Aker BP

Quarterly Report • Feb 19, 2014

Fourth quarter summary 4
Summary of financial results and operating performance 5
Financials6
Field performance and oil prices6
Health, safety and the environment6
PDO approved projects 6
Other projects 7
Exploration7
Business development7
Events after the quarter 7
Outlook8
Financial Statements 9

Report for the fourth quarter 2013

Fourth quarter summary

(All figures in brackets apply to the fourth quarter 2012)

Det norske oljeselskap ASA ("Det norske" or "the company") reported revenues of NOK 254 (117) million in the fourth quarter. Exploration expenses amounted to NOK 544 (195) million, contributing to an operating loss of NOK 1,182 (358) million. Net financial expenses were NOK 106 (14) million. Net loss for the fourth quarter was NOK 329 (47) million, following a tax income of NOK 959 (325) million.

Det norske's four producing assets – Jette, Atla, Varg and Jotun – produced 4,328 boepd on average during the quarter, whereof Jette accounted for 63 percent. The average realized oil price was USD 109 (110) per barrel.

The Ivar Aasen development project, where Det norske is operator with a 35 percent interest, is on schedule. First steel was cut and construction commenced both at the yard at Arbatax in Sardinia, where Saipem is building the steel jacket, and in Singapore, where SMOE is constructing the topside.

On the Johan Sverdrup project, the pre-unit operator Statoil presented their recommended Phase 1 development concept in late 2013. After the close of the quarter, 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 fourth quarter, Det norske participated in a discovery at Askja (PL 272). Two targets gave good results and preliminary estimates of the resources are between 19 and 44 million barrels of oil equivalents (boe). Det norske is also a licensee in the adjacent Krafla discovery, and a joint development with Askja may provide between 69 and 124 million boe. The Mantra prospect in PL 551 was completed in the fourth quarter, but came in dry.

Key events during the fourth quarter 2013

• On 24 December, Det norske announced that exploration well 31/3-4 on the Mantra prospect on PL 551 in the North Sea was dry.
• On 20 December, Det norske provided an update to the market on the progress of the Johan Sverdrup project.
• On 19 December, Det norske sold 10 percent interest in PL 659 in the Barents Sea, where the drilling on the Langlitinden prospect is ongoing. Det norske is the operator and will hold 20 percent in the licence following the transaction.
• On 4 November, Det norske confirmed as partner in PL 272 with a 25 percent interest – the presence of hydrocarbons in exploration well 30/11-9 S on the Askja prospect.
• On 8 October, Karl Johnny Hersvik was appointed as the new Chief Executive Officer of Det norske. He comes from the position as Senior Vice President of Statoil's Research and development division.

Key events after the quarter

• On 13 February, pre unit operator Statoil provided an update on the concept selection and DG2 for Johan Sverdrup. The field will be developed in multiple phases, and the production capacity in the first phase will be between 315,000 and 380,000 barrels of oil equivalents per day.
• On 21 January, Det norske announced that Gro G. Haatvedt had been appointed as the new Senior Vice President 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.

Summary of financial results and operating performance

MNOK= NOK million	Q4 13	Q3 13	Q2 13	Q1 13	Q4 12	2013	2012
Jette (boepd), 70%	2 710	4 378	3 594	0	0	2 683	0
Atla (boepd), 10%	1 031	981	1 446	1 253	2 070	1 177	513
Varg (boepd), 5%	412	377	398	425	395	403	556
Glitne (boepd), 10%	0	0	0	43	75	11	174
Enoch (boepd), 2%	0	0	0	0	0	0	4
Jotun Unit (boepd), 7%	175	204	175	209	231	191	210
Total production (boepd)	4 328	5 940	5 613	1 929	2 771	4 463	1 458
Oil and gas production (Kboe)	398	547	511	174	255	1 629	545
Oil price realised (USD/barrel)	109	112	103	112	110	107	115
Operating revenues (MNOK)	254	324	286	80	117	944	332
Cash flow from production (MNOK)	151	269	227	37	40	684	114
Exploration expenses (MNOK)	544	588	271	234	195	1 637	1 609
Total exploration expenditures (expensed and capitalised) (MNOK)	400	581	373	306	375	1 659	1 656
Operating loss (MNOK)	-1 182	-518	-277	-251	-358	-2 227	-3 843
Net loss for the period (MNOK)	-329	-158	-41	-20	-47	-548	-957
No of licences (operatorships)	80 (33)	74 (30)	72 (30)	69 (28)	67 (26)	80 (33)	67 (26)

Financials

Fourth quarter accounts

Operating revenues in the fourth quarter was NOK 254 (117) million. The main cause of increase is that Jette has commenced production during 2013. The production increased by 56 percent from 2,771 barrels of oil equivalents per day (boepd) in the fourth quarter 2012 to 4,328 boepd this quarter. Jette accounted for 2,710 (0) boepd and Atla for 1,031 (2,070) boepd.

Exploration expenses amounted to NOK 544 (195) million. The company has during the quarter expensed all capitalized costs related to the Grevling discovery in PL 038D with NOK 316 million and also expensed costs related to the Mantra well in PL 551 incurred in the fourth quarter 2013.

The operating loss increased to NOK 1,182 (358) million, mainly due to impairment charges on several producing licenses, whereof Jette accounted for NOK 349 million. Net financial expenses in the fourth quarter amounted to NOK 106 (14) million.

The net loss for the period was NOK 329 (47) million after a tax income of NOK 959 (325) million.

Net cash flow from operating activities was NOK 920 (1,167) million and included tax refund of NOK 1,318 (1,443) million. Net cash flow from investment activities amounted to NOK -635 (-1,031) million, largely as a result of exploration expenses and investments in fields under development. Net cash flow from financing activities totalled NOK 207 (284) million as the company issued new debt and repaid existing debt.

The company's cash and cash equivalents amounted to NOK 1,709 (1,154) million as of 31 December. Tax receivables for disbursement in December 2014 amounted to NOK 1,411 (1,274) million.

The equity ratio at the end of the fourth quarter 2013 was reduced to 30 (45) percent. Discoveries and fields under development contributed to a total asset balance of NOK 10,541 (8,364) million as of 31 December 2013.

Field performance and oil prices

Det norske produced 398,180 barrels of oil equivalents (boe) in the fourth quarter of 2013. This corresponds to 4,328 (2,771) boepd.

The average realized oil price was USD 109 (110) per barrel, while gas revenues were recognized at market value of NOK 2.3 (2.3) per standard cubic metre (scm).

Jette came on stream in May and produced 2,710 boepd net on average in the fourth quarter, accounting for 63 percent of total production. Operations on Jette have been stable during the fourth quarter, but the production level is slowly declining. Jette resources have been downward revised, and as a result an impairment charge of NOK 349 million has been made in the fourthquarter.

Atla produced 1,031 (2,070) boepd net on average in the fourth quarter and accounted for 24 percent of the total production. Atla's production was stable in October and December, but production was lower than expected in the second half of November due to some technical problems on Heimdal.

Varg produced 412 (395) boepd net to Det norske in the fourth quarter, or 10 percent of total production. Production has been stable in the fourth quarter.

The average production rate on Jotun of 175 boepd net to Det norske represented about 4 percent of total production. Production remained stable during the quarter.

Health, safety and the environment

No serious incidents were reported from Det norske's operations in the fourth quarter. In December a lost time injury occurred in Det norske's activities, following a minor injury due to a person that slipped and fell at a yard on contract for Det norske. The Petroleum Safety Authority (PSA) performed an audit of technical and operational barriers on Ivar Aasen in the fourth quarter, pointing out three deviations and eight areas for improvement. A previous PSA audit, covering material handling and working environment on the Ivar Aasen platform, was closed by the PSA in November.

PDO approved projects

Ivar Aasen – PL 001B/242/028B (35% 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 topsides 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 both jacket and topsides fabrication was performed early November. The fabrication of the topsides' primary structural steel members commenced in Indonesia and Singapore in the fourth 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 to 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% 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% partner) & PL 502 (22.22% partner)

The pre-unit operator Statoil has recommended a concept for the first phase. Statoil communicated gross field recoverable contingent resources between 1,800 and 2,900 million barrels oil equivalents. In February 2014, the formal partner decision to pass Decision Gate 2 (DG2) was made and the selected concept was communicated to the public. The selected concept is further described in the section "Events after the quarter".

Exploration

Askja – PL 272 (25% partner)

In September, the semi submersible drilling rig Ocean Vanguard spudded exploration well 30/11-9S on the Askja prospect, south of the Oseberg field. After encountering a 90 metre gas column in the lower part of the Heather

formation and in the upper to middle part of Tarbert in well 30/11-9S, another prospect was tested in appraisal well 30/11-9A. This well encountered oil in a 40 metre net column in the lower part of the Heather formation and the upper part of Tarbert.

Preliminary estimates indicate volumes between 19 and 44 million barrels of oil equivalents. Askja is located adjacent to the Krafla discovery, containing between 50 and 80 million barrels of oil equivalents, and a joint development may provide between 69 and 124 million barrels of oil equivalents.

Mantra – PL 551 (20% partner)

In December, exploration well 31/3-4 on the Mantra prospect offshore Norway encountered reservoir quality sands but all intervals were water-bearing. The well was drilled by the semi-submersible rig Transocean Barents. The well has been plugged and abandoned.

Business development

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

In the fourth quarter, 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 spudded in January 2014. Det norske is the operator and will hold 20 percent in the license following the transaction. As compensation, Atlantic Petroleum will carry part of Det norske's drilling costs related to the exploration well. The agreement is subject to approval by the authorities.

Events after the quarter

Johan Sverdrup concept selection

Statoil, as the pre unit operator on the Johan Sverdrup field, made the key parts of the concept selection known to the public in February 2014, as Decision Gate 2 (DG2) was passed in the Johan Sverdrup pre-unit partnership.

The Johan Sverdrup field will be developed in multiple phases. For the first phase, the Plan for Development and Operations (PDO) will comprise the establishment of a field centre, composed of four platforms: a processing platform, a well head and drilling platform, a riser, utilities and export platform and a living quarter platform, all steel jackets. In addition, three subsea installations for water injection will be installed. The production capacity in the first phase will be between 315,000 and 380,000 barrels of oil equivalents per day.

Statoil communicated gross field recoverable contingent resources between 1,800 and 2,900 million barrels oil equivalents. Preliminary estimated recovery factor is about 60%. However, the ambition is to increase this towards 70%. Total investments for the first phase are estimated to be between NOK 100 and 120 billion. Phase 1 has capacity to produce more than 70% of the resources. The estimate includes all investments in platforms, subsea installations, wells, pipelines and power from shore, including contingencies and market adjustment allowances. The partnership works continuously to reduce the level of investments in the first phase.

The first phase development is robust and has flexibility to secure an optimal development of the total field resources, including IOR/EOR, as well as potential 3rd party production.

The concept for future phases will be decided in a separate process after the phase 1 PDO. Full field production capacity is expected to be in the range 550,000 to 650,000 barrels of oil equivalents. From both a technical and commercial perspective, the expected life of the Johan Sverdrup field is approximately 50 years.

The oil and gas from the Johan Sverdrup will be exported to shore via dedicated pipelines. The oil will be transported to the Mongstad terminal in the county of Hordaland, whereas the gas will be transported via the Statpipe line to Kårstø in the county of Rogaland for processing and onward transportation.

The plan is to submit a Johan Sverdrup PDO to the authorities by the first quarter of 2015. The Johan Sverdrup field spans across three licenses, and a unitization negotiation process will take place between the Johan Sverdrup licensees. The unit agreement needs to be closed before the PDO can be handled by the authorities.

Exploration drilling

In February, the company reported that it, as operator, had confirmed hydrocarbon shows on Langlitinden in PL 659.

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.

Changes in management

In January, 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. Time of taking office is yet to be decided, but will be no later than August 2014.

Outlook

Ivar Aasen and Johan Sverdrup are the most important field development projects for Det norske. Both these projects are progressing satisfactory. In 2014, Det norske will take part in unitisation negotiations both for the Ivar Aasen field and the Johan Sverdrup field.

Det norske is targeting strong production growth. This will require large investments. Over the past two years, the company has strengthened its equity position and in recent months it has put in place both a NOK 1.9 billion unsecured bond and a USD 1 billion bank facility. The board has taken these steps in order to secure a solid financial basis for the field development projects and will continue to work on obtaining an optimal financing structure for the company.

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

Det norske carries out significant offshore operations on the NCS. The company is also operating the Ivar Aasen field development project, and is a partner in the Johan Sverdrup and Gina Krog field developments. These operations activities involve thousands of workers in different countries on different continents. All our activities entail risk. Risk can never be eliminated, but it can be minimized through careful handling and good management. Det norske recognizes its responsibility to the safety of people and the environment, and is devoted to spend time and resources to meet all regulations and the highest HSE standards in the oil industry.

		(Unaudited)	(Audited)	(Unaudited)	(Audited)		(Unaudited)	(Audited)	(Unaudited)	(Audited)
			Q4		1.1 - 31.12			Q4		1.1 - 31.12
(All figures in NOK 1,000)	Note	2013	2012	2013	2012	(All figures in NOK 1,000)	2013	2012*	2013	2012*
Petroleum revenues	2	248 716	113 946	933 162	325 093	Profit/loss for the period	-328 647	-47 264	-548 600	-957 252
Other operating revenues	2	5 636	2 851	10 719	7 351
						Items which not will be
Total operating revenues		254 353	116 797	943 881	332 444	reclassified over profit and loss:
						Actuarial gain/loss pension
						plan	4 064	-1 709	4 064	-6 834
Exploration expenses	3	544 400	194 924	1 637 063	1 609 314	Taxes relating to OCI	-3 170	1 333	-3 170	5 331
Production costs		97 602	74 027	249 619	210 962	Total comprehensive
Payroll and payroll-related expenses	6	3 854	267	38 025	11 000	income in period	-327 752	-47 640	-547 706	-958 756
Depreciation	5	124 021	56 505	470 529	111 687
Net impairment losses	4,5	657 597	127 155	666 135	2 149 653	*see note 1 for information about comparative figures.
Other operating expenses	6	8 811	21 995	109 886	82 799
Total operating expenses		1 436 285	474 873	3 171 256	4 175 414
Operating profit/loss		-1 181 933	-358 076	-2 227 375	-3 842 970
Interest income	7	13 063	13 630	40 750	54 997
Other financial income	7	15 838	26 667	80 567	68 399
Interest expenses	7	103 397	35 084	301 834	128 250
Other financial expenses	7	31 355	18 977	137 435	101 050
Net financial items		-105 851	-13 763	-317 952	-105 906
Profit/loss before taxes		-1 287 784	-371 839	-2 545 327	-3 948 876
Taxes (+)/tax income (-)	8	-959 137	-324 575	-1 996 727	-2 991 624
Net profit/loss		-328 647	-47 264	-548 600	-957 252
Weighted average no. of shares outstanding		140 707 363	136 581 048	140 707 363	128 649 729
Weighted average no. of shares fully diluted		140 707 363	136 581 048	140 707 363	128 649 729
Earnings/(loss) after tax per share		-2,34	-0,35	-3,90	-7,44
Earnings/(loss) after tax per share fully diluted		-2,34	-0,35	-3,90	-7,44

STATEMENT OF INCOME TOTAL COMPREHENSIVE INCOME

(Unaudited)	(Audited)	(Unaudited)	(Audited)		(Unaudited)	(Audited)	(Unaudited)	(Audited)
	Q4		1.1 - 31.12			Q4		1.1 - 31.12
				Items which not will be
				Actuarial gain/loss pension
				plan	4 064	-1 709	4 064	-6 834
				Total comprehensive
				income in period

STATEMENT OF FINANCIAL POSITION

(All figures in NOK 1,000)	Note	(Unaudited) 31.12.2013	(Audited) 31.12.2012	(All figures in NOK 1,000)	Note	(Unaudited) 31.12.2013	(Audited) 31.12.2012*
ASSETS				EQUITY AND LIABILITIES
Intangible assets				Paid-in capital
Goodwill	5	321 120	387 551	Share capital	13	140 707	140 707
Capitalised exploration expenditures	5	2 056 100	2 175 492	Share premium		3 089 542	3 089 542
Other intangible assets	5	646 299	665 542
Deferred tax asset	8	630 423
				Total paid-in equity		3 230 249	3 230 249
Tangible fixed assets
Property, plant, and equipment	5	2 657 566	1 993 269	Retained earnings
				Other equity	1	-41 780	505 926
Financial assets
Long term receivables	11	125 432	31 995	Total Equity		3 188 470	3 736 175
Other non-current assets	9	285 399	193 934
Total non-current assets		6 722 340	5 447 783	Provisions for liabilities
				Pension obligations	1	66 512	65 258
				Deferred taxes	1,8		126 604
Inventories Inventories		40 880	21 209	Abandonment provision Provisions for other liabilities	20	828 529 780	798 057 647
Receivables				Non current liabilities
Account receivables	15	134 221	101 839	Bonds	18	2 473 582	589 078
Other short term receivables	10	499 419	342 566	Other interest-bearing debt	19	2 036 907	1 299 733
Short-term deposits		24 075	23 138	Derivatives	14	49 453	45 971
Calculated tax receivables		1 411 251	1 273 737
				Current liabilities
Cash and cash equivalents				Short-term loan	16	478 050	567 075
Cash and cash equivalents	12	1 709 166	1 154 182	Trade creditors		452 435	258 596
				Accrued public charges and indirect taxes		23 579	24 536
Total current assets		3 819 011	2 916 670	Abandonment provision	20	147 375
				Other current liabilities	17	795 680	852 722
				Total liabilities		7 352 882	4 628 277
TOTAL ASSETS		10 541 352	8 364 453	TOTAL EQUITY AND LIABILITIES		10 541 352	8 364 453

*see note 1 for information about comparative figures.

STATEMENT OF CHANGES IN EQUITY (Unaudited)

			Retained
(All figures in NOK 1,000)	Share capital	Share premium	earnings	Total equity
Equity as of 31.12.2011	127 916	2 083 271	1 465 364	3 676 551
Pension adjustment, see note 1			-684	-684
Equity as of 31.12.2011 (adjusted)	127 916	2 083 271	1 464 680	3 675 867
Private placement	12 792	1 006 271		1 019 063
Profit/loss for the period 1.1.2012 - 31.12.2012			-957 251	-957 251
Pension adjustment, see note 1			-1 504	-1 504
Equity as of 31.12.2012	140 707	3 089 542	505 926	3 736 175
Profit/loss for the period 1.1.2013 - 31.12.2013			-547 706	-547 706
Equity as of 31.12.2013	140 707	3 089 542	-41 780	3 188 470

STATEMENT OF CASH FLOW (Unaudited)

		Q4		01.01-31.12
(All figures in NOK 1,000)	Note	2013	2012	2013	2012
Cash flow from operating activities
Profit/loss before taxes		-1 287 784	-371 839	-2 545 327	-3 948 876
Taxes paid during the period		-26 585		-26 585
Tax refund during the period		1 318 430	1 443 140	1 318 430	1 443 140
Depreciation	5	124 021	56 505	470 529	111 687
Net impairment losses	4	657 597	127 155	666 135	2 149 653
Accretion expenses	20	11 083	4 502	42 765	17 519
Reversal of tax item related to shortfall value of purchase price allocation (PPA)	3				-57 000
Losses on sale of license			-2 500	734	13 461
Changes in derivatives	7	9 310	1 174	3 174	44 847
Amortization of interest expenses and arrangement fee	7	9 162	14 763	88 458	39 576
Expensed capitalized dry wells	3,5	394 367	126 346	1 150 541	1 116 403
Changes in inventories, accounts payable and receivables		120 777	-258 309	141 786	44 467
Changes in other current balance sheet items		-410 386	26 510	-394 934	444 144
Net cash flow from operating activities		919 992	1 167 448	915 707	1 419 020
Cash flow from investment activities
Payment for removal and decommissioning of oil fields	20	-16 176	12 632	-36 739	-678
Disbursements on investments in fixed assets	5	-365 069	-737 426	-1 495 709	-2 874 627
Disbursements on investments in capitalised exploration expenditures and other intangible assets	5	-255 230	-309 159	-1 358 941	-1 114 277
Sale/farmout of tangible fixed assets and licenses		983	2 575	86 472	414 336
Net cash flow from investment activities		-635 492	-1 031 378	-2 804 917	-3 575 247
Cash flow from financing activities
Net equity issue			1 019 063		1 019 063
Repayment of short-term debt	16	-1 200 000	-1 800 000	-1 500 000	-2 000 000
Repayment of long-term debt	18,19		-600 000	-2 185 102	-600 000
Proceeds from issuance of long-term debt	18,19	707 167	1 065 093	4 729 297	1 849 749
Proceeds from issuance of short-term debt	16	700 000	600 000	1 400 000	2 200 000
Net cash flow from financing activities		207 167	284 156	2 444 195	2 468 812
Net change in cash and cash equivalents		491 667	420 226	554 985	312 584
Cash and cash equivalents at start of period	12	1 217 500	733 957	1 154 182	841 599
Cash and cash equivalents at end of period		1 709 166	1 154 182	1 709 166	1 154 182
Specification of cash equivalents at end of period:
Bank deposits, etc.		1 693 319	1 140 750	1 693 319	1 140 750
Restricted bank deposits		15 847	13 432	15 847	13 432
Cash and cash equivalents at end of period	12	1 709 166	1 154 182	1 709 166	1 154 182

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 accordance with the principles used in the Financial statement for 2012, with the following exceptions:

Pension

Effective as of 1 January 2013, the company has utilised IAS 19 Benefits to employees (June 2011) ("IAS 19R") and altered the basis for calculation of pension liabilities and pension costs. The company has previously employed the "corridor" method for accounting of unamortised estimate deviations. The corridor method is no longer allowed and, in accordance with IAS 19R, all estimate deviations are to be recognised under other comprehensive income (OCI). The corridor as of 1 January 2012, in the amount of NOK 3.1 million, has been reset to zero. Pension liabilities increased correspondingly as of 1 January 2012, whereas the equity was reduced by NOK 0.7 million (after tax), and NOK 1.5 million as of 31 December 2012.

Return on pension plan assets was previously calculated on the basis of a long-term expected return on the pension plan assets. Due to the application of IAS 19R, the net interest cost of the period is now calculated by applying the discount rate applicable to the liability at the start of the period on the net liability. Thus, the net interest cost comprises interest on the liability and return on the pension plan assets, both calculated with the discount rate. Changes in net pension liabilities due to premium payments and pension benefits are taken into consideration. The difference between actual return on the pension plan assets and the recognised return is recognised against the OCI on an ongoing basis. The pension cost in 2012, recognised in accordance with the prior principles, amounted to NOK 29.7 million.

As a consequence of the altered principle for handling of unamortised estimate deviations and calculation of net interest cost, the recognised pension cost increased to NOK 36.5 million, whereas an estimate deviation in the amount of NOK 6.8 million was charged to other income and expenses. The pension liability as of 31 January 2012 increased to NOK 65.3 million. IAS 19 R has been applied retrospectively, and the corresponding figures have changed.

Note 2 Revenues

		Q4	01.01.-31.12
Breakdown of revenues:	2013	2012	2013	2012
Recognized income oil	217 692	59 303	791 155	255 844
Recognized income gas	24 934	47 910	117 752	47 917
Tariff income	6 090	6 734	24 255	21 332
Total petroleum revenues	248 716	113 946	933 162	325 093
Breakdown of produced volumes (barrel of oil
equivalents):
Oil	324 143	98 393	1 263 889	388 223
Gas	74 037	141 462	365 226	141 462
Total produced volumes	398 180	239 855	1 629 115	529 685
Other operating revenues (subletting of office space)	5 636	2 851	10 719	7 351

Note 3 Exploration expenses

		Q4	01.01.-31.12
Breakdown of exploration expenses:	2013	2012	2013	2012
Seismic, well data, field studies, other exploration costs	128 198	75 173	312 695	335 265
Recharged rig costs	-25 258	-60 695	-118 958	-31 491
Exploration expenses from license participation incl. seismic	29 913	47 218	151 340	149 267
Expensed capitalized wells previous years	320 961	2 152	553 288	252 719
Expensed capitalized wells this year	73 406	124 194	597 253	863 684
Payroll and other operating expenses classified as exploration	13 000	2 819	122 000	76 333
Exploration-related research and development costs	4 180	4 061	19 445	20 536
Reversal of tax item related to shortfall value of purchase price
allocation				-57 000
Total exploration expenses	544 400	194 924	1 637 063	1 609 314

Note 4 Impairments

An impairment test of goodwill and pertaining licences was carried out in the fourth quarter in accordance with the company's accounting principles. The test was carried out as of 31 December 2013. Goodwill is capitalised as a consequence of the requirement in IFRS 3 to make provision for deferred tax in connection with a business combination, even if the transactions are made on an "after-tax" basis as a result of a section 10 decision in line with applicable petroleum taxation. The offsetting entry to deferred tax is goodwill.

is assessed for each well. Impairment are recognised when the book value of an asset or a cash flowgenerating unit exceeds the recoverable amount. The recoverable amount is the higher of the asset's net sales value and utility value. 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 and the specific risk related to the asset. The valuation unit used for assessment of impairment will depend on the lowest level at which it is possible to identify cash flows that are independent of cash flows from other groups of fixed assets. For oil and gas assets, this is carried out at the field or licence level. The loss in value for capitalised exploration costs

For producing licenses and licenses in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves. The following assumptions have been applied:

* discount rate of 10.7 percent nominal after tax (Weighted average cost of capital - WACC)

* a long term inflation of 2.5 percent

* a long term exchange rate of NOK/USD 6.00

* oil prices are based on forward curve, and it is expected that 2017 will be the final year of production for fields that are currently under production.

The following nominal oil price assumptions are applied:

Year	2014	2015	2016	2017
Oil price average USD	106	98	90	84

In the fourth quarter four of the company's producing fields were impaired. The impairment was mainly due to reduction in reserves and increase in the estimate of the abandonment provision. The remaining impairments for 2013 are related to exploration licences that have been or are in the process of being relinqushed.

The following impairments have been recorded:

	Q4		01.01.-31.12
	2013	2012	2013	2012
Impairment of tangible fixed assets	564 663	123 501	564 663	1 963 351
Impairment of other intangible assets/licence rights	111 058	3 863	124 694	226 194
Impairment of goodwill	63 082	1 328	66 430	135 062
Deferred tax	-81 206	-1 536	-89 653	-174 955
Total impairments	657 597	127 155	666 135	2 149 653

When a license is sold or relinquished and the company previously has accounted for deferred taxes and goodwill from a business combination, both goodwill and deferred taxes will be included in the calculation of gains and losses. In assessing a potential impairment, a similar assumption is made and goodwill and deferred taxes are evaluated together with the value of the corresponding license.

See note 5 for a breakdown of impairment charges.

Note 5 Tangible assets and intangible assets

		Other intangible assets
Intangible assets	Licenses etc.*	Software	Total	Exploration expenditures	Goodwill
Book value 31.12.2012	661 643	3 899	665 542	2 175 492	387 551
Acquisition cost 31.12.2012	1 104 425	45 180	1 149 604	2 175 492	644 570
Additions	118 629	1 353	119 982	1 013 006
Disposals/Expensed dry wells	467		467	973 352
Reclassification				-12 984
Acquisition cost 30.09.2013	1 222 588	46 533	1 269 121	2 202 163	644 570
Accumulated depreciation and impairments	469 946	43 138	513 084		260 368
Book value 30.09.2013	752 642	3 395	756 035	2 202 163	384 202
Acquisition cost 30.09.2013	1 222 588	46 533	1 269 121	2 202 163	644 570
Additions	3 346	1 565	4 910	250 611
Disposals/Expensed dry wells				396 674
Relinquished licenses	323 229		323 229		178 917
Acquisition cost 31.12.2013	902 705	48 098	950 803	2 056 100	465 653
Accumulated depreciation and impairments	261 089	43 414	304 503		144 532
Book value 31.12.2013	641 616	4 684	646 299	2 056 100	321 120
Depreciation Q4 2013	3 186	276
Depreciation 1.1 - 31.12.2013	16 714	2 133
Impairments in Q4 2013	111 058				63 082
Impairments 1.1 - 31.12.2013	124 694				66 430

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 receipt fluids from the Ivar Aasen field. These processing rights are considered as an "Intangible asset" and included with NOK 89.8 million as of 31.12.2013.

Book value of licences as of 31 December 2013 relates to fields in the exploration and evalation phase, development phase and production phase with NOK 399.3 million, NOK 216.7 million, and NOK 25.6 million, respectively. Corresponding figures for 2012 was NOK 499.2 million, NOK 121.5 million and NOK 40.9 million.

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	3 163 747	1 232 675	126 062	4 522 484
Additions	1 021 974	147 710	22 927	1 192 610
Reclassification	-2 874 622	2 887 606		12 984
Acquisition cost 30.09.2013	1 311 099	4 267 992	148 989	5 728 079
Accumulated depreciation and impairments 30.09.2013		2 771 026	89 313	2 860 339
Book value 30.09.2013	1 311 099	1 496 965	59 676	2 867 740
Acquisition cost 30.09.2013	1 311 099	4 267 992	148 989	5 728 080
Additions	336 074	131 460	7 386	474 920
Acquisition cost 31.12.2013	1 647 173	4 399 452	156 375	6 203 000
Accumulated depreciation and impairments 31.12.2013		3 451 496	93 938	3 545 434
Book value 31.12.2013	1 647 173	947 956	62 437	2 657 567
Depreciation Q4 2013		115 934	4 625	120 559
Depreciation 1.1 - 31.12.2013		431 925	19 758	451 683
Impairments in Q4 2013		564 663		564 663
Impairments 1.1 - 31.12.2013	-1 799 650	2 364 313		564 663

Capitalized exploration expenditures are classified as "Fields under development" when the field enteres into the development phase. Fields under development are classified as "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".

		Q4	01.01.-31.12
Reconciliation of depreciation in the income statement:	2013	2012	2013	2012
Depreciation of tangible fixed assets	120 559	48 319	451 683	100 751
Depreciation of intangible assets	3 462	8 185	18 847	10 936
Total depreciation in the income statement	124 021	56 505	470 529	111 687

See note 4 for a breakdown of total impairments in 2013.

Note 6 Payroll and other operating expenses

		Q4		01.01.-31.12
Breakdown of payroll expenses:	2013	2012	2013	2012
Gross payroll expenses	123 354	103 069	444 025	371 616
Share of payroll expenses classified as exploration, development or production expenses, and expenses invoiced
to licences	-119 500	-102 801	-406 000	-360 616
Net payroll expenses	3 854	267	38 025	11 000
		Q4		01.01.-31.12
Breakdown of other operating expenses:	2013	2012	2013	2012
Gross other operating expenses	77 738	72 127	307 288	281 964
Share of other operating expenses classified as exploration, development or production expenses, and expenses invoiced
to licences	-68 927	-50 132	-197 403	-199 165
Net other operating expenses	8 811	21 995	109 886	82 799

Note 7 Financial items

	2013	Q4 2012	2013	01.01.-31.12 2012
Interest income	13 063	13 630	40 750	54 997
Return on financial investments		865	988	1 628
Currency gains	15 838	25 090	70 502	66 771
Fair value of derivatives		712	9 077
Total other financial income	15 838	26 667	80 567	68 399
Interest expenses	114 699	68 512	340 112	217 142
Capitalized interest cost development projects	-20 465	-48 190	-126 737	-128 468
Amortized loan costs and accreation expence	9 162	14 763	88 458	39 576
Total interest expenses	103 397	35 084	301 834	128 250
Currency losses	18 423	14 672	113 222	54 022
Realised loss on derivatives	3 572		11 912	1 941
Fair value of derivatives	9 310	3 828	12 250	44 847
Decline in value of financial investments	50	478	50	240
Total other financial expenses	31 355	18 977	137 435	101 050
Net financial items	-105 851	-13 763	-317 952	-105 906

Note 8 Taxes

2013 -356 222 -585 897 -17 018	Q4 2012 -312 041 -20 048 7 514	2013 -1 413 159 -567 368	01.01.-31.12 2012 -1 299 985 -1 729 168 57 000
		-16 201	-19 472
			-2 991 624
			31.12.2012
Calculated current year exploration tax refund		1 413 159	1 299 985
Prior period adjustments		-1 908	-26 249
		1 411 251	1 273 737
		31.12.2013	31.12.2012
		-126 604	-2 039 627
		567 368	1 672 167
			5 331
			178 525
		-3 170
			57 000
			-126 604
	-959 137	-324 575	-1 996 727 31.12.2013 192 829 630 423

Tax effect of tax losses carryforward:	Applied tax rate	31.12.2013	31.12.2012
Tax losses carryforward	27 %	-479 558	-325 590
Tax losses carryforward	51 %	-939 713	-588 853

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

A full tax calculation has been carried out in accordance with the accounting principles described in the annual report for 2012. The calculated exploration tax receivable as result of exploration activities in 2013 is recognised as a current asset in the the balance sheet. The tax refund for this item is expected to be paid in December 2014.

The tax rate for general corporate tax is changed from 28 to 27 percent from 1 January 2014. The rate for special tax is from the same date changed from 50 to 51 percent. The deferred tax / deferred tax asset is calculated with the new rates as of 31 December 2013. Also the uplift, a special income deduction in the basis for calculation of special tax (can be regarded as an extra depreciation deduction in the special tax basis), is from 5 May 2013 changed to 5.5 percent for four year, totaling 22 percent of the investment. Before this date the uplift was 7.5 percent for four year, with a total of 30 percent of the investment.

Note 9 Other non-current assets

	31.12.2013	31.12.2012
Shares in Sandvika Fjellstue AS	12 000	12 000
Debt service reserve	260 446	169 241
Tenancy deposit	12 954	12 694
Total other non-current assets	285 399	193 934

Note 10 Other short-term receivables

	31.12.2013	31.12.2012
Receivables related to deferred volume at Atla	3 103
Pre-payments, including rigs	146 977	33 648
VAT receivable	11 444	21 289
Underlift/ overlift (-)	18 611	24 288
Other receivables, including operator licences	319 283	263 341
Total other short-term receivables	499 419	342 566

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

Note 11 Long term receivables

	31.12.2013	31.12.2012
Receivables related to deferred volume at Atla	125 432	31 995
Total long term receivables	125 432	31 995

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 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:	31.12.2013	31.12.2012
Cash	5	5
Bank deposits	1 693 314	1 140 745
Restricted funds (tax withholdings)	15 847	13 432
Short-term placements	1 709 166	1 154 182
Unused exploration facility loan	815 991	587 759
Unused revolving credit facility	3 945 286	1 383 498

Note 13 Share capital

	31.12.2013	31.12.2012
Share capital	140 707	140 707
Total number of shares (in 1.000)	140 707	140 707
Nominal value per share in NOK	1.00	1.00

Note 14 Derivatives

	31.12.2013	31.12.2012
Unrealized losses interest rate swaps	49 453	45 971
Total derivatives	49 453	45 971

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 to the Statement of income.

Note 15 Accounts receivables

	31.12.2013	31.12.2012
Receivables related to sale of petroleum	70 885	23 236
Receivables related to license transaction	1 284
Invoicing related to expense refunds including rigs	62 052	78 603
Total account receivable	134 221	101 839

Note 16 Short-term loans

	31.12.2013	31.12.2012
Exploration facility	478 050	567 075
Total short-term loans	478 050	567 075

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 8

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 12 - "Cash and cash equivalents".

Note 17 Other current liabilities

	31.12.2013	31.12.2012
Current liabilities related to overcall in licences	202 037	113 072
Share of other current liabilities in licences	310 673	519 439
Overlift of petroleum	9 588
Other current liabilities	273 382	220 211
Total other current liabilities	795 680	852 722

Included in other current liabilities is

Note 18 Bond

	31.12.2013	31.12.2012
Principal, bond Norsk Tillitsmann 1)	592 304	589 078
Principal, bond Norsk Tillitsmann 2)	1 881 278
Total bond	2 473 582	589 078

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 19 Other interest-bearing debt

	31.12.2013	31.12.2012
Revolving credit facility	1 992 055	1 331 467
Unrealized currency	44 852	-31 734
Total other interest-bearing debt	2 036 907	1 299 733

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 20 Provision for abandonment liabilities

	31.12.2013	31.12.2012
Provisions as of 1 January	798 057	285 201
Incurred cost removal	-36 739	-677
Accreation expense - present value calculation	42 765	17 519
Change in estimates and incurred liabilities on new fields	171 822	496 015
Total provision for abandonment liabilities	975 904	798 057

Break down of the provision to short- and long-term liabilities

Short term	147 375
Long term	828 529
Total provision for abandonment liabilities	975 904

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 21 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 22 Investments in jointly controlled assets

30,0 % 0,0 % PL 001B 35,0 % 35,0 % 30,0 % 0,0 % PL 026B 62,1 % 0,0 % 20,0 % 20,0 % PL 027D 100,0 % 60,0 % 25,0 % 25,0 % PL 027ES 40,0 % 0,0 % 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 048B 10,0 % 10,0 % PL 337 0,0 % 45,0 % PL 048D 10,0 % 10,0 % PL 356* 0,0 % 50,0 % PL 102C 10,0 % 10,0 % PL 364 50,0 % 50,0 % PL 102D 10,0 % 10,0 % PL 414 40,0 % 40,0 % PL 102F 10,0 % 0,0 % PL 414B 40,0 % 40,0 % PL 102G 10,0 % 0,0 % PL 450 80,0 % 60,0 % PL 265 20,0 % 20,0 % PL 460 100,0 % 100,0 % PL 272 25,0 % 25,0 % PL 482 0,0 % 65,0 % PL 332 40,0 % 40,0 % PL 494* 30,0 % 0,0 % PL 362 15,0 % 15,0 % PL 494B 30,0 % 0,0 % PL 438 10,0 % 10,0 % PL 494C 30,0 % 0,0 % PL 440S 0,0 % 10,0 % PL 497 35,0 % 35,0 % PL 442 20,0 % 20,0 % PL 497B 35,0 % 35,0 % PL 453S 25,0 % 25,0 % PL 504 47,6 % 29,3 % PL 492 40,0 % 50,0 % PL 504BS 83,6 % 58,5 % PL 494 0,0 % 30,0 % PL 504CS 21,8 % 0,0 % PL 494B* 0,0 % 30,0 % PL 512 30,0 % 30,0 % PL 494C 0,0 % 30,0 % PL 542 45,0 % 60,0 % PL 502 22,2 % 22,2 % PL 542B/ 45,0 % 0,0 % 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 % 20,0 % PL 593 0,0 % 60,0 % PL 535B*/ 10,0 % 0,0 % PL 626 50,0 % 50,0 % PL 550 10,0 % 20,0 % PL 659 30,0 % 30,0 % PL 551 20,0 % 20,0 % PL 663* 30,0 % 0,0 % PL 554 20,0 % 20,0 % PL 677 60,0 % 0,0 % PL 554B 20,0 % 20,0 % PL 709* 40,0 % 0,0 % PL 558 20,0 % 20,0 % PL 715 40,0 % 0,0 % 33 26 PL 561 0,0 % 20,0 % Number PL 563 30,0 % 30,0 % PL 567 40,0 % 40,0 % * Relinquised licenses or Det norske has withdrawn from the license. PL 568 20,0 % 20,0 % PL 571 40,0 % 40,0 % Interest awarded in APA-round (Application in Predefined Areas) in 2012. Offers were announced in 2013. PL 574 10,0 % 0,0 % PL 613 35,0 % 35,0 % Aqcuired/changed through license transaction or license is split. PL 619 30,0 % 30,0 % PL 627 20,0 % 20,0 % * Det norske previously partner, now operator. PL 652 0,0 % 20,0 % PL 667 30,0 % 0,0 % * Interest awarded in 22nd licensing round. PL 672 25,0 % 0,0 % PL 676S 20,0 % 0,0 % On the 21 January 2014, Det norske was offered ownership interest in six licenses in APA 2013. For two of PL 678S 25,0 % 0,0 % these Det norske will be Operator. PL 681 16,0 % 0,0 % PL 706*** 20,0 % 0,0 % 47 41 Number	Licence - partner-operated:	31.12.2013 31.12.2012 Licence - operatorships:		31.12.2013 31.12.2012
	PL 019C***
	PL 019D***
	PL 029B
	PL 035

Note 23 Results from previous interim reports

	2013			2012
	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Total operating revenues	254 353	323 563	285 626	80 339	116 797	49 014	69 603	97 031
Exploration expenses	544 400	588 289	270 635	233 738	194 924	402 635	417 140	594 616
Production costs	97 602	53 419	57 086	41 512	74 027	45 515	46 154	45 266
Payroll and payroll-related expenses	3 854	4 129	28 515	1 527	267	1 280	703	8 750
Depreciation	124 021	163 666	147 844	34 997	56 505	15 056	19 780	20 346
Impairments	657 597	6 837	1 700		127 155	1 880 953	140 669	875
Other operating expenses	8 811	25 247	56 619	19 208	21 995	21 140	16 050	23 614
Total operating expenses	1 436 285	841 588	562 400	330 983	474 873	2 366 579	640 497	693 467
Operating profit/loss	-1 181 933	-518 025	-276 773	-250 644	-358 076	-2 317 565	-570 894	-596 436
Net financial items	-105 851	-131 089	-48 915	-32 097	-13 763	-45 784	-23 065	-23 293
Profit/loss before taxes	-1 287 784	-649 114	-325 688	-282 741	-371 839	-2 363 349	-593 959	-619 728
Taxes (+)/tax income (-)	-959 137	-490 975	-284 200	-262 415	-324 575	-1 774 462	-376 558	-516 030
Net profit/loss	-328 647	-158 139	-41 488	-20 326	-47 264	-588 887	-217 401	-103 698

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