Aker BP

Quarterly Report • Nov 4, 2015

Q3 2015

QUARTERLY REPORT FOR DET NORSKE OLJESELSKAP

TRONDHEIM, 4 NOVEMBER 2015

KEY EVENTS IN Q3 2015

•	1 July:	Det norske announced the completion of a redetermination process for the reserve-based lending facility, which increased the available borrowing base to USD 2.9 billion and completion of the revolving credit facility of USD 550 million.
•	1 July:	Det norske announced a small oil and gas discovery at Gina Krog East 3
•	2 July:	The Ministry of Petroleum and Energy announced the apportionment of the ownership interests in the Johan Sverdrup field, resulting in an 11.5733 percent ownership interest for Det norske
•	14 August:	Det norske announced first oil from the second well at Bøyla and installation of the Boa extention manifold
•	19 August:	Det norske announced that accumulated oil production from the Alvheim area had reached 300 million barrels
•	21 August:	The development plans for Johan Sverdrup were approved by the Ministry of Petroleum and Energy
•	25 September:	Det norske announced a reduced CAPEX estimate for phase 1 of the Johan Sverdrup development by NOK 9 billion (gross)
		KEY EVENTS AFTER THE QUARTER

• 14 October: Det norske announced the acquisition of Svenska Petroleum's Norwegian subsidiary

SUMMARY OF FINANCIAL RESULTS

	Unit	Q3 2015	Q3 2014	2015 YTD	2014 YTD
Operating revenues	USDm	281	18	942	119
EBITDA	USDm	225	-62	717	-31
Net result	USDm	-166	-17	-157	8
Earnings per share (EPS)	USD	-0.82	-0.09	-0.78	0.05
Production cost per barrel	USD/boe	5	37	7	31
Depreciation per barrel	USD/boe	22	131	22	78
Cash flow from operations	USDm	242	9	559	-32
Cash flow from investments	USDm	-242	-206	-729	-472
Total assets	USDm	5 237	2 398	5 237	2 398
Net interest-bearing debt	USDm	2 147	529	2 147	529
Cash and cash equivalents	USDm	207	445	207	445

SUMMARY OF OPERATIONAL PERFORMANCE

	Unit	Q3 2015	Q3 2014	2015 YTD	2014 YTD
Production
Alvheim (65%)	boepd	35 574	-	35 233	-
Atla (10%)	boepd	306	621	422	551
Bøyla (65%)	boepd	10 502	-	9 063	-
Jette (70%)	boepd	623	1 080	640	1 431
Jotun (7%)	boepd	83	140	117	150
Varg (5%)	boepd	336	494	345	510
Vilje (46.9%)	boepd	6 599	-	6 590	-
Volund (65%)	boepd	8 783	-	9 618	-
SUM	boepd	62 806	2 335	62 029	2 641
Oil price	USD/bbl	52	104	58	106
Gas price	USD/scm	0.26	0.28	0.28	0.29

3

SUMMARY OF THE QUARTER

Det norske oljeselskap ASA ("the company" or "Det norske") reported revenues of USD 281 (18) million in the third quarter of 2015. Production in the period was 62.8 (2.3) thousand barrels of oil equivalent per day ("mboepd"), realising an average oil price of USD 52 (104) per barrel.

EBITDA amounted to USD 225 (-62) million in the quarter and EBIT was USD -91 (-90) million, following an impairment of USD 186 (0) million in the quarter. Net loss for the quarter were USD 166 (17) million, translating into an EPS of USD -0.82 (-0.09). Net interestbearing debt amounted to USD 2,147 (529) million per 30 September 2015.

Production from the Alvheim area was strong in the third quarter. The second producer at Bøyla was started up in August. In September, drilling of the Kneler K6 IOR well was completed and drilling commenced on the BoaKamNorth IOR well.

The Johan Sverdrup project moved forward with approval of the development plans, contract awards continued and the operator announced a reduced CAPEX estimate for phase 1. The Ministry of Petroleum and Energy made its ruling regarding the Tract Participation on 1 July 2015. Det norske has filed a complaint and its awaiting the outcome.

Pre-drilling of production wells at the Ivar Aasen field and laying of pipelines between Ivar Aasen and Edvard Grieg commenced in July. Construction of the topside has reached 85 percent completion in Singapore. The project is progressing well and is on track for first oil in Q4 2016.

During the third quarter, the company has been actively preparing for the upcoming 23rd licensing round by assessing the opportunities in the Barents Sea.

In October, the company announced the acquisition of Svenska Petroleum's Norwegian subsidiary. The acquisition increases the company's ownership in attractive discoveries with resource upside potential and fit well into the existing portfolio.

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. Figures in brackets apply to the corresponding period in the previous year, and is for 2014 not directly comparable as they represent Det norske prior to the acquistion of Marathon Oil Norge AS.

FINANCIAL REVIEW

(USD million)	Q3 2015	Q3 2014
Operating revenues	281	18
EBITDA	225	-62
EBIT	-91	-90
Pre-tax profit/loss	-107	-121
Net profit	-166	-17
EPS (USD)	-0.82	-0.09

Operating revenues in the third quarter were USD 281 (18) million.

Exploration expenses amounted to USD 18 (72) million in the quarter, reflecting seismic costs, area fees and G&G activities.

Production costs were USD 27 (8) million, equating to USD 4.7 per barrel of oil equivalents, while other operating expenses amounted to USD 11 (1) million.

Depreciation was USD 130 (28) million, corresponding to USD 22 per boe.

Non-cash impairment losses were USD 186 (0) million, which is related to impairment of technical goodwill that arose from the acquisition of Marathon Oil Norge AS. The impairment is mainly caused by decreasing forward prices for oil compared to the previous quarter and is detailed in note 4.

The company recorded an operating loss of USD 91 (90) million in the third quarter.

The net loss for the period was USD 166 (17) million after net financial items of USD -16 (-30) million and a tax charge of USD 59 (-104) million.

Earnings per share were USD -0.82 (-0.09).

Income statement Statement of financial position

(USD million)	Q3 2015	Q3 2014
Goodwill	948	50
PP&E	2 929	728
Cash & cash equivalents	207	445
Total assets	5 237	2 398
Equity	495	962
Interest-bearing debt	2 353	974

Total intangible assets amounted to USD 1,846 (639) million, of which goodwill was USD 948 (50) million. Other intangible assets were USD 898 (589) million, with the majority of this relating to excess values from the Marathon Oil Norge AS purchase price allocation.

Property, plant and equipment increased to USD 2,929 (728) million and are detailed in note 5. The company's cash and cash equivalents were USD 207 (445) million as of 30 September.

Total assets increased to USD 5,237 (2,398) million at the end of the quarter.

Equity decreased to USD 495 (962) million at the end of the quarter, reflecting the net loss in the period.

Deferred tax liabilities amounted to USD 1,424 (0) million and are detailed in note 8. The main part of this tax liability arose from the acquisition of Marathon Oil Norge AS.

Interest-bearing debt increased to USD 2,353 (974) million, consisting of the DETNOR02 bond of USD 216 million, the DETNOR03 bond of USD 295 million and the Reserve Based Lending ("RBL") facility of USD 1,842 million.

Payable taxes were 0 (0) at the end of the quarter, mainly due to unrealised foreign exchange loss on long-term debt and lower petroleum revenues.

Statement of cash flow

(USD million)	Q3 2015	Q3 2014
Cash flow from operations	242	9
Cash flow from investments	-242	-206
Cash flow from financing	22	509
Net change in cash & cash eq.	22	312
Cash and cash eq. EOQ	207	445

Net cash flow from operating activities was USD 242 (9) million. Taxes paid in the quarter were USD 45 (0) million, reflecting the August tax instalment.

Net cash flow from investment activities were USD -242 (-206) million. Investments in fixed assets amounted to USD 237 (125) million for the quarter, mainly reflecting CAPEX on Ivar Aasen, Alvheim and Johan Sverdrup.

Net cash flow from financing activities totalled USD 22

(509) million, reflecting the net amount drawn on the company's RBL facility in the quarter.

Hedging

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

During the third quarter, the company benefitted from commodity hedges entered into during the first half of 2015. The company has put options in place with a strike of USD 55/bbl for a volume equal to around 30 percent of the estimated production for the last quarter of 2015 and corresponding to 100 percent of the after-tax value. For 2016, the company has put options in place for around 20 percent of the estimated 2016 production, corresponding to 67 percent of the after-tax value.

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

HEALTH, SAFETY AND THE ENVIRONMENT

HSE is always the number one priority in all Det norske activities. The company ensures that all its operations and projects are carried out under the highest HSE standards. Det norske did not have any serious or high potential incidents during the third quarter.

With the current high activity level, special attention is paid to maintain a high HSE standard and preventing injuries and undesired events at all levels in the organization.

The Petroleum Safety Authority (PSA) conducted three audits of Det norske's activities in the third quarter. The result of two of the audits have been reported by PSA; Four deviations and twelve areas for improvement were reported. These are being registered and followed up according to Det norske's procedures. There are no concerns related to Det norske's ability to close out any of the deviations.

OPERATIONAL REVIEW

Det norske produced 5.8 (0.2) million barrels of oil equivalents ("mmboe") in the third quarter of 2015. This corresponds to 62.8 (2.3) mboepd. The average realized oil price was USD 52 (104) per barrel, while gas revenues were recognized at market value of USD 0.26 (0.28) per standard cubic metre (scm).

Alvheim fields

PL 203/088BS/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 production vessel Alvheim FPSO. The production efficiency for the Alvheim FPSO in the third quarter was 98.1 percent, which is higher than in the second quarter and above target for the quarter. Production efficiency for the first nine months is 96.6 percent, which is also well above the target.

The Bøyla field commenced production from one well in January 2015 and the water injection well (M3) was started up in March 2015. The second production well (Bøyla M2) was started up in early August, marking the completion of the project phase for the Bøyla field development.

The drilling rig Transocean Winner completed the Kneler K6 IOR well mid-September. Production is expected to commence in November this year from the well once it has been connected up to the Kneler A production manifold.

The drilling rig subsequently moved to the Boa manifold to start drilling of the BoaKamNorth well, which is part of the Alvheim IOR project. The BoaKamNorth project consists of one well and a new subsea manifold tied back to the Boa manifold. The progress on the project has been good in the third quarter. The subsea manifold was installed on the seabed in August and will be hooked up to the existing Alvheim infrastructure next year in connection with the BoaKamNorth well tie-in campaign. Production from BoaKamNorth is expected to commence in the middle of 2016.

The Viper-Kobra development, which comprises two small separate discoveries in the Alvheim area is progressing. Drilling of the two production wells is scheduled to start towards the end of Q1 2016 with first oil expected at the end of 2016.

Other producing assets

Production increased on Jette in the quarter and oil production was stable at Varg. Jotun and Atla volumes were impacted by planned maintenance during the third quarter.

Ivar Aasen

PL 001B/242/457 (34.78 percent, operator)

Key activities for the Ivar Aasen project are progressing according to plan with first oil planned for Q4 2016. Ivar Aasen is being developed with a manned production platform. The topside will include living quarters and a processing facility for first stage separation.

Pre-drilling of production wells commenced mid-July with batch setting of five deep set conductors. The Maersk Interceptor jack-up rig has performed very well, and the drilling program is progressing ahead of schedule.

Laying of pipelines between Ivar Aasen and Edvard Grieg commenced in July. By the end of the third quarter, all three pipelines between Ivar Aasen and Edvard Grieg have successfully been installed and tested. The subsea and pipeline offshore activity planned for this year is expected to be finalised early November.

Topside construction in Singapore is progressing well, and is about 85 percent complete. Pipe fabrication and installation is ongoing and piping insulation has commenced. Cable pulling and termination is progressing well. A handover of first priority sub systems to Det norske commissioning team commenced in September.

The construction of the living quarters at Stord in Norway is progressing according to plan. In October, the helideck was delivered to site, assembled and lifted in place.

Johan Sverdrup Unit PL 265/501/502 (11.5733 percent, partner)

The plan for development and operation (PDO) for Phase 1 of the Johan Sverdrup development was approved by the Ministry of Petroleum and Energy (MPE) in August. MPE also approved the plans for installation and operation (PIOs) for the oil and gas export pipelines and power from shore. In addition MPE approved the Unit Operating Agreement (UOA) for the whole field.

The production is expected to commence in the fourth quarter 2019.

Contract awards continued through the third quarter. Kværner ASA was awarded the contracts for delivery of the steel jackets for the drilling and processing platforms. Dragados Offshore S.A was awarded the contract for delivery of the steel jacket for the utility and accommodation platform. The contract for fabrication and installation of two high-voltage cables supplying power from shore was awarded to ABB. Aibel was awarded the contract for onshore construction site work and the converter station for power supply. FMC was awarded the contract for subsea equipment.

In August, the first piece of the Johan Sverdrup development, the pre-drilling template, was succesfully installed at the future field center drilling platform location. Heerema Marine Contractors was responsible for both design, construction and installation. Construction of the first steel jacket (for the processing platform) commenced at Kværner Verdal.

The MPE announced on 2 July the apportionment of the ownership interests in the Johan Sverdrup field. In the decision, Det norske was attributed a total ownership interest in the Johan Sverdrup field of 11.5733 percent. Det norske filed a complaint regarding the decision made by the MPE to the King in Council, as the highest level of the Norwegian administrative authorities and is awaiting the outcome.

In September, the operator presented an update of the CAPEX estimate for the first phase of the development

EXPLORATION

During the quarter, the company's cash spending on exploration was USD 19 million. USD 18 million was recognized as exploration expenses in the period, relating to seismic, area fees and G&G costs. There were no drilling operations in the quarter.

In September, the company applied for the 2015 Awards in Pre-defined Areas (APA) with an aim to secure additional acreage mainly in the company's core areas. to the partnership. The updated estimate is showing reduced CAPEX as a result of positive market response in contracts and purchase orders. In the PDO, CAPEX for the first phase development was estimated at NOK 117 billion in real terms (NOK 2015) and NOK 123 billion in nominal terms. Overall CAPEX for the first phase has been reduced by NOK 9 billion from NOK 123 billion to NOK 114 billion in nominal terms, assuming the same currency assumptions as in the PDO.

The contingency level (in NOK) is maintained in the updated estimate and reflects risks in scope, schedule and project execution.

The route for the oil export pipeline to Mongstad has been changed in order to reduce cost and risk. Instead of a challenging direct route through rugged coastal terrain (nearshore and onshore), the pipeline will deviate northwards and follow the fjord Fensfjorden all the way in to Mongstad.

Gina Krog

PL 029B/029C/048/303 (3.3 percent, partner)

The development plan for the field includes a steel jacket and integrated topside with living quarters and processing facilities. Oil from Gina Krog will be exported to the markets with shuttle tankers while exit for the gas is via the Sleipner platform.

Pre-drilling of production wells commenced in late July, by use of the Maersk Integrator jack-up rig.

Exploration wells drilled on the East-3 segment were completed this summer and possible future tie-in possibilities are being evaluated.

During the third quarter, the company has been actively preparing for the upcoming 23rd licensing round by assessing the opportunities in the Barents Sea, as well as working to optimise the 2016 exploration drilling portfolio.

OTHER EVENTS

Acquisition of Svenska Petroleum Exploration AS

In October, Det norske announced that the company had entered into an agreement to acquire Svenska Petroleum Exploration AS («Svenska») for a cash consideration of USD 75 million on a cash free, debt free basis.

Svenska has 15 employees and holds 13 licenses in Norway, including the Krafla/Askja (25 percent), Garantiana (20 percent), Frigg Gamma Delta (40 percent) and Fulla/Lille-Frigg (25 percent) discoveries in the North Sea. In addition, the company holds four exploration licenses in the Norwegian Sea.

Potential investment decisions on the Krafla/Askja and Garantiana discoveries are expected around 2018.

The transaction will have tax effect from the fiscal year 2015. At the end of 2014, Svenska held a tax loss carry forward equal to an after-tax value of approximately NOK 130 million, which is expected to be offset against Det norske's taxes paid for the fiscal year 2015.

The transaction is expected to close in the fourth quarter 2015, subject to regulatory approvals.

OUTLOOK

The Ivar Aasen project is progressing well and remains on track for first oil in Q4 2016. Det norske continues to develop the Alvheim area and expects to put the Kneler K6 IOR well on stream in the fourth quarter. The Johan Sverdrup project is moving forward and the company is awaiting the outcome of the complaint regarding ownership in the field.

In the continued challenging macro environment, the company's improvement program is moving forward. The company has realized 2015 savings in excess of the USD 100 million that was communicated at the beginning of the year. The next phase of the program is aiming to further reduce costs, streamline work processes and improve the way the company operates, in order to capture run-rate savings in the years to come. This is an integral part of the work to strengthen the business and position the company to benefit when market conditions improve.

Farm-in and farm-out agreements for exploration licenses

In August, Det norske acquired a 10 percent interest in PL722 from North Energy for a cash consideration. The license is subject to a drill or drop decision in 2016.

In October, Det norske signed a farm-out agreement with MOL Norge AS for a 20 percent working interest in PL 790, 10 percent in PL748 and 25 percent in PL 678. As compensation, MOL will carry part of Det norske's cost on up to two conditional exploration wells.

Both agreements are subject to approval by the authorities.

The acquisition of Svenska Petroleum Exploration AS is a logical bolt-on acquisition for Det norske that increases the company's ownership in attractive discoveries with resource upside potential. The company expects further drilling in both the Krafla/Askja and Garantiana areas in 2016.

With available liquidity of about USD 1.7 billion, the company has a robust financing in place and has secured funding for its work program until first oil at Johan Sverdrup.

Production for 2015 is expected to average approximately 62 mboepd, CAPEX is expected to be approximately USD 925 million and exploration expenditures is expected to be approximately USD 95 million. Production cost is expected to average approximately USD 6.5 per barrel of oil equivalent.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT (Unaudited)

		Q3		01.01.-30.09.
Note (USD 1 000)	2015	2014	2015	2014
Petroleum revenues 2	280 537	18 410	940 369	67 251
Other operating revenues	460	-76	2 042	51 309
Total operating revenues	280 996	18 334	942 411	118 560
Exploration expenses 3	18 066	71 778	57 537	112 844
Production costs	26 888	7 906	116 923	22 354
Depreciation 5	129 790	28 080	369 368	56 071
Impairments 4	185 756		238 529	27 402
Other operating expenses 6	11 433	993	48 380	14 714
Total operating expenses	371 932	108 757	830 738	233 386
Operating profit/loss	-90 936	-90 423	111 673	-114 825
Interest income	184	1 856	1 359	5 421
Other financial income Interest expenses	56 653 27 654	6 821 17 738	97 436 79 332	15 386 49 028
Other financial expenses	44 991	21 082	93 538	35 688
Net financial items 7	-15 808	-30 143	-74 076	-63 909
Profit/loss before taxes	-106 744	-120 567	37 597	-178 734
Taxes (+)/tax income (-) 8	59 441	-103 615	194 065	-186 482
Net profit / loss	-166 185	-16 952	-156 468	7 748
Weighted average no. of shares outstanding and fully diluted	202 618 602	178 542 009	202 618 602	153 840 050
Earnings/(loss) after tax per share	-0.82	-0.09	-0.77	0.05

STATEMENT OF COMPREHENSIVE INCOME (Unaudited)

		Q3		01.01.-30.09.
(USD 1 000)	Note	2015	2014	2015	2014
Profit/loss for the period		-166 185	-16 952	-156 468	7 748
Items which will not be reclassified over profit and loss
(net of taxes)
Actuarial gain/loss pension plan			-912		-912
Total comprehensive income in period		-166 185	-17 863	-156 468	6 836

STATEMENT OF FINANCIAL POSITION (Unaudited)

(USD 1 000)	Note	30.09.2015	30.09.2014	31.12.2014
ASSETS
Intangible assets
Goodwill	5	948 175	49 768	1 186 704
Capitalized exploration expenditures	5	300 841	276 772	291 619
Other intangible assets	5	597 140	158 286	648 788
Deferred tax asset	8		154 422
Tangible fixed assets
Property, plant and equipment	5	2 929 128	728 389	2 549 271
Financial assets
Long-term receivables	11	4 440	12 203	8 799
Other non-current assets	9	4 396	46 242	3 598
Long-term derivatives	14	5 768
Total non-current assets		4 789 888	1 426 081	4 688 778
Inventories
Inventories		32 013	5 207	25 008
Receivables
Accounts receivable	15	64 061	9 188	186 461
Other short-term receivables	10	114 049	156 897	184 592
Other current financial assets		2 892	3 797	3 289
Calculated tax receivables	8	8 095	352 476
Short-term derivatives	14	18 786
Cash and cash equivalents
Cash and cash equivalents	12	206 941	444 849	296 244
Total current assets		446 836	972 413	695 594
TOTAL ASSETS		5 236 724	2 398 494	5 384 372

STATEMENT OF FINANCIAL POSITION (Unaudited)

(USD 1 000)	Note	30.09.2015	30.09.2014	31.12.2014
EQUITY AND LIABILITIES
Equity
Share capital	13	37 530	37 530	37 530
Share premium		1 029 617	1 029 617	1 029 617
Other equity		-571 954	-105 375	-415 485
Total equity		495 193	961 772	651 662
Provisions for liabilities
Pension obligations		1 601	2 380	2 021
Deferred taxes	8	1 423 879		1 286 357
Abandonment provision	19	506 541	129 329	483 323
Provisions for other liabilities			67	12 044
Non-current liabilities
Bonds	17	511 070	291 875	253 141
Other interest-bearing debt	18	1 842 425	405 433	2 037 299
Long-term derivatives	14	47 170	6 966	5 646
Current liabilities
Short-term loan			183 851
Trade creditors		56 984	103 906	152 258
Bonds			92 945
Accrued public charges and indirect taxes		6 493	2 847	6 758
Tax payable	8			189 098
Short-term derivatives	14	9 891		25 224
Abandonment provision	19	3 758	15 773	5 728
Other current liabilities	16	331 718	201 351	273 813
Total liabilities		4 741 531	1 436 722	4 732 710
TOTAL EQUITY AND LIABILITIES		5 236 724	2 398 494	5 384 372

STATEMENT OF CHANGES IN EQUITY (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 31.12.2013	27 656	564 736	573 083	-223	-48 334	-592 818	-68 292	524 100
Right issue	9 874	469 249			-24 350		-24 350	454 773
Transaction costs, rights issue		-4 368			261		261	-4 107
Profit/loss for the period 1.1.2014 - 30.09.2014				-897	-19 846	7 748	-12 995	-12 995
Equity as of 30.09.2014	37 530	1 029 617	573 083	-1 121	-92 268	-585 070	-105 375	961 772
Profit/loss for the period 1.10.2014 - 31.12.2014					-23 223	-286 887	-310 110	-310 110
Settlement of defined benefit plan				1 016		-1 016
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 1.1.2015 - 30.09.2015						-156 468	-156 468	-156 468
Equity as of 30.09.2015	37 530	1 029 617	573 083	-105	-115 491	-1 029 440	-571 954	495 193

* 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 was 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)

			Q3		01.01.-30.09.	Year
(USD 1 000)	Note	2015	2014	2015	2014	2014
Cash flow from operating activities
Profit/loss before taxes		-106 744	-120 567	37 597	-178 734	-375 624
Taxes paid during the period		-44 715		-235 221		-109 068
Tax refund during the period						190 532
Depreciation	5	129 790	28 080	369 368	56 071	160 254
Net impairment losses	4	185 756		238 529	27 402	346 420
Accretion expenses	19	6 657	1 836	19 605	6 118	12 410
Gain/loss on licence swaps without cash effect			-118		-49 826	-49 765
Changes in derivatives	7	10 177	-1 073	1 430	-937	10 616
Amortization of interest expenses and arrangement fee	7	3 539	2 259	15 218	5 515	26 711
Amortization of fair value of
contracts assumed in the Marathon acquisition	16			-2 878
Expensed capitalized dry wells	3	-686	48 430	9 190	65 328	99 061
Changes in inventories, accounts payable and receivables		-180 545	20 519	-441 709	49 152	-530 150
Changes in abandonment liabilities through income statement						-1 952
Changes in other current balance sheet items		238 978	29 943	550 629	-11 923	483 345
Net cash flow from operating activities		242 206	9 310	561 757	-31 834	262 791
Cash flow from investment activities
Payment for removal and decommissioning of oil fields	19	-5 592	-11 785	-8 768	-12 608	-14 087
Disbursements on investments in fixed assets	5	-236 659	-125 136	-688 122	-328 253	-583 200
Acquisition of Marathon Oil Norge AS (net of cash acquired)						-1 513 591
Disbursements on investments in capitalized
exploration expenditures and other intangible assets	5	-178	-69 206	-32 093	-139 821	-164 128
Sale/farmout of tangible fixed assets and licences					8 944	8 862
Net cash flow from investment activities		-242 429	-206 128	-728 982	-471 739	-2 266 144
Cash flow from financing activities
Net proceeds from equity issuance			485 496		485 496	474 755
Repayment of short-term debt						-162 434
Repayment of bond (detnor 01)						-87 536
Repayment of long-term debt	18		-130 974	-330 000	-178 603	-1 147 934
Arrangement fee		-3 067		-14 380		-67 350
Proceeds from issuance of long-term debt	17.18	25 000	154 076	425 000	272 183	2 897 354
Proceeds from issuance of short-term debt					114 602	116 829
Net cash flow from financing activities		21 933	508 598	80 620	693 677	2 023 684
Net change in cash and cash equivalents		21 711	311 780	-86 604	190 105	20 331
Cash and cash equivalents at start of period		187 928	156 995	296 244	280 942	280 942
Effect of exchange rate fluctuation on cash held		-2 698	-23 926	-2 698	-26 198	-5 029
Cash and cash equivalents at end of period		206 941	444 849	206 941	444 849	296 244
Specification of cash equivalents at end of period
Bank deposits		203 323	443 126	203 323	443 126	291 346
Restricted bank deposits		3 618	1 723	3 618	1 723	4 897
Cash and cash equivalents at end of period	12	206 941	444 849	206 941	444 849	296 244

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 companies annual financial statement as at 31 December 2014. These interim financial statements have not been subject to review or audit by independent auditors.

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 statement for 2014. There are no new standards effective from 1 January 2015, but there are some annual improvements cycles as described in the annual report 2014. These changes have no significant effect for the company.

As more fully described in the annual report, the company changed its presentation currency from NOK to USD effective 15 October 2014. Accordingly, the interim financial information for Q3 2014 presented herein that was historically presented in NOK has been restated as if the USD had always been the presentation currency.

There has been made a minor change in the presentation of the line items in the Income statement since Q4 2014. The company will no longer present payroll expenses separately, as these costs are fully allocated to other items, such as production cost for producing licenses and development cost for fields under development. The cost previously presented as payroll is mainly classified as other operating expenses in the Income statement and comparative figures have been adjusted accordingly. Additionally, area fee which prior to 2015 was included in other operating expenses is now reclassified to exploration expenses and comparative figures have been adjusted accordingly.

Note 2 Petroleum revenues

	Q3		01.01.-30.09.
Breakdown of revenues (USD 1 000)	2015	2014	2015	2014
Recognized income oil	252 353	14 907	847 056	59 212
Recognized income gas	27 456	2 510	90 971	5 349
Tariff income	728	993	2 342	2 690
Total petroleum revenues	280 537	18 410	940 369	67 251
Breakdown of produced volumes (barrels of oil equivalent)
Oil	5 135 774	153 383	14 888 483	556 523
Gas	642 419	61 405	2 045 493	164 310
Total produced volumes	5 778 193	214 788	16 933 976	720 833

Note 3 Exploration expenses

Breakdown of exploration expenses	Q3		01.01.-30.09.
(USD 1 000)	2015 2014		2015	2014
Seismic, well data, field studies, other exploration costs	6 589	5 516	18 772	16 315
Recharged rig costs		-229	407	-11 091
Exploration expenses from licence participation incl. seismic	1 980	10 653	10 827	23 158
Expensed capitalized wells previous years		1 590	1 292	5 098
Expensed capitalized wells this year	-686	46 840	7 898	60 230
Payroll and other operating expenses classified as exploration	8 720	4 213	12 719	11 527
Exploration-related research and development costs	-114	1 159	274	2 664
Area fee	1 577	2 035	5 348	4 943
Total exploration expenses	18 066	71 778	57 537	112 844

As mentioned in Note 1, area fee included in other operating expenses prior to 2015, are reclassified to exploration expenses.

Note 4 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment triggers are identified. As of 30 September 2015 there has been a decrease in the forward prices compared to 30 June 2015, which is considered as an impairment trigger. The calculation shows that no impairment is needed for tangible assets, while technical goodwill is impaired as outlined below.

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. All impairment testing in Q3 2015 has been based on value in use. In the assessment of the value in use, 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.

For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 30 September 2015.

Oil and gas prices

Future price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on the management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil price is therefore based on the forward curve for the period Q4 2015 to the end of 2019. From 2020, the oil price is based on the company's long-term price assumptions.

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

Year	USD/BOE
2015	47.85
2016	52.53
2017	56.91
2018	59.31
2019	60.84
From 2020 (in real terms)	85.00

Oil and gas reserves

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

Discount rate

The discount rate is derived from the company's WACC. The capital structure considered in the WACC calculation is derived from the capital structures of an identified peer group and market participants with consideration given to optimal structures. The cost of equity is derived from the expected return on investment by the company's investors. The cost of debt is based on the interest-bearing borrowings on debt specific to the assets acquired. The beta factors are evaluated annually based on publicly available market data about the identified peer group.

Based on the above, the post tax nominal discount rate is set to 9.1 per cent.

Currency rates

As Det norske's functional currency changed to USD during 2014, the company is now exposed to exchange rate fluctuations between USD and non-USD cash flows with regard to the financial statements. In line with the methodology for future oil price, it has been concluded to apply the forward curve for the currency rate from Q4 2015 until the end of 2019, and the company's long term assumption from 2020 and onwards. This results in the following currency rates being applied in the impairment test for Q3 2015:

Year	NOK/USD
2015	8.48
2016	8.50
2017	8.47
2018	8.39
2019	8.33
From 2020	7.00

Inflation

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

Impairment testing of goodwill

For the purpose of impairment testing, goodwill acquired through business combinations have, before any impairment charges in Q3 2015, been allocated as follows:

Goodwill allocation (USD 1 000)

Remaining technical goodwill from the acquisition of Marathon Oil Norge AS as of 1 July 2015	803 091
Residual goodwill from the acquisition of Marathon Oil Norge AS	289 628
Remaining technical goodwill from other business combinations	41 212

Technical goodwill has been allocated to individual cash-generating units (CGUs) for the purpose of impairment testing. All fields tied in to the Alvheim FPSO are assessed to be included in the same cash-generating unit ("Alvheim CGU"). The residual goodwill from the acquisition is allocated to group of CGUs including all fields acquired from Marathon Oil Norge AS and all existing Det norske fields, as this mainly was related to tax and workforce synergies. The technical goodwill from previous business combinations are mainly allocated to Johan Sverdrup (USD 23 million) and Ivar Aasen (USD 8 million). The remaining technical goodwill from prior year business combinations is not significant in comparison to the total carrying amount of goodwill.

Impairment testing of residual goodwill

As mentioned above, residual goodwill is allocated across all CGUs for impairment testing. The combined recoverable amount exceeds the carrying amount by a substantial margin. Based on this, no impairment of residual goodwill has been recognized.

Impairment testing of technical goodwill from the acquisition of Marathon Oil Norge AS

The carrying value of the Alvheim CGU consists of the carrying values of the oilfield assets plus associated technical goodwill. In the impairment test performed, carrying value is adjusted by the remaining part of deferred tax from which the technical goodwill arose, to avoid an immediate impairment of all technical goodwill.

The carrying value of the Alvheim CGU is, in accordance with the above, calculated as follows:

(USD 1 000)
Carrying value of oilfield licences and fixed assets	2 167 839
+ Technical goodwill	803 091
- Deferred tax related to technical goodwill	-1 120 692
Net carrying value pre-impairment of goodwill	1 850 238

The impairment charge is the difference between the recoverable amount and the carrying value.

(USD 1 000) Net carrying value as specified above 1 850 238 Recoverable amount (including tax amortization benefit) 1 664 482 Impairment charge 185 756 Impairment charge 01.01. - 30.06.2015 52 773 Impairment charge 01.01. - 30.09.2015 238 529

As depicted in the table over carrying value above, deferred tax (from the date of acquisition) reduces the net carrying value prior to the impairment charges. When deferred tax from the Marathon acquisition decreases, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable. In Q3 2015 the impact from the decrease in deferred tax, together with an update of assumptions, have been the main reasons for the impairment charge of USD 185.8 million.

Sensitivity analysis

The table below shows how the impairment of goodwill allocated to the Alvheim CGU would be affected by changes in the various assumptions, given that the remainders of the assumptions are constant.

		Change in goodwill impairment after
Assumption (USD million)	Change	Increase in assumption	Decrease in assumption
Oil and gas price	+/- 20%	-185.8	304.2
Production profiles (reserves)	+/- 5%	-78.9	78.8
Discount rate	+/- 1% point	47.4	-50.1
Currency rate USD/NOK	+/- 1.0 NOK	3.9	-5.0
Inflation	+/- 1% point	-55.5	51.7

Impairment testing of technical goodwill from previous business combinations

No impairment charge of technical goodwill from other business combinations have been recognized in Q3 2015.

Note 5 Tangible assets and intangible assets

Tangible fixed assets (USD 1 000)	Assets under development	Production facilities including wells	Fixtures and fittings, office machinery	Total
Book value 31.12.2014	1 324 556	1 206 077	18 639	2 549 271
Acquisition cost 31.12.2014 Additions Reclassification	1 324 556 398 289 -452 953	1 856 371 51 023 452 963	35 684 5 854	3 216 612 455 167 9
Acquisition cost 30.06.2015 Accumulated depreciation and impairments 30.06.2015	1 269 893	2 360 357 848 977	41 538 19 109	3 671 788 868 085
Book value 30.06.2015	1 269 893	1 511 381	22 430	2 803 703
Acquisition cost 30.06.2015 Additions Reclassification*	1 269 892 205 334 -56 215	2 360 357 24 187 61 446	41 539 1 304	3 671 788 230 825 5 231
Acquisition cost 30.09.2015 Accumulated depreciation and impairments 30.09.2015	1 419 011	2 445 991 958 579	42 843 20 137	3 907 843 978 716
Book value 30.09.2015	1 419 011	1 487 412	22 706	2 929 128
Depreciation Q3 2015 Depreciation 01.01. - 30.09.2015		109 603 308 284	1 012 3 055	110 615 311 339

*An additional well on the Bøyla license entered into the production phase during Q3 2015 and the related costs are thus reclassified from fields under development to production facilities.

Acquisition cost and historical depreciation as of 31.12.2014 in the table above does not match the corresponding figures in the annual report 2014 as the foreign currency translation reserve from 2014 is no longer presented separately.

Capitalized exploration expenditures are reclassified to "Fields under development" when the field enters into the development phase. 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				Exploration
(USD 1 000)	Licences etc.	Software	Total	wells	Goodwill
Book value 31.12.2014	646 482	2 306	648 788	291 619	1 186 704
Acquisition cost 31.12.2014	712 237	9 064	721 301	291 619	1 556 468
Additions	2 467	21	2 487	27 363
Disposals/expensed dry wells				9 876
Reclassification				-9
Acquisition cost 30.06.2015	714 704	9 085	723 788	309 096	1 556 468
Acc. depreciation and impairments 30.06.2015	104 287	7 080	111 368		422 538
Book value 30.06.2015	610 416	2 004	612 421	309 096	1 133 930
Acquisition cost 30.06.2015	714 704	9 085	723 788	309 096	1 556 468
Additions				184
Disposals/expensed dry wells				-686
Reclassification	3 895		3 895	-9 126
Acquisition cost 30.09.2015	718 598	9 085	727 683	300 841	1 556 468
Acc. depreciation and impairments 30.09.2015	123 276	7 266	130 542		608 293
Book value 30.09.2015	595 322	1 818	597 140	300 841	948 175
Depreciation Q3 2015	18 989	186	19 175
Depreciation 01.01. - 30.09.2015	57 521	508	58 030
Impairments Q3 2015					185 756
Impairments 01.01. - 30.09.2015					238 529

Acquisition cost and historical depreciation as of 31.12.2014 in the table above does not match the corresponding figures in the annual report 2014 as the foreign currency translation reserve from 2014 is no longer presented separately.

See Note 4 for information regarding impairment charges.

	Q3		01.01.-30.09.
Depreciation in the Income statement (USD 1 000)	2015	2014	2015	2014
Depreciation of tangible fixed assets	110 615	27 710	311 339	54 958
Depreciation of intangible assets	19 175	370	58 030	1 113
Total depreciation in the Income statement	129 790	28 080	369 368	56 071

Note 6 Other operating expenses

Breakdown of other operating expenses	Q3		01.01.-30.09.
(USD 1 000)	2015	2014	2015	2014
Gross other operating expenses	34 046	31 398	106 928	108 722
Share of other operating expenses classified as exploration, development or
production expenses, and expenses invoiced to licences	-22 613	-30 405	-58 549	-94 007
Net other operating expenses	11 433	993	48 380	14 714

As mentioned in Note 1, the cost item presented as payroll prior to 2015, is now included in other operating expenses.

Note 7 Financial items

	Q3		01.01.-30.09.
(USD 1 000)	2015	2014	2015	2014
Interest income	184	1 856	1 359	5 421
Realised gains on derivatives	6 743		6 936
Return on financial investments		23	24	72
Change in fair value of derivatives	30 642	1 073	42 804	1 463
Currency gains	19 268	5 725	47 672	13 851
Total other financial income	56 653	6 821	97 436	15 386
Interest expenses	36 193	25 998	90 511	62 952
Capitalized interest cost, development projects	-18 735	-12 356	-46 001	-25 557
Amortized loan costs and accretion expenses	10 196	4 096	34 822	11 633
Total interest expenses	27 654	17 738	79 332	49 028
Currency losses		20 456		32 453
Realized loss on derivatives	4 166	626	49 299	2 708
Change in fair value of derivatives	40 819		44 234	526
Decline in value of financial investments	6		6
Total other financial expenses	44 991	21 082	93 538	35 688
Net financial items	-15 808	-30 143	-74 076	-63 909

Note 8 Taxes

	Q3		01.01.-30.09.
Taxes for the period appear as follows (USD 1 000)	2015	2014	2015	2014
Calculated current year tax/exploration tax refund	-8 956	-70 675	67 207	-138 695
Change in deferred taxes in the Income statement	68 400	-31 054	131 418	-46 729
Tax entered directly against the Income statement		-1 885
Prior period adjustments	-3		-4 560	-1 058
Tax expenses (+)/tax income (-)	59 441	-103 615	194 065	-186 482
Calculated tax receivable (+)/tax payable (-) (USD 1 000)		30.09.2015	30.09.2014	31.12.2014
Tax receivable/payable at 1.1.		-189 098	231 972	231 972
Current year tax (-)/tax receivable (+)		-67 431	138 695	581 667
Tax payable related to acquisition of Marathon Oil Norge AS				-910 332
Tax payment/tax refund		235 221		-81 464
Prior period adjustments		10 664		-528
Revaluation of tax payable		18 740		19 574
Foreign currency translation reserve*			-18 192	-29 988
Total tax receivable (+)/tax payable (-)		8 095	352 476	-189 098
Deferred taxes (-)/deferred tax asset (+) (USD 1 000)		30.09.2015	30.09.2014	31.12.2014
Deferred taxes/deferred tax asset 1.1.		-1 286 357	103 625	103 625
Change in deferred taxes in the Income statement		-131 418	58 858	-484 360
Deferred tax related to acquisition of Marathon Oil Norge AS				-911 363
Prior period adjustment		-6 104	1 058
Deferred tax related to impairment, disposal and licence transactions				14 938
Deferred tax charged to OCI and equity				4 999
Foreign currency translation reserve*			-9 118	-14 195
Total deferred tax (-)/deferred tax asset (+)		-1 423 879	154 422	-1 286 357

*Foreign currency translation reserve arose on the difference between average and currency rates at end of period applied when deriving USD from NOK amounts, as described in the accounting principles note in the annual report 2014.

	Q3		01.01.-30.09.
Reconciliation of tax expense (USD 1 000)	2015	2014	2015	2014
27% company tax on profit before tax	-28 821	-32 553	10 151	-48 258
51% special tax on profit before tax	-54 439	-61 489	19 174	-91 155
Tax effect of financial items - 27% only	72 818	15 882	144 174	29 221
Tax effect on uplift	-23 662	-13 171	-71 107	-32 143
Interest of tax losses carry forward		-1 913		-4 234
Permanent difference - impairment of goodwill	144 889	-92	186 052	-38 815
Foreign currency translation of NOK monetary items	-18 753		-32 447
Foreign currency translation of USD monetary items	-123 887		-206 083
Revaluation of tax balances**	94 335		145 958
Other items (other permanent differences and previous period adjustment)	-3 039	-10 279	-1 808	-1 099
Total taxes (+)/tax income (-)	59 441	-103 615	194 065	-186 482

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

In accordance with statutory requirements, the calculation of current tax is required to be based on NOK currency. This may impact the tax rate when the functional currency is different from NOK. The main factor in the first nine months of 2015 is the foreign exchange losses of the USD loans, which is a taxable loss without any corresponding impact on profit before tax.

The revaluation of tax 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

(USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Shares in Alvheim AS	10		10
Shares in Det norske oljeselskap AS	1 021
Shares in Sandvika Fjellstue AS	1 814	1 860	1 814
Investment in subsidiaries	2 845	1 860	1 824
Debt service reserve		42 374
Tenancy deposit	1 551	2 008	1 774
Total other non-current assets	4 396	46 242	3 598

Det norske oljeselskap AS was previously named Marathon Oil Norge AS. This company was consolidated in the group accounts for Q4 2014 but is deemed immaterial from 2015 as all activity in previously Marathon Oil Norge AS was transferred to the company during Q4 2014.

Note 10 Other short-term receivables

(USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Receivables related to deferred volume at Atla*	6 660	8 135	5 866
Pre-payments, including rigs	35 757	46 249	41 682
VAT receivable	7 472	3 809	7 986
Underlift of petroleum	17 755	4 922	22 896
Accrued income from sale of petroleum products	25 084
Other receivables, including operated licences	21 322	93 782	106 162
Total other short-term receivables	114 049	156 897	184 592

*For information about receivables related to deferred volume at Atla, see Note 11.

Note 11 Long-term receivables

(USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Receivables related to deferred volume at Atla	4 440	12 203	8 799
Total long-term receivables	4 440	12 203	8 799

The physical production volumes from Atla were higher than the commercial production volumes. This was caused by the high pressure from the Atla field which temporarily stalled the production from the neighbouring field Skirne. The Skirne partners have therefore historically received and sold oil and gas from Atla, but from 2014 they started to deliver oil and gas back to the Atla partners. Revenue was recognized based on physical production volumes measured at market value, similar to over/underlift. This deferred compensation is recorded as long-term or short-term receivables, depending on when the deliverance of oil and gas is expected, see also Note 10.

Note 12 Cash and cash equivalents

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

Breakdown of cash and cash equivalents (USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Bank deposits	203 323	443 126	291 346
Restricted funds (tax withholdings)	3 618	1 723	4 897
Cash and cash equivalents	206 941	444 849	296 244
Unused revolving credit facility (see Note 18)	550 000
Unused exploration facility loan		142 706
Unused reserve-based lending facility (see Note 18)	985 964	580 000	593 000

Note 13 Share capital

(USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Share capital	37 530	37 530	37 530
Total number of shares (in 1 000)	202 619	202 619	202 619
Nominal value per share in NOK	1.00	1.00	1.00

Note 14 Derivatives

(USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Unrealized gain on commodity derivatives	5 768
Long-term derivatives included in assets	5 768
Unrealized gain on commodity derivatives	18 786
Short-term derivatives included in assets	18 786
Total derivatives included in assets	24 553
Unrealized losses currency contracts	2 889
Unrealized losses interest rate swaps	44 281	6 966	5 646
Long-term derivatives included in liabilities	47 170	6 966	5 646
Unrealized losses currency contracts	9 590		25 224
Unrealized losses interest rate swaps	301
Short-term derivatives included in liabilities	9 891		25 224
Total derivatives included in liabilities	57 061	6 966	30 870

The company has different types of hedging instruments. The commodity derivatives are used to hedge the risk of oil price reduction. The company 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. Currently all these derivatives are marked to market with changes in market value recognized in the Income statement.

Note 15 Accounts receivable

(USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Receivables related to sale of petroleum Receivables related to licence transaction	62 945	7 424 1 080	182 384 285
Invoicing related to expense refunds including rigs	787	682	3 792
Other	329
Total accounts receivable	64 061	9 187	186 461

Note 16 Other current liabilities

Breakdown of other current liabilities (USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Current liabilities related to overcall in licences	52 416	28 013	195
Share of other current liabilities in licences	156 576	104 718	163 369
Overlift of petroleum	12 615	302	7 508
Fair value of contracts assumed in acquisition of Marathon Oil Norge AS*	17 837		22 903
Other current liabilities**	92 273	68 317	79 838
Total other current liabilities	331 718	201 351	273 813

*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 balance was split between current and non-current liabilities based on the cash flows in the contract, and amortized over the lifetime of the contract, which ends in 2016.

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

Note 17 Bond

(USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Principal, bond Nordic Trustee 1)	216 415	291 875	253 141
Principal, bond Nordic Trustee 2)	294 654
Total bond	511 070	291 875	253 141

1) The loan is denominated in NOK and runs from July 2013 to July 2020 and carries an interest rate of 3 month NIBOR + 5 per cent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The loan is unsecured. In April 2015, the bondholders approved certain requested amendments to the bond. The changes involved removal of the Adjusted Equity Ratio covenant, and inclusion of two new financial covenants to align the covenants on this bond with the covenants on the reserve-based lending facility. As compensation for approval, the bondholders received an increased interest by 1.5 per cent, to 3 month NIBOR plus 6.5 per cent, in addition to a one-time consent fee of 2.0 per cent (flat).

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

Note 18 Other interest-bearing debt

(USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Reserve-based lending facility	1 842 425		2 037 299
Revolving credit facility		405 433
Total other interest-bearing debt	1 842 425	405 433	2 037 299

The RBL Facility is a senior secured seven-year USD 3.0 billion facility and includes an additional uncommitted accordion option of USD 1.0 billion. 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.

At the end of June 2015 the company completed a semi-annual redetermination process with its bank consortium. The new borrowing base availability under the facility has been increased to USD 2.9 billion, up from USD 2.7 billion at the end of 2014.

A revolving credit facility ("RCF") of USD 550 million was also completed with a consortium of banks at June 30. 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 2.2 per cent is paid on unused credit. Covenants are the same as for the company's RBL.

Note 19 Provision for abandonment liabilities

(USD 1 000)	30.09.2015	30.09.2014	31.12.2014
Provisions as of 1 January	489 051	160 413	160 413
Removal obligation from acquisition of Marathon Oil Norge AS			340 897
Incurred cost removal	-8 768	-12 608	-14 087
Accretion expense - present value calculation	19 605	6 118	12 410
Foreign currency translation reserve*		-8 820	-10 674
Change in estimates and incurred liabilities on new fields	10 411		93
Total provision for abandonment liabilities	510 299	145 102	489 051
Break down of the provision to short-term and long-term liabilities
Short-term	3 758	15 773	5 728
Long-term	506 541	129 329	483 323
Total provision for abandonment liabilities	510 299	145 102	489 051

The company's removal and decommissioning liabilities relates mainly to the producing fields.

The company has recognized the first abandonment liabilities on the Ivar Aasen field, as the jackets were installed during second quarter 2015.

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 3.89 per cent and 5.69 per cent.

*Foreign currency translation reserve arose on the difference between average and currency rates at end of period applied when deriving USD from NOK amounts at 15 October 2014, as described in the accounting principles note in the annual report 2014.

Note 20 Contingent liabilities

During the normal course of its business, the company will be involved in disputes, including tax disputes. The company has made accruals for probable liabilities related to litigation and claims based on the management's best judgment and in line with IAS 37. The Management is of the opinion that none of the disputes will lead to significant commitments for the company.

Note 21 Subsequent events

The company has identified the following events that have occurred between the end of the reporting period and the date of this report.

Acquisition of Svenska Petroleum Exploration AS

On 14 October 2015 Det norske announced that it has entered into an agreement to acquire Svenska Petroleum Exploration AS for a cash consideration of USD 75 million on a cash free, debt free basis. The transaction will be funded through existing cash and undrawn debt facilities. The transaction will have tax effect from the fiscal year 2015, and is expected to close in the fourth quarter 2015, subject to regulatory approval.

Note 22 Investments in joint operations

Fields operated:	30.09.2015		31.12.2014 Fields non-operated:	30.09.2015	31.12.2014
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 %	N/A
Vilje	46.904 %	46.904 % Jotun		7.000 %	7.000 %
Volund	65.000 %	65.000 % Varg		5.000 %	5.000 %
Production licences in which Det norske is the operator:			Production licences in which Det norske is a partner:
Licence:	30.09.2015	31.12.2014 Licence:		30.09.2015	31.12.2014
PL 001B	35.000 %	35.000 % PL 019C		30.000 %	30.000 %
PL 026B	62.130 %	62.130 % PL 019D		30.000 %	30.000 %
PL 027D	100.000 %	100.000 % PL 029B		20.000 %	20.000 %
PL 027ES *	0.000 %	40.000 % PL 035		25.000 %	25.000 %
PL 028B	35.000 %	35.000 % PL 035B		15.000 %	15.000 %
PL 036C	65.000 %	65.000 % PL 035C		25.000 %	25.000 %
PL 036D	46.904 %	46.604 % PL 038		5.000 %	5.000 %
PL 088BS	65.000 %	65.000 % PL 038D		30.000 %	30.000 %
PL 103B	70.000 %		70.000 % PL 038E	5.000 %	5.000 %
PL 150	65.000 %	65.000 % PL 048B		10.000 %	10.000 %
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 340	65.000 %	65.000 % PL 265		20.000 %	20.000 %
PL 340BS	65.000 %	65.000 % PL 272		25.000 %	25.000 %
PL 364	50.000 %	50.000 % PL 362		15.000 %	15.000 %
PL 460	100.000 %	100.000 % PL 438		10.000 %	10.000 %
PL 494	30.000 %	30.000 % PL 442		20.000 %	20.000 %
PL 494B	30.000 %	30.000 % PL 457		40.000 %	40.000 %
PL 494C	30.000 %		30.000 % PL 457BS	40.000 %	40.000 %
PL 504	47.593 %	47.593 % PL 492		40.000 %	40.000 %
PL 504BS *	0.000 %	83.571 % PL 502		22.222 %	22.222 %
PL 504CS *	0.000 %		21.814 % PL 522 *	0.000 %	10.000 %
PL 553 *	0.000 %		40.000 % PL 533 ***	35.000 %	20.000 %
PL 626	50.000 %	50.000 % PL 550		10.000 %	10.000 %
PL 659	20.000 %	20.000 % PL 551		20.000 %	20.000 %
PL 663	30.000 %	30.000 % PL 554		10.000 %	10.000 %
PL 677	60.000 %	60.000 % PL 554B		10.000 %	10.000 %
PL 709	40.000 %	40.000 % PL 554C		10.000 %	10.000 %
PL 715	40.000 %	40.000 % PL 558 *		0.000 %	20.000 %
PL 724	40.000 %	40.000 % PL 567		40.000 %	40.000 %
PL 724B **	40.000 %	0.000 % PL 574		10.000 %	10.000 %
PL 736S	65.000 %	65.000 % PL 613		20.000 %	20.000 %
PL 748	40.000 %	40.000 % PL 619 *		0.000 %	30.000 %
PL 777 **	40.000 %	0.000 % PL 627		20.000 %	20.000 %
PL 790 **	50.000 %		0.000 % PL 627B **	20.000 %	0.000 %
Number	34		35 PL 653	30.000 %	30.000 %
			PL 667 *	0.000 %	30.000 %
* Relinquished licences or Det norske has withdrawn from the licence.			PL 672	25.000 %	25.000 %
			PL 676BS *	0.000 %	0.000 %
** Interest awarded in the APA Licensing round (Application in Predefined			PL 676S *	0.000 %	10.000 %
Areas) in 2014. The awards were announced in 2015.			PL 678BS	25.000 %	25.000 %
			PL 678C **	25.000 %	0.000 %
*** Acquired/changed through licence transactions or licence splits.			PL 678S	25.000 %	25.000 %
			PL 681	16.000 %	16.000 %
**** According to a ruling by Ministry of Oil and Energy.			PL 694 **	20.000 %	0.000 %
			PL 706 *	0.000 %	20.000 %

PL 730 30.000 % 30.000 % PL 730B 30.000 % 0.000 % PL 778 ** 20.000 % 0.000 % PL 804 ** 30.000 % 0.000 % Number 46 46

Note 23 Results from previous interim reports

		2015			2014			2013
	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Total operating revenues	280 996	337 236	324 178	345 670	18 334	74 304	25 923	43 279
Exploration expenses	18 066	24 949	14 523	51 491	71 778	21 027	20 040	95 472
Production costs	26 888	50 686	39 349	44 400	7 906	7 417	7 032	16 607
Depreciation	129 790	117 354	122 224	104 183	28 080	13 443	14 548	21 103
Impairments	185 756		52 773	319 018			27 402	111 893
Other operating expenses	11 433	22 550	14 397	10 679	993	12 896	825	-685
Total operating expenses	371 932	215 539	243 266	529 772	108 757	54 782	69 847	244 391
Operating profit/loss	-90 936	121 697	80 912	-184 102	-90 423	19 522	-43 924	-201 112
Net financial items	-15 808	-58 523	254	-12 788	-30 143	-23 865	-9 901	-18 011
Profit/loss before taxes	-106 744	63 174	81 166	-196 889	-120 567	-4 343	-53 824	-219 123
Taxes (+)/tax income (-)	59 441	55 897	78 727	89 997	-103 615	-31 627	-51 240	-163 202
Net profit / loss	-166 185	7 277	2 439	-286 887	-16 952	27 284	-2 584	-55 921

Financial figures from quarters prior to the change in functional currency have been converted to USD by yearly average currency rate for 2013 and nine months average for the three first quarters in 2014.

NOTES