017	-	-	-	-	-	59 896	59 896	59 896
Equity as of 30.06.2017	54 349	3 150 567	573 083	-88	-115 907	-1 209 440	-752 351	2 452 565

* 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 (Unaudited)

		Group
		Q2		01.01.-30.06.		Year
(USD 1 000)	Note	2017	2016	2017	2016	2016
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		126 840	45 353	353 612	29 720	290 453
Taxes paid during the period		-	-1 268	-	-1 268	-1 419
Tax refund during the period		-	-	-	-	212 944
Depreciation	5	184 194	120 264	368 198	234 582	509 027
Net impairment losses	4, 5	365	-19 644	30 147	18 319	71 375
Accretion expenses	6, 15	32 742	6 063	64 456	11 875	47 977
Interest expenses	6	44 874	39 599	86 040	77 234	160 808
Interest paid		-45 614	-47 481	-86 770	-76 913	-161 634
Changes in derivatives	2, 6	-17 766	34 876	-29 939	-1 014	10 408
Amortized loan costs	6	10 520	4 287	17 663	7 396	17 915
Gain on change of pension scheme		-	-	-	-	-115 616
Amortization of fair value of contracts	10	8 155	-	8 155	-	-
Expensed capitalized dry wells	3, 5	34 562	17 938	35 621	34 389	51 669
Changes in inventories, accounts payable and receivables		42 217	-161 403	36 499	-60 623	-317 488
Changes in abandonment liabilities through income statement		-	-	-	-	-1 131
Changes in other current balance sheet items		25 600	88 695	-1 517	49 414	120 365
NET CASH FLOW FROM OPERATING ACTIVITIES		446 691	127 279	882 165	323 110	895 652
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	15	-20 282	-1 714	-27 966	-3 020	-12 237
Disbursements on investments in fixed assets	5	-271 105	-278 872	-503 512	-488 151	-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	-20 547	-44 039	-50 451	-65 267	-181 492
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-311 934	-324 625	-581 929	-556 438	-705 494
CASH FLOW FROM FINANCING ACTIVITIES
Repayment of long-term debt		-190 000	-	-225 470	-	-612 825
Net proceeds from issuance of long-term debt		-	112 328	-	212 328	512 013
Paid dividend		-62 500	-	-125 000	-	-62 500
NET CASH FLOW FROM FINANCING ACTIVITIES		-252 500	112 328	-350 470	212 328	-163 312
Net change in cash and cash equivalents		-117 743	-85 019	-50 234	-20 999	26 846
Cash and cash equivalents at start of period		182 795	154 618	115 286	90 599	90 599
Effect of exchange rate fluctuation on cash held		517	-1 206	517	-1 206	-2 158
CASH AND CASH EQUIVALENTS AT END OF PERIOD	9	65 569	68 393	65 569	68 393	115 286
SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits and cash		57 069	62 411	57 069	62 411	106 369
Restricted bank deposits		8 501	5 983	8 501	5 983	8 917
CASH AND CASH EQUIVALENTS AT END OF PERIOD	9	65 569	68 393	65 569	68 393	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 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 13 July 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
	Q2		01.01.-30.06.
Breakdown of petroleum revenues (USD 1 000)	2017	2016	2017	2016
Recognized income liquids	502 180	250 022	1 049 491	430 410
Recognized income gas	82 976	19 311	177 181	37 414
Tariff income	5 316	1 940	10 970	4 217
Total petroleum revenues	590 471	271 272	1 237 642	472 040
Breakdown of produced volumes (barrels of oil equivalent)
Liquids	10 071 954	5 025 916	20 352 340	9 845 062
Gas	2 914 916	656 148	5 714 938	1 352 941
Total produced volumes	12 986 870	5 682 064	26 067 278	11 198 003
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-1 053	5 988	-3 601	23 062
Unrealized gain/loss (-) on oil derivatives	4 016	-25 312	5 407	-38 443
Gain on license transactions	556	-	556	-
Other income	511	3 716	748	3 854
Total other income	4 031	-15 608	3 109	-11 527

Note 3 Exploration expenses

			Group
	Q2		01.01.-30.06.
Breakdown of exploration expenses (USD 1 000)	2017	2016	2017	2016
Seismic	17 418	5 171	27 807	6 195
Area fee	3 264	2 842	8 572	5 104
Dry well expenses*	34 562	17 938	35 621	34 389
Other exploration expenses	20 130	10 263	33 634	26 640
Total exploration expenses	75 375	36 214	105 634	72 329

*Mainly related to the Gohta and Volund West wells

Note 4 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment triggers are identified.

As described in previous financial reporting, the technical goodwill recognized in relation to prior year`s business combinations, will be subject to impairment charges as it is fully allocated to the respective individual CGU's. Hence, a quarterly impairment charge is expected if all assumptions remain unchanged. However, in Q2 2017 the positive impact from profile updates exceeds the negative impact from decreased forward curves compared to Q1 2017. The group's calculation shows that no impairment charge of technical goodwill is needed. Previous impairment of technical goodwill in 2017 amounted to USD 29.2 million.

The minor impairment of USD 0.4 million in the quarter relates to intangible assets recognized in acquisitions of exploration licenses which have been relinguished.

Note 5 Tangible assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

		Production	Fixtures and
(USD 1 000)	Assets under development	facilities including wells	fittings, office machinery	Total
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 31.3.2017	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 31.3.2017	1 560	1 606 213	25 427	1 633 200
Book value 31.3.2017	1 158 564	3 407 011	34 050	4 599 627
Acquisition cost 31.3.2017	1 160 124	5 013 224	59 478	6 232 826
Additions	227 971	52 059	11 725	291 755
Disposals	4 200	-	1 685	5 884
Reclassification	-136 657	132 258	1 996	-2 404
Acquisition cost 30.06.2017	1 247 238	5 197 541	71 514	6 516 293
Accumulated depreciation and impairments 31.3.2017	1 560	1 606 213	25 427	1 633 200
Depreciation	-	157 551	2 424	159 975
Impairment	-	-	-	-
Retirement/transfer depreciations	-	-	-1 685	-1 685
Accumulated depreciation and impairments 30.06.2017	1 560	1 763 765	26 167	1 791 491
Book value 30.06.2017	1 245 678	3 433 777	45 347	4 724 803

* The reclassification in this quarter is mainly related to Gina Krog which entered into production phase during the quarter.

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.

INTANGIBLE ASSETS - GROUP

	Other intangible assets			Exploration
(USD 1 000)	Licences etc.	Software	Total	wells	Goodwill
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 31.3.2017	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 31.3.2017	267 606	7 293	274 898	-	903 025
Book value 31.3.2017	1 307 803	208	1 308 011	355 910	1 817 810
Acquisition cost 31.3.2017	1 575 409	7 501	1 582 910	355 910	2 720 835
Additions	41	-	41	20 506	-
Disposals/expensed dry wells	858	-	858	34 562	324
Reclassification*	-11	-	-11	2 414	-
Acquisition cost 30.06.2017	1 574 581	7 501	1 582 082	344 268	2 720 511
Accumulated depreciation and impairments 31.3.2017	267 606	7 293	274 898	-	903 025
Depreciation	24 149	70	24 219	-	-
Impairment	365	-	365	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 30.06.2017	292 119	7 363	299 482	-	903 025
Book value 30.06.2017	1 282 462	138	1 282 600	344 268	1 817 486

	Group
	Q2			01.01.-30.06.
Depreciation in the Income statement (USD 1 000)	2017	2016	2017	2016
Depreciation of tangible fixed assets	159 975	96 753	319 600	192 551
Depreciation of intangible assets	24 219	23 512	48 598	42 031
Total depreciation in the Income statement	184 194	120 264	368 198	234 582
Impairment in the Income statement (USD 1 000)
Impairment/reversal of tangible fixed assets	-	-19 644	-6	-9 870
Impairment/reversal of intangible assets	365	-	992	-
Impairment of goodwill	-	-	29 161	28 189
Total impairment in the Income statement	365	-19 644	30 147	18 319

Note 6 Financial items

	Group
	Q2		01.01.-30.06.
(USD 1 000)	2017	2016	2017	2016
Interest income	1 085	1 523	2 159	2 340
Realized gains on derivatives	1 634	1 237	2 023	1 737
Change in fair value of derivatives	13 750	-	24 533	39 457
Net currency gains Total other financial income	- 15 384	9 200 10 437	3 674 30 230	- 41 194
Interest expenses	44 874	39 599	86 040	77 234
Capitalized interest cost, development projects	-24 135	-22 761	-42 436	-42 804
Amortized loan costs*	10 520	4 287	17 663	7 396
Total interest expenses	31 259	21 125	61 267	41 826
Net currency losses	2 426	-	-	1 509
Realised loss on derivatives Change in fair value of derivatives	1 351 -	1 239 9 564	2 862 -	5 029 -
Accretion expenses	32 742	6 063	64 456	11 875
Other financial expenses**	32 287	2 921	33 909	4 627
Total other financial expenses	68 806	19 786	101 227	23 040
Net financial items	-83 597	-28 951	-130 105	-21 331

* In June 2017 the company notified Nordic trustee that it is exercising its early redemption right for bond issue DETNOR03. Remaining unamortized fees related to this bond issue have thus been expensed in Q2.

** As a result of the early redemption of DETNOR03, the entire bond issue will be repaid at 110 per cent of par value, in accordance with the early redemption terms in the Bond agreement. The related cost of USD 30 million has been included in other financial expenses in Q2.

Note 7 Taxes

	Group
	Q2			01.01.-30.06.
Taxes for the period appear as follows (USD 1 000)	2017	2016	2017	2016
Calculated current year tax/exploration tax refund	101 524	-22 745	140 535	-28 835
Change in deferred taxes in the Income statement	-35 290	56 840	84 903	15 262
Prior period adjustments	710	4 951	-540	4 752
Total taxes (+)/tax income (-)	66 944	39 046	224 898	-8 821

		Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	30.06.2017	30.06.2016	31.12.2016
Tax receivable/payable at 01.01.	307 977	126 391	126 391
Current year tax (-)/tax receivable (+)	-140 535	28 835	131 488
Tax receivable related to acquisitions/sales	-91	64 453	255 873
Tax payment/tax refund	-	1 268	-211 525
Prior period adjustments	3 623	4 729	-1 681
Revaluation of tax receivable	5 925	9 163	7 430
Total net tax receivable (+)/tax payable (-)	176 900	234 840	307 977
Tax receivable included as current assets (+)	401 857	206 749	400 638
Tax receivable included as non-current assets (+)	-	28 090	-
Tax payable included as current liabilities (-)	-224 957	-	-92 661

	Group
Deferred taxes (-)/deferred tax asset (+) (USD 1 000)	30.06.2017	30.06.2016	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	-84 903	-15 262	-374 617
Reclassification of acquired loss carried forward	-	-60 379	-238 866
Deferred tax related to acquisitions/sales	3 616	1 401	942 611
Prior period adjustment	2 080	-9 587	-18 555
Deferred tax charged to OCI and equity	-	-	-1
Net deferred tax (-)/deferred tax asset (+)	-1 124 750	-1 439 940	-1 045 542

			Group
		Q2	01.01.-30.06.
Reconciliation of tax expense (USD 1 000)	2017	2016	2017	2016
78% tax rate on profit before tax	98 935	35 376	275 818	23 182
Tax effect on uplift	-31 757	-26 527	-62 246	-51 124
Permanent difference on impairment	-	-	22 813	21 987
Foreign currency translation of NOK monetary items	505	-3 955	-2 866	4 719
Foreign currency translation of USD monetary items	34 661	-23 445	46 662	102 174
Tax effect of financial and other 24%/25% items	-5 580	33 235	-9 497	-52 635
Revaluation of tax balances*	-37 733	20 018	-49 910	-59 926
Other permanent differences and prior period adjustment	7 914	4 344	4 125	2 801
Total taxes (+)/tax income (-)	66 944	39 046	224 898	-8 821

* 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)	30.06.2017	30.06.2016	31.12.2016
Receivables related to deferred volume at Atla	-	3 457	-
Prepayments	40 166	29 814	40 730
VAT receivable	9 332	8 760	7 913
Underlift of petroleum	48 465	28 942	70 003
Accrued income from sale of petroleum products	75 086	43 297	86 429
Other receivables, mainly from licenses	273 445	113 035	217 857
Total other short-term receivables	446 493	227 306	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.

		Group
Breakdown of cash and cash equivalents (USD 1 000)	30.06.2017	30.06.2016	31.12.2016
Bank deposits	57 069	62 411	106 369
Restricted funds (tax withholdings)	8 501	5 983	8 917
Cash and cash equivalents	65 569	68 393	115 286
Unused revolving credit facility (see Note 14)	550 000	550 000	550 000
Unused reserve-based lending facility (see Note 14)	2 055 000	403 000	1 805 000

Note 10 Provisions for other liabilities

	Group
Breakdown of provisions for other liabilities (USD 1 000)	30.06.2017	30.06.2016	31.12.2016
Fair value of contracts assumed in acquisition of BP Norge AS*	180 771	-	202 874
Other long term liabilities	15 770	1 204	15 688
Total provisions for other liabilities	196 541	1 204	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)	30.06.2017	30.06.2016	31.12.2016
Unrealized gain currency contracts	7 398	2 287	-
Long-term derivatives included in assets	7 398	2 287	-
Unrealized gain on commodity derivatives	4 225	6 774	-
Unrealized gain currency contracts	1 924	-	-
Short-term derivatives included in assets	6 149	6 774	-
Total derivatives included in assets	13 547	9 061	-
Unrealized losses currency contracts	-	-	5 073
Unrealized losses interest rate swaps	24 315	38 117	30 586
Long-term derivatives included in liabilities	24 315	38 117	35 659
Unrealized losses currency contracts	-	230	3 868
Unrealized losses commodity derivatives	-	-	1 181
Short-term derivatives included in liabilities	-	230	5 049
Total derivatives included in liabilities	24 315	38 347	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.

QUARTERLY REPORT Q2 2017 26

Note 12 Other current liabilities

	Group
Breakdown of other current liabilities (USD 1 000)	30.06.2017	30.06.2016	31.12.2016
Current liabilities related to overcall in licences	53 332	46 506	81 686
Share of other current liabilities in licences	388 982	264 533	360 222
Overlift of petroleum	23 516	4 192	20 000
Fair value of contracts assumed in acquisition of BP Norge AS*	47 524	3 160	36 199
Other current liabilities**	106 436	36 478	85 737
Total other current liabilities	619 789	354 870	583 844

* Refer to note 10.

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

Note 13 Bonds

		Group
(USD 1 000)	30.06.2017	30.06.2016	31.12.2016
DETNOR02 Senior unsecured bond1)	223 523	220 255	214 827
DETNOR03 Subordinated PIK toggle bond 2)	-	295 231	295 510
Long-term bonds	223 523	515 486	510 337
DETNOR03 Subordinated PIK toggle bond 2)	330 000
Short-term bonds	330 000	-	-
Total bonds	553 523	515 486	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. In June 2017 the group notified the DETNOR 03 Bondholders that it is exercising its early redemption right under a Replacing Capital Event, and redeem the entire bond at 110 per cent of par value with settlement date 31 July 2017. The bond has thus been reclassified to short term debt, and the book value reflects the 110 per cent of par value with no remaining amortization of fees.

Note 14 Other interest-bearing debt

	Group
(USD 1 000)	30.06.2017	30.06.2016	31.12.2016
Reserve-based lending facility	1 814 053	2 336 361	2 030 209
Total other interest-bearing debt	1 814 053	2 336 361	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. In connection with the current amendment process, as described in the Financial Review section of the Q2 report, the scheduled redetermination for June 2017 has been waived.

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 30 June 2017.

27

Note 15 Provision for abandonment liabilities

		Group
(USD 1 000)	30.06.2017	30.06.2016	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	-19 811	-3 020	-12 237
Accretion expense - present value calculation	64 456	11 875	47 977
Change in estimates and incurred liabilities on new fields*	20 650	30 409	17 650
Total provision for abandonment liabilities	2 222 216	462 589	2 156 921
Break down of the provision to short-term and long-term liabilities
Short-term	112 907	17 504	75 981
Long-term	2 109 309	445 085	2 080 940
Total provision for abandonment liabilities	2 222 216	462 589	2 156 921

* The change in estimates are mainly related to the completion of new wells on 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 Change of ownership supply vessels

In Q2 2017 two supply vessels leased by the group, have been sold from BP Shipping to Ocean Yield ASA, and the contractual commitments related to the two vessels have thus changed from one related party, as defined by IAS 24, to another. The transaction meets the IAS 24 definition of a related party transaction, though is not a transaction between closely related parties according to the Public Limited Liabilities Act section 3-8.

Note 18 Subsequent events

The group 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 19 Investments in joint operations

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

Skarv 23.835 % 23.835 %

Fields operated:	30.06.2017		31.03.2017 Fields non-operated:	30.06.2017	31.03.2017
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 %
Tambar Øst	46.200 %	46.200 %
Ula	80.000 %	80.000 %

Production licences in which Aker BP is the operator: Production licences in which Aker BP is a partner:
Licence:	30.06.2017	31.03.2017 Licence:		30.06.2017	31.03.2017
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 457BS	40.000 %	40.000 %
PL 203B	65.000 %	65.000 % PL 492		60.000 %	60.000 %
PL 212	30.000 %	30.000 % PL 502		22.222 %	22.222 %
PL 212B	30.000 %	30.000 % PL 507		45.000 %	45.000 %
PL 212E	30.000 %	30.000 % PL 533		35.000 %	35.000 %
PL 242	35.000 %	35.000 % PL 554		30.000 %	30.000 %
PL 261	50.000 %	50.000 % PL 554B		30.000 %	30.000 %
PL 262	30.000 %	30.000 % PL 554C		30.000 %	30.000 %
PL 300	55.000 %	55.000 % PL 613*		0.000 %	20.000 %
PL 340	65.000 %	65.000 % PL 627		20.000 %	20.000 %
PL 340BS	65.000 %		65.000 % PL 627B	20.000 %	20.000 %
PL 364**	90.260 %	100.000 % PL 719		20.000 %	20.000 %
PL 442	90.260 %	90.260 % PL 721		40.000 %	40.000 %
PL 442B****	90.260 %	90.260 % PL 722		20.000 %	20.000 %
PL 460	100.000 %	100.000 % PL 778		20.000 %	20.000 %
PL 504	47.593 %	47.593 % PL 782S		20.000 %	20.000 %
PL 626	50.000 %		50.000 % PL 782SB	20.000 %	20.000 %
PL 659	50.000 %		50.000 % PL 782SC****	20.000 %	20.000 %
PL 677	60.000 %	60.000 % PL 811		20.000 %	20.000 %
PL 715	40.000 %	40.000 % PL 813		3.300 %	3.300 %
PL 724	40.000 %	40.000 % PL 838		30.000 %	30.000 %
PL 724B	40.000 %	40.000 % PL 842		30.000 %	30.000 %
PL 736S*	0.000 %	65.000 % PL 844		20.000 %	20.000 %
PL 748	50.000 %	50.000 % PL 852		40.000 %	40.000 %
PL 748B****	50.000 %	50.000 % PL 857		20.000 %	20.000 %
PL 762	20.000 %		20.000 % PL 862****	50.000 %	50.000 %
PL 777	40.000 %		40.000 % PL 863****	40.000 %	40.000 %
PL 777B	40.000 %		40.000 % PL 864****	20.000 %	20.000 %
PL 777C****	40.000 %		40.000 % PL 871****	20.000 %	20.000 %
PL 784	40.000 %		40.000 % PL 891****	30.000 %	30.000 %
PL 790	30.000 %		30.000 % PL 892****	30.000 %	30.000 %
PL 814	40.000 %		40.000 % PL 902****	30.000 %	30.000 %
PL 818	40.000 %	40.000 % Number		47	48
PL 821	60.000 %	60.000 %
PL 821B****	60.000 %	60.000 % 60.000 %
PL 822S	60.000 %	23.835 %
PL 839	23.835 %	40.000 %
PL 843	40.000 %	40.000 %
PL 858	40.000 %	50.000 %
PL 861* PL 867*	50.000 % 40.000 %	40.000 %
PL 868****	60.000 %	60.000 %

Number 63 64

PL 869**** 40.000 % 40.000 % PL 872**** 40.000 % 40.000 % PL 873**** 40.000 % 40.000 % PL 874**** 90.260 % 90.260 % PL 893**** 60.000 % 60.000 % PL 895**** 60.000 % 60.000 %

* Relinquished licences or Aker BP has withdrawn from the licence.

** Acquired/changed through licence transactions or licence splits. *** According to a ruling by Ministry of Oil and Energy.

**** Interest awarded in the APA Licensing round (Application in Predefined Areas) in 2016. The awards were announced in 2017.

Note 20 Results from previous interim reports

		2017			2016		2015
(USD 1 000)	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Total income	594 501	646 250	655 624	247 993	255 665	204 848	254 634	316 393
Exploration expenses	75 375	30 259	44 281	30 843	36 214	36 115	18 867	18 066
Production costs	121 017	120 874	121 139	32 188	39 116	34 374	24 077	26 888
Depreciation	184 194	184 004	159 796	114 649	120 264	114 318	111 590	129 790
Impairments	365	29 782	44 627	8 429	-19 644	37 964	191 939	185 756
Other operating expenses	3 113	8 051	5 029	6 223	5 410	5 330	3 228	11 433
Total operating expenses	384 065	372 969	374 872	192 333	181 360	228 101	349 701	371 932
Operating profit/loss	210 436	273 280	280 752	55 660	74 305	-23 253	-95 067	-55 539
Net financial items	-83 597	-46 508	-70 572	-5 107	-28 951	7 620	-56 138	-51 205
Profit/loss before taxes	126 840	226 772	210 180	50 553	45 353	-15 633	-151 205	-106 744
Taxes (+)/tax income (-)	66 944	157 955	277 183	-12 880	39 046	-47 866	4 980	59 441
Net profit/loss	59 896	68 818	-67 003	63 433	6 308	32 233	-156 184	-166 185

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

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 2017 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.

The Board of Directors of Aker BP ASA

Oslo, 13 July 2017

Gro Kielland, Board member Bernard Looney, Board member

Bjørn Thore Synsvoll Ribesen, Board member Terje Solheim, Board member

Lone Margrethe Olstad, Board member Kate Thomson, Board member

Karl Johnny Hersvik, Chief Executive Officer

Øyvind Eriksen, Chair of the Board Kjell Inge Røkke, Board member

Anne Marie Cannon, Deputy Chair Trond Brandsrud, Board member

QUARTERLY REPORT Q2 2017 32

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