Aker BP

Quarterly Report • Feb 6, 2019

Fourth Quarter 2018

QUARTERLY REPORT FOR AKER BP ASA

SUMMARY OF 2018

Aker BP continued its positive development and strong growth in 2018. Total income increased by 46 percent from 2017 and all major field development projects progressed as planned. Reserve replacement was above 100 percent and the company continued to grow its resource base through acquisitions and exploration success. The debt level was significantly reduced and the company paid a dividend of USD 450 million (USD 1.25 per share) in 2018.

For the full year 2018, the company's net production in 2018 was 155.7 (138.8) thousand barrels of oil equivalents per day ("mboepd"). Total production volume was 56.8 million barrels of oil equivalents ("boe"). Total income amounted to USD 3,750 (2,563) million for the year. Average realised oil price was USD 72 (56) per barrel, while the realised price for natural gas averaged USD 0.29 (0.21) per standard cubic metre ("scm").

Production costs amounted to USD 689 (523) million in 2018, or USD 12.1 (10.3) per boe. Exploration expenses amounted to USD 296 (226) million. Total cash spend on exploration amounted to USD 359 (262) million. The company's exploration activities in 2018 resulted in the Frosk discovery and a positive appraisal of the Gekko discovery. In addition, the company expanded its licence portfolio, further strengthening its position as the second largest licence holder on the Norwegian Continental Shelf.

Profit before taxes amounted to USD 1,805 (811) million. Tax expense was USD 1,328 (536) million, representing an effective tax rate of 74 percent. Net profit increased by 73 percent to USD 476 (275) million.

In the fourth quarter 2018, production volumes increased due to improved efficiency and new wells. Net production was 155.7 (135.6) mboepd. Profit before taxes amounted to USD 359 (248), and Net profit was USD 54 (34) million. The company completed several transactions, reduced its debt level significantly and paid a dividend of USD 112.5 million (USD 0.3124 per share) during the fourth quarter.

Investments in fixed assets amounted to USD 1,313 (977) million in 2018. All field development projects, including Johan Sverdrup, Valhall Flank West and Ærfugl, progressed according to plans.

Aker BP's 2P reserves increased to 917 (914) mmboe, as the total additions and revisions exceeded the year's production. The company also made two significant acquisitions in 2018, adding 171 mmboe to its 2C contingent resource base. In total, contingent resources grew by 23 percent to 946 mmboe.

The company's net interest-bearing debt was USD 1,973 million at the end of 2018, down USD 1,183 million from 2017. This was mainly driven by the repayment of a USD 1.5 billion bank loan following the refund of the tax losses in Hess Norge. Total available liquidity at the end of 2018 was USD 3.1 (2.9) billion.

Total dividends for 2018 amounted to USD 1.25 or NOK 10 per share. The Board has resolved to pay a quarterly dividend of USD 187.5 million (USD 0.5207 per share) in February 2019.

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.

SUMMARY OF FINANCIAL RESULTS

	Unit	Q4 2018	Q3 2018	Q2 2018	Q1 2018
Total income	USDm	886	1 000	975	890
EBITDA	USDm	619	736	735	658
Net profit	USDm	54	125	136	161
Earnings per share (EPS)	USD	0.15	0.35	0.38	0.45
Capex	USDm	380	310	276	237
Exploration spend	USDm	84	109	86	80
Abandonment spend	USDm	16	72	72	82
Production cost	USD/boe	13.0	11.9	11.4	12.1
Taxes paid	USDm	340	163	69	34
Net interest-bearing debt	USDm	1 973	2 849	2 968	3 048
Leverage ratio		0.65	0.95	1.11	1.27

For definitions, see description of "Alternative performance measures" at the end of this report.

SUMMARY OF PRODUCTION

	Unit	Q4 2018	Q3 2018	Q2 2018	Q1 2018
Alvheim area	mboepd	58.4	56.7	60.1	62.9
Ivar Aasen	mboepd	23.3	22.7	23.7	24.4
Skarv	mboepd	23.5	23.3	27.6	27.1
Ula area	mboepd	8.4	10.5	10.8	8.1
Valhall area	mboepd	39.6	36.0	33.7	34.5
Other	mboepd	2.6	1.4	1.9	1.6
Total	mboepd	155.7	150.6	157.8	158.6
- liquids	mboepd	124.0	119.8	122.8	123.6
- natural gas	mboepd	31.8	30.7	35.0	35.0
Realized price oil	USD/bbl	64.3	77.9	76.4	69.1
Ralized price natural gas	USD/scm	0.30	0.30	0.28	0.28

FINANCIAL REVIEW

Income statement

(USD million)	Q4 2018	Q4 2017
Total income	886	726
EBITDA	619	509
EBIT	403	305
Pre-tax profit	359	248
Net profit	54	34
EPS (USD)	0.15	0.10

Total income in the fourth quarter amounted to USD 886 (726) million. The increase was mainly driven by higher production volume, which increased 15 percent compared to the fourth quarter 2017. Revenues were impacted by the low oil prices at the end of the quarter, which caused a negative valuation effect on the underlift balance amounting to approximately USD 48 million.

Production costs were USD 187 (147) million, equivalent to USD 13.0 (11.8) per barrel of oil equivalent ("boe"). The increase in the production costs was caused by the increased interest in Valhall and Hod following the acquisition of Hess Norge in the fourth quarter 2017, and by high maintenance activity in the fourth quarter 2018. For the full year, production cost amounted to USD 12.1 per boe, in line with the company's guidance.

Exploration expenses amounted to USD 72 (56) million. The main components were field evaluation and seismic, amounting to USD 28 (14) million and USD 21 (10) respectively. Dry well expenses were USD 4 (19) million.

Depreciation amounted to USD 196 (183) million, corresponding to USD 13.7 (14.7) per boe. Impairments amounted to USD 20 (21) million, of which USD 25 million was related to Gina Krog, while there was a reversal of impairment of USD 5 million on other assets (see note 4).

Operating profit was USD 403 (305) million. Net financial expenses amounted to USD 44 (57) million.

Profit before taxes amounted to USD 359 (248) million. Taxes amounted to USD 305 (214) million for the fourth quarter, representing an effective tax rate of 85 (86) percent.

The effective tax rate was impacted by negative currency effects on NOK-denominated tax balances which caused an increase in deferred tax. In addition, the tax expense included prior period adjustments of USD 16 million.

This resulted in a net profit for the fourth quarter of USD 54 (34) million.

Statement of financial position

(USD million)	Q4 2018	Q4 2017
Goodwill	1 860	1 860
Other intangible assets	2 005	1 617
PP&E	5 746	5 582
Cash & cash equivalents	45	233
Total assets	10 777	12 019
Equity	2 990	2 989
Interest-bearing debt	2 018	3 389

At the end of fourth quarter 2018, total intangible assets amounted to USD 4,293 (3,843) million, of which goodwill was USD 1,860 (1,860) million.

Property, plant and equipment increased to USD 5,746 (5,582) million, driven by investments in development projects, net of depreciation. Current tax receivables decreased to USD 11 (1,586) as the tax loss acquired with Hess Norge was refunded during the fourth quarter.

Cash and cash equivalents were USD 45 (233) million at the end of the quarter. Total assets were USD 10,777 (12,019) million.

Equity amounted to USD 2,990 (2,989) million at the end of the fourth quarter, corresponding to an equity ratio of 28 (25) percent. The change was caused by total comprehensive income of USD 451 million and dividend payments of USD 450 million for 2018.

Deferred tax liabilities amounted to USD 1,800 (1,307) million and are detailed in note 7 to the financial statements.

Gross interest-bearing debt was USD 2,018 (3,389) million, consisting of the DETNOR02 bond of USD 224 million, the AKERBP Senior Notes (17/22) of USD 393 million, the AKERBP Senior Notes (18/25) of USD 493 million, and the Reserve Based Lending ("RBL") facility of USD 908 million. A bank term loan of USD 1,500 million was repaid during the fourth quarter following the refund of the previously mentioned tax loss related to the Hess Norge acquisition.

At the end of the fourth quarter, the company had total available liquidity of USD 3.1 (2.9) billion, comprising USD 45 (233) million in cash and cash equivalents, and USD 3,050 (2,670) million in undrawn credit facilities.

Cash flow

(USD million)	Q4 2018	Q4 2017
Cash flow from operations	1 889	543
Cash flow from investments	910	2 192
Cash flow from financing	-1 063	1 796
Net change in cash & cash equivalents	-83	147
Cash and cash equivalents	45	233

Net cash flow from operating activities was USD 1,889 (543) million in the fourth quarter. This increase was mainly driven by tax refunds of USD 1,513 (141) million. Excluding taxes, the net cash from operations increased by USD 246 million, mainly driven by higher production volume.

Net cash flow to investment activities was USD 910 (2,192) million, of which investments in fixed assets amounted to USD 415 (248) million. Disbursements related to licencese acquisitions amounted to USD 463 million.

Net cash flow from financing activities totalled USD -1,063 (1,796) million, reflecting a net debt repayment of USD 950 million and dividend disbursements of USD 113 million during the quarter.

Risk management

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

For first half 2019, the company holds put options for 23 percent of expected oil production, corresponding to 83 percent of the after-tax value, at an average strike price of USD 55 per barrel (Brent).

Dividends

A quarterly dividend of USD 112.5 million, corresponding to USD 0.3124 per share was disbursed on 9 November 2018. Total dividend payments for 2018 amounted to USD 450 million, equivalent to approximately USD 1.25 (NOK 10) per share.

On 5 February 2019, the Board of Directors declared a quarterly dividend of USD 0.5207 per share, to be disbursed on or about 19 February 2019.

The Board's intention is to increase the dividend level to USD 750 million in 2019, with an ambition to increase the level by USD 100 million per year until 2023.

OPERATIONAL REVIEW

Aker BP produced 14.3 (12.5) mmboe in the fourth quarter of 2018, corresponding to 155.7 (138.8) mboepd. The average realized oil price was USD 64 (65) per barrel, while the average realised gas price was USD 0.30 (0.26) per standard cubic metre.

Alvheim Area

Key figures	Aker BP interest	Q4 2018	Q3 2018	Q2 2018	Q1 2018
Production, boepd
Alvheim	65 %	43 406	38 872	40 091	40 516
Bøyla	65 %	2 039	3 125	3 265	3 235
Vilje	46.904 %	3 257	3 716	4 098	5 090
Volund	65 %	9 655	11 016	12 649	14 109
Total production		58 356	56 729	60 100	62 949
Production efficiency		98.3 %	96.0 %	95.3 %	98.4 %

Fourth quarter production from the Alvheim area was 58.4 mboepd net to Aker BP, representing an increase of three percent from the previous quarter. The main driver was the startup of the Kameleon Infill South well in the Alvheim field, combined with increased production efficiency, which more than compensated for natural decline.

The Skogul project is progressing according to plan and production start is planned for the first quarter of 2020. Skogul will be developed with a single multilateral production well tied back to the Vilje field, utilising the existing pipeline from Vilje to the Alvheim FPSO.

In the first quarter 2018, an oil discovery was made in the Frosk prospect near the Bøyla field. A new well is planned to be drilled in the first half of 2019. This well will gather more information about the reservoir, and be completed as a production well which will be used for test production from mid-2019.

Exploration of the Frosk area is continuing in 2019. The first well on Froskelår Main was spudded in January and has encountered oil and gas. The preliminary analysis indicates a gross discovery size within the previously communicated estimate of 45-153 mmboe. The drilling operation will continue, and a comprehensive data collection program will be performed to determine the size and quality of the discovery. After Froskelår Main, a combined exploration and production well will be drilled on Frosk, and the Rumpetroll prospect will be drilled later in the year.

Following the successful appraisal well on the Gekko discovery in 2018, and Aker BP's acquisition of interests in the discoveries Trell and Trine, the company has started the process of integrating these discoveries in the area development plan for the Alvheim area.

Valhall Area

Key figures	Aker BP interest	Q4 2018	Q3 2018	Q2 2018	Q1 2018
Production, boepd
Valhall	90 %	38 816	35 120	32 670	33 500
Hod	90 %	802	872	1 063	1 016
Total production		39 618	35 993	33 733	34 515
Production efficiency		91.1 %	87.6 %	84.5 %	84.7 %

Fourth quarter production from the Valhall area was 39.6 mboepd net to Aker BP, representing a 10 percent increase from the previous quarter, driven by ramp-up of production from new wells and high production efficiency.

Drilling from the IP platform continued with the G22 well coming onstream during the quarter. The G11 well was subsequently drilled and completed with the new Fishbones technology in one section of the well. Test production is planned to commence in February 2019. If successful, this new technology has the potential to significantly reduce the time to production for new wells.

The first phase of the campaign to permanently plug old wells at Valhall was completed in early October, significantly ahead of the original plan. The Maersk Invincible rig was subsequently moved to Valhall Flank North where it

successfully drilled a new water injection well. The rig has now been redeployed to Valhall Flank South to drill two infill wells.

In the fourth quarter, the Maersk Reacher rig arrived at the Valhall field center, providing additional accommodation capacity to support the high activity set at the field.

The Valhall Flank West development project is progressing as planned, with excellent HSE performance. Engineering of the topside and jacket has been completed. Construction activities remain on track, and subsea engineering and planning for the upcoming offshore campaign this summer are ahead of schedule.

Ula Area

Key figures	Aker BP interest	Q4 2018	Q3 2018	Q2 2018	Q1 2018
Production, boepd
Ula	80 %	5 784	6 498	5 361	6 486
Tambar	55 %	2 572	4 008	5 398	1 611
Total production		8 356	10 506	10 759	8 097
Production efficiency		64.9 %	72.5 %	65.4 %	62.5 %

Fourth quarter production from the Ula area was 8.4 mboepd net to Aker BP. Production was impacted by underperformance of the two new Tambar wells, in addition to temporary lower Ula production due to well intervention. A flotel is in operation at the field to provide additional accommodation capacity to support the ongoing maintenance and upgrade activities at Ula.

The development of the Oda field is in its final stages. Drilling operations were completed in the fourth quarter, and the operator is currently performing the final preparations for production start, which is expected during the first half of 2019.

Aker BP considers the resource potential in the Ula area to be significant, both from increased oil recovery in the Ula and Tambar fields, from potential tie-backs of other discoveries including the newly acquired King Lear discovery, and from exploration opportunities. To unlock this upside potential, the first step in the Ula strategy is to improve the technical condition and extend the expected life of the facilities to ensure stable performance. In parallel, the company is working diligently to mature the opportunity set, which is a complex process involving a broad set of technical and commercial disciplines. This could eventually lead to the addition of a new platform at Ula in the mid-2020s.

Skarv Area

Key figures	Aker BP interest	Q4 2018	Q3 2018	Q2 2018	Q1 2018
Production, boepd
Skarv	23.835 %	23 454	23 313	27 579	27 092
Production efficiency		92.6 %	90.0 %	88.4 %	94.4 %

Fourth quarter production from the Skarv area was 23.5 mboepd net to Aker BP, which was marginally higher than the previous quarter. Production was shut in for three days in the beginning of October due to a planned emergency shutdown test. The B09 well resumed production late November after successful in-situ repair of the Xmas tree.

Phase 1 of the Ærfugl development is progressing on plan. Currently there is high activity on engineering, procurement and fabrication of subsea system structure, the wellheads and the Vertical Xmas Tree system.

The remaining technology qualification activities for the trace heated pipe in pipe system and the new generation of vertical Xmas trees are on plan and well underway to be ready for assembly and construction in 2019. Production start is planned for fourth quarter 2020. For Ærfugl phase 2, work is progressing steadily towards a formal concept selection in the second quarter.

Ivar Aasen

Key figures	Aker BP interest	Q4 2018	Q3 2018	Q2 2018	Q1 2018
Production, boepd
Ivar Aasen	34.7862 %	23 343	22 651	23 699	24 421
Production efficiency		93.2 %	93.2 %	90.4 %	91.2 %

Production from Ivar Aasen was 23.3 mboepd net to Aker BP in the fourth quarter, up three percent from the previous quarter. The average plant availability at Ivar Aasen was 98.5 percent in the period, which was the same as the previous

quarter. The overall production efficiency was negatively impacted by an emergency shutdown of the Sture terminal due to a ship collision, and by reduced power supply from Edvard Grieg.

Johan Sverdrup

Phase 1 of the Johan Sverdrup (11.5733 percent) development project is progressing steadily towards planned production start in November 2019. At the end of the fourth quarter, the Phase 1 facilities were approximately 94 percent complete. Offshore hook-up, commissioning and completion of the two platforms installed at the field centre during the early summer continued throughout the fourth quarter. From early October the field centre was powered from shore through two 200 km long AC cables. Installation of the gas export pipeline was completed in the fourth quarter. The processing platform construction (P1 topside) was completed in December and is now in transit from South Korea to Norway. Tie-back operations of the eight pre-drilled oil production wells started in December.

Phase 2 of the Johan Sverdrup development is also progressing well. Ongoing activities include detailed engineering and construction preparations at the main construction sites. The Plan for Development and Operations ("PDO") for Phase 2 has been submitted to Norwegian authorities and is subject to final approval by the Norwegian Parliament, which is expected by mid-April 2019.

North of Alvheim and Krafla-Askja (NOAKA)

The North of Alvheim and Askja-Krafla ("NOAKA") area consists of the discoveries Frigg Gamma Delta, Langfjellet, Frøy, Fulla, Frigg, Rind and Askja-Krafla. Gross resources in the area are estimated to be more than 500 mmboe.

Aker BP and the other partners have performed detailed studies of different development solutions for the NOAKA area. The premise defined by the authorities, and confirmed in recent dialogue, has been that a development should capture all discovered resources in the area and facilitate future tie-ins of new discoveries.

These studies have resulted in two alternative development solutions. One solution involves two unmanned production platforms ("UPP") or similar concepts, supported from an

existing host in the area. The other solution involves a new hub platform in the central part of the area, with processing and living quarters ("PQ").

Aker BP's recommendation is to develop the area with the PQ concept. This concept is the only alternative that allows for economic recovery of all discovered resources in the area, and provides higher resource recovery and socio-economic benefits than the alternative. The PQ concept is also the better alternative with regards to exploiting additional resources that may be discovered through future exploration.

Discussions are still ongoing between the partners on how to develop the NOAKA area.

HEALTH, SAFETY, SECURITY AND THE ENVIRONMENT

HSSE is always the number one priority in all of Aker BP's activities. The company strives to ensure that all its operations, drilling campaigns and projects are carried out under the highest HSSE standards.

	Unit	Q4 2018	Q3 2018	Q2 2018	Q1 2018
Total recordable injury frequency (TRIF)	Per mill. exp. hours	3.4	4.1	4.2	1.9
Serious incident frequency (SIF)	Per mill. exp. hours	0.5	0.6	0.6	1.3
Loss of primary containment (LOPC)	Count	0	1	0	1
Process safety events Tier 1 and 2	Count	0	1	1	1
CO2 emissions intensity	Kg CO2/boe	7.6	7.5	6.8	7.4

In November 2018 Aker BP received an improvement order from the Petroleum Safety Authority Norway ("PSA") following an audit of risk, barrier and maintenance management on the Ula field. The company is working systematically to address the issues raised by the PSA and will rectify a number of items by March 2019, and commit to a plan for rectification of any outstanding issues at the same time.

In January 2019 the PSA completed an investigation of an incident with a motion-compensated walkway on the Tambar field in July 2018. The company is addressing the non-conformities and will use the lessons learnt from the incident when planning similar activities in the future.

EXPLORATION

Total exploration expenses in the fourth quarter amounted to USD 72 million, mainly relating to seismic, area fees, field evaluation and G&G costs. For the full year 2018 the company's cash spend on exploration was USD 359 million, slightly below the latest guidance of USD 400 million due to late arrival of a drilling rig.

In the Alvheim area, drilling of the Gekko appraisal well (Aker BP 65 % and operator) started in September, and was completed in early October. The well discovered additional volumes of oil and gas, increasing the probability of a development of Gekko as a tie-back to the Alvheim FPSO.

Spirit Energy Norge AS completed drilling of the Cassidy prospect in PL 405 (Aker BP 15 %) in January 2019. The well was drilled about five kilometres north of the Oda field in the Ula area. The objective of the well was to prove petroleum in Upper Jurassic reservoir rocks (the Ula formation) and to assess the reservoir properties in Upper Jurassic and Triassic intervals. The well was classified as dry.

During the fourth quarter, the company divested its interests in licences PL 871 and PL 842, and reduced its interest in licence PL 019C from 80 to 60 percent, as part of its ongoing portfolio optimization.

On 15 January 2019, the Norwegian Ministry of Petroleum and Energy announced the results of the APA 2018 licensing round. Aker BP was awarded 21 new exploration licences, of which 11 as operator.

On 4 February, Aker BP announced a discovery on the Froskelår Main prospect. Preliminary analysis indicate a gross discovery size within the previously communicated estimate of 45-153 million barrels oil equivalents. Froskelår Main is located in the Alvheim area and follows the Frosk discovery from last year. The major part of the discovery is in licence 869 on the Norwegian Continental Shelf, while a part may straddle the UK-Norwegian border in the North Sea. The drilling operation will continue, and a comprehensive data collection program will be performed to determine the size and quality of the discovery.

OUTLOOK

Aker BP continues to build on a strong platform for further value creation through safe operations, an effective business model built on lean principles, technological competence and industrial cooperation to secure long term competitiveness.

The company has a strong balance sheet, providing the company with ample financial flexibility going forward, and will continue to pursue selective growth opportunities as well as increasing dividend distributions to its shareholders.

For 2019, the company's financial plan consists of the following main items1):

• Production of 155-160,000 boe per day, broadly in line with 2018

• Capex USD 1.6 billion – of which the main drivers are Valhall and Johan Sverdrup

• Exploration spend of USD 500 million, to cater for an ambitious exploration program comprising of 15 exploration wells targeting net prospective resources of 500 mmboe

• Abandonment spend of USD 150 million, related to plugging of depleted wells and removal of the old quarters platform at Valhall

• Production cost of around USD 12.5 per boe, slightly above 2018 due to high maintenance and modifications activity particularly at Valhall and Ula

The Board has proposed to pay USD 750 million in dividends in 2019, with an intention to increase the dividend level by USD 100 million per year until 2023. The company pays dividends each quarter. For 2019, the quarterly dividend is expected to be approximately USD 0.52 per share.

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

Financial statements with notes

INCOME STATEMENT (Unaudited)

Q4 01.01.-31.12. (USD 1 000) Note 2018 2017 2018 2017 Petroleum revenues 860 810 737 204 3 711 472 2 575 654 Other operating income 25 286 -11 210 38 600 -12 721 Total income 2 886 096 725 994 3 750 072 2 562 933 Production costs 186 530 147 076 689 102 523 379 Exploration expenses 3 72 458 56 181 295 908 225 702 Depreciation 5 195 962 183 138 752 437 726 670 Impairments 4, 5 20 172 21 111 20 172 52 349 Other operating expenses 7 739 13 549 17 037 27 606 Total operating expenses 482 862 421 055 1 774 658 1 555 705 Operating profit 403 234 304 940 1 975 414 1 007 228 Interest income 7 157 2 991 25 976 7 716 Other financial income 72 625 18 298 141 823 75 507 Interest expenses 28 511 15 230 120 033 103 627 Other financial expenses 95 175 62 585 218 272 175 696 Net financial items 6 -43 905 -56 526 -170 505 -196 100 Profit before taxes 359 329 248 413 1 804 909 811 128 Taxes (+)/tax income (-) 7 305 022 214 377 1 328 486 536 340 Net profit 54 307 34 036 476 423 274 787 Weighted average no. of shares outstanding basic and diluted 360 113 509 347 465 957 360 113 509 340 189 283		Group
Basic and diluted earnings USD per share 0.15 0.10 1.32 0.81

STATEMENT OF COMPREHENSIVE INCOME

	Group
	Q4		01.01.-31.12.
(USD 1 000) Note	2018	2017	2018	2017
Profit for the period	54 307	34 036	476 423	274 787
Items which will not be reclassified over profit and loss (net of taxes) Actuarial gain/loss pension plan	8	-1	8	-1
Items which may be reclassified over profit and loss (net of taxes)
Currency translation adjustment	-81 981	25 524	-72 612	25 167
Reclassification to profit and loss	47 504		47 504
Total comprehensive income in period	19 838	59 558	451 323	299 953

STATEMENT OF FINANCIAL POSITION (Unaudited)

		Group
(USD 1 000)	Note	31.12.2018	31.12.2017
ASSETS
Intangible assets
Goodwill	5	1 860 126	1 860 126
Capitalized exploration expenditures	5	427 439	365 417
Other intangible assets	5	2 005 885	1 617 039
Tangible fixed assets
Property, plant and equipment	5	5 746 275	5 582 493
Financial assets
Long-term receivables		37 597	40 453
Long-term derivatives	11	-	12 564
Other non-current assets		10 388	8 398
Total non-current assets		10 087 710	9 486 491
Inventories
Inventories		93 179	75 704
Receivables
Accounts receivable		162 798	99 752
Tax receivables	7	11 082	1 586 006
Other short-term receivables	8	360 194	535 518
Short-term derivatives	11	17 253	2 585
Cash and cash equivalents
Cash and cash equivalents	9	44 944	232 504
Total current assets		689 450	2 532 069
TOTAL ASSETS		10 777 160	12 018 560

STATEMENT OF FINANCIAL POSITION (Unaudited)

		Group
(USD 1 000)	Note	31.12.2018	31.12.2017
EQUITY AND LIABILITIES
Equity
Share capital		57 056	57 056
Share premium		3 637 297	3 637 297
Other equity		-704 432	-705 756
Total equity		2 989 920	2 988 596
Non-current liabilities
Deferred taxes	7	1 800 199	1 307 148
Long-term abandonment provision	15	2 447 558	2 775 622
Provisions for other liabilities	10	107 519	152 418
Long-term bonds	13	1 110 488	622 039
Long-term derivatives	11	26 275	13 705
Other interest-bearing debt	14	907 954	1 270 556
Current liabilities
Trade creditors		105 567	32 847
Accrued public charges and indirect taxes		25 061	27 949
Tax payable	7	551 942	351 156
Short-term derivatives	11	8 783	7 691
Short-term abandonment provision	15	105 035	268 262
Short-term interest-bearing debt	14	-	1 496 374
Other current liabilities	12	590 860	704 197
Total liabilities		7 787 241	9 029 964
TOTAL EQUITY AND LIABILITIES		10 777 160	12 018 560

STATEMENT OF CHANGES IN EQUITY - GROUP (Unaudited)

			Other equity
					Other comprehensive income
					Foreign currency
		Share	Other paid-in	Actuarial	translation	Retained	Total other
(USD 1 000)	Share capital	premium	capital	gains/(losses)	reserves*	earnings	equity	Total equity
Equity as of 31.12.2017	57 056	3 637 297	573 083	-89	-90 383	-1 188 366	-705 756	2 988 596
Dividend distributed	-	-	-	-	-	-337 500	-337 500	-337 500
Profit/loss for the period	-	-	-	-	-	422 116	422 116	422 116
Other comprehensive income for the period	-	-	-	-	9 369	-	9 369	9 369
Equity as of 30.09.2018	57 056	3 637 297	573 083	-89	-81 014	-1 103 750	-611 771	3 082 581
	-	-	-	-	-	-	-	-
Dividend distributed	-	-	-	-	-	-112 500	-112 500	-112 500
Profit for the period	-	-	-	-	-	54 307	54 307	54 307
Other comprehensive income for the period	-	-	-	8	-34 477	-	-34 469	-34 469
Equity as of 31.12.2018	57 056	3 637 297	573 083	-81	-115 491	-1 161 943	-704 432	2 989 920

* The amount arose mainly as a result of the change in functional currency in Q4 2014.

STATEMENT OF CASH FLOW (Unaudited)

			Group
			Q4	01.01.-31.12.
(USD 1 000)	Note	2018	2017	2018	2017
CASH FLOW FROM OPERATING ACTIVITIES
Profit before taxes		359 329	248 413	1 804 909	811 128
Taxes paid	7	-339 609	-67 024	-606 082	-101 115
Tax refund	7	1 513 394	140 913	1 513 394	404 704
Depreciation	5	195 962	183 138	752 437	726 670
Net impairment losses	4, 5	20 172	21 111	20 172	52 349
Accretion expenses	6, 15	32 082	32 407	128 737	129 619
Interest expenses	6	56 739	32 539	200 524	156 704
Interest paid		-59 703	-31 716	-195 659	-145 940
Changes in derivatives	2, 6	4 624	33 107	11 558	-34 461
Amortized loan costs	6	6 856	6 336	29 722	36 900
Amortization of fair value of contracts	10	14 195	4 398	56 775	11 728
Expensed capitalized dry wells	3, 5	4 424	19 246	65 852	75 401
Changes in inventories, accounts payable and receivables		-9 908	-63 673	-7 800	-7 583
Changes in other current balance sheet items		90 471	-16 245	25 031	39 387
NET CASH FLOW FROM OPERATING ACTIVITIES		1 889 029	542 949	3 799 570	2 155 491
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	15	-16 069	-31 094	-242 545	-85 733
Disbursements on investments in fixed assets		-414 861	-248 303	-1 312 697	-977 462
Acquisitions of companies (net of cash acquired)		-	-2 055 033	-	-2 055 033
Cash received from sale of licenses		-	170 959	-	170 959
Disbursements on investments in capitalized exploration	5	-15 764	-28 523	-128 795	-111 569
Disbursements on investments in licenses		-463 049	-	-463 049	-156
NET CASH FLOW USED IN INVESTMENT ACTIVITIES		-909 743	-2 191 994	-2 147 085	-3 058 994
CASH FLOW FROM FINANCING ACTIVITIES
Net drawdown/repayment of long-term debt		550 000	-130 000	-380 252	-777 911
Repayment of bond (DETNOR03)		-	-	-	-330 000
Repayment of short-term debt		-1 500 000	-	-1 500 000	-
Net cash received from issuance of new shares		-	489 436	-	489 436
Net proceeds from issuance of debt		-	1 498 885	492 423	1 886 885
Paid dividend		-112 500	-62 500	-450 000	-250 000
NET CASH FLOW FROM FINANCING ACTIVITIES		-1 062 500	1 795 820	-1 837 829	1 018 410
Net change in cash and cash equivalents		-83 214	146 776	-185 344	114 906
Cash and cash equivalents at start of period		126 608	80 764	232 504	115 286
Effect of exchange rate fluctuation on cash held		1 550	4 965	-2 216	2 312
CASH AND CASH EQUIVALENTS AT END OF PERIOD	9	44 944	232 504	44 944	232 504
SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits and cash		44 944	231 506	44 944	231 506
Restricted bank deposits		-	998	-	998
CASH AND CASH EQUIVALENTS AT END OF PERIOD	9	44 944	232 504	44 944	232 504

NOTES

(All figures in USD 1 000 unless otherwise stated)

These interim financial statements have been prepared in accordance with the International Financial Reporting Standards as adopted by the EU ("IFRS") IAS 34 "Interim Financial Reporting", thus the interim financial statements do not include all information required by IFRS and should be read in conjunction with the group's annual financial statements as at 31 December 2017. 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 5 February 2019.

Note 1 Accounting principles

As described in the group's annual financial statements for 2017, two new accounting standards entered into force from 1 January 2018. IFRS 9 Financial Instruments does not have any significant impact on the group's financial statements. IFRS 15 Revenue from contracts with customers has no impact on the line item petroleum revenues in the income statement, but additional details have been provided in the note disclosures (note 2) to specify the part of revenues that arises from change in over/underlift balances. The adoption of IFRS 9 and IFRS 15 does not impact any line items in the balance sheet or have any impact on reported cash flows.

Except for the changes described above, the accounting principles used for this interim report are consistent with the principles used in the group's annual financial statements as at 31 December 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 are the same as those that applied to the annual financial statements as at 31 December 2017.

Note 2 Income

		Group
	Q4		01.01.-31.12.
Breakdown of petroleum revenues (USD 1 000)	2018	2017	2018	2017
Sales of liquids	747 439	581 059	3 141 997	2 140 738
Sales of gas	139 062	106 577	554 248	369 694
Tariff income	4 413	5 440	19 423	22 891
Total petroleum sales	890 914	693 076	3 715 668	2 533 323
Impact from change in over/underlift balances of liquids	-30 104	44 128	-4 197	42 331
Total petroleum revenues	860 810	737 204	3 711 472	2 575 654

Breakdown of produced volumes (barrels of oil equivalent)

Liquids	11 405 002	9 847 526	44 732 273	39 634 824
Gas	2 921 380	2 623 436	12 082 972	11 036 406
Total produced volumes	14 326 382	12 470 962	56 815 246	50 671 230
Other income (USD 1 000)
Realized gain/loss (-) on oil derivatives	-4 111	-2 549	-16 242	-7 440
Unrealized gain/loss (-) on oil derivatives	28 087	-5 563	24 944	-6 510
Other income	1 310	-3 098	29 898	1 230
Total other operating income	25 286	-11 210	38 600	-12 721

Note 3 Exploration expenses

	Q4		01.01.-31.12.
Breakdown of exploration expenses (USD 1 000)	2018	2017	2018	2017
Seismic	21 306	9 637	95 458	53 283
Area fee	5 149	4 363	13 822	16 589
Field evaluation	27 782	14 471	79 323	40 162
Dry well expenses*	4 424	19 246	65 852	75 401
Other exploration expenses	13 798	8 465	41 453	40 267
Total exploration expenses	72 458	56 181	295 908	225 702

* Q4 2018 dry well expenses are mainly related to the Cassidy well in PL 405.

Note 4 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment triggers are identified, and for goodwill impairment is tested at least annually. In Q4 2018, two categories of impairment tests have been performed:

• Impairment test of fixed assets and related intangible assets, other than goodwill
• Impairment test of goodwill

Impairment is recognized when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. For assets and goodwill in the group prior to the acquisition of BP Norge AS, the impairment testing has been based on value in use, consistent with the impairment testing prior to the acquisition of BP Norge AS. For assets and goodwill recognized in relation to the acquisition of BP Norge AS and Hess Norge AS, the impairment testing has been based on fair value (level 3 in fair value hierarchy). For both value in use and fair value, the impairment testing is performed based on discounted cash flows. The expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years. If not specifically stated otherwise, the same assumptions have been applied for value in use and fair value testing.

For producing licenses and licenses in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 December 2018.

Prices

The nominal oil price applied in the impairment test is as follows:

Year	USD/BOE
2019	56.0
2020	57.1
2021	58.1
From 2022 (in real terms)	65.0

Reserves

Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves. The recoverable amount is sensitive to changes in reserves.

Discount rate

For value in use testing, the post tax nominal discount rate used is 7.9 per cent, which is a change from 7.5 per cent applied in previous quarters in 2018 and year end 2017. For fair value testing, the discount rate used is 10.0 per cent (unchanged from previous quarters in 2018 and from year end 2017). The difference between the discount rate applied for fair value and value in use testing reflects the additional risk in the cash flows used in fair value testing.

Currency rates
Year	USD/NOK
2019	8.58
2020	8.48
2021	8.42
From 2022	7.50

Inflation

The long-term inflation rate is assumed to be 2.0 per cent, which is a change from 2.5 per cent applied in previous quarters in 2018 and year end 2017

Impairment testing of assets other than goodwill

The impairment test of assets other than goodwill has been performed prior to the quarterly goodwill impairment test. If these assets are found to be impaired, their carrying value will be written down before the impairment test of goodwill. The carrying value of the assets is the sum of tangible assets and intangible assets as of the assessment date.

Below is an overview of the impairment charge and the carrying value per cash generating unit where impairment has been recognized in Q4 2018

		Impairment charge/reversal
Cash-generating unit (USD 1 000)	Intangible	Tangible		Recoverable amount/ carrying value as of 31.12.2018
Gina Krog	-	25 202		97 535
Other CGU's	516	-5 546		-
Total	516	19 657		97 535

The reversal of impairment and impairment charge for other CGU's with no carrying value is related to changes in the ARO liability.

Impairment testing of technical goodwill

In line with the methodology described in the annual report, deferred tax (from the date of acquisitions) reduces the net carrying value prior to the impairment charges. When deferred tax liabilities from the acquisitions decreases as a result of depreciation, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable. We have tested the Alvheim, Valhall/Hod, Skarv/Ærfugl and Ula/Tambar CGUs, and the calculation shows that no impairment charge of technical goodwill is needed.

Sensitivity analysis

The table below shows how the impairment of technical goodwill would be affected by changes in the various assumptions, given that the remaining assumptions are constant. The only impacted CGU is Ula/Tambar.

	Change in goodwill impairment after
Assumption (USD 1 000)	Change	Increase in assumptions	Decrease in assumptions
Oil and gas price	+/- 20%	-	135 422
Production profile (reserves)	+/- 5%	-	34 854
Discount rate	+/- 1% point	20 081	-
Currency rate USD/NOK	+/- 1.0 NOK	-	56 760
Inflation	+/- 1% point	-	33 628

Note 5 Tangible fixed 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 31.12.2017	1 480 689	4 032 797	69 007	5 582 493
Acquisition cost 31.12.2017	1 480 689	6 057 801	104 346	7 642 835
Additions	792 046	152 314	13 102	957 462
Disposals	-	-	-	-
Reclassification	-191 853	184 935	7 839	921
Acquisition cost 30.09.2018	2 080 882	6 395 050	125 286	8 601 218
Accumulated depreciation and impairments 31.12.2017	-	2 025 004	35 338	2 060 342
Depreciation	-	486 832	15 089	501 922
Impairment	-	-	-	-
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 30.09.2018	-	2 511 836	50 428	2 562 264
Book value 30.09.2018	2 080 882	3 883 214	74 858	6 038 954
Acquisition cost 30.09.2018	2 080 882	6 395 050	125 286	8 601 218
Additions*	219 175	-324 929	9 560	-96 193
Disposals	-	-	-	-
Reclassification	-16 456	16 241	214	-
Acquisition cost 31.12.2018	2 283 602	6 086 362	135 061	8 505 025
Accumulated depreciation and impairments 30.09.2018	-	2 511 836	50 428	2 562 264
Depreciation	-	169 864	6 965	176 829
Impairment	-	19 657	-	19 657
Retirement/transfer depreciations	-	-	-	-
Accumulated depreciation and impairments 31.12.2018	-	2 701 357	57 392	2 758 750
Book value 31.12.2018	2 283 602	3 385 005	77 669	5 746 275

*The negative addition is mainly caused by decreased abandonment provision during the year, refer to note 15

Capitalized exploration expenditures are reclassified to "Assets 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. Assets 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 31.12.2017	1 617 005	34	1 617 039	365 417	1 860 126
Acquisition cost 31.12.2017	1 933 241	7 501	1 940 742	365 417	2 738 973
Additions	-	-	-	113 029	-
Disposals/expensed dry wells	-	-	-	61 428	-
Reclassification	-	-	-	-921	-
Acquisition cost 30.09.2018	1 933 241	7 501	1 940 742	416 097	2 738 973
Accumulated depreciation and impairments 31.12.2017	316 236	7 467	323 703	-	878 847
Depreciation	54 541	13	54 553	-	-
Impairment	-	-	-	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 30.09.2018	370 777	7 480	378 257	-	878 847
Book value 30.09.2018	1 562 464	21	1 562 486	416 097	1 860 126
Acquisition cost 30.09.2018	1 933 241	7 501	1 940 742	416 097	2 738 973
Additions	463 049	-	463 049	15 765	-
Disposals/expensed dry wells	-	-	-	4 424	-
Reclassification	-	-	-	-	-
Acquisition cost 31.12.2018	2 396 290	7 501	2 403 791	427 439	2 738 973
Accumulated depreciation and impairments 30.09.2018	370 777	7 480	378 257	-	878 847
Depreciation	19 112	21	19 133	-	-
Impairment	516	-	516	-	-
Retirement/transfer depreciations	-	-	-	-	-
Accumulated depreciation and impairments 31.12.2018	390 404	7 501	397 906	-	878 847
Book value 31.12.2018	2 005 885	-	2 005 885	427 439	1 860 126

		Group
	Q4			01.01.-31.12.
Depreciation in the income statement (USD 1 000)	2018	2017	2018	2017
Depreciation of tangible fixed assets	176 829	162 664	678 751	635 563
Depreciation of intangible assets	19 133	20 474	73 686	91 107
Total depreciation in the income statement	195 962	183 138	752 437	726 670
Impairment in the income statement (USD 1 000)
Impairment/reversal of tangible fixed assets	19 657	21 111	19 657	21 232
Impairment/reversal of intangible assets	516	-	516	1 956
Impairment of goodwill	-	-	-	29 161
Total impairment in the income statement	20 172	21 111	20 172	52 349

Note 6 Financial items

		Group
	Q4		01.01.-31.12.
(USD 1 000)	2018	2017	2018	2017
Interest income	7 157	2 991	25 976	7 716
Realized gains on derivatives	72 625	8 659	141 823	18 428
Change in fair value of derivatives	-	-	-	40 971
Net currency gains	-	9 639	-	16 107
Total other financial income	72 625	18 298	141 823	75 507
Interest expenses	56 739	32 539	200 524	156 704
Capitalized interest cost, development projects	-35 085	-23 645	-110 213	-89 977
Amortized loan costs	6 856	6 336	29 722	36 900
Total interest expenses	28 511	15 230	120 033	103 627
Net currency loss/gain (-) before reclassification from OCI	-47 453	-	-43 592	-
Reclassification from OCI*	47 504	-	47 504	-
Realized loss on derivatives	28 824	1 472	45 993	9 331
Change in fair value of derivatives	32 710	27 543	36 503	-
Accretion expenses	32 082	32 407	128 737	129 619
Other financial expenses	1 509	1 162	3 128	36 746
Total other financial expenses	95 175	62 585	218 272	175 696
Net financial items	-43 905	-56 526	-170 505	-196 100

* The reclassification from OCI relates to the refund of tax losses in Aker BP AS (previously Hess Norge AS) which was received in Q4, and the subsequent liquidation of Aker BP AS. The reclassification reflects the USD/NOK currency movement from the acquisition of Hess Norge AS at 22 December 2017 to the tax refund and liquidation of Aker BP AS on 28 November 2018.

Note 7 Tax

		Group
	Q4			01.01.-31.12.
Tax for the period (USD 1 000)	2018	2017	2018	2017
Calculated current year tax	133 275	125 092	803 396	332 092
Change in deferred tax in the income statement	151 491	89 979	526 933	202 715
Prior period adjustments	20 255	-694	-1 843	1 533
Total tax (+)/tax income (-)	305 022	214 377	1 328 486	536 340

	Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	31.12.2018	31.12.2017
Tax receivable/payable at 01.01.	1 234 850	307 977
Current year tax (-)/tax receivable (+)	-803 396	-332 092
Taxes receivable/payable related to acquisitions/sales	4 387	1 523 512
Net tax payment (+)/tax refund (-)	-907 312	-303 589
Prior period adjustments and change in estimate of uncertain tax positions	-30 269	9 502
Currency movements of tax receivable/payable	-39 119	29 540
Total net tax receivable (+)/tax payable (-)	-540 860	1 234 850
Tax receivable included as current assets (+)	11 082	1 586 006
Tax payable included as current liabilities (-)	-551 942	-351 156

		Group
Deferred tax (-)/deferred tax asset (+) (USD 1 000)	31.12.2018	31.12.2017
Deferred tax/deferred tax asset 01.01.	-1 307 148	-1 045 542
Change in deferred tax in the income statement	-526 933	-202 715
Deferred tax related to acquisitions/sales	-	-61 877
Prior period adjustment	33 912	2 982
Deferred tax charged to OCI and equity	-30	5
Net deferred tax (-)/deferred tax asset (+)	-1 800 199	-1 307 148

	Group
	Q4 01.01.-31.12.
Reconciliation of tax expense (USD 1 000)	2018	2017	2018	2017
78% tax rate on profit before tax	280 277	194 040	1 407 829	632 680
Tax effect of uplift	-33 532	-30 784	-130 767	-123 057
Change in tax rates	-2 047	-1 893	-2 047	-1 894
Permanent difference on impairment	-	-	-	22 813
Tax effect on OCI reclassification*	37 053	-	37 053	-
Foreign currency translation of NOK monetary items	-37 014	-8 022	-34 002	-12 955
Foreign currency translation of USD monetary items	-121 121	-11 176	-111 806	120 113
Tax effect of financial and other 23%/24% items	41 678	23 398	50 578	-19 592
Currency movements of tax balances**	123 541	47 848	113 147	-84 676
Other permanent differences, prior period adjustments and change in estimate of	16 187	966	-1 498	2 908
uncertain tax positions
Total taxes (+)/tax income (-)	305 022	214 377	1 328 486	536 340

* Refer to note 6. This amount is not tax deductible, and so represents a permanent difference in the effective tax rate reconciliation.

** Tax balances are in NOK and converted to USD using the period end currency rate. When NOK weakens against USD, the tax rate increases as there is less remaining tax depreciation measured in USD (vice versa).

The tax rate for general corporation tax changed from 23 to 22 per cent from 1 January 2019. The rate for special tax changed from the same date from 55 to 56 per cent.

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

Note 8 Other short-term receivables

		Group
(USD 1 000)	31.12.2018	31.12.2017
Prepayments	64 004	59 100
VAT receivable	8 871	10 856
Underlift of petroleum	122 713	118 012
Accrued income from sale of petroleum products	52 825	105 670
Other receivables, mainly from licenses	111 781	241 879
Total other short-term receivables	360 194	535 518

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
31.12.2018	31.12.2017
44 944	231 506
-	998
44 944	232 504
3 050 000	2 670 000

* During Q4 2017, the company extended its bank guarantee related to withheld payroll tax to NOK 300 million. In Q1 2018 the remaining restricted funds were released in full.

Note 10 Provisions for other liabilities

		Group
Breakdown of provisions for other liabilities (USD 1 000)	31.12.2018	31.12.2017
Fair value of contracts assumed in acquisitions*	106 040	149 031
Other long term liabilities	1 480	3 387
Total provisions for other liabilities	107 519	152 418

* The negative contract values are mainly related to rig contracts entered into by companies acquired by Aker BP, which differed from current market terms at the time of the acquisitions. The fair value is based on the difference between market price and contract price at the time of the acquisitions. The balance is split between current and non-current liabilities based on the cash flow in the contracts, and amortized over the lifetime of the contracts.

Note 11 Derivatives

	Group
(USD 1 000)	31.12.2018	31.12.2017
Unrealized gain currency contracts	-	12 564
Long-term derivatives included in assets	-	12 564
Unrealized gain on commodity derivatives	17 253	-
Unrealized gain currency contracts	-	2 585
Short-term derivatives included in assets	17 253	2 585
Total derivatives included in assets	17 253	15 149
Unrealized losses interest rate swaps	26 275	13 705
Long-term derivatives included in liabilities	26 275	13 705
Unrealized losses commodity derivatives	-	7 691
Unrealized losses currency contracts	8 783	-
Short-term derivatives included in liabilities	8 783	7 691
Total derivatives included in liabilities	35 058	21 396

The group has various types of economic hedging instruments. Commodity derivatives are used to hedge the risk of oil price reduction. The group manages its interest rate exposure using interest rate derivatives, including interest rate swap and a cross currency interest rate swap. Foreign currency exchange derivatives are used to manage the company's exposure to currency risks, mainly costs in NOK, EUR and GBP. These derivatives are mark to market with changes in market value recognized in the income statement. The nature of the instruments and the valuation method is consistent with the disclosed information in the annual financial statements as at 31 December 2017.

Note 12 Other current liabilities

		Group
Breakdown of other current liabilities (USD 1 000)	31.12.2018	31.12.2017
Current liabilities against JV partners	22 779	81 223
Share of other current liabilities in licences	309 260	409 387
Overlift of petroleum	17 021	9 610
Fair value of contracts assumed in acquisitions*	42 998	62 097
Other current liabilities**	198 801	141 880
Total other current liabilities	590 860	704 197

* 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)	31.12.2018	31.12.2017
DETNOR02 Senior unsecured bond *	223 839	230 375
AKERBP – Senior Notes (17/22) **	393 301	391 664
AKERBP – Senior Notes (18/25) ***	493 349	-
Long-term bonds	1 110 488	622 039

* The bond is denominated in NOK and runs from July 2013 to July 2020 and carries an interest rate of 3 month Nibor + 6.5 per cent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The bond is unsecured. The bond has been swapped into USD using a cross currency interest rate swap whereby the group pays Libor + 6.81 per cent quarterly. The financial covenants for this bond are consistent with the RBL as described in note 14.

** The bond was established in July 2017 and carries an interest of 6.0 per cent. The principal falls due in July 2022 and interest is paid on a semi annual basis. The bond is senior unsecured and has no financial covenants.

*** The bond was established in March 2018 and carries an interest of 5.875 per cent. The principal falls due in March 2025 and interest is paid on a semi annual basis. The bond is senior unsecured and has no financial covenants.

Note 14 Other interest-bearing debt

		Group
(USD 1 000)	31.12.2018	31.12.2017
Reserve-based lending facility	907 954	1 270 556
Long-term interest-bearing debt	907 954	1 270 556
Bridge facility	-	1 496 374
Short-term interest-bearing debt	-	1 496 374

The RBL facility was established in 2014 and is a senior secured seven-year facility. The facility size amounts to USD 4.0 billion, with an uncommitted accordion option of USD 1.0 billion. 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. The financial covenants are as follows:

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

• Interest Coverage Ratio shall be minimum 3.5

In relation to the acquisition of Hess Norge AS, the company obtained a new USD 1.5 billion bank facility ("Bridge facility"). The terms of the facility included a mandatory repayment clause triggered by the refund of tax losses in Hess Norge. The refund took place in November 2018 and the facility was repaid and cancelled at the same time.

Note 15 Provision for abandonment liabilities

	Group
(USD 1 000)	31.12.2018	31.12.2017
Provisions as of 1 January	3 043 884	2 156 921
Abandonment liability from acquisitions	-	1 315 181
Change in abandonment liability due to asset sales	-	-207 516
Incurred cost removal	-201 227	-74 005
Accretion expense - present value calculation	128 737	129 619
Changed net present value from changed discount rate	-277 081	511 330
Change in estimates and incurred liabilities on new drilling and installations	-141 721	-787 646
Total provision for abandonment liabilities	2 552 592	3 043 884
Break down of the provision to short-term and long-term liabilities
Short-term	105 035	268 262
Long-term	2 447 558	2 775 622

The estimate is based on executing a concept for abandonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.0 per cent and a nominal discount rate before tax of between 4.46 per cent and 5.01 per cent. For previous quarters in 2018 and year end 2017 the inflation rate was 2.5 per cent and the discount rate was between 3.44 per cent and 4.42 per cent. The credit margin included in the discount rate is 2.00 per cent. For previous quarters in 2018 and year end 2017 the credit margin was 1.68 per cent.

Total provision for abandonment liabilities 2 552 592 3 043 884

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

The company has not identified any events with significant accounting impacts that have occurred between the end of the reporting period and the date of this report.

Note 18 Investments in joint operations

31.12.2018	30.09.2018
65.000%	65.000 %
65.000%	65.000 %
90.000%	90.000 %
34.786%	34.786 %
70.000%	70.000 %
90.000%	90.000 %
46.904%	46.904 %
65.000%	65.000 %
55.000%	55.000 %
46.200%	46.200 %
80.000%	80.000 %
23.835%	23.835 %

Production licences in which Aker BP is the operator:

Licence:	31.12.2018	30.09.2018 Licence:	31.12.2018	30.09.2018
PL 001B	35.000%	35.000 % PL 777	40.000%	40.000 %
PL 006B	90.000%	90.000 % PL 777B	40.000%	40.000 %
PL 019	80.000%	80.000 % PL 777C	40.000%	40.000 %
PL 019C	80.000%	80.000 % PL 777D	40.000%	40.000 %
PL 019E	80.000%	80.000 % PL 784	40.000%	40.000 %
PL 026*	92.130%	0.000 % PL 790	30.000%	30.000 %
PL 026B	90.260%	90.260 % PL 814	40.000%	40.000 %
PL 027D	100.000%	100.000 % PL 818	40.000%	40.000 %
PL 028B	35.000%	35.000 % PL 818B	40.000%	40.000 %
PL 033	90.000%	90.000 % PL 822S	60.000%	60.000 %
PL 033B	90.000%	90.000 % PL 839	23.835%	23.835 %
PL 036C	65.000%	65.000 % PL 843	40.000%	40.000 %
PL 036D	46.904%	46.904 % PL 858	40.000%	40.000 %
PL 036E**	64.000%	0.000 % PL 861	50.000%	50.000 %
PL 065	55.000%	55.000 % PL 867	40.000%	40.000 %
PL 065B	55.000%	55.000 % PL 868	60.000%	60.000 %
PL 088BS	65.000%	65.000 % PL 869	60.000%	60.000 %
PL 102D*	50.000%	0.000 % PL 872	40.000%	40.000 %
PL 102F*	50.000%	0.000 % PL 873	40.000%	40.000 %
PL 102G*	50.000%	0.000 % PL 874	90.260%	90.260 %
PL 102H**	50.000%	0.000 % PL 893	60.000%	60.000 %
PL 127C**	100.000%	0.000 % PL 895	60.000%	60.000 %
PL 146**	77.800%	0.000 % PL 906**	60.000%	40.000 %
PL 150	65.000%	65.000 % PL 907**	60.000%	40.000 %
PL 159D	23.835%	23.835 % PL 914S	34.786%	34.786 %
PL 169C	50.000%	50.000 % PL 915	35.000%	35.000 %
PL 203	65.000%	65.000 % PL 916	40.000%	40.000 %
PL 203B	65.000%	65.000 % PL 919	65.000%	65.000 %
PL 212	30.000%	30.000 % PL 932	60.000%	60.000 %
PL 212B	30.000%	30.000 % PL 941	50.000%	50.000 %
PL 212E	30.000%	30.000 % PL 948	40.000%	40.000 %
PL 242	35.000%	35.000 % PL 951	40.000%	40.000 %
PL 261	50.000%	50.000 % PL 963	70.000%	70.000 %
PL 262	30.000%	30.000 % PL 964	40.000%	40.000 %
PL 300	55.000%	55.000 %
PL 333**	77.800%	0.000 %
PL 340	65.000%	65.000 %
PL 340BS	65.000%	65.000 %
PL 364	90.260%	90.260 %
PL 442	90.260%	90.260 %
PL 442B	90.260%	90.260 %
PL 460	65.000%	65.000 %
PL 504	47.593%	47.593 %
PL 626	60.000%	60.000 %
PL 659	50.000%	50.000 %
PL 677***	0.000%	90.000 %
PL 685**	40.000%	0.000 %
PL 748	50.000%	50.000 %
PL 748B	50.000%	50.000 %
PL 762	20.000%	20.000 %
Number of licenses in which Aker BP is the operator			83	74

* Aker BP became the operator of the license during Q4 2018.

** Acquired/changed through transactions or license splits.

*** Relinquished license or Aker BP has withdrawn from the license.

Fields non-operated:	31.12.2018	30.09.2018
Atla	10.000%	10.000 %
Enoch	2.000%	2.000 %
Gina Krog	3.300%	3.300 %
Johan Sverdrup	11.573%	11.573 %
Oda	15.000%	15.000 %
Varg***	0.000%	5.000 %

31.12.2018 30.09.2018 Licence: PL 006C 15.000% 15.000 % PL 006E 15.000% 15.000 % 13.338% PL 018DS 13.338 % 0.000% PL 026 30.000 % 20.000% PL 029B 20.000 % 50.000% PL 035 50.000 % 50.000% PL 035C 50.000 % 0.000% PL 038 5.000 % 10.000% PL 048D 10.000 % 10.000% PL 102C 10.000 % 0.000% PL 102D 10.000 % 0.000% PL 102F 10.000 % 0.000% PL 102G* 10.000 % 50.000% PL 127 0.000 % 50.000% PL 127B 0.000 % 15.000% PL 220 15.000 % 20.000% PL 265 20.000 % 50.000% PL 272 50.000 % 15.000% PL 405 15.000 % 40.000% PL 457BS 40.000 % 60.000% PL 492 60.000 % 22.222% PL 502 22.222 % 35.000% PL 533 35.000 % 35.000% PL 533B 35.000 % 30.000% PL 554 30.000 % 30.000% PL 554B 30.000 % 30.000% PL 554C 30.000 % 30.000% PL 554D 30.000 % 4.000% PL 615 0.000 % 4.000% PL 615B 0.000 % 20.000% PL 719 20.000 % 40.000% PL 721 40.000 % 20.000% PL 722 20.000 % 20.000% PL 782S 20.000 % 20.000% PL 782SB 20.000 % 20.000% PL 782SC 20.000 % 30.000% PL 810 30.000 % 30.000% PL 810B 30.000 % 20.000% PL 811 20.000 % 3.300% PL 813 3.300 % 30.000% PL 838 30.000 % 30.000% PL 842 30.000 % 20.000% PL 844 20.000 % 40.000% PL 852 40.000 % 40.000% PL 852B 40.000 % 40.000% PL 852C 40.000 % 20.000% PL 857 20.000 % 50.000% PL 862 50.000 % 40.000% PL 863 40.000 % 40.000% PL 863B 40.000 % 20.000% PL 864 20.000 % 0.000% PL 871 20.000 % 30.000% PL 891 30.000 % 30.000% PL 892 30.000 % 30.000% PL 902 30.000 % 30.000% PL 942 30.000 % 20.000% PL 954 20.000 % 30.000% PL 955 30.000 % 30.000% PL 961 30.000 % 20.000% PL 962 20.000 % PL 966 30.000% 30.000 % Number of licenses in which Aker BP is a partner 55 57	Production licences in which Aker BP is a partner:

** Acquired/changed through transactions or license splits. * Aker BP became the operator of the license during Q4 2018.

*** Relinquished license or Aker BP has withdrawn from the license.

Note 19 Results from previous interim reports

	2018
(USD 1 000)	Q4	Q3	Q2	Q1	Q4	2017 Q3	Q2	Q1
Total income	886 096	999 631	974 745	889 599	725 994	596 188	594 501	646 250
Production costs	186 530	165 466	163 625	173 481	147 076	134 411	121 017	120 874
Exploration expenses	72 458	93 519	75 270	54 661	56 181	63 887	75 375	30 259
Depreciation	195 962	188 526	182 528	185 421	183 138	175 334	184 194	184 004
Impairments	20 172	-	-	-	21 111	1 091	365	29 782
Other operating expenses	7 739	4 334	1 324	3 640	13 549	2 893	3 113	8 051
Total operating expenses	482 862	451 845	422 747	417 204	421 055	377 617	384 065	372 969
Operating profit/loss	403 234	547 787	551 998	472 395	304 940	218 571	210 436	273 280
Net financial items	-43 905	-57 869	-21 778	-46 954	-56 526	-9 469	-83 597	-46 508
Profit/loss before taxes	359 329	489 918	530 220	425 442	248 413	209 102	126 840	226 772
Taxes (+)/tax income (-)	305 022	365 047	394 219	264 197	214 377	97 065	66 944	157 955
Net profit/loss	54 307	124 871	136 001	161 245	34 036	112 037	59 896	68 818

Alternative performance measures

Aker BP may disclose alternative performance measures as part of its financial reporting as a supplement to the financial statements prepared in accordance with IFRS. Aker BP believes that the alternative performance measures provide useful supplemental information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Aker BP's business operations and to improve comparability between periods.

Abandonment spend (abex) is payment for removal and decommissioning of oil fields

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

Dividend per share (DPS) is dividend paid in the quarter divided by number of shares outstanding

Capex is disbursements on investments in fixed assets deducted by capitalized interest cost

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

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

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

Equity ratio is total equity divided by total assets

Exploration spend (expex) is exploration expenses plus additions to capitalized exploration wells less dry well expenses

Leverage ratio is calculated as Net interest-bearing debt divided by twelve months rolling EBITDAX

Net interest-bearing debt is book value of current and non-current interest-bearing debt less cash and cash equivalents

Production cost per boe is production cost divided by number of barrels of oil equivalents produced in the corresponding period

AKER BP ASA

Fornebuporten, Building B Oksenøyveien 10 1366 Lysaker

Post: Postboks 65, 1324 Lysaker

Telefon: +47 51 35 30 00 E-post: post@akerbp.com

www.akerbp.com