Aker BP

Quarterly Report • Oct 30, 2017

Q3 2017 QUARTERLY REPORT FOR AKER BP ASA

KEY EVENTS IN Q3 2017

13 July:	The Board declared a quarterly dividend of USD 0.185 per
31 July:	share to be paid out in August 2017 The company repaid its USD 300 million DETNOR03 subordinated bond
10 August:	The company announced a rig contract to Odfjell Drilling for exploration and development drilling in the Norwegian Sea and the Barents Sea in 2018
25 August:	The company cancelled its USD 550 million revolving credit facility
4 September:	The partners in the Johan Sverdrup development reported further project improvements, including a NOK 5 billion reduction in Phase 1 investment costs

KEY EVENTS AFTER THE QUARTER

24 October: Aker BP entered into an agreement to acquire Hess Norge 24 October: The Board proposed to increase the annual dividend level by USD 100 million to USD 350 million, with first uplift expected for fourth quarter 2017 (payable in February 2018) 27 October: The Board declared a quarterly dividend of USD 0.185 per share to be paid in November

SUMMARY OF FINANCIAL RESULTS

	Unit	Q3 2017	Q3 2016	2017 YTD	2016 YTD
Operating income	USDm	596	248	1 837	709
EBITDA	USDm	395	179	1 277	483
Net result	USDm	112	63	241	102
Earnings per share (EPS)	USD	0.33	0.31	0.71	0.50
Production cost per barrel	USD/boe	11	6	10	6
Depreciation per barrel	USD/boe	14	21	14	21
Cash flow from operations	USDm	730	251	1 613	573
Cash flow from investments	USDm	-285	164	-867	-392
Total assets	USDm	9 116	10 280	9 116	10 280
Net interest-bearing debt (book value)	USDm	1 941	2 380	1 941	2 380
Cash and cash equivalents	USDm	81	786	81	786

SUMMARY OF PRODUCTION

	Unit	Q3 2017	Q3 2016	2017 YTD	2016 YTD
Alvheim (65%)	boepd	47 259	41 045	57 747	39 800
Bøyla (65%)	boepd	4 276	6 191	4 584	7 727
Gina Krog (3.3%)	boepd	1 453	-	490	-
Hod (37.5%)	boepd	500	-	549	-
Ivar Aasen (34.8%)	boepd	16 574	-	16 284	-
Skarv (23.8%)	boepd	24 518	-	28 458	-
Tambar / Tambar East (55.0%/46.2%)	boepd	2 145	-	2 275	-
Ula (80%)	boepd	6 468	-	6 629	-
Valhall (36.0%)	boepd	11 132	-	12 989	-
Vilje (46.9%)	boepd	5 063	7 381	5 485	6 727
Volund (65%)	boepd	12 316	4 195	4 325	5 553
Other	boepd	175	1 026	112	1 154
SUM	boepd	131 880	59 839	139 928	60 961
Oil price	USD/bbl	55	47	53	45
Gas price	USD/scm	0.20	0.15	0.20	0.17

3

SUMMARY OF THE QUARTER

Aker BP ASA ("the company" or "Aker BP") reported total income of USD 596 (248) million in the third quarter of 2017. Production in the period was 131.9 (59.8) thousand barrels of oil equivalent per day ("mboepd"), realising an average oil price of USD 55 (47) per barrel, while gas revenues were recognized at market value of USD 0.20 (0.15) per standard cubic metre (scm). Production cost per barrel of oil equivalents ("boe") was USD 11.1 (5.8).

EBITDA amounted to USD 395 (179) million in the quarter and EBIT was USD 219 (56) million. Net profit for the quarter was USD 112 (63) million, translating into an EPS of USD 0.33 (0.31). Net interest-bearing debt amounted to USD 1,941 (2,380) million per 30 September 2017.

Two new wells commenced production at the Volund field during the quarter, resulting in a reallocation of production capacity from the Alvheim field. The Transocean Arctic drilling rig is currently drilling infill wells at Boa.

Production from the Skarv and Valhall areas was impacted by planned maintenance in the third quarter. Drilling from the Valhall injection platform continued and P&A activity commenced with the Maersk Invincible drilling rig.

Production at Ivar Aasen has remained stable in the third quarter. The Johan Sverdrup project is progressing according to plan with the first steel jacket installed on the field during the quarter.

Drilling of the Delta appraisal well in the NOAKA area was completed in the quarter and the Hyrokkin and Nordfjellet exploration wells in the North Sea were completed in the quarter, both dry.

Following a successful placement of a new USD 400 million bond in June, the company in the third quarter redeemed its USD 300 million subordinated bond and cancelled its USD 550 million revolving credit facility.

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

After the end of the third quarter, Aker BP entered into an agreement to acquire Hess Norge AS ("Hess Norge") for a cash consideration of USD 2.0 billion. The transaction includes Hess Norge's interests in the Valhall and Hod fields, and a tax loss carry forward with a nominal after tax value of USD 1.5 billion.

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)	Q3 2017	Q3 2016
Operating income	596	248
EBITDA	395	179
EBIT	219	56
Pre-tax profit/loss	209	51
Net profit	112	63
EPS (USD)	0.33	0.31

Income statement Statement of financial position

(USD million)	Q3 2017	Q3 2016
Goodwill	1 817	1 858
PP&E	4 782	4 383
Cash & cash equivalents	81	786
Total assets	9 116	10 280
Equity	2 502	2 579
Interest-bearing debt	2 022	3 165

Total income in the third quarter was USD 596 (248) million, higher than the third quarter 2016 mainly due to inclusion of BP Norge activities. Petroleum revenues amounted to USD 601 (247) million, while other income was USD -5 (1) million, primarily related to realized and unrealized gains and losses on commodity hedges.

Exploration expenses amounted to USD 64 (31) million in the quarter, reflecting dry hole costs, seismic costs, area fees and G&G activities. Production costs were USD 134 (32) million, equating to 11.1 (5.8) USD/boe, including shipping and handling of 3.2 (1.0) USD/boe. The increase from the third quarter 2016 is mainly due to inclusion of BP Norge fields and production from Ivar Aasen, which have higher production costs per boe compared to the Alvheim area. Other operating expenses amounted to USD 3 (6) million.

Depreciation amounted to USD 175 (115) million, corresponding to 14 (21) USD/boe, which represents a decrease from third quarter 2016 mainly due to the inclusion of the BP Norge assets.

The company recorded an operating profit of USD 219 (56) million in the third quarter, higher than the third quarter 2016 primarily due to the merger with BP Norge. The net profit for the period was USD 112 (63) million after net financial items of USD -9 (-5) million and a tax expense of USD 97 (-13) million. Earnings per share were USD 0.33 (0.31).

Total intangible assets amounted to USD 3,433 (4,449) million, of which goodwill was USD 1,817 (1,858) million. The decrease from the third quarter 2016 is mainly related to impairment losses recorded in fourth quarter 2016 and first quarter 2017.

Property, plant and equipment increased to USD 4,782 (4,383) million, reflecting investments in development projects less depreciation. Current tax receivables amounted to USD 145 (133) million at the end of the quarter, and is related to last year's exploration spending.

The group's cash and cash equivalents were USD 81 (786) million as of 30 September 2017. Total assets were USD 9,116 (10,280) million at the end of the quarter.

Equity amounted to USD 2,502 (2,579) million at the end of the quarter, corresponding to an equity ratio of 27 (25) percent. The decrease is mainly related to the quarterly dividend payments, offset by net profit in the period.

Deferred tax liabilities decreased to USD 1,137 (1,415) million and are detailed in note 7 to the financial statements.

Gross interest-bearing debt decreased to USD 2,022 (3,165) million, consisting of the DETNOR02 bond of USD 237 million, the AKERBP Senior Note 2017 (17/22) of USD 389 million and the Reserve Based Lending ("RBL") facility of USD 1,396 million.

Statement of cash flow

(USD million)	Q3 2017	Q3 2016
Cash flow from operations	730	251
Cash flow from investments	-285	164
Cash flow from financing	-427	300
Net change in cash & cash eq.	18	715
Cash and cash eq. EOQ	81	786

Net cash flow from operating activities was USD 730 (251) million. The change was mainly caused by increased profit before tax and a tax refund received following the liquidation of BP Norge.

Net cash flow from investment activities was USD -285 (164) million. Investments in fixed assets amounted to USD 226 (203) million for the quarter, mainly reflecting capital expenditures ("CAPEX") on Ivar Aasen, Alvheim, Valhall/Hod, Ula/Tambar and Johan Sverdrup. Investments in intangible assets including capitalized exploration were USD 33 (54) million in the quarter and payment for decommissioning activities were USD 27 (3) million in the quarter.

Net cash flow from financing activities totalled USD 427 (300) million, reflecting a repayment of USD 422 million on the group's RBL facility in the quarter, USD 330 million related to repayment of DETNOR03 (including early redemption fee), issuance of AKERBP Senior Note of USD 388 million (net of fees) and dividend disbursements of USD 62.5 million during the quarter.

Funding

At the end of the third quarter, the company had total available liquidity of USD 2.6 (1.5) billion, comprising of cash and cash equivalents of USD 81 (786) million and undrawn credit facilities of USD 2,540 (712) million.

Bondholders representing NOK 2.0 million nominal worth of DETNOR02 bonds exercised the distribution put option following the dividend payment in August. Aker BP consequently owns DETNOR02 bonds equal to NOK 5.8 million.

On 28 June, the company priced a notes offering of USD 400 million aggregate principal amount of 6.00 percent senior unsecured 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 was repaid at 110 percent of par value (plus accrued interest) on 31 July 2017. The remaining balance of the notes proceeds was 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.

During the third quarter, the Company completed certain amendments to its RBL facility and has achieved a more flexible and cost effective structure. The borrowing base under the amended facility is set annually based on the company's certified 2P reserves. The company also cancelled its second lien RCF facility which was established in 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 exposures 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 14 percent of estimated 2017 oil production, corresponding to approximately 50 percent of the undiscounted after-tax value.

Subsequent to the end of the third quarter, the company has bought put options at a strike price of USD 50 per barrel for approximately 14 percent of estimated oil production for the first half of 2018.

Dividends

A quarterly dividend of USD 62.5 million, corresponding to USD 0.185 per share was disbursed on 9 August 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 27 October 2017, the Board of Directors declared a quarterly dividend of USD 0.185 per share, to be disbursed on or about 9 November 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, drilling campaigns and projects are carried out under the highest HSE standards.

During the third quarter, no process safety events, high potential incidents or acute spills were recorded. One recordable injury at Valhall resulted in an arm fracture. This incident has been investigated and root causes addressed. Two notifications were sent to the Petroleum Safety Authority (PSA).

There was a high activity level in the third quarter at several of the company's operated fields related to

scheduled maintenance activities. Safety awareness briefs and start-up of a self-verification program offshore within Aker BP have been prioritized in order to have a proactive and structured approach to manage safety barriers.

Adequate and robust support of HSE to the new project alliance structures has been an important activity to align all parties and ensure high quality deliverables.

Five audits by the PSA were conducted during third quarter, and thorough preparations and follow up activities have been executed in response to the audit reports received.

OPERATIONAL REVIEW

Aker BP produced 12.1 (5.5) mmboe in the third quarter of 2017, corresponding to 131.9 (59.8) mboepd. The average realized oil price was USD 55 (47) per barrel, while gas revenues were recognized at market value of USD 0.20 (0.15) 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.

Third quarter production from Alvheim area was approximately five percent down from previous quarter. This was partly a result of ordinary decline, but also impacted by outage of the SAGE gas pipeline and by a planned Alvheim emergency shut down test.

Production from the Volund field was restored in the third quarter as two new wells started production. These new wells are given priority over the Viper/ Kobra wells, which is part of the Alvheim field, but is produced via the Volund infrastructure. This resulted in a corresponding reduction in production from the Alvheim field.

The production efficiency for the Alvheim area was 96 percent in the quarter.

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 third quarter partly driven by a planned maintenance shutdown, reservoir depletion and temporary well shutdowns related to drilling and well operations.

During the quarter, four parallel drilling and wells operations have been in progress. The Maersk Invincible rig continued the P&A campaign at Valhall, while the IP rig drilling campaign progressed very well and two wireline crews were running production and abandonment well interventions. Well G-09 was completed and put on production in August.

The production efficiency for the Valhall area was 86 percent in the quarter.

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 was slightly down in third quarter, with the reduction mostly caused by cyclic well performance. The alternating water and gas injection mode of these wells is expected to cause fluctuation in production volumes going forward.

The production efficiency for the Ula area was 68 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 stable during the third quarter with continued high plant uptime. Three wells at Skarv are shut in due to technical issues. Ample capacity from the other wells has softened the negative impact of these shut-ins. The Songa Enabler drilling unit is currently on the field performing workovers with an aim reinstate production within year end. Aker BP is taking steps to prevent similar problems elsewhere.

The Snadd test producer was shut in during the third quarter as it had reached its allowed production volume for 2017. An extended pressure build up test is currently being performed in order to obtain key reservoir data in support of the Snadd development.

The production efficiency for the Skarv area was 87 percent in the quarter, influenced by the planned testing of emergency shutdown valves in September.

Ivar Aasen

PL001B/242/457 (operator)

Ivar Aasen (34.786 percent) delivered planned production in the third quarter and completed the PDO drilling scope. The plant continued to perform well averaging 97 percent availability in the quarter.

QUARTERLY REPORT Q3 2017 8

The production efficiency for Ivar Aasen was 82 percent in the quarter, impacted pre-dominantly by power availability issues.

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

PROJECTS

Johan Sverdrup Unit PL265/501/502 (partner)

Phase 1 of the Johan Sverdrup (11.5733 percent) 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.

At the end of the third quarter, approximately 70 percent of the Phase 1 facilities construction has been completed. In July the first steel jacket (of four) was delivered by Kværner (Verdal) and installed offshore, becoming the first visible structure at the Johan Sverdrup field. In September three large modules constructed by Aibel (Thailand and Haugesund) and Nymo (Grimstad) were lifted by Heerema and integrated on a giant barge inshore in Klosterfjorden (south of Stord) to become the Drilling Platform, which was thereafter hauled to Haugesund for final onshore hook up and commissioning. The plan is to pick up the "drilling ready" topside by the new build twin hull heavy lift ship Pioneering Spirit (Allseas) and conduct a single lift installation offshore in the summer of 2018.

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 made good progress.

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 platform with living quarters and processing facilities. Oil from Gina Krog is exported with shuttle tankers while gas is exported via the Sleipner platform. The field is operated by Statoil.

1. Phase 2 includes 28 additional production and injection wells in the peripheral parts of the Johan Sverdrup oil field, increasing the total number of wells 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 increased power from shore capacity which will allow Johan Sverdrup to 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 92 billion (nominal at project currency), which is more than NOK 30 billion (25 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 USD 25 per 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 in April, and is currently in the FEED phase and experiencing a seamless transition into detail engineering. The plan is to submit a PDO before the end of 2017.

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, Frigg 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 the first quarter 2018.

Storklakken

PL460 (operator)

Storklakken (65 percent) 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. Project sanctioning is planned for the fourth quarter 2017 and first oil is expected in 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 production start scheduled for 2020.

The key upcoming activities include sanctioning of the project (DG3) in fourth quarter 2017 followed by the submission of the Plan for Development and Operation (PDO), award of the main contracts for the electrical trace heating system, subsea production system and topsides modifications scopes as well as establishment of an alliance organisation to deliver the project. The near term focus is the qualification of the electrical trace heated pipe-in-pipe flowline system and placement of commitments for long lead items.

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 and modify facilities to provide gas lift from Ula field to new and existing Tambar wells. The 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 third quarter the execution of offshore facility modifications has started, including preparing for intake of the drilling rig. Drilling with the Maersk Interceptor commenced in October 2017.

Oda

PL405 (partner)

The Oda field (15 percent) 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. Aker BP performs the required facility modifications to receive production from and provide injection water to Oda. Oda's recoverable reserves are estimated at 48 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 approved by the Ministry of Petroleum and Energy in May 2017. Total investments for Oda are estimated to NOK 5.4 billion. Offshore execution of facility modifications on the Ula field centre to be ready to receive Oda production is ongoing. First oil from Oda is expected in second quarter 2019.

EXPLORATION

During the quarter, the company's cash spending on exploration was USD 76 million. USD 64 million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees and G&G costs.

Drilling of the Hyrokkin prospect in PL677 in the North Sea was completed in August as a dry hole.

Drilling of the Delta appraisal well and the Nordfjellet exploration well in PL442 near the Frigg Gamma Delta discovery was completed in September. The objective of the appraisal well was to delineate the oil discovery in the Delta structure towards the north and examine the mobility of the oil in the Frigg formation. The well encountered an oil column of 13.5 metres in sandstone with good reservoir quality. The oil/water contact was

encountered near 1,950 metres below the sea surface. Analyses are ongoing to confirm the resource estimate. The Nordfjellet exploration well was classified as dry.

Drilling commenced on the Hufsa prospect in PL533 in the Barents Sea in October and results are expected in the fourth quarter 2017.

In August, the company entered into an agreement with Odfjell Drilling for the lease of the semisubmersible drilling rig Deepsea Stavanger for a period of approximately nine months, with commencement in February 2018. The contract is for exploration and development drilling at various locations in the Norwegian Sea and the Barents Sea.

BUSINESS DEVELOPMENT

In August, the company entered into an agreement to acquire Wellesley's 30 percent share in PL 810. The license is located in one of Aker BP's core areas, between

Ula and Tambar. The transaction has been approved by relevant authorities, and the company expects to close the transactions within the end of the month.

ACQUISITION OF HESS NORGE AS

On 24 October 2017, Aker BP entered into an agreement to acquire Hess Norge. Through the transaction, Aker BP will strengthen its production and resource base, and will become the sole owner of the Valhall and Hod fields, where the company sees a great value creation potential through increased oil recovery and flank developments.

The cash consideration of the transaction is USD 2.0 billion. The transaction includes a 64.05 percent interest in the Valhall field and a 62.5 percent interest in the Hod field. As per end-2016, the corresponding proven and probable reserves (2P) amounted to 150 million barrels of oil equivalent (mmboe), while the best estimate for contingent resources (2C) was 195 mmboe, based on Aker BP's own assessment per year-end 2016. For the first nine months of 2017, Hess Norge's share of production from these fields was approximately 24,000 barrels of oil equivalent per day (boepd). Aker BP will also assume Hess Norge's tax positions, which include a tax loss carry forward with a net nominal after-tax value of USD 1.5 billion, as booked in Hess Norge's 2016 annual accounts.

The transaction will be financed through Aker BP's existing long-term Reserve Based Lending bank facility, and by the issuance of USD 500 million in new equity. The issue price will be determined through a book building process. Aker ASA ("Aker") and BP plc ("BP") will subscribe for 40 percent and 30 percent of the shares to be issued, respectively, at the price determined through the bookbuilding process, or minimum NOK 155 per share. In addition, Aker and BP will underwrite the remaining shares to be issued at NOK 155 per share.

The transaction is subject to customary conditions for completion, including approval by the Ministry of Oil and Energy, Ministry of Finance and relevant competition clearance. The effective date of the transaction will be 1 January 2017, and closing is expected by the end of 2017. A general meeting in Aker BP will be called to approve the issuance of new equity.

Following the completion of the transaction and the equity issue, the board will increase the shareholder dividends from USD 250 million to USD 350 million per year, effective from the dividend for the fourth quarter 2017 which is payable in the first quarter 2018.

Aker BP intends to subsequently sell or swap a minority interest in the Valhall and Hod fields to partners who want to work together with Aker BP to proactively target the upside potential in the area.

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 selectively pursue growth opportunities which will enhance production and increase dividend capacity. A dividend of USD 0.185 per share is scheduled to be paid in November. The board will raise the dividend level to USD 350 million per year for the fourth quarter 2017 which is payable in the first quarter 2018 and will further increase this level once Johan Sverdrup is in production.

The company will have four rigs in operation in the fourth quarter. Operations include infill drilling at Boa and Tambar as well as new production wells and P&A activity at Valhall. In addition, the company is partner in drilling of the Hufsa and Hurri prospects in the Barents 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 going forward. The announced USD 500 million equity issue is expected to be carried out shortly. The Hess transaction is expected to close before year-end 2017.

The company expects 2017 production (excluding the Hess transaction) to be in the upper half of the 135-140 mboepd guidance with a production cost of approximately 10 USD/boe. 2017 CAPEX is expected to be between USD 900 – 950 million. Guidance for 2017 exploration expenditures is unchanged at USD 280 – 300 million, while total cash spend on decommissioning is expected to be USD 80 – 90 million (previously USD 100 – 110 million).

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT (Unaudited)

	Group
	Q3		01.01.-30.09.
(USD 1 000) Note	2017	2016	2017	2016
Petroleum revenues 2	600 808	247 213	1 838 450	719 254
Other income 2	-4 620	779	-1 511	-10 748
Total income	596 188	247 993	1 836 939	708 506
Exploration expenses 3	63 887	30 843	169 521	103 172
Production costs	134 411	32 188	376 303	105 678
Depreciation 5	175 334	114 649	543 532	349 231
Impairments 4, 5	1 091	8 429	31 238	26 748
Other operating expenses	2 893	6 223	14 057	16 964
Total operating expenses	377 617	192 333	1 134 651	601 794
Operating profit/loss	218 571	55 660	702 288	106 712
Interest income	2 566	568	4 725	2 908
Other financial income	54 522	37 918	84 752	79 113
Interest expenses	27 129	20 107	88 397	61 933
Other financial expenses	39 427	23 487	140 654	46 527
Net financial items 6	-9 469	-5 107	-139 574	-26 439
Profit/loss before taxes	209 102	50 553	562 714	80 273
Taxes (+)/tax income (-) 7	97 065	-12 880	321 963	-21 701
Net profit/loss	112 037	63 433	240 751	101 974
Weighted average no. of shares outstanding basic and diluted Basic and diluted earnings/(loss) per share	337 737 071 0.33	202 618 602 0.31	337 737 071 0.71	202 618 602 0.50

STATEMENT OF COMPREHENSIVE INCOME (Unaudited)

		Group
		Q3		01.01.-30.09.
(USD 1 000)	Note	2017	2016	2017	2016
Profit/loss for the period		112 037	63 433	240 751	101 974
Items which may be reclassified over profit and loss (net of taxes)
Currency translation adjustment		-	-	-356	-59
Total comprehensive income in period		112 037	63 433	240 395	101 914

STATEMENT OF FINANCIAL POSITION (Unaudited)

	Group
(USD 1 000) Note	30.09.2017	30.09.2016	31.12.2016
ASSETS
Intangible assets
Goodwill 5	1 817 486	1 858 465	1 846 971
Capitalized exploration expenditures 5	355 926	361 696	395 260
Other intangible assets 5	1 259 511	1 339 433	1 332 813
Deferred tax assets 7	-	889 108	-
Tangible fixed assets
Property, plant and equipment 5	4 781 618	4 383 110	4 441 796
Financial assets
Long-term receivables	41 402	42 308	47 171
Long-term tax receivable 7	-	22 234	-
Long-term derivatives 11	23 238	14 924	-
Other non-current assets	6 041	12 866	12 894
Total non-current assets	8 285 223	8 924 144	8 076 905
Inventories
Inventories	73 762	66 499	69 434
Receivables
Accounts receivable	53 548	99 775	170 000
Tax receivables 7	145 245	133 101	400 638
Other short-term receivables 8	463 597	259 579	422 932
Short-term derivatives 11	14 106	7 988	-
Other current financial assets	-	3 070	-
Cash and cash equivalents
Cash and cash equivalents 9	80 764	785 622	115 286
Total current assets	831 022	1 355 635	1 178 290
TOTAL ASSETS	9 116 244	10 279 778	9 255 196

STATEMENT OF FINANCIAL POSITION (Unaudited)

		Group
(USD 1 000) Note	30.09.2017	30.09.2016	31.12.2016
EQUITY AND LIABILITIES
Equity
Share capital	54 349	54 349	54 349
Share premium	3 150 567	3 150 567	3 150 567
Other equity	-702 814	-626 206	-755 709
Total equity	2 502 102	2 578 710	2 449 207
Non-current liabilities Deferred taxes 7	1 137 008	1 414 944	1 045 542
Long-term abandonment provision 15	2 210 726	2 019 566	2 080 940
Provisions for other liabilities 10	89 209	359 909	218 562
Long-term bonds 13	625 726	525 645	510 337
Long-term derivatives 11	8 356	20 072	35 659
Other interest-bearing debt 14	1 396 158	2 639 517	2 030 209
Current liabilities
Trade creditors	72 787	77 042	88 156
Accrued public charges and indirect taxes	15 280	22 598	39 048
Tax payable 7	265 080	-	92 661
Short-term derivatives 11	2 128	-	5 049
Short-term abandonment provision 15	152 668	83 498	75 981
Other current liabilities 12	639 016	538 276	583 844
Total liabilities	6 614 142	7 701 068	6 805 988
TOTAL EQUITY AND LIABILITIES	9 116 244	10 279 778	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	-	-	-	-	-	-125 000	-125 000	-125 000
Profit/loss for the period 01.01.2017 - 30.06.2017	-	-	-	-	-356	128 714	128 358	128 358
Equity as of 30.06.2017	54 349	3 150 567	573 083	-88	-115 907	-1 209 440	-752 351	2 452 565
Dividend distributed	-	-	-	-	-	-62 500	-62 500	-62 500
Profit/loss for the period 01.07.2017 - 30.09.2017	-	-	-	-	-	112 037	112 037	112 037
Equity as of 30.09.2017	54 349	3 150 567	573 083	-88	-115 907	-1 159 903	-702 814	2 502 102

* 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
		Q3		01.01.-30.09.		Year
(USD 1 000)	Note	2017	2016	2017	2016	2016
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		209 102	50 553	562 714	80 273	290 453
Taxes paid during the period		-34 091	-151	-34 091	-1 419	-1 419
Tax refund during the period		263 791	83 666	263 791	83 666	212 944
Depreciation	5	175 334	114 649	543 532	349 231	509 027
Net impairment losses	4, 5	1 091	8 429	31 238	26 748	71 375
Accretion expenses	6, 15	32 757	6 816	97 212	18 691	47 977
Interest expenses	6	38 124	40 882	124 164	118 116	160 808
Interest paid		-27 454	-32 405	-114 224	-109 319	-161 634
Changes in derivatives	2, 6	-37 628	-32 126	-67 568	-33 140	10 408
Amortized loan costs	6	12 901	4 846	30 564	12 242	17 915
Gain on change of pension scheme		-	-	-	-	-115 616
Amortization of fair value of contracts	10	-825	-	7 330	-	-
Expensed capitalized dry wells	3, 5	20 534	9 313	56 155	43 702	51 669
Changes in inventories, accounts payable and receivables		19 591	-31 465	56 090	-92 088	-317 488
Changes in abandonment liabilities through income statement		-	-	-	-	-1 131
Changes in other current balance sheet items		57 150	28 365	55 633	76 571	120 365
NET CASH FLOW FROM OPERATING ACTIVITIES		730 376	251 372	1 612 541	573 275	895 652
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	15	-26 673	-2 473	-54 640	-5 493	-12 237
Disbursements on investments in fixed assets	5	-225 648	-203 337	-729 159	-691 487	-935 755
Net of cash consideration paid for, and cash acquired from, BP Norge AS		-	423 990	-	423 990	423 990
Disbursements on investments in capitalized exploration expenditures and
other intangible assets	5	-32 750	-54 194	-83 201	-119 459	-181 492
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-285 071	163 986	-867 000	-392 450	-705 494
CASH FLOW FROM FINANCING ACTIVITIES
Repayment of long-term debt		-422 441	-	-647 911	-	-612 825
Repayment of bond (DETNOR03)		-330 000	-	-330 000	-	-
Net proceeds from issuance of long-term debt		388 000	299 685	388 000	512 013	512 013
Paid dividend		-62 500	-	-187 500	-	-62 500
NET CASH FLOW FROM FINANCING ACTIVITIES		-426 941	299 685	-777 411	512 013	-163 312
Net change in cash and cash equivalents		18 365	715 043	-31 870	692 838	26 846
Cash and cash equivalents at start of period		65 569	68 393	115 286	90 599	90 599
Effect of exchange rate fluctuation on cash held		-3 170	2 186	-2 653	2 186	-2 158
CASH AND CASH EQUIVALENTS AT END OF PERIOD	9	80 764	785 622	80 764	785 622	115 286
SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits and cash		71 821	778 863	71 821	778 863	106 369
Restricted bank deposits		8 943	6 759	8 943	6 759	8 917
CASH AND CASH EQUIVALENTS AT END OF PERIOD	9	80 764	785 622	80 764	785 622	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 27 October 2017.

The acquisition of BP Norge AS was completed on 30 September 2016. Corresponding Income statement 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 group's annual financial statements as at 31 December 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 annual financial statements as at 31 December 2016.

Note 2 Income

	Group
	Q3		01.01.-30.09.
Breakdown of petroleum revenues (USD 1 000)	2017	2016	2017	2016
Recognized income liquids	508 390	229 954	1 557 881	660 364
Recognized income gas	85 936	14 338	263 117	51 752
Tariff income	6 482	2 922	17 451	7 138
Total petroleum revenues	600 808	247 213	1 838 450	719 254
Breakdown of produced volumes (barrels of oil equivalent)
Liquids	9 434 958	4 909 309	29 787 298	14 754 370
Gas	2 698 032	595 866	8 412 970	1 948 807
Total produced volumes	12 132 990	5 505 174	38 200 268	16 703 177
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-1 291	5 640	-4 892	28 702
Unrealized gain/loss (-) on oil derivatives	-6 353	-4 993	-947	-43 436
Gain on license transactions	2 718	-	3 274	-
Other income	306	132	1 054	3 986

Total other income -4 620 779 -1 511 -10 748

Note 3 Exploration expenses

	Group
		Q3	01.01.-30.09.
Breakdown of exploration expenses (USD 1 000)	2017 2016		2017	2016
Seismic	15 840	4 810	43 647	11 006
Area fee	3 653	4 151	12 225	9 255
Dry well expenses*	20 534	9 313	56 155	43 702
Other exploration expenses	23 859	12 569	57 493	39 210
Total exploration expenses	63 887	30 843	169 521	103 172

* Mainly related to the Hyrokkin and Nordfjellet 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 Q3 2017 there has been an increase in forward prices as well as some updates of the production profiles. 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 1.1 million in the quarter mainly relates to intangible assets recognized in acquisitions of exploration licenses which are in the process of being relinquished.

Note 5 Tangible fixed 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 31.12.2016	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	412 095	114 717	14 401	541 213
Disposals	4 200	-	1 685	5 884
Reclassification	-69 332	132 258	2 661	65 587
Acquisition cost 30.06.2017	1 247 238	5 197 541	71 514	6 516 293
Accumulated depreciation and impairments 31.12.2016	1 566	1 448 659	23 357	1 473 582
Depreciation	-	315 106	4 494	319 600
Impairment	-6	-	-	-6
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
Acquisition cost 30.06.2017	1 247 238	5 197 541	71 514	6 516 293
Additions	132 709	78 826	18 028	229 562
Disposals*	19 961	29 546	-154	49 353
Reclassification**	-105 147	102 105	3 690	648
Acquisition cost 30.09.2017	1 254 838	5 348 926	93 386	6 697 150
Accumulated depreciation and impairments 30.06.2017	1 560	1 763 765	26 167	1 791 491
Depreciation	-	149 234	4 065	153 299
Impairment	-	-	128	128
Retirement/transfer depreciations*	6	-29 546	154	-29 386
Accumulated depreciation and impairments 30.09.2017	1 566	1 883 452	30 513	1 915 532
Book value 30.09.2017	1 253 272	3 465 473	62 873	4 781 618

* The disposal mainly relates to sale of 35 per cent share in Storklakken, as well as derecognition of the Glitne field as the removal and decommissioning operations in all material respect are finalized.

** The reclassification in this quarter is mainly related to infill wells on Vallhall and Volund.

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
(USD 1 000)	Licences etc.	Software	Total	Exploration 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	246	-	246	50 205	-
Disposals/expensed dry wells	858	-	858	35 621	324
Reclassification	-11	-	-11	-65 576	-
Acquisition cost 30.06.2017	1 574 581	7 501	1 582 082	344 268	2 720 511
Accumulated depreciation and impairments 31.12.2016	242 670	7 223	249 892	-	873 864
Depreciation	48 458	140	48 598	-	-
Impairment	992	-	992	-	29 161
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 30.06.2017	292 119	7 363	299 482	-	903 025
Book value 30.06.02017	1 282 462	138	1 282 600	344 268	1 817 486
Acquisition cost 30.06.2017	1 574 581	7 501	1 582 082	344 268	2 720 511
Additions	-90	-	-90	32 841
Disposals/expensed dry wells*	10 120	-	10 120	20 534	9 619
Reclassification	-	-	-	-648	-
Acquisition cost 30.09.2017	1 564 371	7 501	1 571 872	355 926	2 710 892
Accumulated depreciation and impairments 30.06.2017	292 119	7 363	299 482	-	903 025
Depreciation	21 965	70	22 035	-	-
Impairment	963	-	963	-	-
Retirement/transfer depreciations*	-10 120	-	-10 120	-	-9 619
Accumulated depreciation and impairments 30.09.2017	304 928	7 433	312 361	-	893 406
Book value 30.09.2017	1 259 443	68	1 259 511	355 926	1 817 486

* The disposal mainly relates to sale of 35 per cent share in Storklakken, as well as derecognition of the Glitne field as the removal and decommissioning operations in all material respect are finalized.

	Group
		Q3	01.01.-30.09.
Depreciation in the Income statement (USD 1 000)	2017	2016	2017	2016
Depreciation of tangible fixed assets	153 299	92 353	472 899	284 904
Depreciation of intangible assets	22 035	22 296	70 633	64 327
Total depreciation in the Income statement	175 334	114 649	543 532	349 231
Impairment in the Income statement (USD 1 000)
Impairment/reversal of tangible fixed assets	128	-	121	-9 870
Impairment/reversal of intangible assets	963	8 429	1 956	8 429
Impairment of goodwill	-	-	29 161	28 189
Total impairment in the Income statement	1 091	8 429	31 238	26 748

Note 6 Financial items

	Group
	Q3		01.01.-30.09.
(USD 1 000)	2017	2016	2017	2016
Interest income	2 566	568	4 725	2 908
Realized gains on derivatives	7 746	799	9 769	2 536
Change in fair value of derivatives	43 982	37 119	68 515	76 576
Net currency gains	2 794	-	6 468	-
Total other financial income	54 522	37 918	84 752	79 113
Interest expenses	38 124	40 882	124 164	118 116
Capitalized interest cost, development projects	-23 895	-25 621	-66 331	-68 425
Amortized loan costs*	12 901	4 846	30 564	12 242
Total interest expenses	27 129	20 107	88 397	61 933
Net currency losses	-	14 773	-	16 282
Realised loss on derivatives	4 997	1 180	7 858	6 209
Accretion expenses	32 757	6 816	97 212	18 691
Other financial expenses	1 674	717	35 584	5 345
Total other financial expenses	39 427	23 487	140 654	46 527
Net financial items	-9 469	-5 107	-139 574	-26 439

* As described in note 14, the RCF facility was cancelled during the quarter, and remaining unamortized fees related to this facility have thus been expensed in Q3.

Note 7 Taxes

	Group
	Q3		01.01.-30.09.
Taxes for the period appear as follows (USD 1 000)	2017	2016	2017	2016
Calculated current year tax/exploration tax refund	66 465	12 116	207 000	-16 719
Change in deferred taxes in the Income statement	27 833	-24 996	112 736	-9 734
Prior period adjustments	2 767	-	2 227	4 752
Total taxes (+)/tax income (-)	97 065	-12 880	321 963	-21 701
			Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)		30.09.2017	30.09.2016	31.12.2016
Tax receivable/payable at 01.01.		307 977	126 391	126 391
Current year tax (-)/tax receivable (+)		-206 837	16 719	131 488
Taxes related to acquisitions/sales		-1 010	75 042	255 873
Net tax payment (+)/tax refund (-)		-229 700	-82 247	-211 525
Prior period adjustments		9 711	4 716	-1 681
Revaluation of taxes		24	14 714	7 430
Total net tax receivable (+)/tax payable (-)		-119 835	155 335	307 977
Tax receivable included as current assets (+)		145 245	133 101	400 638
Tax receivable included as non-current assets (+)		-	22 234	-
Tax payable included as current liabilities (-)		-265 080	-	-92 661

			Group
Deferred taxes (-)/deferred tax asset (+) (USD 1 000)		30.09.2017	30.09.2016	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		-112 736	9 734	-374 617
Reclassification of acquired loss carried forward		-	-60 379	-238 866
Deferred tax related to acquisitions/sales		19 190	890 510	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 (+)	-1 137 008		-525 836	-1 045 542
Deferred tax asset		-	889 108	-
Deferred tax		-1 137 008	-1 414 944	-1 045 542
		Group
	Q3			01.01.-30.09.
Reconciliation of tax expense (USD 1 000)	2017	2016	2017	2016
78% tax rate on profit before tax	162 822	39 431	438 639	62 613
Tax effect of uplift	-30 027	-24 598	-92 274	-75 722
Permanent difference on impairment	-	-	22 813	21 987
Foreign currency translation of NOK monetary items	-2 067	5 970	-4 933	10 689
Foreign currency translation of USD monetary items	84 627	78 567	131 289	180 741
Tax effect of financial and other 24%/25% items	-33 492	-51 580	-42 989	-104 214
Revaluation of tax balances*	-82 614	-57 924	-132 524	-117 850
Other permanent differences and prior period adjustment	-2 184	-2 747	1 942	54

* 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.

Total taxes (+)/tax income (-) 97 065 -12 880 321 963 -21 701

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
30.09.2017	30.09.2016	31.12.2016
29 604	34 835	40 730
9 163	9 478	7 913
51 308	59 590	70 003
116 222	6 024	86 429
257 300	149 651	217 857
463 597	259 579	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)	30.09.2017	30.09.2016	31.12.2016
Bank deposits	71 821	778 863	106 369
Restricted funds (tax withholdings)	8 943	6 759	8 917
Cash and cash equivalents	80 764	785 622	115 286
Unused revolving credit facility (see note 14)	-	550 000	550 000
Unused reserve-based lending facility (see note 14)	2 540 000	162 000	1 805 000

Note 10 Provisions for other liabilities

	Group
Breakdown of provisions for other liabilities (USD 1 000)	30.09.2017	30.09.2016	31.12.2016
Fair value of contracts assumed in acquisition of BP Norge AS*	80 766	210 425	202 874
Other long term liabilities	8 443	149 483	15 688
Total provisions for other liabilities	89 209	359 909	218 562

* The negative contract values 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. In Q3 2017 there has been a reclassification between fair value of contracts and abandonment liabilities as described in note 15.

Note 11 Derivatives

	Group
(USD 1 000)	30.09.2017	30.09.2016	31.12.2016
Unrealized gain currency contracts	23 238	14 924	-
Long-term derivatives included in assets	23 238	14 924	-
Unrealized gain on commodity derivatives	-	1 781	-
Unrealized gain currency contracts	14 106	6 207	-
Short-term derivatives included in assets	14 106	7 988	-
Total derivatives included in assets	37 344	22 912	-
Unrealized losses currency contracts	-	-	5 073
Unrealized losses interest rate swaps	8 356	20 072	30 586
Long-term derivatives included in liabilities	8 356	20 072	35 659
Unrealized losses currency contracts	-	-	3 868
Unrealized losses commodity derivatives	2 128	-	1 181
Short-term derivatives included in liabilities	2 128	-	5 049
Total derivatives included in liabilities	10 484	20 072	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 annual financial statements as at 31 December 2016.

Note 12 Other current liabilities

	Group
Breakdown of other current liabilities (USD 1 000)	30.09.2017	30.09.2016	31.12.2016
Current liabilities related to overcall in licences	78 595	104 821	81 686
Share of other current liabilities in licences	389 230	329 299	360 222
Overlift of petroleum	1 940	9 561	20 000
Fair value of contracts assumed in acquisition of BP Norge AS*	19 316	-	36 199
Other current liabilities**	149 935	94 596	85 737
Total other current liabilities	639 016	538 276	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)	30.09.2017	30.09.2016	31.12.2016
DETNOR02 Senior unsecured bond 1)	237 126	230 274	214 827
DETNOR03 Subordinated PIK toggle bond 2)	-	295 371	295 510
AKERBP – Senior Notes 2017 (17/22) 3)	388 600	-	-
Long-term bonds	625 726	525 645	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. In connection with the RBL amendment described in note 14, the financial covenants in this bond has been adjusted to be consistent with the RBL.

2) As described in the Q2 2017 report, the bond was repaid in July 2017.

3) The bond was established in July 2017 and carries an interest of 6 per cent. The principal falls due on July 2022 and interest is paid on a semiannually basis. The loan is senior unsecured and has no financial covenants.

Note 14 Other interest-bearing debt

		Group
(USD 1 000)	30.09.2017	30.09.2016	31.12.2016
Reserve-based lending facility	1 396 158	2 639 517	2 030 209
Total other interest-bearing debt	1 396 158	2 639 517	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.

In Q3 2017 certain amendments have been made to the RBL facility. The borrowing base under the amended facility is set annually based on the company's certified 2P reserves. Current availability under the RBL is USD 4 billion. In addition, the financial covenants have been adjusted as follows:

• Leverage Ratio shall be maximum 4 untill the production start of Johan Sverdrup, thereafter maximum 3.5

• Interest Coverage Ratio shall be minimum 3.5

The interest rate is from 1 - 6 months LIBOR plus a margin of 2 - 3 per cent based on drawn amount. In addition, a commitment fee is paid on unused credit.

As part of the amendment process of the RBL facility, the revolving credit facility ("RCF") of USD 550 miillion was cancelled during the quarter.

Note 15 Provision for abandonment liabilities

	Group
(USD 1 000)	30.09.2017	30.09.2016	31.12.2016
Provisions as of 1 January	2 156 921	423 325	423 325
Abandonment liabilities from acquisition of BP Norge AS*	128 143	1 588 236	1 680 206
Incurred cost removal	-47 310	-5 493	-12 237
Accretion expense - present value calculation	97 212	18 691	47 977
Change in estimates and incurred liabilities on new fields**	28 427	78 306	17 650
Total provision for abandonment liabilities	2 363 394	2 103 065	2 156 921
Break down of the provision to short-term and long-term liabilities
Short-term	152 668	83 498	75 981
Long-term	2 210 726	2 019 566	2 080 940
Total provision for abandonment liabilities	2 363 394	2 103 065	2 156 921

* The increase of USD 128 million is caused by a reclassification between fair value of contracts and abandonment liabilities, both in relation to the acquisition of BP Norge AS.

** 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 Subsequent events

24 October 2017 the company announced that it has entered into an agreement to acquire all the shares in Hess Norge AS for a cash consideration of USD 2.0 billion. Hess Norge's assets include a 64.05 per cent share of the Valhall field and a 62.5 per cent share of the Hod field, and a tax loss carry forward with a net nominal after tax value of USD 1.5 billion. The cash consideration will be financed through Aker BP's existing long-term Reserve Based Lending bank facility, and by new equity of USD 500 million.

Note 18 Investments in joint operations

Fields operated:	30.09.2017		30.06.2017 Fields non-operated:	30.09.2017	30.06.2017
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	11.5733 %	11.5733 %
Jette Unit	70.000 %	70.000 % Jotun		7.000 %	7.000 %
Valhall	35.953 %	35.953 % Oda		15.000 %	15.000 %
Vilje	46.904 %	46.904 % Varg		5.000 %	5.000 %
Volund	65.000 %	65.000 %
Tambar	55.000 %	55.000 %
Tambar Øst	46.200 %	46.200 %
Ula	80.000 %	80.000 %
Skarv	23.835 %	23.835 %

Production licences in which Aker BP is the operator:	Production licences in which Aker BP is a partner:
Licence:	30.09.2017	30.06.2017 Licence:		30.09.2017	30.06.2017
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 627		20.000 %	20.000 %
PL 340	65.000 %		65.000 % PL 627B	20.000 %	20.000 %
PL 340BS	65.000 %	65.000 % PL 719		20.000 %	20.000 %
PL 364**	90.260 %	90.260 % PL 721		40.000 %	40.000 %
PL 442	90.260 %	90.260 % PL 722		20.000 %	20.000 %
PL 442B***	90.260 %	90.260 % PL 778		20.000 %	20.000 %
PL 460**	65.000 %	100.000 % PL 782S		20.000 %	20.000 %
PL 504	47.593 %		47.593 % PL 782SB	20.000 %	20.000 %
PL 626	50.000 %		50.000 % PL 782SC***	20.000 %	20.000 %
PL 659	50.000 %	50.000 % PL 811		20.000 %	20.000 %
PL 677	60.000 %	60.000 % PL 813		3.300 %	3.300 %
PL 715	40.000 %	40.000 % PL 838		30.000 %	30.000 %
PL 724	40.000 %	40.000 % PL 842		30.000 %	30.000 %
PL 724B	40.000 %	40.000 % 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	47
PL 821	60.000 %	60.000 %
PL 821B***	60.000 %	60.000 %
PL 822S	60.000 %	60.000 %
PL 839	23.835 %	23.835 %
PL 843	40.000 %	40.000 %
PL 858	40.000 %	40.000 %
PL 861***	50.000 %	50.000 %
PL 867***	40.000 %	40.000 %
PL 868***	60.000 %	60.000 %

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

** Acquired/changed through licence transactions or licence splits.

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

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 % Number 63 63

Note 19 Results from previous interim reports

	2017			2016				2015
(USD 1 000)	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Total income	596 188	594 501	646 250	655 624	247 993	255 665	204 848	254 634
Exploration expenses	63 887	75 375	30 259	44 281	30 843	36 214	36 115	18 867
Production costs	134 411	121 017	120 874	121 139	32 188	39 116	34 374	24 077
Depreciation	175 334	184 194	184 004	159 796	114 649	120 264	114 318	111 590
Impairments	1 091	365	29 782	44 627	8 429	-19 644	37 964	191 939
Other operating expenses	2 893	3 113	8 051	5 029	6 223	5 410	5 330	3 228
Total operating expenses	377 617	384 065	372 969	374 872	192 333	181 360	228 101	349 701
Operating profit/loss	218 571	210 436	273 280	280 752	55 660	74 305	-23 253	-95 067
Net financial items	-9 469	-83 597	-46 508	-70 572	-5 107	-28 951	7 620	-56 138
Profit/loss before taxes	209 102	126 840	226 772	210 180	50 553	45 353	-15 633	-151 205
Taxes (+)/tax income (-)	97 065	66 944	157 955	277 183	-12 880	39 046	-47 866	4 980
Net profit/loss	112 037	59 896	68 818	-67 003	63 433	6 308	32 233	-156 184

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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