Aker BP

Quarterly Report • Oct 31, 2016

QUARTERLY REPORT FOR AKER BP ASA

FORNEBU, 31 OCTOBER 2016

KEY EVENTS IN Q3 2016

29 August:	The company announced an increase in value of Johan Sverdrup through reduced CAPEX estimates and increased volumes
31 August:	The company announced an oil discovery at the Langfjellet prospect in PL442 in the North Sea
14 September:	The company increased its 2016 production guidance following stronger than expected production from the Alvheim area
15 September:	The Extraordinary General Meeting approved the proposed merger with BP Norge AS
30 September:	The company announced an increase in its reserve-based lending facility to USD 4.0 billion and removal of dividend restrictions
30 September:	The company announced that the merger with BP Norge AS was completed, including registration of a share capital increase and a new company name: Aker BP ASA
	KEY EVENTS AFTER THE QUARTER
3 October:	The company announced the acquisition of licenses from Tullow Norge AS, including 15 percent interest in the Oda discovery
14 October:	The bondholder meeting in the DETNOR02 bond resolved certain amendments, including to remove restrictions related

to dividend disbursements from the loan agreement

SUMMARY OF FINANCIAL RESULTS

	Unit	Q3 2016	Q3 2015	2016 YTD	2015 YTD
Operating income	USDm	248	316	709	967
EBITDA	USDm	179	260	483	744
Net result	USDm	63	-166	102	-156
Earnings per share (EPS)	USD	0.31	-0.82	0.50	-0.77
Production cost per barrel	USD/boe	6	5	6	7
Depreciation per barrel	USD/boe	21	22	21	22
Cash flow from operations	USDm	251	242	562	686
Cash flow from investments	USDm	164	-242	-729	-1 168
Total assets	USDm	10 280	5 237	10 280	5 237
Net interest-bearing debt	USDm	2 380	2 147	2 380	2 147
Cash and cash equivalents	USDm	786	207	786	207

SUMMARY OF PRODUCTION

	Unit	Q3 2016	Q3 2015	2016 YTD	2015 YTD
Production
Alvheim (65%)	boepd	41 045	35 574	39 800	35 233
Atla (10%)	boepd	60	306	141	422
Bøyla (65%)	boepd	6 191	10 502	7 727	9 063
Enoch (2%)	boepd	33	-	19	-
Jette (70%)	boepd	888	623	683	640
Jotun (7%)	boepd	55	83	86	117
Varg (5%)	boepd	-10	336	226	345
Vilje (46.9%)	boepd	7 381	6 599	6 727	6 590
Volund (65%)	boepd	4 195	8 783	5 553	9 618
SUM	boepd	59 839	62 806	60 961	62 029
Oil price	USD/bbl	47	52	45	58
Gas price	USD/scm	0.15	0.26	0.17	0.28

3

SUMMARY OF THE QUARTER

Aker BP ASA ("the company" or "Aker BP") reported revenues of USD 248 (316) million in the third quarter of 2016. Production in the period was 59.8 (62.8) thousand barrels of oil equivalent per day ("mboepd"), realising an average oil price of USD 47 (52) per barrel.

EBITDA amounted to USD 179 (260) million in the quarter and EBIT was USD 56 (-56) million. Net earnings for the quarter was USD 63 (-166) million, translating into an EPS of USD 0.31 (-0.82). Net interest-bearing debt amounted to USD 2,380 (2,147) million per September 30, 2016.

The merger with BP Norge AS ("BP Norge") was closed on September 30, 2016 and the company changed its name to Aker BP ASA with its headquarters moved to Fornebuporten outside Oslo. BP plc consequently became a major shareholder (30 percent) in the company in addition to Aker ASA (40 percent).

Production from the Alvheim area in the third quarter was positively impacted by strong production from BoaKamNorth and the Vilje lower branch. Production efficiency was 83.3 percent in the quarter, following a 13-day planned shutdown of the Alvheim FPSO.

The pre-drilling program at Ivar Aasen was completed with five oil producers and three water injection wells finalised. In July, the topside was successfully installed, and the flotel was mobilised to accommodate personnel for the hook-up and commissioning phase. The project remains on schedule and budget towards the planned start-up in December 2016.

The Johan Sverdrup project is progressing according to plan with pre-drilling of wells and facilities construction. CAPEX estimates for the project continue to come down and the break-even oil price for phase one is now estimated to be below USD 25 per barrel.

The company announced an oil discovery at the Langfjellet prospect in August and a second sidetrack is currently being drilled. Preliminary volume estimates for the discovery are in the range of 24 to 74 million barrels of oil equivalent.

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.

FINANCIAL REVIEW

The merger with BP Norge closed on September 30, 2016. For accounting purposes, the third quarter income statement therefore does not include operations in BP Norge. The balance sheet as of September 30, 2016 reflects the consolidated Group, including a purchase price allocation.

(USD million)	Q3 2016	Q3 2015
Operating income	248	316
EBITDA	179	260
EBIT	56	-56
Pre-tax profit/loss	51	-107
Net profit	63	-166
EPS (USD)	0.31	-0.82

Income statement Statement of financial position

(USD million)	Q3 2016	Q3 2015
Goodwill	1 858	948
PP&E	4 383	2 929
Cash & cash equivalents	786	207
Total assets	10 280	5 237
Equity	2 579	495
Interest-bearing debt	3 165	2 353

Total operating revenues in the third quarter were USD 248 (316) million, lower than the third quarter 2015 mainly due to lower oil prices and production. Petroleum revenues accounted for USD 247 (281) million, while other revenues were USD 1 (36) million, primarily relating to net realized and unrealized losses on commodity hedges.

Exploration expenses amounted to USD 31 (18) million in the quarter, reflecting dry hole costs, seismic costs, area fees and G&G activities. Production costs were USD 32 (27) million, equating to 5.8 (4.7) USD/boe, including shipping and handling of 1.0 USD/boe. The increase from the third quarter 2015 is mainly due to a 13-day maintenance stop in August 2016 on the Alvheim field. Other operating expenses amounted to USD 6 (11) million, a decrease from the third quarter 2015 due to one-off effects in Q3 2015.

Depreciation was USD 115 (130) million, corresponding to 21 (22) USD/boe, which is slightly below the third quarter 2015. During the quarter, an impairment of USD 8 (186) million related to impairment of exploration prospects was recognized.

The company recorded an operating profit of USD 56 (-56) million in the third quarter, higher than the third quarter 2015 primarily due to lower impairment. The net profit for the period was USD 63 (-166) million after net financial items of USD -5 (-51) million and a tax income of USD 13 (-59) million. Earnings per share were USD 0.31 (-0.82).

Total intangible assets amounted to USD 4,449 (1,846) million, of which goodwill was USD 1,858 (948) million and deferred tax assets was USD 889 (0) million. The increase during the quarter mainly arose through the merger with BP Norge, as described in note 3.

Property, plant and equipment increased to USD 4,383 (2,929) million, reflecting the increase related to the acquisition of BP Norge and investments in development projects and depreciation. Current tax receivables amounted to USD 133 (8) million at the end of the quarter after USD 84 million was received during the third quarter, related to the acquisition of Premier Oil Norge AS.

The group's cash and cash equivalents were USD 786 (207) million as of 30 September. Total assets were USD 10,280 (5,237) million at the end of the quarter.

Equity was USD 2,579 (495) million at the end of the quarter, corresponding to an equity ratio 25 (9) percent. The increase is mainly related to the share issue in connection with the merger with BP Norge.

Deferred tax liabilities decreased to USD 1,415 (1,424) million and are detailed in note 8 to the financial statements.

Gross interest-bearing debt increased to USD 3,165 (2,353) million, consisting of the DETNOR02 bond of USD 230 million, the DETNOR03 bond of USD 295 million and the Reserve Based Lending ("RBL") facility of USD 2,640 million.

Statement of cash flow

(USD million)	Q3 2016	Q3 2015
Cash flow from operations	251	242
Cash flow from investments	164	-242
Cash flow from financing	300	22
Net change in cash & cash eq.	715	22
Cash and cash eq. EOQ	786	207

Net cash flow from operating activities was USD 251 (242) million.

Net cash flow from investment activities was USD 164 (-242) million. Investments in fixed assets amounted to USD 203 (237) million for the quarter, mainly reflecting CAPEX on Ivar Aasen, Alvheim and Johan Sverdrup. Investments in intangible assets including capitalised exploration were USD 54 (0) million in the quarter. Net cash received from the acquisition of BP Norge amounted to USD 424 million.

Net cash flow from financing activities totaled USD 300 (22) million, reflecting the net amount drawn on the group's RBL facility in the quarter.

Funding

Following the announcement of the merger with BP Norge, the company made certain changes to its two bank facilities, including an increase in its reserve-based lending ("RBL") facility from USD 3.0 to 4.0 billion and certain amendments to the loan documentation. In addition, the RBL facility includes an uncommitted accordion option of USD 1.0 billion.

DIVIDENDS

Following the previously stated ambition to pay quarterly dividends from the fourth quarter 2016, the company will call for an Extraordinary General Meeting (EGM), scheduled for November 24, 2016. The Board of Directors proposes to pay a dividend of USD 125 million, split equally for December 2016 and March 2017. This translates into a dividend per share (DPS) of USD 0.185 per quarter.

Amendments to the bank loan agreements include removal of the dividend restriction, replaced by an incurrence test of 4.5x (Net interest-bearing debt / EBITDAX). Subject to successful completion of the updated security package, expected in December 2016, the new borrowing base in the RBL has been set at USD 3.6 billion until the end of 2016.

In October, the bondholder meeting in the DETNOR02 bond loan approved a proposal to remove restrictions related to dividend disbursements and replaced that clause with an incurrence test aligned with the banks, and a put option. As compensation, the DETNOR02 bonds will be repaid at 107 percent of par (+3 percent compared to the previous repayment level) at maturity in 2020.

In view of the merger with BP Norge, the company will assess the composition of its capital structure going forward.

Hedging

The company seeks to reduce the risk related to both foreign exchange rates, interest rates and commodity prices through hedging instruments.

During the third quarter, the company benefitted from the realisation of commodity hedges entered into during the first half of 2015. The company has put options in place with a strike price of 55 USD/bbl for approximately 20 percent of the estimated 2016 oil production (ex. BP Norge), corresponding to 67 percent of the undiscounted after-tax value.

The company actively manages its foreign currency exposure through a mix of forward contracts and options.

The company aims to sustain a minimum dividend level of USD 250 million per year going forward, payable quarterly and to increase this level once Johan Sverdrup is in production.

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.

Aker BP had four minor recordable injuries in the third quarter. The incidents were followed up and measures were taken to prevent reoccurrence. As a follow up to the time out for safety held in May, a "silent deviation" campaign was carried out at all offices and at the site locations to ensure a continued high awareness to HSE and compliance to governing documents. Deviations and areas for improvement were identified across the organization, and registered for follow-up.

There were two supervisory audits from the authorities during the third quarter. One audit by the Petroleum Safety Authority related to the integration process with BP Norge where no deviations noted to date. This audit is ongoing and is anticipated to continue into 2017. The other audit was performed by the Civil Aviation Authority related to the Ivar Aasen helideck with 16 deviations. All deviations are since closed.

OPERATIONAL REVIEW

Aker BP produced 5.5 (5.8) million barrels of oil equivalents ("mmboe") in the third quarter of 2016, corresponding to 59.8 (62.8) mboepd. The average realized oil price was USD 47 (52) per barrel, while gas revenues were recognized at market value of USD 0.15 (0.26) per standard cubic metre (scm).

Alvheim fields

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 third quarter, apart from the planned shutdown period in August. The higher then planned production in the quarter is mainly attributable to the Vilje 2 well and the BoaKamNorth well. The lower branch of the Vilje 2 well achieved strong production in the quarter with no signs of significant water production and the new tri-lateral BoaKamNorth well has also produced above expectations.

The production efficiency for the Alvheim FPSO in the third quarter was 83.3 percent, which was higher than planned for the quarter, but lower than the previous quarter due to the 13-day planned shutdown in August.

The Viper-Kobra development, which comprises two small separate discoveries in the Alvheim area, is progressing according to plan, with first oil expected towards the end of 2016. Drilling of the two wells are complete with good drilling performance and very good reservoir outcomes. The subsea hook-up campaign is currently ongoing with good progress and no significant incidents.

Other producing assets

Production from Jette and Jotun increased in the quarter. Cessation of production was planned to occur end September for both assets but following successful negotiations between the Jotun group and the Ringhorne group, production will now continue until year end. Atla produced in July and August as reservoir pressure allowed and was shut-in during September to build pressure again. Production from Enoch has been stable since the restart in May.

Ivar Aasen

PL001B/242/457 (34.78 percent, operator)

Key activities for the Ivar Aasen project are progressing according to plan and budget with first oil scheduled for December 2016. Ivar Aasen is being developed with a manned production platform. The topside includes living quarters and a processing facility for first stage separation.

The Maersk Interceptor jack-up rig completed the predrilling campaign at Ivar Aasen in July and left location to drill exploration wells at Rovarkula in PL626 and Langfjellet in PL442. After completing the Langfjellet exploration well, the rig will return to Ivar Aasen and

function as an accommodation unit for a period until drilling of additional production and injection wells are expected to commence during the first quarter of 2017.

All offshore lifting and installation activities were completed without any incidents and according to plan during July 2016.

Hook-up and commissioning activities are ongoing, and in September the living quarters were taken into use and the helideck was ready for operation. Five Christmas trees have been lifted in place and installed at Ivar Aasen.

The pipelines between Ivar Aasen and Edvard Grieg have been commissioned. "Consent to start-up and operate" was received from PSA in September.

Johan Sverdrup Unit PL265/501/502 (11.5733 percent, 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 center with four fixed platforms, three subsea templates, oil and gas export pipelines, power from shore and 35 production and injection wells.

The pre-drilling campaign with Deepsea Atlantic is ongoing and progressing ahead of schedule. Engineering and construction of steel jackets, topsides, subsea facilities, pipelines and power from shore facilities is progressing according to plan.

In August, Statoil as the operator announced an increased estimate for production capacity for phase 1 at 440 mboepd, and 660 mboepd for full field compared to the PDO full field range of 550 – 650 mboepd.

In August, the operator announced an updated CAPEX estimate for phase 1 at NOK 99 billion (nominal value), which is down NOK 24 billion from the nominal CAPEX estimate at PDO (NOK 123 billion), based on the same FX-assumptions as in the PDO. The operator also announced an updated full field CAPEX of NOK 140 to 170 billion (real), (down from NOK 170 – 220 billion). Aker BP still sees further potential for CAPEX reductions.

Following the reduced CAPEX estimates and increased production capacity the operator's phase 1 break-even price is reduced to below USD 25 per boe, and the full field break-even price is below USD 30 per boe.

The full field development of the peripheral parts of the Johan Sverdrup oil field will be accompanied by an increased production capacity on a 5th platform at the field center and increased power from shore capacity that will also supply the surrounding fields Ivar Aasen, Edvard Grieg and Gina Krog. Start-up of production from phase 2 is expected in 2022.

Aker BP is still evaluating whether the decision made by the King in Council regarding the distribution of the participating interests should be contested in the court system.

Gina Krog PL029B/029C/048/303 (3.3 percent, partner)

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

The project is progressing according to plan towards production start-up the first half of 2017. The topside was successfully installed offshore August 2016 by Saipem 7000. Flotel Endurance arrived at the field late August and hook-up and commissioning scope is ongoing.

EXPLORATION

During the quarter, the company's cash spending on exploration was USD 76 million. USD 31 million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees and G&G costs.

Exploration drilling in the Krafla/Askja area in PL272/035 in the North Sea commenced in March with the aim to prove additional resource potential in the area. Gross proven resources in the two licenses were estimated to 140 – 220 mmboe prior to the drilling campaign. Drilling of the Slemmestad prospect and the Haraldsplass sidetrack in PL272 in the North Sea was completed in July and marked the completion of the 2016 drilling campaign in the Krafla/Askja area. Preliminary estimates for Slemmestad are between 6 – 13 mmboe and Haraldsplass 13 – 31 mmboe.

Drilling of the Rovarkula prospect in PL626 in the North Sea was completed in August as a dry well.

Drilling of the Langfjellet prospect in PL442 in the North Sea was completed in September. The well encountered a gross oil column of 109 meters in the Vestland Group. Two technical sidetracks were drilled to collect data and a third sidetrack is currently being drilled. Preliminary volume estimates for the discovery are in the range of 24 to 74 million barrels of oil equivalent. The licensees will evaluate the discovery with regards to a potential development together with other discoveries in the area. Following the successful drilling results at Langfjellet, the licensees have identified further prospectivity within the license.

BUSINESS DEVELOPMENT

In July, Aker BP acquired a 15% interest in PL659 from Point Resources and sold its interest in PL038D (Grevling) to Okea. Also in the quarter, Aker BP entered into an agreement with LOTOS to align ownership interest in PL442 and PL026B and acquired a 20% interest in PL719 from North E&P.

In October, Aker BP announced the acquisition of eight licenses from Tullow Norge AS, including 15 percent in the Oda (previously known as Butch) discovery in PL405. The transaction strengthens Aker BP's position in core areas surrounding the Ula, North of Alvheim, Skarv and the Krafla/Askja areas. The transaction is subject to regulatory approval.

The Oda development concept is a tie-in to the Ula field and the discovery is estimated to contain 43 mmboe (gross) according to the NPD. The partners are targeting an investment decision in 2016.

MERGER WITH BP NORGE

On September 30, Aker BP announced that the merger between Det norske and BP Norge was closed and the company changed its name to Aker BP ASA with its headquarters moved to Fornebuporten outside Oslo.

In this regard, 135.1 million new shares were issued to BP plc as compensation for all shares in BP Norge. In parallel, Aker ASA acquired 33.8 million shares from BP plc to achieve the agreed-upon ownership structure. The effective date of the transaction is January 1, 2016. The merger and the share issue were approved by an extraordinary general meeting September 15, 2016.

Aker BP has a portfolio of 95 licenses on the Norwegian Continental Shelf, of which 47 are operated. The combined company holds an estimated 795 million barrels of oil equivalent P50 reserves, with a 2015 joint production of approximately 122,000 barrels of oil equivalent per day.

BP Norge became a wholly-owned subsidiary of Aker BP from closing of the transaction on September 30, 2016. Full organizational and operational incorporation into Aker BP will take place on "Day 1", planned to be December 1, 2016.

Before BP Norge is fully incorporated into Aker BP, it will be a subsidiary of Aker BP with a separate Board of Directors. For the period from closing to Day 1, Jan Norheim is Managing Director of BP Norge with the necessary authorities to operate BP Norge in a safe and reliable manner.

In order for BP Norge to be operational on a standalone basis, a transitional services agreement has been established according to which BP Group is providing certain services to BP Norge, and subsequently to Aker BP after Day 1.

OTHER EVENTS

Murray Auchincloss, CFO Upstream in BP plc, was elected as new member to the company's Corporate Assembly at the Extraordinary General Meeting September 15,2016, replacing Odd Reitan.

Effective from the closing of the merger, Bernard Looney, Chief executive, Upstream and Kate Thomson, Group head of tax in BP plc, were elected new members of the Board of Directors in Aker BP. Kitty Hall and Kjell Pedersen have at the same time resigned from their duties as members of the Board.

OPERATIONAL UPDATE BP NORGE

The merger with BP Norge closed on September 30, 2016. For accounting purposes, the third quarter income statement therefore does not include operations in BP Norge. The balance sheet as of September 30, 2016 reflects the consolidated Group, including a purchase price allocation.

BP Norge produced 4.9 mmboe in the third quarter of 2016, corresponding to 52.8 mboepd.

Valhall Area PL006B/033/033B (operator)

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

The Valhall area produced 17.9 mboepd in Q3 (Valhall 17.2 mboepd and Hod 0.6 mboepd) which is an increase from 12.1 in the previous quarter, mainly driven by a planned shutdown in June. The operation efficiency ended at 91 percent in Q3 significantly higher than the previous quarter (60 percent), mainly due to the planned shutdown. Two wells were back on stream after a well work over.

In July, the Maersk Reacher rig completed a planned P&A program at the DP platform and was successfully removed from location. The new-built Maersk Invincible drilling rig will continue the P&A campaign in first half 2017. In addition, the 2/4 G topside was removed during 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 Talisman operated Blane field and the Dong operated Oselvar field.

Ula area produced 10.0 mboepd in the third quarter (Ula 7.2 mboepd and Tambar 2.8 mboepd) which is an increase from 8.5 mboepd in the previous quarter, mainly driven by a planned shutdown in June. The operation efficiency ended at 75 percent in Q3 significantly higher than the previous quarter (64 percent), mainly due to the planned shutdown. Efficiency on Ula is impacted by delays in restoring full water alternating gas (WAG) injection flexibility.

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 (A1H) is reported as Skarv volumes.

The Skarv area produced 24.6 mboepd in Q3 which is a reduction from the previous quarter, mainly driven by the planned shutdown in August (27 days). All turnaround work was completed as planned, however with a slower ramp up than planned driven by start-up issues. The operation efficiency ended at 74 percent in the third quarter, significantly lower than the previous quarter (94 percent), mainly due to the planned shutdown.

OUTLOOK

The creation of Aker BP has established a strong platform for value creation and efficiency through leveraging on unique industrial capabilities, a world-class asset base, and financial robustness. The Board of Directors proposes to pay a dividend of USD 125 million, split equally for December 2016 and March 2017. Going forward, the company will pursue further growth opportunities both to enhance production and increase dividend capacity.

The Viper and Kobra wells are scheduled to commence production before year-end. The Transocean Arctic drilling rig will commence drilling programme in the Alvheim area in December 2016.

The hook-up and commissioning activities at Ivar Aasen are progressing according to plan towards planned start-up in December 2016. The Johan Sverdrup project is moving forward according to plan and the company continues to see potential for further cost reductions. Drilling and data gathering at the Langfjellet prospect in the North of Alvheim area continues and a second side track is currently being drilled.

The company's balance sheet and funding outlook has been significantly strengthened following the merger with BP Norge. Going forward, the company will assess the composition of its capital structure.

Aker BP expects the full year 2016 (BP Norge included for 12 months) CAPEX to be USD 910 – 930 million and exploration expenditures are expected to be USD 240 – 260 million. Production guidance for 2016 is expected between 118 and 120 mboepd and production cost is expected to average about 13 USD per barrel of oil equivalent.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT (Unaudited)

Q3 01.01.-30.09. (USD 1 000) Note 2016 2015 2016 2015 Petroleum revenues 2 247 213 280 537 719 254 940 369 Other operating income 2 779 35 857 -10 748 26 798 Total operating income 247 993 316 394 708 506 967 167 Exploration expenses 4 30 843 18 066 103 172 57 537 Production costs 32 188 26 888 105 678 116 923 Depreciation 6 114 649 129 790 349 231 369 368 Impairments 5, 6 8 429 185 756 26 748 238 529 Other operating expenses 6 223 11 433 16 964 48 380 Total operating expenses 192 333 371 932 601 794 830 738 Operating profit/loss 55 660 -55 539 106 712 136 430 Interest income 568 184 2 908 1 359 Other financial income 37 918 19 954 79 113 66 826 Interest expenses 20 107 20 997 61 933 59 728 Other financial expenses 23 487 50 346 46 527 107 290 Net financial items 7 -5 107 -51 205 -26 439 -98 832 Profit/loss before taxes 50 553 -106 744 80 273 37 597 Taxes (+)/tax income (-) 8 -12 880 59 441 -21 701 194 065 Net profit/loss 63 433 -166 185 101 974 -156 468 Weighted average no. of shares outstanding and fully diluted 202 618 602 202 618 602 202 618 602 202 618 602 Earnings/(loss) after tax per share 0.31 -0.82 0.50 -0.77		Group

STATEMENT OF COMPREHENSIVE INCOME (Unaudited)

		Group
		Q3		01.01.-30.09.
(USD 1 000)	Note	2016	2015	2016	2015
Profit/loss for the period		63 433	-166 185	101 974	-156 468
Items which will not be reclassified over profit and loss (net of taxes)
Currency translation adjustment		-	-	-59	-
Total comprehensive income in period		63 433	-166 185	101 914	-156 468

STATEMENT OF FINANCIAL POSITION (Unaudited)

		Group
(USD 1 000) Note	30.09.2016	30.09.2015	31.12.2015
ASSETS
Intangible assets
Goodwill 6	1 858 465	948 175	767 571
Capitalized exploration expenditures 6	361 696	300 841	289 980
Other intangible assets 6	1 339 433	597 140	648 030
Deferred tax assets 8	889 108	-	-
Tangible fixed assets
Property, plant and equipment 6	4 383 110	2 929 128	2 979 434
Financial assets
Long-term receivables	42 308	4 440	3 782
Long-term tax receivable 8	22 234	-	-
Other non-current assets 9	12 866	4 396	12 628
Long-term derivatives 13	14 924	5 768	-
Total non-current assets	8 924 144	4 789 888	4 701 425
Inventories
Inventories	66 499	32 013	31 533
Receivables
Accounts receivable	99 775	64 061	85 546
Other short-term receivables 10	259 579	114 049	105 190
Other current financial assets	3 070	2 892	2 907
Tax receivables 8	133 101	8 095	126 391
Short-term derivatives 13	7 988	18 786	45 217
Cash and cash equivalents
Cash and cash equivalents 11	785 622	206 941	90 599
Total current assets	1 355 635	446 836	487 384
TOTAL ASSETS	10 279 778	5 236 724	5 188 809

STATEMENT OF FINANCIAL POSITION (Unaudited)

			Group
(USD 1 000)	Note	30.09.2016	30.09.2015	31.12.2015
EQUITY AND LIABILITIES
Equity
Share capital	12	54 349	37 530	37 530
Share premium		3 150 567	1 029 617	1 029 617
Other equity		-626 206	-571 954	-728 121
Total equity		2 578 710	495 193	339 026
Non-current liabilities
Deferred taxes	8	1 414 944	1 423 879	1 356 114
Long-term abandonment provision	17	2 019 566	506 541	412 805
Provisions for other liabilities		359 909	1 601	1 638
Long-term bonds	15	525 645	511 070	503 440
Other interest-bearing debt	16	2 639 517	1 842 425	2 118 935
Long-term derivatives	13	20 072	47 170	62 012
Current liabilities
Trade creditors		77 042	56 984	51 078
Accrued public charges and indirect taxes		22 598	6 493	9 060
Short-term derivatives	13	-	9 891	13 506
Short-term abandonment provision	17	83 498	3 758	10 520
Other current liabilities	14	538 276	331 718	310 675
Total liabilities		7 701 068	4 741 531	4 849 783
TOTAL EQUITY AND LIABILITIES		10 279 778	5 236 724	5 188 809

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 31.12.2014	37 530	1 029 617	573 083	-105	-115 491	-872 972	-415 485	651 662
Profit/loss for the period 01.01.2015 - 31.12.2015	-	-	-	17	-	-312 652	-312 636	-312 636
Equity as of 31.12.2015	37 530	1 029 617	573 083	-88	-115 491	-1 185 625	-728 121	339 026
Private placement	16 820	2 120 950	-	-	-	-	-	2 137 769
Profit/loss for the period 01.01.2016 - 30.9.2016	-	-	-	-	-59	101 974	101 914	101 914
Equity as of 30.9.2016	54 349	3 150 567	573 083	-88	-115 550	-1 083 651	-626 206	2 578 710

* At 15 October 2014, the presentation currency was changed to USD retrospectively as if USD had always been the presentation currency. For each category of the opening equity as at 1 January 2013, the historical rates were used for translation to USD, and therefore an exchange reserve was established which represents the fact that the presentation currency is different from the functional currency in the periods presented prior to the change in functional currency to USD as at 15 October 2014. For each period presented prior to the change in functional currency, the ending balance of total equity is translated to USD using the end rate.

STATEMENT OF CASH FLOW (Unaudited)

		Group
			Q3	01.01.-30.09.		Year
(USD 1 000)	Note	2016	2015	2016	2015	2015
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		50 553	-106 744	80 273	37 597	-113 607
Taxes paid during the period		-151	-44 715	-1 419	-235 221	-320 618
Tax refund during the period		83 666	-	83 666	-	87 662
Depreciation	6	114 649	129 790	349 231	369 368	480 959
Net impairment losses	5, 6	8 429	185 756	26 748	238 529	430 468
Accretion expenses	7, 17	6 816	6 657	18 691	19 605	26 351
Interest expenses	7	40 882	36 193	118 116	90 511	127 620
Interest paid		-32 405	-32 675	-109 319	-79 428	-124 276
Changes in derivatives	2, 7	-32 126	10 177	-33 140	1 430	-793
Amortized loan costs	7	4 846	3 539	12 242	15 218	17 480
Amortization of fair value of contracts assumed in the
Marathon acquisition		-		-	-2 878	-2 878
Expensed capitalized dry wells	4, 6	9 313	-686	43 702	9 190	11 682
Changes in inventories, accounts payable and receivables		-31 465	-180 545	-92 088	-441 709	-13 060
Changes in abandonment liabilities through income statement		-	-	-	-	-1 569
Changes in other current balance sheet items		28 365	235 460	76 571	539 546	81 048
NET CASH FLOW FROM OPERATING ACTIVITIES		251 372	242 206	573 275	561 757	686 467
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	17	-2 473	-5 592	-5 493	-8 768	-12 508
Disbursements on investments in fixed assets	6	-203 337	-236 659	-691 487	-688 122	-917 150
Net of cash consideration paid for, and cash acquired with, BP Norge AS	3	423 990	-	423 990	-	-
Acquisition of Premier Oil Norge AS (net of cash acquired)		-	-	-	-	-125 600
Disbursements on investments in capitalized exploration expenditures and
other intangible assets	6	-54 194	-178	-119 459	-32 093	-113 051
NET CASH FLOW FROM INVESTMENT ACTIVITIES		163 986	-242 429	-392 450	-728 982	-1 168 310
CASH FLOW FROM FINANCING ACTIVITIES
Repayment of short-term debt		-	-	-	-	-70 938
Repayment of long-term debt		-	-	-	-330 000	-330 000
Net proceeds from issuance of long-term debt		299 685	21 933	512 013	410 620	685 620
NET CASH FLOW FROM FINANCING ACTIVITIES		299 685	21 933	512 013	80 620	284 683
Net change in cash and cash equivalents		715 043	21 711	692 838	-86 604	-197 160
Cash and cash equivalents at start of period		68 393	187 928	90 599	296 244	296 244
Effect of exchange rate fluctuation on cash held		2 186	-2 698	2 186	-2 698	-8 485
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	785 622	206 941	785 622	206 941	90 599
SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits and cash		778 863	203 323	778 863	203 323	86 201
Restricted bank deposits CASH AND CASH EQUIVALENTS AT END OF PERIOD	11	6 759 785 622	3 618 206 941	6 759 785 622	3 618 206 941	4 398 90 599

NOTES

(All figures in USD 1 000)

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 2015. These interim financial statements have not been subject to review or audit by independent auditors.

The acquisition of BP Norge AS was completed on 30 September 2016, and the transaction is thus reflected in the statement of financial position in this report. The acquisition has no impact on the income statement in Q3 2016. See note 3 for more information regarding the acquisition. In relation to the acquisition, the company changed name from Det norske oljeselskap ASA to Aker BP ASA, and the ticker on Oslo Stock Exchange was changed from DETNOR to AKERBP.

Note 1 Accounting principles

The accounting principles used for this interim report are in all material respect consistent with the principles used in the financial statements for 2015. There are no new standards effective from 1 January 2016.

The group changed the presentation of accretion expenses in Q1 2016. It is now included in the line item other financial expenses, while it has been presented as interest expenses prior to 2016. In addition, following the change from defined benefit to defined contribution scheme, pension is no longer presented on a separate line in the Statement of financial position. Comparable figures have been restated accordingly.

Note 2 Operating income

	Group
	Q3			01.01.-30.09.
Breakdown of petroleum revenues (USD 1 000)	2016	2015	2016	2015
Recognized income oil	229 954	252 353	660 364	847 056
Recognized income gas	14 338	27 456	51 752	90 971
Tariff income	2 922	728	7 138	2 342
Total petroleum revenues	247 213	280 537	719 254	940 369
Breakdown of produced volumes (barrels of oil equivalent)
Oil	4 909 309	5 135 774	14 754 370	14 888 483
Gas	595 866	642 419	1 948 807	2 045 493
Total produced volumes	5 505 174	5 778 193	16 703 177	16 933 976
Other operating income (USD 1 000)
Realized gain/loss (-) on oil derivatives	5 640	4 755	28 702	204
Unrealized gain/loss (-) on oil derivatives	-4 993	30 642	-43 436	24 553
Other income	132	460	3 986	2 042
Total other operating income	779	35 857	-10 748	26 798

The group changed its presentation of commodity derivatives in Q4 2015. Gains and losses are now presented as other operating income, while it was included in financial items prior to Q4 2015. Comparable figures have been restated accordingly.

Note 3 Business combination

On 30 September 2016, Aker BP finalized the acquisition of 100 per cent of the shares in BP Norge AS. The transaction was announced on 10 June 2016, and Aker BP issued 135.1 million new shares to BP Group as compensation for the shares in BP Norge AS. In addition, the group paid a cash consideration of USD 251 million. The main reasons for the acquisition were to create a group with a strong platform through industrial capabilities, a world class asset based and financial robustness to take advantage of the attractive growth potential on the Norwegian Continental Shelf. The portfolio of licences from BP Norge AS comes with limited capital expenditure commitments and high near-term production that complement the planned production start of Aker BP's Ivar Aasen and Johan Sverdrup developments.

The acquisition date for accounting purposes corresponds to the finalization of the transaction on 30 September 2016. For tax purposes, the effective date was 1 January 2016. The acquisition is regarded as a business combination and has been accounted for using the acquisition method of accounting in accordance with IFRS 3. A purchase price allocation (PPA) has been performed to allocate the consideration to fair value of assets and liabilities of BP Norge AS. The PPA is performed as of the acquisition date, 30 September 2016. The closing share price at Oslo Stock Exchange (NOK 127) was used as a basis for measuring the value of the shares consideration.

Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 13. The standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. This definition emphasizes that fair value is a market-based measurement, not an entity-specific measurement. When measuring fair value, the group uses the assumptions that market participants would use when pricing the asset or liability under current market conditions, including assumptions about risk. Acquired property, plant and equipment have been valued using the cost approach (replacement cost), while intangible assets (value of licenses) have been valued using the income approach.

Accounts receivable are recognized at gross contractual amounts due, as they relate to large and credit-worthy customers. Historically, there has been no significant uncollectible accounts receivable in BP Norge AS.

The recognized amounts of assets and liabilities assumed as at the date of the acquisition were as follows:

(USD 1 000)	30.09.2016
Other intangible assets	759 962
Deferred tax asset	889 108
Property, plant and equipment	921 081
Long-term receivables*	41 546
Long-term tax receivable	5 860
Inventories	20 860
Accounts receivable	14 053
Other short-term receivables	66 618
Tax receivables	4 881
Cash and cash equivalents	674 543
Total assets	3 398 513
Long-term abandonment provision	1 515 699
Provisions for other liabilities**	357 307
Trade creditors	16 001
Accrued public charges and indirect taxes	13 209
Short-term abandonment provision	72 537
Other current liabilities	154 521
Total liabilities	2 129 273
Total identifiable net assets at fair value	1 269 240
Consideration paid on acquisition	2 388 322
Goodwill arising on acquisition	1 119 083

* This is a receivable towards BP Group related to certain obligations that will be covered by the sellers according to the transaction agreement.

** The main part of the provision is related to negative contract values related to rig contracts entered into by BP Norge AS, which was different from current market terms at the time of acquisition at 30 September 2016. The fair value is based on the difference between market price and contract price.

*** No part of the goodwill will be deductible for tax purposes.

The goodwill of USD 1 119 million arises principally because of the following factors:

1. The ability to capture synergies that can be realized from managing a portfolio of both acquired and existing fields on the Norwegian Continental Shelf ("residual goodwill").

2. The requirement to recognize deferred tax assets and liabilities for the difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licences under development and licences in production can only be sold in a market after tax, based on a decision made by the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act Section 10. The assessment of fair value of such licences is therefore based on cash flows after tax. Nevertheless, in accordance with IAS 12 Sections 15 and 19, a provision is made for deferred tax corresponding to the tax rate multiplied with the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax ("technical goodwill").

Reconciliation of goodwill from the acquisition of BP Norge AS (USD 1 000)	30.09.2016
Goodwill as a result of deferred tax - technical goodwill	944 903
Goodwill related to synergies - residual goodwill	174 180
Net goodwill from the acquisition of BP Norge AS	1 119 083

The above valuation is based on currently available information about fair values as of the acquisition date. If new information becomes available within 12 months from the acquisition date, the group may change the fair value assessment in the PPA, in accordance with guidance in IFRS 3.

Note 4 Exploration expenses

	Group
		Q3	01.01.-30.09.
Breakdown of exploration expenses (USD 1 000)	2016	2015	2016	2015
Seismic	4 810	5 105	11 006	12 271
Area fee	4 151	1 577	9 255	5 348
Expensed capitalized wells this year	7 358	-686	30 531	7 898
Expensed capitalized wells previous years	1 955	-	13 171	1 292
Other exploration expenses	12 569	12 070	39 210	30 729
Total exploration expenses	30 843	18 066	103 172	57 537

In Q1 2016 the group did some changes in the subcategories within exploration expenses presented above. Comparable figures have been restated accordingly.

Note 5 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 the acquisition of Marathon Oil Norge AS will be subject to impairment charges as it is fully allocated to the Alvheim CGU. Hence, a quarterly impairment charge is expected if all assumptions remain unchanged. However, in Q3 2016 there has been an increase in the oil and gas forward curves compared to Q2 2016, as well as some profile updates on the Alvheim fields. The group's calculation shows that no impairment charge of the Alvheim CGU is needed in Q3 2016. Previous impairment in 2016 of this technical goodwill amounted to USD 28.2 million.

In the Purchase Price Allocation in relation to the acquisition of Marathon Oil Norge AS in 2014, some values were allocated to certain exploration prospects. During Q3 2016 the group has concluded to cease the activity on some of these exploration assets, and the related value of approximately USD 8 million is thus impaired.

Note 6 Tangible assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

		Production	Fixtures and
	Assets under	facilities	fittings, office
(USD 1 000)	development	including wells	machinery	Total
Book value 31.12.2015	1 493 795	1 470 881	14 758	2 979 434
Acquisition cost 31.12.2015	1 505 779	2 514 487	35 506	4 055 772
Additions	421 071	85 193	2 184	508 448
Disposals	-	-	91	91
Reclassification	-48 307	48 287	-9	-30
Acquisition cost 30.6.2016	1 878 543	2 647 967	37 590	4 564 100
Accumulated depreciation and impairments 30.6.2016	1 566	1 234 260	23 193	1 259 019
Book value 30.6.2016	1 876 976	1 413 707	14 397	3 305 081
Acquisition cost 30.6.2016	1 878 543	2 647 967	37 590	4 564 100
Acquisition of BP Norge AS	-	921 081	-	921 081
Additions	234 962	8 798	5 747	249 506
Reclassification	6 692	-18 576	11 834	-50
Acquisition cost 30.9.2016	2 120 197	3 559 271	55 171	5 734 638
Accumulated depreciation and impairments 30.9.2016	1 566	1 325 351	24 612	1 351 529
Book value 30.9.2016	2 118 630	2 233 920	30 559	4 383 110
Depreciation Q3 2016	-	90 934	1 419	92 353
Depreciation 01.01.2016 - 30.9.2016	-	281 040	3 864	284 904
Impairments/reversal of impairments Q3 2016	-	-	-	-
Impairments/reversal of impairments 01.01.2016 - 30.9.2016	-10 418	548	-	-9 870

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 31.12.2015	646 487	1 543	648 030	289 980	767 571
Acquisition cost 31.12.2015	789 316	9 149	798 465	289 980	1 561 880
Additions	3 178	-	3 178	62 059
Disposals/expensed dry wells	-	-	-	34 388	-
Reclassification	767	-	767	-737
Acquisition cost 30.6.2016	793 260	9 149	802 409	316 913	1 561 880
Accumulated depreciation and impairments 30.6.2016	184 446	8 019	192 466	-	822 498
Book value 30.6.2016	608 814	1 129	609 943	316 913	739 383
Acquisition cost 30.6.2016	793 260	9 149	802 409	316 913	1 561 880
Acquisition of BP Norge AS	759 962	-	759 962	-	1 119 083
Additions	1 430	-1 383	48	54 097	-
Disposals/expensed dry wells	-	-	-	9 314	-
Reclassification	50	-	50	-	-
Acquisition cost 30.9.2016	1 554 702	7 766	1 562 468	361 696	2 680 963
Accumulated depreciation and impairments 30.9.2016	215 618	7 417	223 035	-	822 498
Book value 30.9.2016	1 339 084	349	1 339 433	361 696	1 858 465
Depreciation Q3 2016	22 899	-602	22 296	-	-
Depreciation 01.01.2016 - 30.9.2016	64 516	-188	64 327	-	-
Impairments Q3 2016	8 429	-	8 429	-	-
Impairments 01.01.2016 - 30.9.2016	8 429	-	8 429	-	28 189

See Note 5 for information regarding impairment charges.

	Group
	Q3		01.01.-30.09.
Depreciation in the Income statement (USD 1 000)	2016	2015	2016	2015
Depreciation of tangible fixed assets	92 353	110 615	284 904	311 339
Depreciation of intangible assets	22 296	19 175	64 327	58 030
Total depreciation in the Income statement	114 649	129 790	349 231	369 368

	Group
	Q3 01.01.-30.09.
Impairment in the Income statement (USD 1 000)	2016	2015	2016	2015
Impairment/reversal of tangible fixed assets	-	-	-9 870	-
Impairment/reversal of intangible fixed assets	8 429	-	8 429	-
Impairment of goodwill	-	185 756	28 189	238 529
Total impairment in the Income statement	8 429	185 756	26 748	238 529

Note 7 Financial items

	Group
	Q3		01.01.-30.09.
(USD 1 000)	2016	2015	2016	2015
Interest income	568	184	2 908	1 359
Realised gains on derivatives	799	686	2 536	879
Return on financial investments	-	-	-	24
Change in fair value of derivatives	37 119	-	76 576	18 251
Currency gains	-	19 268	-	47 672
Total other financial income	37 918	19 954	79 113	66 826
Interest expenses	40 882	36 193	118 116	90 511
Capitalized interest cost, development projects	-25 621	-18 735	-68 425	-46 001
Amortized loan costs	4 846	3 539	12 242	15 218
Total interest expenses	20 107	20 997	61 933	59 728
Currency losses	14 773	-	16 282	-
Realised loss on derivatives	1 180	2 864	6 209	43 446
Change in fair value of derivatives	-	40 819	-	44 234
Accretion expenses	6 816	6 657	18 691	19 605
Other financial expenses	717	6	5 345	6
Total other financial expenses	23 487	50 346	46 527	107 290
Net financial items	-5 107	-51 205	-26 439	-98 832

The group changed its presentation of commodity derivatives in Q4 2015. Gains and losses are now presented as other operating income, while it was included in financial items prior to Q4 2015. Comparable figures have been restated accordingly.

The group changed the presentation of accretion expenses in Q1 2016. It is now included in the line item other financial expenses, while it was presented as interest expenses prior to 2016. Comparable figures have been restated accordingly.

Note 8 Taxes

			Group
	Q3			01.01.-30.09.
Taxes for the period appear as follows (USD 1 000)	2016	2015	2016	2015
Calculated current year tax/exploration tax refund	12 116	68 400	-16 719	131 418
Change in deferred taxes in the Income statement	-24 996	-8 956	-9 734	67 207
Prior period adjustments	-	-3	4 752	-4 560
Total taxes (+)/tax income (-)	-12 880	59 441	-21 701	194 065

	Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	30.09.2016	30.09.2015	31.12.2015
Tax receivable/payable at 1.1.	126 391	-189 098	-189 098
Current year tax (-)/tax receivable (+)	16 719	-67 431	-49 776
Tax receivable related to acquisition of Svenska Petroleum Exploration AS/Premier Oil Norge AS	60 379	-	108 047
Tax receivable related to acquisition of BP Norge AS	10 740	-	-
Tax receivable related to acquisition of licences	3 923	-	-
Tax payment/tax refund	-82 247	235 221	232 956
Prior period adjustments	4 716	10 664	11 580
Revaluation of tax receivable	14 714	18 740	12 682
Total tax receivable (+)/tax payable (-)	155 335	8 095	126 391
Tax receivable included as non-current assets	22 234	-	-
Tax receivable included as current assets	133 101	8 095	126 391

	Group
Deferred taxes (-)/deferred tax asset (+) (USD 1 000)	30.09.2016	30.09.2015	31.12.2015
Deferred taxes/deferred tax asset 1.1.	-1 356 114	-1 286 357	-1 286 357
Change in deferred taxes in the Income statement	9 734	-131 418	-153 927
Reclassification of loss carried forward from Premier Oil Norge AS	-60 379	-	-
Deferred tax related to acquisition of BP Norge AS	889 108	-	-
Deferred tax related to acquisition of Svenska Petroleum Exploration AS/Premier Oil Norge AS	-	-	91 151
Deferred tax related to impairment, disposal and licence transactions	1 401	-	-
Prior period adjustment	-9 587	-6 104	-6 921
Deferred tax charged to OCI and equity	-	-	-59
Net deferred tax (-)/deferred tax asset (+)	-525 836	-1 423 879	-1 356 114
Deferred tax asset	889 108	-	-
Deferred tax	-1 414 944	-1 423 879	-1 356 114

Group
		Q3	01.01.-30.09.
Reconciliation of tax expense (USD 1 000)	2016	2015	2016	2015
25%/27% group tax on profit before tax	12 638	-28 821	20 068	10 151
53%/51% special tax on profit before tax	26 793	-54 439	42 545	19 174
Tax effect on uplift	-24 598	-23 662	-75 722	-71 107
Permanent difference on impairment	-	144 889	21 987	186 052
Foreign currency translation of NOK monetary items	5 970	-18 753	10 689	-32 447
Foreign currency translation of USD monetary items	78 567	-123 887	180 741	-206 083
Tax effect of financial and other 25%/27% items	-51 580	72 818	-104 214	144 174
Revaluation of tax balances*	-57 924	94 335	-117 850	145 958
Other items (other permanent differences and prior period adjustment)	-2 747	-3 039	54	-1 808
Total taxes (+)/tax income (-)	-12 880	59 441	-21 701	194 065

* 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 when the functional currency is different from NOK.

The revaluation of tax receivable and payable is presented as foreign exchange loss/gain in the Income statement, while the impact on deferred tax from revaluation of tax balances is presented as tax.

Note 9 Other non-current assets

	Group
(USD 1 000)	30.09.2016	30.09.2015	31.12.2015
Shares in Alvheim AS	10	10	10
Shares in Det norske oljeselskap AS	1 021	1 021	1 021
Shares in Sandvika Fjellstue AS	1 814	1 814	1 814
Investment in subsidiaries	2 845	2 845	2 845
Tenancy deposit	1 654	1 551	1 512
Other non-current assets	8 367	-	8 272
Total other non-current assets	12 866	4 396	12 628

Alvheim AS, Det norske oljeselskap AS (previously Marathon Oil Norge AS) and Sandvika Fjellstue AS have been deemed immaterial for consolidation purposes.

The acquisition of BP Norge AS was completed at 30 September 2016 and is consolidated in this report as outlined in note 3. Det norske oil AS and Det norske Exploration AS was liquidated during Q2 2016.

Note 10 Other short-term receivables

		Group
(USD 1 000)	30.09.2016	30.09.2015	31.12.2015
Pre-payments, including rigs	34 835	35 757	21 634
VAT receivable	9 478	7 472	6 121
Underlift of petroleum	59 590	17 755	3 696
Accrued income from sale of petroleum products	6 024	25 084	1 866
Other receivables, mainly from licenses	149 651	27 982	71 873
Total other short-term receivables	259 579	114 049	105 190

Note 11 Cash and cash equivalents

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

Group
30.09.2016	30.09.2015	31.12.2015
778 863	203 323	86 201
6 759	3 618	4 398
785 622	206 941	90 599
550 000	550 000	550 000
162 000	985 964	731 370

Note 12 Share capital

	Group
(USD 1 000)	30.09.2016	30.09.2015	31.12.2015
Share capital	54 349	37 530	37 530
Total number of shares (in 1 000)	337 737	202 619	202 619
Nominal value per share in NOK	1.00	1.00	1.00

The group completed a private placement in Q3 2016, increasing the number of outstanding shares with 135.1 million to 337.7 million shares. The additional shares have a nominal value of NOK 1 and a share premium value of NOK 126 per share.

Note 13 Derivatives

	Group
(USD 1 000)	30.09.2016	30.09.2015	31.12.2015
Unrealized gain currency contracts	14 924	5 768	-
Long-term derivatives included in assets	14 924	5 768	-
Unrealized gain on commodity derivatives	1 781	18 786	45 217
Unrealized gain currency contracts	6 207	-	-
Short-term derivatives included in assets	7 988	18 786	45 217
Total derivatives included in assets	22 912	24 553	45 217
Unrealized losses currency contracts	-	2 889	7 840
Unrealized losses interest rate swaps	20 072	44 281	54 172
Long-term derivatives included in liabilities	20 072	47 170	62 012
Unrealized losses currency contracts	-	9 590	13 506
Unrealized losses interest rate swaps	-	301	-
Short-term derivatives included in liabilities	-	9 891	13 506
Total derivatives included in liabilities	20 072	57 061	75 518

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 contracts are used to swap USD into foreign currencies, mainly NOK, EUR, GBP and SGD, in order to reduce currency risk related to expenditures. These derivatives are marked to market with changes in market value recognized in the Income statement.

Note 14 Other current liabilities

Breakdown of other current liabilities (USD 1 000)	30.09.2016	30.09.2015	31.12.2015
Current liabilities related to overcall in licences	104 821	52 416	33 444
Share of other current liabilities in licences	329 299	156 576	184 010
Overlift of petroleum	9 561	12 615	17 088
Fair value of contracts assumed in acquisition of Marathon Oil Norge AS*	-	17 837	12 009
Other current liabilities**	94 596	92 273	64 125
Total other current liabilities	538 276	331 718	310 675

* The negative contract value is related to a rig contract entered into by Marathon Oil Norge AS, which was different from current market terms at the time of acquisition at 15 October 2014. The fair value was based on the difference between market price and contract price. The contracts expired in 2016.

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

Note 15 Long-term bonds

	Group
(USD 1 000)	30.09.2016	30.09.2015	31.12.2015
DETNOR02 Senior unsecured bond1)	230 274	216 415	208 744
DETNOR03 Subordinated PIK toggle bond 2)	295 371	294 654	294 696
Total bond	525 645	511 070	503 440

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 October 2016 the group removed the dividend restriction, subject to a leverage incurrence test at 4.5x (net interest-bearing debt / EBITDAX). In addition, the bondholders have received a put option for an amount corresponding to any dividend payment from Aker BP at put price of 107. As compensation, the DETNOR02 bonds will be repaid at 107 per cent of par at maturity in 2020, up from the previous 104 per cent resulting from the covenant amendment process earlier this year.

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

Note 16 Other interest-bearing debt

	Group
(USD 1 000)	30.09.2016	30.09.2015	31.12.2015
Reserve-based lending facility	2 639 517	1 842 425	2 118 935
Total other interest-bearing debt	2 639 517	1 842 425	2 118 935

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, 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.

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.

The borrowing base availability in the second half of 2016 was reset to USD 2.9 billion (up from USD 2.8 billion in the first half of 2016). However, subject to the successful completion of the updated security package related to the BP Norge assets, expected in December 2016, the new borrowing base will increase to USD 3.6 billion until the end of 2016.

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 September 2016.

In October 2016, the group completed a process with its bank consortium in order to amend certain provisions of the RBL and RCF, including removal of the dividend restrictions, subject to a leverage incurrence test of 4.5x (net interest-bearing debt / EBITDAX).

Note 17 Provision for abandonment liabilities

		Group
(USD 1 000)	30.09.2016	30.09.2015	31.12.2015
Provisions as of 1 January	423 325	489 051	489 051
Abandonment liabilities from acquisition of BP Norge AS	1 588 236	-	-
Incurred cost removal	-5 493	-8 768	-12 508
Accretion expense - present value calculation	18 691	19 605	26 351
Change in estimates and incurred liabilities on new fields*	78 306	10 411	-79 569
Total provision for abandonment liabilities	2 103 065	510 299	423 325
Break down of the provision to short-term and long-term liabilities
Short-term	83 498	3 758	10 520

Long-term 2 019 566 506 541 412 805 Total provision for abandonment liabilities 2 103 065 510 299 423 325

* The change in estimates are mainly related to the completion of new wells and installation of topsides on fields under development.

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

The estimate is based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.5 per cent and a nominal discount rate before tax of between 3.91 per cent and 5.93 per cent.

Note 18 Contingent liabilities

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

Note 19 Relocation of the Stavanger office

In Q3 2016, Aker BP entered into a seven year agreement to sublease offices from Aker Solutions in Stavanger, Norway. 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 20 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.

The covenant changes as described in note 15 and 16 where finalized in October 2016. On 3 October 2016 the group announced the acquisition of eight licenses from Tullow Norge AS.

Note 21 Investments in joint operations

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

Fields operated:	30.09.2016		30.06.2016 Fields non-operated:	30.09.2016	30.06.2016
Alvheim	65.000 %	65.000 % Atla		10.000 %	10.000 %
Bøyla	65.000 %	65.000 % Enoch		2.000 %	2.000 %
Ivar Aasen Unit	34.786 %		34.786 % Gina Krog	3.300 %	3.300 %
Jette Unit	70.000 %		70.000 % Johan Sverdrup ****	11.573 %	11.573 %
Vilje	46.904 %	46.904 % Jotun		7.000 %	7.000 %
Volund	65.000 %	65.000 % Varg		5.000 %	5.000 %
Hod*	37.500 %	0.000 %
Valhall*	35.953 %	0.000 %
Ula*	80.000 %	0.000 %
Tambar*	55.000 %	0.000 %
Tambar East*	46.200 %	0.000 %
Skarv*	23.835 %	0.000 %
Snadd*	30.000 %	0.000 %

Production licences in which Aker BP is the operator:			Production licences in which Aker BP is a partner:
Licence:	30.09.2016	30.06.2016 Licence:		30.09.2016	30.06.2016
PL 001B	35.000 %		35.000 % PL 006C***	15.000 %	15.000 %
PL 026B***	92.130 %		92.130 % PL 018DS***	13.338 %	13.338 %
PL 027D	100.000 %	100.000 % PL 019C		30.000 %	30.000 %
PL 028B	35.000 %		35.000 % PL 026***	30.000 %	30.000 %
PL 036C	65.000 %	65.000 % PL 029B		20.000 %	20.000 %
PL 036D	46.904 %	46.904 % PL 035		50.000 %	50.000 %
PL 088BS	65.000 %	65.000 % PL 035C		50.000 %	50.000 %
PL 103B	70.000 %	70.000 % PL 038		5.000 %	5.000 %
PL 150	65.000 %	65.000 % PL 038D		30.000 %	30.000 %
PL 150B	65.000 %	65.000 % PL 048D		10.000 %	10.000 %
PL 169C	50.000 %	50.000 % PL 102C		10.000 %	10.000 %
PL 203	65.000 %	65.000 % PL 102D		10.000 %	10.000 %
PL 203B	65.000 %	65.000 % PL 102F		10.000 %	10.000 %
PL 242	35.000 %	35.000 % PL 102G		10.000 %	10.000 %
PL 261*	50.000 %	0.000 % PL 265		20.000 %	20.000 %
PL 300*	55.000 %	0.000 % PL 272		50.000 %	50.000 %
PL 340	65.000 %	65.000 % PL 457		40.000 %	40.000 %
PL 340BS	65.000 %		65.000 % PL 457BS	40.000 %	40.000 %
PL 364	100.000 %	100.000 % PL 492***		60.000 %	60.000 %
PL 406	50.000 %	50.000 % PL 502		22.222 %	22.222 %
PL 407	50.000 %		50.000 % PL 507***	25.000 %	25.000 %
PL 442***	90.000 %	90.000 % PL 533		35.000 %	35.000 %
PL 460	100.000 %	100.000 % PL 550		10.000 %	10.000 %
PL 504	47.593 %	47.593 % PL 554		30.000 %	30.000 %
PL 539	40.000 %	40.000 % PL 554B		30.000 %	30.000 %
PL 626	50.000 %	50.000 % PL 554C		30.000 %	30.000 %
PL 659	20.000 %	20.000 % PL 613		20.000 %	20.000 %
PL 677	60.000 %		60.000 % PL 616***	20.000 %	20.000 %
PL 690***	50.000 %	50.000 % PL 617		35.000 %	35.000 %
PL 701***	40.000 %	40.000 % PL 627		20.000 %	20.000 %
PL 709	40.000 %	40.000 % PL 627B		20.000 %	20.000 %
PL 715	40.000 %	40.000 % PL 653		30.000 %	30.000 %
PL 724	40.000 %	40.000 % PL 672		25.000 %	25.000 %
PL 724B	40.000 %	40.000 % PL 689		20.000 %	20.000 %
PL 736S	65.000 %	65.000 % PL 689B		20.000 %	20.000 %
PL 748***	50.000 %	50.000 % PL 694		20.000 %	20.000 %
PL 762***	20.000 %	20.000 % PL 712*		20.000 %	0.000 %
PL 777	40.000 %		40.000 % PL 722***	20.000 %	20.000 %
PL 777B	40.000 %	40.000 % PL 778		20.000 %	20.000 %
PL 790	30.000 %	30.000 % PL 782S		20.000 %	20.000 %
PL 814	40.000 %		40.000 % PL 782SB	20.000 %	20.000 %
PL 818	40.000 %	40.000 % PL 797		25.000 %	25.000 %
PL 821	60.000 %	60.000 % PL 804		30.000 %	30.000 %
PL 822S	60.000 %	60.000 % PL 813		3.300 %	3.300 %
PL 839*	23.835 %	0.000 % PL 842		30.000 %	30.000 %
PL 843	40.000 %	40.000 % PL 844		20.000 %	20.000 %
PL 858**	40.000 %	40.000 % PL 852**		40.000 %	40.000 %
Number	47	44	PL 857**	20.000 %	20.000 %
			Number	48	47

* Licenses from BP Norge AS.

** Interest awarded in the 23 Licensing round announced in May 2016.

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

**** According to a ruling by Ministry of Oil and Energy.

Note 22 Results from previous interim reports

	2016 2015						2014
(USD 1 000)	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Total operating income	247 993	255 665	204 848	254 634	316 393	321 850	328 924	345 670
Exploration expenses	30 843	36 214	36 115	18 867	18 066	24 949	14 523	51 491
Production costs	32 188	39 116	34 374	24 077	26 888	50 686	39 349	44 400
Depreciation	114 649	120 264	114 318	111 590	129 790	117 354	122 224	104 183
Impairments	8 429	-19 644	37 964	191 939	185 756	-	52 773	319 018
Other operating expenses	6 223	5 410	5 330	3 228	11 433	22 550	14 397	10 679
Total operating expenses	192 333	181 360	228 101	349 701	371 932	215 539	243 266	529 772
Operating profit/loss	55 660	74 305	-23 253	-95 067	-55 539	106 310	85 658	-184 102
Net financial items	-5 107	-28 951	7 620	-56 138	-51 205	-43 136	-4 492	-12 788
Profit/loss before taxes	50 553	45 353	-15 633	-151 205	-106 744	63 174	81 166	-196 889
Taxes (+)/tax income (-)	-12 880	39 046	-47 866	4 980	59 441	55 897	78 727	89 997
Net profit/loss	63 433	6 308	32 233	-156 184	-166 185	7 277	2 439	-286 887

Alternative performance measures

Aker BP discloses 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.

EBITDAX is short for earnings before interest and other financial items, taxes, depreciation and amortisation, impairments and exploration.

EBITDA is short for earnings before interest and other financial items, taxes, depreciation and amortisation and impairments.'

EBIT is short for earnings before interest and other financial items and taxes

Earnings per share (EPS) is net profit divided by number of shares outstanding

Equity ratio is total equity divided by total assets

Gross interest-bearing debt is book value of current and non-current interest-bearing debt

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

Depreciation per boe is depreciation divided by number of barrels of oil equivalents produced in the corresponding period

NOTES

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