Aker BP

Quarterly Report • Apr 30, 2014

First quarter report

Trondheim, April 30, 2014

Table of contents

First quarter summary
Summary of financial results and operating performance
Financials
Field performance and oil prices
Health, safety and the environment
PDO approved projects
Other projects
Exploration
Business development
Other issues
Events after the quarter
Outlook
Financial Statements

Report for the first quarter 2014

First quarter summary

(All figures in brackets apply to the first quarter 2013)

Det norske oljeselskap ASA ("Det norske" or "the company") reported revenues of NOK 158 (80) million in the first quarter. Exploration expenses amounted to NOK 110 (234) million, contributing to an operating loss of NOK 101 (251) million. Net financial expenses were NOK 60 (32) million. Net result for the first quarter was NOK 21 (-20) million, following a tax income of NOK 182 (262) million.

Det norske's four producing assets – Jette, Atla, Varg and Jotun – produced 2,895 boepd on average during the quarter, with about half of this coming from Jette. The average realized oil price was USD 107 (112) per barrel.

The Ivar Aasen development project, where Det norske is operator with a 35 percent interest, is on schedule. Fabrication has commenced on the living quarters at Stord, the jacket in Sardinia and the topside in Singapore.

On the Johan Sverdrup project, the formal partner decision to pass Decision Gate 2 (DG2) was made. The plan is to submit a Plan for Development and Operations (PDO) that can be approved by the Norwegian Parliament in the first half of 2015, with first oil production in late 2019. The pre-unit operator Statoil has estimated gross field contingent resources in the range of 1,800 to 2,900 million barrels of oil equivalents. In the first quarter, an appraisal well on Geitungen encountered a gross oil column of six metres and subsequently a sidetrack well was drilled approximately 1 km to the southwest.

Additionally, Det norske participated in the drilling of two wildcat exploration wells in the quarter. On the Trell prospect in the North Sea, a small oil discovery was made. The Langlitinden prospect in the Barents Sea encountered oil-bearing channel sands, but Det norske deems the discovery non-commercial.

Key events during the first quarter 2014

• On 27 March, Det norske announced that the appraisal well in the Geitungen part of the Johan Sverdrup field encountered oil believed to represent the Statfjord formation. A planned sidetrack was also announced (see events after the quarter).
• On 21 March, Det norske's Corporate Assembly re-elected Tom Røtjer and elected Gro Kielland as members of the Board of Directors.
• On 21 February, Det norske announced a small oil discovery at the Trell prospect in PL 102F in the North Sea.
• On 21 February, Det norske announced that well 7222/11-2 encountered sub-commercial volumes in the Langlitinden prospect in PL 659 in the Barents Sea.
• On 13 February, pre-unit operator Statoil provided an update on the concept selection for Johan Sverdrup. The field will be developed in multiple phases and full field production capacity is expected to be in the range 550,000 to 650,000 barrels of oil equivalents
• On 21 January, Det norske announced that Gro G. Haatvedt had been appointed as the new SVP Exploration in Det norske. She comes from the job as SVP Exploration for the NCS in Statoil.
• On 21 January, Det norske was awarded six new licenses in the APA 2013, of which two as operator.
• On 2 January, Det norske announced oil discoveries in two targets at Askja in PL 272. Exploration well 30/11-9 S encountered a 90 metre gas column and appraisal well 30/11-9 A encountered a 40 metre oil column.

Key events after the quarter

The Geitungen sidetrack encountered a 12-metre oil-bearing interval of medium good reservoir.

Summary of financial results and operating performance

MNOK= NOK million	Q1 14	Q4 13	Q3 13	Q2 13	Q1 13	2013
Jette (boepd), 70%	1 458	2 710	4 378	3 594	0	2 683
Atla (boepd), 10%	750	1 031	981	1 446	1 253	1 177
Varg (boepd), 5%	500	412	377	398	425	403
Glitne (boepd), 10%	0	0	0	0	43	11
Enoch (boepd), 2%	0	0	0	0	0	0
Jotun Unit (boepd), 7%	188	175	204	175	209	191
Total production (boepd)	2 895	4 328	5 940	5 613	1 929	4 463
Oil and gas production (Kboe)	261	398	547	511	174	1 629
Oil price realised (USD/barrel)	107	109	112	103	112	107
Operating revenues (MNOK)	158	254	324	286	80	944
EBITDA (MNOK)	-12	-400	-348	-127	-216	-1 091
Cash flow from production (MNOK)	112	151	269	227	37	684
Exploration expenses (MNOK)	110	544	588	271	234	1 637
Total exploration expenditures (expensed and capitalised) (MNOK)	151	400	581	373	306	1 659
Operating loss (MNOK)	-101	-1 182	-518	-277	-251	-2 227
Net profit/loss(-) for the period (MNOK)	21	-329	-158	-41	-20	-548
No of licences (operatorships)	77 (27)	80 (33)	74 (30)	72 (30)	69 (28)	80 (33)

Financials

First quarter accounts

Operating revenues in the first quarter was NOK 158 (80) million. The main cause of increase is that Jette commenced production in the second quarter 2013. Production in the quarter increased by 50 percent from 1,929 barrels of oil equivalents per day (boepd) in the first quarter 2013 to 2,895 boepd this quarter. Jette accounted for 1,458 (0) boepd and Atla for 750 (1,253) boepd.

Exploration expenses amounted to NOK 110 (234) million. The company expensed costs relating to the Langlitinden well in PL 659 as well as other exploration costs.

The operating loss decreased to NOK 101 (251) million, as revenues increased and exploration expenses decreased.

Net financial expenses in the first quarter amounted to NOK 60 (32) million.

The net profit/(loss) for the period was NOK 21 (-20) million after a tax income of NOK 182 (262) million. This translates to a tax rate of 113 percent due to uplift, a special income deduction in the basis for calculation of petroleum tax, on previous years' investments.

Net cash flow from operating activities was NOK -489 (-267) million. Net cash flow from investment activities amounted to NOK -707 (-699) million, mainly caused by investments in fields under development. Net cash flow from financing activities totalled NOK 308 (548) million as the company had net withdrawal of debt.

The company's cash and cash equivalents amounted to NOK 821 (736) million as of 31 March. Tax receivables for disbursement in December 2014 amounted to NOK 1,417 (1,278) million and tax receivable for disbursement in December 2015 amounted to NOK 148 (261) million.

The equity ratio as of 31 March was 30.6 (42.3) percent. Discoveries and fields under development contributed to a total asset balance of NOK 10,504 (8,794) million as of 31 March.

Field performance and oil prices

Det norske produced 260,569 barrels of oil equivalents (boe) in the first quarter of 2014. This corresponds to 2,895 (1,929) boepd.

The average realized oil price was USD 107 (112) per barrel, while gas revenues were recognised at market value of NOK 2.3 (2.3) per standard cubic metre (scm).

Jette (70 percent operator) came on stream in May 2013 and produced 1,458 boepd net on average in the first quarter, accounting for 50 percent of total production. During March, Jette's main producer was shut for 10 days and the other well for four days. This was to test whether more optimal production could be achieved by producing one well at a time in order to reduce watercut and allow pressure build-up. For the time being, it has proved more effective to continue to produce from both wells simultaneously. Into the second quarter, the Jette field has had stable operations from both wells.

Atla (10 percent partner) produced 750 (1,253) boepd net on average in the first quarter and accounted for 26 percent of the total production. Atla's production was somewhat restricted in January and February 2014 due to priority to the Skirne field, but was stable in March.

Varg (5 percent partner) produced 500 (425) boepd net to Det norske in the first quarter, or 17 percent of total production. Gas export commenced from the field in early February 2014. The gas is exported through the Rev gas field to the Armada platform and transported to the UK via the CATS pipeline.

The average production rate on Jotun (7% partner) was 188 (209) boepd net to Det norske in the first quarter, which represented about 6 percent of total production. Production remained stable during the quarter.

Health, safety and the environment

The company is devoted to securing that all its projects are developed under the highest HSE standards in the oil industry.

During the first quarter, Det norske drilled the PL 659 Langlitinden exploration well in the Barents Sea. One notification was made to the Petroleum Safety Authority to inform that Det norske had to leave a radioactive source in the well as it got stuck and was not possible to retrieve. The Environmental Directorate carried out an audit of Det norske during the drilling operations, without finding any deviations.

In February 2014, the Ivar Aasen project experienced a near-miss hazardous situation with a dropped object at a yard on contract with Det norske. Det norske has investigated the incident and measures have been implemented.

PDO approved projects

Ivar Aasen – PL 001B/242/028B (35 percent, operator)

The Ivar Aasen field development project is progressing according to schedule towards planned start up in Q4 2016.

Ivar Aasen is being developed with a steel jacket platform. The topside will include living quarters and a processing facility for first stage separation. The detailed engineering for the topside is being carried out by Mustang Engineering outside London, UK. First steel cutting for jacket and topside fabrication was performed in November 2013 and in March 2014 for the living quarter.

In December 2012, the partners in PL 457 encountered oil in the 16/1-16 and 16/1-16A wells. PL 457 is located adjacent and to the east of Ivar Aasen. The Ivar Aasen partners have signed a pre-unitization agreement with the partners in PL 457. The agreement allows for a coordinated development of the discoveries and sets out principles for the work processes towards an initial unitization split. The unitization agreement is progressing according to plan and will be finalized by June 2014. This will reduce Det norske's total ownership in the enlarged field.

Gina Krog – PL 029B/029C/048/303 (3.3 percent partner)

The Gina Krog field is progressing according to schedule with planned start up in 2017.

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.

Other projects

Johan Sverdrup – PL 265 (20 percent, partner) & PL 502 (22.22 percent, partner)

Statoil, as the pre-unit operator on the Johan Sverdrup field, announced the key parts of the field concept selection in February 2014, as Decision Gate 2 (DG2) for the first development phase was passed in the Johan Sverdrup preunit partnership. The concept for future phases will be decided in a separate process after the phase 1 PDO.

Statoil communicated full field production capacity is expected to be in the range 550,000 to 650,000 barrels of oil equivalents and gross field recoverable contingent resources between 1,800 and 2,900 million barrels oil equivalents. Total investments for the first phase are estimated to be between NOK 100 and 120 billion, including contingencies and provisions for market adjustments. Phase 1 has capacity to produce more than 70% of the resources.

The plan is to submit a Johan Sverdrup PDO to the authorities by the first quarter of 2015, with first oil expected in the fourth quarter of 2019. A unitization negotiation process has commenced between the Johan Sverdrup licensees and will be finalised at the same time as the PDO.

During the first quarter an appraisal well (16/2-19) was drilled on Geitungen on the northern margin of the Johan Sverdrup field in PL 265. The well encountered six metres of oil-bearing sandstone of medium to good quality assumed to constitute part of the Statfjord group. The well was drilled to a vertical depth of 2,024 metres and was terminated in basement rocks. Following this, the partnership decided to drill a sidetrack well approximately 1 km to the southwest with the objective to clarify the northern extent of the Johan Sverdrup main reservoir of the Draupne formation sandstones.

Exploration

During the quarter, the company's cash spending on exploration was NOK 151 million, of which NOK 110 million was recognised as exploration expenses.

Trell – PL 102F (10 percent, partner)

Drilling of exploration well 25/5-9 on the Trell prospect in the North Sea was completed in February this year. The well encountered a gross oil column of 21 meters in the Heimdal formation, of which 19 meters had good reservoir quality. Basic data acquisition and sampling indicate very good production properties, in line with expectations.

Preliminary estimates indicate between 0.5 and 2.0 million standard cubic meters of recoverable oil. The licensees will evaluate the discovery together with other nearby prospects and consider further follow-up.

Langlitinden – PL 659 (20 percent, operator)

Drilling of exploration well 7222/11-2 on the Langlitinden prospect in the Barents Sea was completed in February this year. The well encountered an oil-bearing channel sand of Triassic age. Extensive data sampling, including cores, wireline logs and fluid samples have been performed.

Hydrocarbons were proved in the main target for the well, but a mini-drillstem test proved poor reservoir properties. Det norske is of the opinion that the volumes proven in this well, as of today, are insufficient to justify a field development.

APA 2013

In the Awards in Predefined Areas (APA) 2013, Det norske was awarded six new licenses, of which two as operator. All six licenses are located in the North Sea.

New SVP Exploration

In January 2014, Gro Haatvedt accepted an offer to become Senior Vice President Exploration in Det norske oljeselskap ASA. Haatvedt was previously Senior Vice President for Exploration on the Norwegian Continental Shelf in Statoil.

Business development

As part of a continuous program to optimise its portfolio, Det norske relinquishes exploration licenses, and farms in and out of licenses on a regular basis.

In the fourth quarter 2013, Det norske entered into an agreement with Atlantic Petroleum Norge AS concerning the sale of a 10 percent interest in PL 659 in the Barents Sea. The licence contains the Langlitinden prospect, which drilled in the first quarter. Det norske is the operator and holds 20 percent in the license following the transaction. As compensation, Atlantic Petroleum carried part of Det norske's drilling costs related to the exploration well.

Other issues

Det norske's Corporate Assembly in March re-elected Tom Røtjer as member of the Board of Directors and elected Gro Kielland, formerly CEO of BP Norway, as new member of the Board of Directors in replacement of Maria Moræus Hanssen, who resigned from the Board of Directors in the autumn of 2013.

Events after the quarter

In the Geitungen sidetrack well, a 12-metre oil-bearing sandstone / siltstoneinterval of medium good reservoir development was encountered in the Draupne formation. The well was drilled to a vertical depth of 1 971 metres and was terminated in basement rocks. Extensive data acquisition and sampling have been carried out in both wells. The well results will be incorporated into the Johan Sverdrup field development work.

The General Assembly in April gave the Board of Directors an authorisation to increase the share capital, in one or more rounds, by a total of up to NOK 14,070,730. The Board of Directors were also authorised to acquire up to NOK 14,070,736 in treasury shares. The mandates are valid to the ordinary general meeting in 2015, but no later than June 30, 2015.

Outlook

Ivar Aasen and Johan Sverdrup are the most important field development projects for Det norske and both projects are progressing according to plan. Unitisation negotiations for the Ivar Aasen field and the Johan Sverdrup field are ongoing.

Det norske has strong growth ambitions, which will require large investments. Over the past two years, the company has both strengthened its equity position and secured new debt. These steps have been taken to ensure a solid financial basis for the company's field development projects. Given the funding requirements of the company arising in the medium term, the Board is committed to securing the optimum financing structure for the company.

Based on current plans, Det norske will participate in around 10 exploration wells through 2014.

			Q1		1.1 - 31.03			Q1	1.1 - 31.03
(All figures in NOK 1,000)	Note	2014	2013	2014	2013	(All figures in NOK 1,000)	2014	2013	2014	2013
Petroleum revenues	2	155 101	78 709	155 101	78 709	Profit/loss for the period	21 039	-20 326	21 039	-20 326
Other operating revenues	2	3 241	1 630	3 241	1 630
						Total comprehensive
Total operating revenues		158 342	80 339	158 342	80 339	income in period	21 039	-20 326	21 039	-20 326
Exploration expenses	3	109 582	233 738	109 582	233 738
Production costs		42 949	41 512	42 949	41 512
Payroll and payroll-related expenses	5	4 559	1 527	4 559	1 527
Depreciation	4	88 863	34 997	88 863	34 997
Other operating expenses	5	13 305	19 208	13 305	19 208
Total operating expenses		259 258	330 983	259 258	330 983
Operating profit/loss		-100 917	-250 644	-100 917	-250 644
Interest income	6	12 145	7 202	12 145	7 202
Other financial income	6	34 663	20 602	34 663	20 602
Interest expenses	6	86 753	12 748	86 753	12 748
Other financial expenses	6	20 530	47 153	20 530	47 153
Net financial items		-60 475	-32 097	-60 475	-32 097
Profit/loss before taxes		-161 392	-282 741	-161 392	-282 741
Taxes (+)/tax income (-)	7	-182 431	-262 415	-182 431	-262 415
Net profit/loss		21 039	-20 326	21 039	-20 326
Weighted average no. of shares outstanding		140 707 363	140 707 363	140 707 363	140 707 363
Weighted average no. of shares fully diluted		140 707 363	140 707 363	140 707 363	140 707 363
Earnings/(loss) after tax per share		0,15	-0,14	0,15	-0,14
Earnings/(loss) after tax per share fully diluted		0,15	-0,14	0,15	-0,14

STATEMENT OF INCOME (Unaudited) TOTAL COMPREHENSIVE INCOME (Unaudited)

	Q1	1.1 - 31.03
Total comprehensive income in period

STATEMENT OF FINANCIAL POSITION

ASSETS					EQUITY AND LIABILITIES
Intangible assets					Paid-in capital
Other intangible assets	4	643 050	660 581	646 299
Deferred tax asset	7	664 850		630 423
Tangible fixed assets
Property, plant, and equipment	4	3 703 657	2 486 607	2 657 566	Retained earnings
Financial assets
Calculated tax receivables	7	148 004	261 139
Other non-current assets	8	282 472	200 559	285 399
Total non-current assets		7 456 579	6 311 395	6 722 340	Provisions for liabilities
Receivables					Non current liabilities
Calculated tax receivables	7	1 416 550	1 278 297	1 411 251
					Current liabilities

		(Unaudited)		(Audited)			(Unaudited)		(Audited)
(All figures in NOK 1,000)	Note	31.03.2014	31.03.2013	31.12.2013	(All figures in NOK 1,000)	Note	31.03.2014	31.03.2013	31.12.2013
ASSETS					EQUITY AND LIABILITIES
Intangible assets					Paid-in capital
Goodwill	4	321 120	387 551	321 120	Share capital	12	140 707	140 707	140 707
Capitalised exploration expenditures	4	1 555 348	2 247 718	2 056 100	Share premium		3 089 542	3 089 542	3 089 542
Other intangible assets	4	643 050	660 581	646 299
Deferred tax asset	7	664 850		630 423
					Total paid-in equity		3 230 249	3 230 249	3 230 249
Tangible fixed assets
Property, plant, and equipment	4	3 703 657	2 486 607	2 657 566	Retained earnings
					Other equity		-20 741	485 600	-41 780
Financial assets
Long term receivables	10	138 078	67 240	125 432	Total Equity		3 209 509	3 715 849	3 188 470
Calculated tax receivables	7	148 004	261 139
Other non-current assets	8	282 472	200 559	285 399
Total non-current assets		7 456 579	6 311 395	6 722 340	Provisions for liabilities
					Pension obligations		36 375	54 625	66 512
					Deferred taxes	7		125 113
Inventories					Abandonment provision	19	829 720	867 895	828 529
Inventories		39 549	21 059	40 880	Provisions for other liabilities		696	325	780
Receivables					Non current liabilities
Account receivables	14	128 239	86 452	134 221	Bonds	17	2 475 559	589 939	2 473 582
Other short term receivables	9	617 286	337 720	499 419	Other interest-bearing debt	18	2 150 288	1 453 035	2 036 907
Short-term deposits		24 375	23 625	24 075	Derivatives	13	48 228	48 693	49 453
Calculated tax receivables	7	1 416 550	1 278 297	1 411 251
					Current liabilities
Cash and cash equivalents					Short-term loan	15	680 794	969 819	478 050
Cash and cash equivalents	11	821 069	735 706	1 709 166	Trade creditors		218 370	230 398	452 435
					Accrued public charges and indirect taxes		24 457	18 881	23 579
Total current assets		3 047 067	2 482 859	3 819 011	Abandonment provision	19	156 397		147 375
					Other current liabilities	16	673 254	719 684	795 680
					Total liabilities		7 294 137	5 078 405	7 352 882
TOTAL ASSETS		10 503 646	8 794 255	10 541 352	TOTAL EQUITY AND LIABILITIES		10 503 646	8 794 255	10 541 352

STATEMENT OF CHANGES IN EQUITY(Unaudited)

				Ot he ity r e q u
				Ot he r c om
			Ot he id- in r p a	he ive p re ns	Re ine d ta	To l o he ta t r
( All fig in N O K 1 ) 00 0 ure s ,	S ha ita re ca p	l S ha ium re p rem	ita l ca p	inc om e	rni ea ng s	ity eq u	To l e ity ta q u
Eq ity f 3 1.1 2.2 01 2 u as o	14 0 7 07	3 0 8 9 5 42	3 6 00 10 7	-2 188	-3 09 1 9 94	5 05 9 26	3 7 3 6 1 75
for To l lo 20 13 ta ss				89 4	-54 8 6 00	-54 7 7 06	-54 7 7 06
Eq ity f 3 1.1 2.2 01 3 u as o	14 0 7 07	3 0 8 9 5 42	3 6 00 10 7	-1 29 4	-3 64 0 5 94	-41 78 0	3 1 8 8 4 6 9
Pro fit / los for he io d 1 .1. 20 14 - 3 1.0 3.2 01 4 t s p er					21 03 9	21 03 9	21 03 9
Eq ity f 3 1.0 3. 20 14 u as o	14 0 7 07	3 0 8 9 5 42	3 6 00 10 7	-1 29 4	-3 61 9 5 55	-20 74 1	3 20 9 5 0 9

STATEMENT OF CASH FLOW (Unaudited)

		Q1		Year
(All figures in NOK 1,000)	Note	2014	2013	2013
Cash flow from operating activities
Profit/loss before taxes		-161 392	-282 741	-2 545 327
Taxes paid during the period				-26 585
Tax refund during the period				1 318 430
Depreciation	4	88 863	34 997	470 529
Net impairment losses				666 135
Accretion expenses	19	12 920	9 924	42 765
Losses on sale of license				734
Changes in derivatives	6	-2 383	2 708	3 174
Amortization of interest expenses and arrangement fee	6	10 064	9 291	88 458
Expensed capitalized dry wells	3,4	73 601	163 563	1 150 541
Changes in inventories, accounts payable and receivables		-226 752	-12 661	141 786
Changes in other current balance sheet items		-283 796	-191 924	-394 934
Net cash flow from operating activities		-488 876	-266 843	915 707
Cash flow from investment activities
Payment for removal and decommissioning of oil fields	19	-2 706	-2 056	-36 739
Disbursements on investments in fixed assets	4	-589 611	-461 186	-1 495 709
Disbursements on investments in capitalised exploration expenditures and other intangible assets	4	-114 942	-236 007	-1 358 941
Sale/farmout of tangible fixed assets and licenses				86 472
Net cash flow from investment activities		-707 260	-699 249	-2 804 917
Cash flow from financing activities
Repayment of short-term debt	15			-1 500 000
Repayment of long-term debt	17,18	-290 927		-2 185 102
Proceeds from issuance of long-term debt	17,18	398 966	147 616	4 729 297
Proceeds from issuance of short-term debt	15	200 000	400 000	1 400 000
Net cash flow from financing activities		308 039	547 616	2 444 195
Net change in cash and cash equivalents		-888 097	-418 476	554 985
Cash and cash equivalents at start of period	11	1 709 166	1 154 182	1 154 182
Cash and cash equivalents at end of period		821 069	735 706	1 709 166
Specification of cash equivalents at end of period:
Bank deposits, etc.		810 723	725 109	1 693 319
Restricted bank deposits		10 346	10 597	15 847
Cash and cash equivalents at end of period	11	821 069	735 706	1 709 166

NOTES

(All figures in NOK 1,000)

This interim report has been prepared in accordance with international standards for financial reporting (IFRS), issued by the board of IASB, and in accordance with IAS 34 "Interim financial reporting". The quarterly report is unaudited.

Note 1 Accounting principles

The accounting principles used for this interim report are in all material respect in accordance with the principles used in the Financial statement for 2013. There are some new and amended standards effective from 1 January 2014, as mentioned in the annual report 2013. These standards are implemented in Q1 2014, but do not have material impact on the accounts.

Note 2 Revenues

	Q1
Breakdown of revenues:	2014	2013
Recognized income oil	128 541	47 299
Recognized income gas	21 891	25 815
Tariff income	4 668	5 595
Total petroleum revenues	155 101	78 709
Breakdown of produced volumes (barrel of oil equivalents):
Oil	195 760	85 330
Gas	64 810	88 310
Total produced volumes	260 569	173 639
Other operating revenues (subletting of office space)	3 241	1 630

Note 3 Exploration expenses

		Q1
Breakdown of exploration expenses:	2014	2013
Seismic, well data, field studies, other exploration costs	17 222	60 345
Recharged rig costs	-47 047	-38 418
Exploration expenses from license participation incl. seismic	37 857	37 985
Expensed capitalized wells previous years	13 434	13 993
Expensed capitalized wells this year	60 166	149 570

Note 4 Tangible assets and intangible assets

Other intangible assets
Intangible assets	Licenses etc.*	Software	Total	Exploration exp **	Goodwill
Book value 31.12.2012	661 642	3 899	665 541	2 175 492	387 550
Acquisition cost 31.12.2012	1 104 425	45 180	1 149 604	2 175 492	644 570
Additions		219		235 788
Disposals/Expensed dry wells				163 563
Acquisition cost 31.03.2013	1 104 425	45 399	1 149 824	2 247 718	644 570
Acc. depreciation and impairments 31.03.2014	447 333	41 910	489 243		257 019
Book value 31.03.2013	657 093	3 488	660 581	2 247 718	387 551
Acquisition cost 31.12.2013	902 705	48 099	950 804	2 056 100	465 653
Additions		46	46	114 896
Disposals/Expensed dry wells				73 601
Reclassification				-542 047
Acquisition cost 31.03.2014	902 705	48 145	950 850	1 555 348	465 653
Acc. depreciation and impairments 31.03.2014	263 821	43 977	307 798		144 532
Book value 31.03.2014	638 884	4 168	643 050	1 555 348	321 120
Depreciation Q1 2014	2 732	563	3 295

Software is depreciated linearly over the software's lifetime, which is three years. Licences related to fields in production is depreciated using the Unit of Production method.

*The Ivar Aasen-field has an obligation related to investments to enable the Edvard Grieg facilites to receive fluids from the Ivar Aasen field. These processing rights are considered as an "Intangible asset" and included with NOK 89.8 million as of 31.03.2014.

Tangible fixed assets	Fields under development **	Production facilities including wells	Fixtures and fittings, office machinery	Total
Book value 31.12.2012	1 364 097	577 290	51 882	1 993 269
Acquisition cost 31.12.2012 Additions	3 163 747 430 005	1 232 676 90 942	126 062 2 209	4 522 486 523 156
Acquisition cost 31.03.2013 Accumulated depreciation and impairments 31.03.2013	3 593 752 1 799 650	1 323 617 680 125	128 271 79 259	5 045 641 2 559 034
Book value 31.03.2013	1 794 102	643 493	49 012	2 486 606
Acquisition cost 31.12.2013 Additions Reclassification	1 647 173 567 662 542 047	4 399 452 9 635	156 375 12 314	6 203 000 589 611 542 047
Acquisition cost 31.03.2014 Accumulated depreciation and impairments 31.03.2014	2 756 883	4 409 087 3 532 702	168 689 98 299	7 334 659 3 631 002
Book value 31.03.2014	2 756 883	876 385	70 390	3 703 657
Depreciation Q1 2014		81 206	4 361	85 567

Capitalized exploration expenditures are reclassified to "Fields under development" when the field enteres into the development phase. Fields under development are reclassified to "Production facilities" from 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 decommisioning costs are included as "Production facilities".

**The Johan Sverdrup Field is considered to have entered into the development phase in the first quarter 2014. All costs relating to the development are thus recognised as tangible assets and previously capitalised exploration expenditures have been reclassified accordingly from intangible assets.

	Q1		01.01.-31.03
Reconciliation of depreciation in the income statement:	2014	2013	2014	2013
Depreciation of tangible fixed assets	85 567	29 818	85 567	29 818
Depreciation of intangible assets	3 295	5 180	3 295	5 180
Total depreciation in the income statement	88 863	34 997	88 863	34 997

Note 5 Payroll and other operating expenses

	Q1
Breakdown of payroll expenses:	2014	2013
Gross payroll expenses	127 559	107 527
Share of payroll expenses classified as exploration, development or production expenses, and
expenses invoiced to licences	-123 000	-106 000
Net payroll expenses	4 559	1 527

		Q1
Breakdown of other operating expenses:	2014	2013
Gross other operating expenses	85 486	73 298
Share of other operating expenses classified as exploration,
development or production expenses, and expenses invoiced
to licences	-72 181	-54 090
Net other operating expenses	13 305	19 208

Note 6 Financial items

	Q1
	2014	2013
Interest income	12 145	7 202
Return on financial investments	300	488
Currency gains	31 981	20 114
Fair value of derivatives	2 383
Total other financial income	34 663	20 602
Interest expenses	105 120	57 895
Capitalized interest cost development projects	-28 431	-54 439
Amortized loan costs and accreation expence	10 064	9 291
Total interest expenses	86 753	12 748
Currency losses	16 847	41 454
Realised loss on derivatives	3 683	2 991
Fair value of derivatives		2 707
Total other financial expenses	20 530	47 153
Net financial items	-60 475	-32 097

Note 7 Taxes

		Q1
Taxes for the period appear as follows:	2014	2013
Calculated current year exploration tax refund	-148 004	-261 139
Change in deferred taxes	-26 659	-2 093
Prior period adjustments	-7 768	818
Total taxes (+) / tax income (-)	-182 431	-262 415

A full tax calculation has been carried out in accordance with the accounting principles described in the annual report for 2013. The calculated exploration tax receivable as result of exploration activities in 2014 is recognised as a long-term item in the balance sheet. The tax refund for this item is expected to be paid in December 2015. The calculated exploration tax receivable as result of exploration activities in 2013 is recognised as a current asset in the balance sheet. The exploration tax refund for this item is expected to be paid in December 2014.

Calculated tax receivables	31.03.2014	31.03.2013	31.12.2013
Tax receivables included as non-current assets	148 004	261 139
Tax receivables included as current assets	1 416 550	1 278 297	1 411 251

Deferred taxes/deferred tax asset:	31.03.2014	31.03.2013	31.12.2013
Deferred taxes 1.1.	630 423	-126 604	-126 604
Change in deferred taxes	26 659	2 093	567 368
Prior period adjustments	7 768	-602
Deferred tax related to impairment and disposal of licenses			192 830
Deferred tax recorded towards OCI			-3 170
Total deferred taxes asset	664 850	-125 113	630 423

	Applied tax
Tax effect of tax losses carryforward:	rate	31.03.2014	31.03.2013	31.12.2013
Tax losses carryforward	27 %	-560 954	-375 008	-479 558
Tax losses carryforward	51 %	-1 136 874	-700 205	-939 713

Temporary differences of tax losses carryforward is incuded in the deferred taxes.

		Q1
Reconciliation of tax income	2014	2013
27% company tax on result before tax	43 576	76 340
51% special tax on result before tax	82 310	144 198
Tax effect of financial items - 27% only	-20 842	257
Tax effect on uplift	62 189	31 025
Interest of tax losses carryforward	6 343	4 017
Other items (permanent differences and previous period adjustment)	8 854	6 578
Total tax income	182 431	262 415

Note 8 Other non-current assets

	31.03.2014	31.03.2013	31.12.2013
Shares in Sandvika Fjellstue AS	12 000	12 000	12 000
Debt service reserve	257 518	175 865	260 446
Tenancy deposit	12 954	12 694	12 954
Total other non-current assets	282 472	200 559	285 399

Note 9 Other short-term receivables

	31.03.2014	31.03.2013	31.12.2013
Receivables related to deferred volume at Atla	5 256		3 103
Pre-payments, including rigs	195 660	33 648	146 977
VAT receivable	25 055	21 289	11 444
Underlift	43 540	23 318	18 611
Other receivables, including operator licences	347 775	259 465	319 283
Total other short-term receivables	617 286	337 720	499 419

For information about receivables related to deferred volume at Atla, see note 10.

Note 10 Long term receivables

	31.03.2014	31.03.2013	31.12.2013
Receivables related to deferred volume at Atla	138 078	67 240	125 432
Total long term receivables	138 078	67 240	125 432

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 has stalled the production from the neighbouring field Skirne. This is expected to continue through 2014 and into 2015. Income is recognised based on physical production volumes measured at market value. This deferred compensation is recorded as a long term or short term receivables, depending on when the income will occur, see Note 9.

Note 11 Cash and cash equivalents

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

Breakdown of cash and cash equivalents:	31.03.2014	31.03.2013	31.12.2013
Cash	5	5	5
Bank deposits	810 718	725 104	1 693 314
Restricted funds (tax withholdings)	10 346	10 597	15 847
Short-term placements	821 069	735 706	1 709 166
Unused exploration facility loan	758 947	435 525	815 991
Unused revolving credit facility	3 740 648	1 401 120	3 945 286

Note 12 Share capital

	31.03.2014	31.03.2013	31.12.2013
Share capital	140 707	140 707	140 707
Total number of shares (in 1.000)	140 707	140 707	140 707
Nominal value per share in NOK	1.00	1.00	1.00

Note 13 Derivatives

	31.03.2014	31.03.2013	31.12.2013
Unrealized losses interest rate swaps	48 228	48 693	49 453
Total derivatives	48 228	48 693	49 453

The company has entered into three interest rate swaps. The purpose is to swap floating rate loans to fixed rate. These rate swaps are market to market and recognized in the Statement of income.

Note 14 Accounts receivables

	31.03.2014	31.03.2013	31.12.2013
Receivables related to sale of petroleum	13 202	15 399	70 885
Receivables related to license transaction	99 271	70 542	1 284
Invoicing related to expense refunds including rigs	15 766	511	62 052
Total account receivable	128 239	86 452	134 221

Note 15 Short-term loans

	31.03.2014	31.03.2013	31.12.2013
Exploration facility	680 794	969 819	478 050
Total short-term loans	680 794	969 819	478 050

The current facility of NOK 3,500 million was established in December 2012 and the company can draw on the facility until 31 December 2015 with a final date for repayment in December 2016. The maximum utilization including interest is limited to 95 percent of tax refund related to exploration expenses. The lender have security in the company's tax receivable. The calculated exploration tax receivable as result of exploration activities in 2013 is expected to be paid in December 2014, and will be used to repay this loan. See note 7.

The interest rate is three months' NIBOR plus a margin of 1.75 percent, with a utilization fee of 0.25 percent on outstanding loan up to NOK 2,750 million and 0.5 percent if the utilized credit exceeds NOK 2,750 million. In addition a commitment fee of 0.7 percent is also paid on unused credit.

For information about the unused part of the credit facility for exploration purposes, see Note 11 - "Cash and cash equivalents".

Note 16 Other current liabilities

	31.03.2014	31.03.2013	31.12.2013
Current liabilities related to overcall in licences	10 960	31 551	202 037
Share of other current liabilities in licences	443 729	503 576	310 673
Overlift of petroleum			9 588
Other current liabilities	218 565	184 556	273 382
Total other current liabilities	673 254	719 684	795 680

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

Note 17 Bond

	31.03.2014	31.03.2013	31.12.2013
Principal, bond Norsk Tillitsmann 1) Principal, bond Norsk Tillitsmann 2)	593 240 1 882 319	589 939	592 304 1 881 278
Total bond	2 475 559	589 939	2 473 582

1)The loan runs from 28 Januar 2011 to 28 January 2016 and carries an interest rate of 3 month NIBOR + 6.75 percent. The principal falls due on 28 January 2016 and interest is paid on a quarterly basis. The loan is unsecured.

2)The loan runs from July 2013 to July 2020 and carries an interest rate of 3 month NIBOR + 5 percent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The loan is unsecured.

Note 18 Other interest-bearing debt

	31.03.2014	31.03.2013	31.12.2013
Revolving credit facility Unrealized currency	2 131 650 18 639	1 449 131 3 904	1 992 055 44 852
Total other interest-bearing debt	2 150 288	1 453 035	2 036 907

In September 2013, the company entered into a USD 1 billion revolving credit facility with a group of nordic and international banks. The revolving credit facility can be increased with USD 1 billion on certain future conditions. The company can draw on the facility until September 2018 with a final date for repayment as of September 2018. The facility replaced the company's USD 500 million tranche which originally matured on 31 December 2015.

The interest rate on the revolving credit facility is from 1 - 6 months NIBOR/LIBOR pluss a margin of 3 percent, with a utilization fee of 0.5 percent or 0.75 percent based on the amount drawn under the facility. In addition commitment fee of 1.20 percent is also paid on unused credit.

Note 19 Provision for abandonment liabilities

	31.03.2014	31.03.2013	31.12.2013
Provisions as of 1 January	975 904	798 057	798 057
Incurred cost removal	-2 706	-2 056	-36 739
Accreation expense - present value calculation	12 920	9 924	42 765
Change in estimates and incurred liabilities on new fields		61 970	171 822
Total provision for abandonment liabilities	986 117	867 895	975 904

Breakdown of the provision to short- and long-term liabilities

Total provision for abandonment liabilities	986 117	867 895	975 904
Long term	829 720	867 895	828 529
Short term	156 397		147 375

The company's removal and decommissioning liabilities relate to the fields Jette, Glitne, Varg, Atla, Enoch, and Jotun. Time of removal is expected to come in 2018 for Jette, 2014-2016 for Glitne, 2016-2018 for Varg, 2018-2020 for Atla, 2017 for Enoch and in 2018-2021 for Jotun.

The estimate is based on executing a concept for removal in accordance with the Petroleum Activities Act and international regulations and guidelines.

Note 20 Uncertain commitments

During the second quarter 2012, the company announced that it had received a notice of reassessment from the Norwegian Oil Taxation Office (OTO) in respect of 2009 and 2010. Subsequently the notice has been extended to include 2011 and 2012. At the end of the third quarter 2012, the company responded to the notice of reassessment by submitting detailed comments.

During the normal course of its business, the company will be involved in disputes. The company provides accruals in its financial statements for probable liabilities related to litigation and claims based on the company's best judgement. Det norske does not expect that the financial position, results of operations or cash flows will be materially affected by the resolution of these disputes.

Note 21 Investments in jointly controlled assets

Number 50 47

License - partner-operated:	31.03.2014	31.12.2013	Licence - operatorships:	31.03.2014	31.12.2013
PL 019C	30,0 %	30,0 %	PL 001B	35,0 %	35,0 %
PL 019D	30,0 %	30,0 %	PL 026B***	62,1 %	62,1 %
PL 029B	20,0 %	20,0 %	PL 027D	100,0 %	100,0 %
PL 035	25,0 %	25,0 %	PL 027ES	40,0 %	40,0 %
PL 035B	15,0 %	15,0 %	PL 028B	35,0 %	35,0 %
PL 035C	25,0 %	25,0 %	PL 103B	70,0 %	70,0 %
PL 038	5,0 %	5,0 %	PL 169C	50,0 %	50,0 %
PL 038D	30,0 %	30,0 %	PL 242	35,0 %	35,0 %
PL 038E **	5,0 %	0,0 %	PL 364	50,0 %	50,0 %
PL 048B	10,0 %	10,0 %	PL 414 *	0,0 %	40,0 %
PL 048D	10,0 %	10,0 %	PL 414B *	0,0 %	40,0 %
PL 102C	10,0 %	10,0 %	PL 450 *	0,0 %	80,0 %
PL 102D	10,0 %	10,0 %	PL 460	100,0 %	100,0 %
PL 102F	10,0 %	10,0 %	PL 494	30,0 %	30,0 %
PL 102G	10,0 %	10,0 %	PL 494B	30,0 %	30,0 %
PL 265	20,0 %	20,0 %	PL 494C	30,0 %	30,0 %
PL 272	25,0 %	25,0 %	PL 497 *	0,0 %	35,0 %
PL 332 *	0,0 %	40,0 %	PL 497B *	0,0 %	35,0 %
PL 362	15,0 %	15,0 %	PL 504	47,6 %	47,6 %
PL 438	10,0 %	10,0 %	PL 504BS	83,6 %	83,6 %
PL 442	20,0 %	20,0 %	PL 504CS	21,8 %	21,8 %
PL 453S	25,0 %	25,0 %	PL 512 *	0,0 %	30,0 %
PL 492	40,0 %	40,0 %	PL 542 *	0,0 %	45,0 %
PL 502	22,2 %	22,2 %	PL 542B *	0,0 %	45,0 %
PL 522	10,0 %	10,0 %	PL 549S	35,0 %	35,0 %
PL 531	10,0 %	10,0 %	PL 553	40,0 %	40,0 %
PL 533	20,0 %	20,0 %	PL 573S	35,0 %	35,0 %
PL 535	10,0 %	10,0 %	PL 626	50,0 %	50,0 %
PL 535B	10,0 %	10,0 %	PL 659 ***	20,0 %	30,0 %
PL 550	10,0 %	10,0 %	PL 663	30,0 %	30,0 %
PL 551	20,0 %	20,0 %	PL 677	60,0 %	60,0 %
PL 554	20,0 %	20,0 %	PL 709	40,0 %	40,0 %
PL 554B	20,0 %	20,0 %	PL 715	40,0 %	40,0 %
PL 554C **	20,0 %	0,0 %	PL 724**	40,0 %	0,0 %
PL 558	20,0 %	20,0 %	PL 748**	40,0 %	0,0 %
PL 563	30,0 %	30,0 %	Number	27	33
PL 567	40,0 %	40,0 %
PL 568	20,0 %	20,0 %	* Relinquised licenses or Det norske has withdrawn from the license.
PL 571	40,0 %	40,0 %
PL 574	10,0 %	10,0 %	** Interest awarded in APA-round (Application in Predefined Areas) in 2013. Offers were announced in 2014.
PL 613	35,0 %	35,0 %
PL 619	30,0 %	30,0 %	*** Aqcuired/changed through license transaction or license is split.
PL 627	20,0 %	20,0 %
PL 667	30,0 %	30,0 %
PL 672	25,0 %	25,0 %
PL 676S	20,0 %	20,0 %
PL 678BS **	25,0 %	0,0 %
PL 678S	25,0 %	25,0 %
PL 681	16,0 %	16,0 %
PL 706	20,0 %	20,0 %
PL 730 **	30,0 %	0,0 %

Note 22 Results from previous interim reports

	2014		2013				2012
	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Total operating revenues	158 342	254 353	323 563	285 626	80 339	116 797	49 014	69 603
Exploration expenses	109 582	544 400	588 289	270 635	233 738	194 924	402 635	417 140
Production costs	42 949	97 602	53 419	57 086	41 512	74 027	45 515	46 154
Payroll and payroll-related expenses	4 559	3 854	4 129	28 515	1 527	267	1 280	703
Depreciation	88 863	124 021	163 666	147 844	34 997	56 505	15 056	19 780
Impairments		657 597	6 837	1 700		127 155	1 880 953	140 669
Other operating expenses	13 305	8 811	25 247	56 619	19 208	21 995	21 140	16 050
Total operating expenses	259 258	1 436 285	841 588	562 400	330 983	474 873	2 366 579	640 497
Operating profit/loss	-100 917	-1 181 933	-518 025	-276 773	-250 644	-358 076	-2 317 565	-570 894
Net financial items	-60 475	-105 851	-131 089	-48 915	-32 097	-13 763	-45 784	-23 065
Profit/loss before taxes	-161 392	-1 287 784	-649 114	-325 688	-282 741	-371 839	-2 363 349	-593 959
Taxes (+)/tax income (-)	-182 431	-959 137	-490 975	-284 200	-262 415	-324 575	-1 774 462	-376 558
Net profit/loss	21 039	-328 647	-158 139	-41 488	-20 326	-47 264	-588 887	-217 401

Det norske oljeselskap ASA

www.detnor.no Postal and office address: Føniks, Munkegata 26 NO-7011 Trondheim Telephone: +47 90 70 60 00 Fax: +47 73 54 05 00