Aker BP

Quarterly Report • Jul 14, 2016

QUARTERLY REPORT FOR DET NORSKE OLJESELSKAP

TRONDHEIM, 14 JULY 2016

KEY EVENTS IN Q2 2016

•	18 April:	Det norske announced that the company had entered into an agreement to acquire Centrica Resources Norge AS' shares in the Frigg Gamma Delta and Rind discoveries
•	18 May:	Det norske were awarded one operatorship and two partnership in the 23rd licencing round
•	27 May:	Det norske announced that the bondholders' meeting in DETNOR02 had approved amendments to the loan agreement
•	6 June:	The Ivar Aasen platform deck sailed from the yard in Singapore
•	10 June:	Det norske announced a proposed merger with BP Norge AS, creating Aker BP ASA
•	29 June:	The Ivar Aasen living quarters were loaded on to the transportation barge, ready to be towed to the field
		KEY EVENTS AFTER THE QUARTER

• 4 July: Det norske appointed Per Harald Kongelf as new SVP Improvement

SUMMARY OF FINANCIAL RESULTS

	Unit	Q2 2016	Q2 2015	2016 YTD	2015 YTD
Operating income	USDm	256	322	461	651
EBITDA	USDm	175	224	304	484
Net result	USDm	6	7	39	10
Earnings per share (EPS)	USD	0.03	0.04	0.19	0.05
Production cost per barrel	USD/boe	7	10	7	8
Depreciation per barrel	USD/boe	21	22	21	21
Cash flow from operations	USDm	127	43	323	324
Cash flow from investments	USDm	-325	-225	-556	-487
Total assets	USDm	5 609	5 301	5 609	5 301
Net interest-bearing debt	USDm	2 783	2 159	2 783	2 159
Cash and cash equivalents	USDm	68	188	68	188

SUMMARY OF PRODUCTION

	Unit	Q2 2016	Q2 2015	2016 YTD	2015 YTD
Production
Alvheim (65%)	boepd	39 923	32 414	39 170	35 060
Atla (10%)	boepd	59	494	182	481
Bøyla (65%)	boepd	7 923	8 320	8 504	8 331
Enoch (2%)	boepd	22	-	11	-
Jette (70%)	boepd	537	506	579	649
Jotun (7%)	boepd	98	120	102	135
Varg (5%)	boepd	230	377	345	350
Vilje (46.9%)	boepd	7 615	6 741	6 396	6 586
Volund (65%)	boepd	6 033	9 390	6 239	10 042
SUM	boepd	62 440	58 363	61 527	61 634
Oil price	USD/bbl	49	65	44	62
Gas price	USD/scm	0.17	0.27	0.18	0.28

3

SUMMARY OF THE QUARTER

Det norske oljeselskap ASA ("the company" or "Det norske") reported revenues of USD 256 (322) million in the second quarter of 2016. Production in the period was 62.4 (58.4) thousand barrels of oil equivalent per day ("mboepd"), realising an average oil price of USD 49 (65) per barrel.

EBITDA amounted to USD 175 (224) million in the quarter and EBIT was USD 74 (106) million. Net earnings for the quarter was USD 6 (7) million, translating into an EPS of USD 0.03 (0.04). Net interest-bearing debt amounted to USD 2,783 (2,159) million per 30 June, 2016.

Production from the Alvheim area in the second quarter achieved a production efficiency of 97.0 percent. Production from the tri-lateral BoaKamNorth well started up in May, and drilling of the Viper-Kobra wells were finalised in June with good drilling performance and very good reservoir outcomes.

The drilling program at Ivar Aasen continues to progress ahead of schedule, with five oil producer and three water injection wells finalised. Construction of the topside is completed in Singapore, and the topside modules are transported to Norway for offshore installation planned in July. The project remains on schedule and budget towards the planned start-up in the fourth quarter 2016.

The Johan Sverdrup project is progressing according to plan. The pre-drilling campaign, construction of jackets, topside, subsea facilities, pipelines and power from shore facilities are progressing as planned.

In June, Det norske announced that the company has entered into an agreement with BP p.l.c. to merge with BP Norge AS, creating Aker BP ASA, subject to regulatory approval and approval by the Extraordinary General Meeting.

Forward-looking statements in this report reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future.

All figures are presented in USD unless otherwise stated, and figures in brackets apply to the corresponding period in the previous year.

FINANCIAL REVIEW

(USD million)	Q2 2016	Q2 2015
Operating income	256	322
EBITDA	174	224
EBIT	74	106
Pre-tax profit/loss	45	63
Net profit	6	7
EPS (USD)	0.03	0.04

Income statement Statement of financial position

(USD million)	Q2 2016	Q2 2015
Goodwill	739	1 134
PP&E	3 305	2 804
Cash & cash equivalents	68	188
Total assets	5 609	5 301
Equity	378	661
Interest-bearing debt	2 852	2 347

Total operating revenues in the second quarter were USD 256 (322) million, lower than the second quarter 2015 mainly due to lower oil prices. Petroleum revenues accounted for USD 271 (336) million, while other revenues were USD -16 (-14) million, primarily relating to net realized and unrealized losses on commodity hedges.

Exploration expenses amounted to USD 36 (25) million in the quarter, reflecting dry hole costs, seismic costs, area fees and G&G activities. Production costs were USD 39 (51) million, equating to 6.9 (9.5) USD/boe, including shipping and handling of 1.1 USD/boe. The decrease from the second quarter 2015 is mainly due to a workover on the Alvheim field during the second quarter of 2015, partly offset by some minor projects in the second quarter 2016. Other operating expenses amounted to USD 5 (23) million, a decrease from the second quarter 2015 due to one-off effects in Q2 2015.

Depreciation was USD 120 (117) million, corresponding to 21 USD/boe, which slightly below the second quarter 2015. During the quarter, the company reversed USD 20 (0) million in impairment charges related to Gina Krog mainly due to increased forward prices.

The company recorded an operating profit of USD 74 (106) million in the second quarter, lower than the second quarter 2015 primarily due to lower revenues. The net profit for the period was USD 6 (7) million after net financial items of USD -29 (-43) million and a tax expense of USD 39 (56) million. Earnings per share were USD 0.03 (0.04).

Total intangible assets amounted to USD 1,666 (2,055) million, of which goodwill was USD 739 (1,134) million.

Property, plant and equipment increased to USD 3,305 (2,804), reflecting investments in development projects and depreciation. Current tax receivables amounted to USD 207 (0) million at the end of the quarter. Of this, USD 84 million was received in early July 2016.

The company's cash and cash equivalents were USD 68 (188) million as of 30 June. Total assets were USD 5,609 (5,301) million at the end of the quarter.

Equity was USD 378 (661) million at the end of the quarter, reflecting the net profit in the period.

Deferred tax liabilities increased to USD 1,440 (1,354) million (detailed breakdown in note 7 to the financial statements).

Gross interest-bearing debt increased to USD 2,852 (2,347) million, consisting of the DETNOR02 bond of USD 220 million, the DETNOR03 bond of USD 295 million and the Reserve Based Lending ("RBL") facility of USD 2,336 million.

Statement of cash flow

(USD million)	Q2 2016	Q2 2015
Cash flow from operations	127	43
Cash flow from investments	-325	-225
Cash flow from financing	112	-41
Net change in cash & cash eq.	-85	-223
Cash and cash eq. EOQ	68	188

Net cash flow from operating activities was USD 127 (43) million.

Net cash flow from investment activities was USD -325 (-225) million. Investments in fixed assets amounted to USD 279 (213) million for the quarter, mainly reflecting CAPEX on Ivar Aasen, Alvheim and Johan Sverdrup. Investments in intangible assets including capitalised exploration were USD 44 (11) million in the quarter.

Net cash flow from financing activities totaled USD 112 (-41) million, reflecting the net amount drawn on the company's RBL facility in the quarter.

Funding

In April, the company obtained acceptance for a covenant amendment package from its bank consortium. The bank consortium in the company's USD 3.0 billion RBL and its USD 550 million revolving credit facility ("RCF") agreed to ease covenant levels to the end of 2019. In May, the bondholder meeting in DETNOR02 approved the same amendment package. The new covenant thresholds are detailed in note 15.

At the end of the second quarter 2016, the company had cash and undrawn credit facilities of USD 1.02 billion. From July to year-end 2016, the company's borrowing base availability under its RBL facility has been set at USD 2.9 billion.

Following the anticipated merger with BP Norge AS, the company will assess the composition of its capital structure going forward, including optimal covenant structure and increased borrowing capacity.

Hedging

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

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

The company actively manages its foreign currency exposure through a mix of forward contracts and options. During the second quarter, the company entered into floating to fixed interest rate swaps for USD 400 million of its debt. The LIBOR reference rate for this amount has been fixed at below 1 percent for the period until the end of 2020.

HEALTH, SAFETY AND THE ENVIRONMENT

HSE is always the number one priority in all Det norske's activities. The company ensures that all its operations and projects are carried out under the highest HSE standards. Det norske had two recordable injuries in the second quarter – a broken finger and an ankle injury. There were no serious or high potential incidents during the same period. In May, a time out for safety was carried out at all offices and at the site locations to ensure a continued high HSE awareness.

With the continued high activity level, special attention is paid to maintain a high HSE standard and preventing injuries and undesired events related to all activities.

There were four supervisory activities from the authorities during the second quarter; three from the Petroleum Safety Authority with no deviations and one from the Norwegian Maritime Authority (NME). The company received two deviations from the NME, which were both closed at the end of the quarter.

OPERATIONAL REVIEW

Det norske produced 5.7 (5.3) million barrels of oil equivalents ("mmboe") in the second quarter of 2016, corresponding to 62.4 (58.4) mboepd. The average realized oil price was USD 49 (65) per barrel, while gas revenues were recognized at market value of USD 0.17 (0.27) per standard cubic metre (scm).

Alvheim fields

PL203/088BS/036C/036D/150 (Operator)

The producing fields Alvheim (65 percent), Volund (65 percent), Bøyla (65 percent) and Vilje (46.9 percent) are all tied back to the Alvheim FPSO.

Production from the Alvheim area increased significantly in May with the opening of the lower branch of the existing Vilje 2 well and the startup of the new tri-lateral BoaKamNorth well that was put on production in May.

The production efficiency for the Alvheim FPSO in the second quarter was also very high at 97.0 percent, but lower than the previous quarter (99.3), mainly due to a main power shutdown and clean-up of the new BoaKamNorth well in May.

The operator of the SAGE gas terminal is scheduling a 12-day planned shutdown in August 2016, which will cause Alvheim FPSO to shut down during this period.

The Viper-Kobra development, which comprises two small separate discoveries in the Alvheim area, is progressing according to plan, with first oil expected towards the end of 2016. Drilling of the two wells are complete with good drilling performance and very good reservoir outcomes. The Kobra well was changed to a dual lateral based on the discovery of oil-filled sands above the main reservoir when drilling the landing pilot. The Kobra well was also used to drill a successful exploratory pilot hole into the Kobra East prospect.

Other producing assets

Production from Jette and Jotun has been stable in the quarter. Atla was restarted in June, following the shut-in to build reservoir pressure in late March. Varg ceased production in June and Enoch was restarted in late May.

Ivar Aasen

PL001B/242/457 (34.78 percent, operator)

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

The Maersk Interceptor jack-up rig has continued to perform well during the second quarter, and the drilling program is ahead of schedule. To date, five producers and three water injectors have been drilled.

In April, the rig drilled two geo-pilot wells in the West Cable area. Preliminary estimates indicate 3 – 13 mmboe (gross) of additional resources in the area. The license partners will assess development of the additional resources. Moreover, the geo-pilot wells gave valuable information with regards to placement of the West Cable production well.

The topside was completed in June and the modules have been shipped from Singapore to Norway. The installation of the topside in the North Sea is scheduled for July 2016.

The construction of the living quarters at Stord in Norway is completed. The living quarter module is loaded out onto the transportation barge, ready for transportation to the Ivar Aasen field during July 2016.

In April, installation of the subsea power cable between Edvard Grieg and Ivar Aasen was carried out by EMAS, and the tie-in spools and spool covers were installed in June.

Johan Sverdrup Unit PL265/501/502 (11.5733 percent, partner)

The project is progressing according to plan towards production start-up in the fourth quarter 2019. Contract awards continued through the second quarter. In June, Rosenberg WorleyParsons AS was awarded the contract of fabrication of two flare towers and three bridges.

The pre-drilling campaign with Deepsea Atlantic commenced in March, and is progressing well. Engineering and construction of jackets, topsides, subsea facilities, pipelines and power from shore facilities is progressing according to plan.

The debottlenecking study of the phase 1 processing platform has been concluded, resulting in increased production capacity compared to the PDO design capacity of 315 – 380 mboepd to 440 mboepd.

The latest estimate for capital expenditures for phase 1 is NOK 108.5 billion (nominal value) and NOK 160 to 190 billion (real) for full field, based on the same FX-assumptions as in the PDO.

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

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

EXPLORATION

During the quarter, the company's cash spending on exploration was USD 60 million. USD 36 million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees and G&G costs.

Exploration drilling in the Krafla/Askja area in PL272/035 in the North Sea commenced in March with the aim to prove additional resource potential in the area. Gross proven resources in the two licenses were estimated to 140 – 220 mmboe prior to the drilling campaign.

The first well in the drilling campaign targeted the Madam Felle prospect in PL035. The well encountered a 25-meter oil column in the upper part of the Tarbert formation, of which 22 meters had moderate to good reservoir properties. A preliminary estimate of the discovery is 1 – 3 mmboe (gross). A side track well was subsequently drilled in to Viti prospect, however this well was dry.

The Askja SE prospect was drilled in May and the well encountered a 37-meter oil column in the upper part of the Tarbert formation, of which about 30 meters had good to moderate reservoir properties. A preliminary estimate of the discovery is 4 – 16 (gross) mmboe. A sidetrack was subsequently drilled further down on the structure, but this well was dry.

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

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

The project is progressing according to plan towards production start-up mid-2017. The topside construction at the DSME yard in Korea is completed and the modules were lifted onto the heavy lift vessel, which sailed from Korea late June 2016. Installation of the topside is planned in August 2016 by Saipem.

The Beerenberg prospect was the third main prospect in the drilling campaign. Gas columns at two levels in the top part of the Tarbert formation encountered a total of 5 and 31 meters, respectively, of which 4 and 22 meters had good to moderate reservoir properties. A preliminary estimate of the discovery is 3 – 19 mmboe (gross).

The three discoveries will be included in the evaluation of a potential new field development along with previous discoveries in the area.

The Slemmestad prospect was spudded in June and results are expected shortly. Drilling of a sidetrack, Haraldsplass, commenced in early July.

In May, Det norske was awarded all three licenses the company applied for in the 23rd licensing round. The awards included one operatorship (40% in PL858) and two partnerships (20% in PL857 and 40% in PL852), all in the Barents Sea.

Due to efficient drilling operations at the Maersk Interceptor drilling rig, Det norske has decided to utilize the rig to drill the Langfjellet prospect in PL442/026B in the third quarter.

BUSINESS DEVELOPMENT

In June, the previously announced acquisitions of Noreco's Norwegian portfolio and licenses from Centrica were completed.

Also in June, Det norske sold its interest in PL 038D (Grevling) for an undisclosed cash consideration to Okea.

MERGER WITH BP NORGE AS

On 10 June, Det norske announced an agreement with BP p.l.c. (BP) to merge with BP Norge AS (BP Norge) through a share purchase transaction.

Det norske will issue 135.1 million new shares to BP as compensation for all shares in BP Norge, including assets, a tax loss carry forward of USD 267 million (nominal after-tax value) and a net cash position of USD 178 million (the Transaction). In parallel, Aker will acquire 33.8 million shares from BP to achieve the agreed-upon ownership structure. The effective date of the transaction is 1 January 2016 and it is expected to close at the end of the third quarter 2016, subject to shareholder approval at an Extraordinary General Meeting and regulatory approval.

The combined company will be named Aker BP ASA (Aker BP) and will be headquartered at Fornebuporten, Norway. Aker BP will be jointly owned by Aker ASA (Aker) (40%), BP (30%) and other Det norske shareholders (30%). Øyvind Eriksen will remain Chairman of the Board of Directors and Karl Johnny Hersvik Chief Executive Officer of the combined company.

After the Transaction, Aker BP will hold a portfolio of 97 licenses on the Norwegian Continental Shelf, of which 46 are operated. The combined company will hold an estimated 723 million barrels of oil equivalent P50 reserves, with a 2015 joint production of approximately 122,000 barrels of oil equivalent per day. Det norske and BP Norge had at the end of 2015 a combined workforce of approximately 1,400 employees.

Aker BP will have a balanced portfolio of operated assets and a high quality inventory of non-sanctioned discoveries, with potential to reach production above 250,000 barrels of oil equivalent per day in 2023. The combined company has the ambition to leverage on Det norske's lean and nimble business model and will gain access to state-of-the-art technological know-how and capabilities, through the industrial collaboration with BP.

The transaction strengthens Det norske´s balance sheet and is credit accretive through a 35 percent reduction in net interest-bearing debt per barrel of oil equivalent of reserves. Aker BP aims to introduce a quarterly dividend policy. The first dividend payment is planned for the fourth quarter of 2016, conditional upon the approval of its creditors.

Det norske has started to plan the integration project to ensure that organisation, commercial agreements, governing documents and regulatory approvals are in place when the integrated company, Aker BP, is scheduled to go live in the fourth quarter 2016, having obtained the necessary approvals.

The new executive management team for Aker BP ASA was appointed in July, effective from the fourth quarter 2016. The team consists of:

• • Karl Johnny Hersvik, Chief Executive Officer
• • Alexander Krane, Chief Financial Officer
• Eldar Larsen, SVP Operations
• Olav Henriksen, SVP Projects
• Gro Gunleiksrud Haatvedt, SVP Exploration
• Ole-Johan Molvig, SVP Reservoir
• Tommy Sigmundstad, SVP Drilling and Well
• Jorunn Kvaale, SVP HSE
• Per Harald Kongelf, SVP Improvement

REPORT FOR THE FIRST HALF 2016

(USD million)	Per 30 June 2016	Per 30 June 2015
Oil and gas production (mboepd)	61.5	61.6
Oil price (USD/bbl)	44	62
Operating revenues (USDm)	461	651
EBITDA (USDm)	304	484
Net result (USDm)	39	10
Net interest-bearing debt (USDm)	2 783	2 159

During the first six months, the company reported consolidated revenues of USD 461 (651) million. Production in the period was 61.5 (61.6) thousand barrels of oil equivalent per day ("mboepd"), realising an average oil price of USD 44 (62) per barrel.

EBITDA amounted to USD 304 (484) million in the period and EBIT was USD 51 (192) million. Net profit for the first half of 2016 were USD 39 (10) million, translating into an EPS of USD 0.19 (0.05).

Per 30 June, 2016, the company had net interest-bearing debt of 2,783 million and cash and undrawn credit of about USD 1.02 billion.

The company did not have any serious or high potential HSE incidents during the first half of 2016. With the continued high activity level, special attention is paid to maintain a high HSE standard and preventing injuries and undesired events related to all activities.

The Alvheim fields have had stable operations and high uptime in the first half of 2016. First oil from the tri-lateral BoaKamNorth well was achieved in May. Drilling of the Viper-Kobra wells were finalized in June and the development is progressing according to plan towards first oil at end of 2016.

The Ivar Aasen development made good progress during the first half of 2016. The drilling program is well ahead of schedule with sufficient well capacity to deliver the initial production profile. Construction of the topside and living quarters were completed during the first half of the year. In July, the modules will be lifted in place onto the jacket on the field. The project is on budget and plan towards first oil in the fourth quarter 2016.

The Johan Sverdrup project is progressing according to

plan toward first oil in the fourth quarter 2019. During the first half of 2016 the pre-drilling campaign and construction of jackets, topsides, subsea facilities and power from shore facilities commenced.

Estimated capital expenditures for Johan Sverdrup phase 1 has been reduced with 12 percent from the PDO (NOK 123 billion, nominal value) to NOK 108.5 billion, based on the same FX-assumptions as in the PDO. A debottlenecking study of phase 1 processing capacity has concluded with an increase from the PDO capacity estimate of 315 – 380 mboepd to 440 mboepd.

Det norske participated in six exploration wells during the first half of 2016. The Uptonia exploration well in PL554 was finished in the first quarter and was classified as dry. The company also participated in three exploration wells in the Askja/Krafla area, which were classified as minor discoveries and two sidetrack that were dry. The discoveries will be included in the evaluation of a field development in the Askja/Krafla area. In May, Det norske was awarded three licenses in the 23rd licencing round.

In April, the company obtained acceptance for a covenant amendment package from its bank consortium. The bank consortium in the company's USD 3.0 billion RBL and its USD 550 million revolving credit facility ("RCF") agreed to ease covenant levels to the end of 2019. In May, the bondholder meeting in DETNOR02 approved the same amendment package.

During the first half of 2016, Det norske acquired Noreco's Norwegian portfolio and Centrica Resources Norge AS' licenses in the Frigg Gamma Delta and Rind discoveries. In June, Det norske announced that the company has entered into an agreement with BP p.l.c. to merge with BP Norge AS, creating Aker BP ASA.

RISK AND UNCERTAINTY

Investment in Det norske involves risks and uncertainties as described in the company's annual report for 2015. As an oil and gas company operating on the Norwegian Continental Shelf, exploration results, reserve and resource estimates and estimates for capital and operating expenditures are associated with uncertainty. The field's production performance may be uncertain over time.

The company is exposed to various forms of financial risks, including, but not limited to, fluctuation in oil prices, exchange rates, interest rates and capital requirements; these are described in the company's annual report and accounts, and in note 30 to the accounts for 2015. The company is also exposed to uncertainties relating to the international capital markets and access to capital and this may influence the speed with which development projects can be accomplished. There are several risks relating to the implementation of the merger with BP Norge. These risks can relate to successful integration of BP Norge's business, the company's ability to transfer contracts currently held by BP Norge or transfer these on the same terms and the potential loss of key employees. Moreover, the company may fail to successfully implement synergies from consolidated tax positions or may discover contingent or other liabilities within BP Norge. Other business risks after the merger with BP Norge involve unexpected shutdowns as well as risks relating to capacity booking for transport of gas. There is also risk that the transaction may not be approved by the relevant authorities or the Extraordinary General Meeting.

OUTLOOK

The merger with BP Norway AS will create the leading offshore independent E&P company. Aker BP will have a balanced portfolio of operated assets and a high quality inventory of non-sanctioned discoveries, with potential for significant production growth in the coming years.

The combined company has the ambition to leverage on Det norske's lean and nimble business model and will gain access to state-of-the-art technological know-how and capabilities, through the industrial collaboration with BP. Preparations of integration work is well underway and closing of the transaction is expected late in the third quarter.

A 12-day planned shut-down at Alvheim is scheduled for August, which will impact third quarter production. The Viper and Kobra wells are expected to commence production before year-end.

The Ivar Aasen project is progressing well and remains on track for first oil in Q4 2016. Offshore installation of topside including living quarters will be carried out in July, followed by hook-up and commissioning. The Johan Sverdrup project is moving forward according to plan and the company sees potential for further cost reductions.

In July, the Maersk Interceptor rig is scheduled to drill the Rovarkula exploration prospect near Ivar Aasen, before drilling the Langfjellet prospect in the North of Alvheim area.

Det norske (ex. BP Norge) expects 2016 CAPEX to be USD 900 – 920 million, a reduction from the previous range due to project cost savings. Exploration expenditures are expected to be USD 200 – 220 million, an increase due to added number of wells. Production guidance for 2016 is reiterated between 55 and 60 mboepd and production cost is expected to average in the range 8 to 9 USD per barrel of oil equivalent.

The company's balance sheet and funding outlook will be significantly strengthened following the merger with BP Norge AS. Going forward, the company will assess the composition of its capital structure, including optimal covenant structure and increased borrowing capacity. The company aims to pay dividends from the fourth quarter 2016, conditional upon the approval of its creditors.

FINANCIAL STATEMENTS WITH NOTES

INCOME STATEMENT (Unaudited)

		Group
		Q2 01.01.-30.06.
(USD 1 000)	Note	2016	2015	2016	2015
Petroleum revenues	2	271 272	336 084	472 040	659 832
Other operating income	2	-15 608	-14 234	-11 527	-9 059
Total operating income		255 665	321 849	460 513	650 774
Exploration expenses	3	36 214	24 949	72 329	39 471
Production costs		39 116	50 686	73 490	90 035
Depreciation	5	120 264	117 354	234 582	239 578
Impairments	4, 5	-19 644	-	18 319	52 773
Other operating expenses		5 410	22 550	10 741	36 947
Total operating expenses		181 360	215 539	409 461	458 805
Operating profit/loss		74 305	106 310	51 052	191 969
Interest income		1 523	913	2 340	1 175
Other financial income		10 437	8 135	41 194	55 759
Interest expenses		21 125	18 653	41 826	38 721
Other financial expenses		19 786	33 532	23 040	65 841
Net financial items	6	-28 951	-43 136	-21 331	-47 628
Profit/loss before taxes		45 353	63 174	29 720	144 340
Taxes (+)/tax income (-)	7	39 046	55 897	-8 821	134 624
Net profit/loss		6 308	7 277	38 541	9 716
Weighted average no. of shares outstanding and fully diluted Earnings/(loss) after tax per share		202 618 602 0.03	202 618 602 0.04	202 618 602 0.19	202 618 602 0.05

STATEMENT OF COMPREHENSIVE INCOME (Unaudited)

		Group
			Q2	01.01.-30.06.
(USD 1 000)	Note	2016	2015	2016	2015
Profit/loss for the period		6 308	7 277	38 541	9 716
Items which will not be reclassified over profit and loss (net of taxes)
Currency translation adjustment		-	-	-59	-
Total comprehensive income in period		6 308	7 277	38 482	9 716

STATEMENT OF FINANCIAL POSITION (Unaudited)

			Group
(USD 1 000)	Note	30/06/2016	30/06/2015	31/12/2015
ASSETS
Intangible assets
Goodwill	5	739 383	1 133 930	767 571
Capitalized exploration expenditures	5	316 913	309 096	289 980
Other intangible assets	5	609 943	612 421	648 030
Tangible fixed assets
Property, plant and equipment	5	3 305 081	2 803 703	2 979 434
Financial assets
Long-term receivables		1 724	4 725	3 782
Long-term tax receivable	7	28 090	-	-
Other non-current assets	8	13 545	4 523	12 628
Long-term derivatives	12	2 287	-	-
Total non-current assets		5 016 966	4 868 398	4 701 425
Inventories
Inventories		35 816	26 606	31 533
Receivables
Accounts receivable		43 572	53 981	85 546
Other short-term receivables	9	227 306	160 209	105 190
Other current financial assets		2 951	3 136	2 907
Tax receivables	7	206 749	-	126 391
Short-term derivatives	12	6 774	639	45 217
Cash and cash equivalents
Cash and cash equivalents	10	68 393	187 928	90 599
Total current assets		591 561	432 499	487 384
TOTAL ASSETS		5 608 527	5 300 897	5 188 809

STATEMENT OF FINANCIAL POSITION (Unaudited)

			Group
(USD 1 000)	Note	30/06/2016	30/06/2015	31/12/2015
EQUITY AND LIABILITIES
Equity
Share capital	11	37 530	37 530	37 530
Share premium		1 029 617	1 029 617	1 029 617
Other equity		-689 639	-405 769	-728 121
Total equity		377 508	661 378	339 026
Non-current liabilities
Deferred taxes	7	1 439 940	1 353 978	1 356 114
Long-term abandonment provision	16	445 085	501 339	412 805
Provisions for other liabilities		1 204	3 660	1 638
Long-term bonds	14	515 486	528 800	503 440
Other interest-bearing debt	15	2 336 361	1 818 148	2 118 935
Long-term derivatives	12	38 117	17 536	62 012
Current liabilities
Trade creditors		74 879	39 548	51 078
Accrued public charges and indirect taxes		7 343	9 237	9 060
Tax payable	7	-	47 142	-
Short-term derivatives )	12	230	5 820	13 506
Short-term abandonment provision	16	17 504	7 894	10 520
Other current liabilities	13	354 870	306 416	310 675
Total liabilities		5 231 019	4 639 519	4 849 783
TOTAL EQUITY AND LIABILITIES		5 608 527	5 300 897	5 188 809

STATEMENT OF CHANGES IN EQUITY - GROUP (Unaudited)

				Other equity
			Other comprehensive income
		Share	Other paid-in	Actuarial	Foreign currency translation	Retained	Total other
(USD 1 000)	Share capital	premium	capital	gains/(losses)	reserves*	earnings	equity	Total equity
Equity as of 31.12.2014	37 530	1 029 617	573 083	-105	-115 491	-872 972	-415 485	651 662
Profit/loss for the period 01.01.2015 - 31.12.2015	-	-	-	17	-	-312 652	-312 636	-312 636
Equity as of 31.12.2015	37 530	1 029 617	573 083	-88	-115 491	-1 185 625	-728 121	339 026
Profit/loss for the period 01.01.2016 - 30.6.2016	-	-	-	-	-59	38 541	38 482	38 482
Equity as of 30.6.2016	37 530	1 029 617	573 083	-88	-115 550	-1 147 083	-689 639	377 508

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

STATEMENT OF CASH FLOW (Unaudited)

		Group
			Q2 01.01.-30.06.
(USD 1 000)	Note	2016	2015	2016	2015	2015
CASH FLOW FROM OPERATING ACTIVITIES
Profit/loss before taxes		45 353	63 174	29 720	144 340	-113 607
Taxes paid during the period		-1 268	-126 364	-1 268	-190 506	-320 618
Tax refund during the period		-	-	-	-	87 662
Depreciation	5	120 264	117 354	234 582	239 578	480 959
Net impairment losses	4, 5	-19 644	-	18 319	52 773	430 468
Accretion expenses	6, 16	6 063	6 551	11 875	12 947	26 351
Interest expenses	6	39 599	29 242	77 234	54 308	127 620
Interest paid		-47 481	-21 280	-76 913	-46 743	-124 276
Changes in derivatives	2, 6	34 876	3 038	-1 014	-8 746	-793
Amortized loan costs	6	4 287	5 077	7 396	11 679	17 480
Amortization of fair value of contracts assumed in the
Marathon acquisition			-2 878		-2 878	-2 878
Expensed capitalized dry wells	3	17 938	10 185	34 389	9 876	11 682
Changes in inventories, accounts payable and receivables		-161 403	-86 177	-60 623	-261 163	-13 060
Changes in abandonment liabilities through income statement		-	-	-	-	-1 569
Changes in other current balance sheet items		88 695	45 444	49 414	308 784	81 048
NET CASH FLOW FROM OPERATING ACTIVITIES		127 279	43 366	323 110	324 250	686 467
CASH FLOW FROM INVESTMENT ACTIVITIES
Payment for removal and decommissioning of oil fields	16	-1 714	-2 042	-3 020	-3 176	-12 508
Disbursements on investments in fixed assets	5	-278 872	-212 561	-488 151	-451 463	-917 150
Acquisition of Premier Oil Norge AS (net of cash acquired)		-	-	-	-	-125 600
Disbursements on investments in capitalized exploration expenditures and
other intangible assets	5	-44 039	-10 709	-65 267	-31 914	-113 051
NET CASH FLOW FROM INVESTMENT ACTIVITIES		-324 625	-225 312	-556 438	-486 553	-1 168 310
CASH FLOW FROM FINANCING ACTIVITIES
Repayment of short-term debt		-	-	-	-	-70 938
Repayment of long-term debt		-	-330 000	-	-330 000	-330 000
Net proceeds from issuance of long-term debt		112 328	288 687	212 328	388 687	685 620
NET CASH FLOW FROM FINANCING ACTIVITIES		112 328	-41 313	212 328	58 687	284 683
Net change in cash and cash equivalents		-85 019	-223 258	-20 999	-103 616	-197 160
Cash and cash equivalents at start of period		154 618	411 691	90 599	296 244	296 244
Effect of exchange rate fluctuation on cash held		-1 206	-504	-1 206	-4 699	-8 485
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	68 393	187 928	68 393	187 928	90 599
SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD
Bank deposits and cash		62 411	182 802	62 411	182 802	86 201
Restricted bank deposits		5 983	5 126	5 983	5 126	4 398
CASH AND CASH EQUIVALENTS AT END OF PERIOD	10	68 393	187 928	68 393	187 928	90 599

NOTES

(All figures in USD 1 000)

These interim financial statements have been prepared in accordance with the International Financial Reporting Standards as adopted by the EU (IFRS) IAS 34 "Interim Financial Reporting", thus the interim financial statements do not include all information required by IFRS and should be read in conjunction with the company's annual financial statement as at 31 December 2015. These interim financial statements have not been subject to review or audit by independent auditors.

Note 1 Accounting principles

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

The group has changed the presentation of accretion expenses since Q4 2015. It is now included in the line item other financial expenses, while it has been presented as interest expenses prior to 2016. In addition, following the change from defined benefit to defined contribution scheme, pension is no longer presented on a separate line in the Statement of financial position. Comparable figures have been restated accordingly.

During Q2 2016, the subsidiaries Det norske Exploration AS (previously Svenska Petroleum Exploration AS) and Det norske oil AS (previously Premier Oil Norge AS) have been liquidated following transfer of their activity to Det norske oljeselskap ASA in Q4 2015 and Q1 2016 respectively. As of 30 June 2016 there is thus no other subsidaries than those mentioned in note 9, which have not been consolidated in this report due to materiality considerations.

Note 2 Operating income

	Group
	Q2			01.01.-30.06.
Breakdown of petroleum revenues (USD 1 000)	2016	2015	2016	2015
Recognized income oil	250 022	306 826	430 410	594 703
Recognized income gas	19 311	28 375	37 414	63 515
Tariff income	1 940	883	4 217	1 614
Total petroleum revenues	271 272	336 084	472 040	659 832
Breakdown of produced volumes (barrels of oil equivalent)
Oil	5 025 916	4 658 320	9 845 062	9 752 709
Gas	656 148	652 728	1 352 941	1 403 074
Total produced volumes	5 682 064	5 311 049	11 198 003	11 155 783
Other operating income (USD 1 000)
Realized gain/loss (-) on oil derivatives	5 988	-4 551	23 062	-4 551
Unrealized gain/loss (-) on oil derivatives	-25 312	-10 836	-38 443	-6 090
Other income	3 716	1 152	3 854	1 582
Total other operating income	-15 608	-14 234	-11 527	-9 059

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

Note 3 Exploration expenses

	Group
		Q2	01.01.-30.06.
Breakdown of exploration expenses (USD 1 000)	2016	2015	2016	2015
Seismic	5 171	3 952	6 195	7 166
Area fee	2 842	1 627	5 104	3 771
Expensed capitalized wells this year	9 439	8 884	23 173	8 584
Expensed capitalized wells previous years	8 498	-	11 216	-9
Other exploration expenses	10 263	10 486	26 640	19 960
Total exploration expenses	36 214	24 949	72 329	39 471

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

Note 4 Impairments

Impairment testing

Impairment tests of individual cash-generating units are performed when impairment triggers are identified. In Q2 2016, no impairment triggers have been identified. Mainly due to increased forward prices compared to the end of Q1 2016, a reversal of the impairment on Gina Krog has been made during Q2 2016. The reversal amounts to USD 19.6 million.

As described in previous financial reporting, the technical goodwill recognized in relation to the acquisition of Marathon Oil Norge AS will be subject to impairment charges as it is fully allocated to the Alvheim CGU. Hence, a quarterly impairment charge is expected if all assumptions remain unchanged. However, in Q2 2016 there has been an increase in the oil and gas forward curves compared to Q1 2016 and the company's calculation shows that no impairment charge of the Alvheim CGU is needed in Q2 2016. In Q1 2016 the impairment of this technical goodwill amounted to USD 28.2 million.

Note 5 Tangible assets and intangible assets

TANGIBLE FIXED ASSETS - GROUP

		Production	Fixtures and
	Assets under	facilities	fittings, office
(USD 1 000)	development	including wells	machinery	Total
Book value 31.12.2015	1 493 795	1 470 881	14 758	2 979 434
Acquisition cost 31.12.2015	1 505 779	2 514 487	35 506	4 055 772
Additions	203 066	11 946	1 049	216 061
Disposals	-	-	91	91
Reclassification	8 523	-8 514	-9	-
Acquisition cost 31.3.2016	1 717 368	2 517 919	36 455	4 271 742
Accumulated depreciation and impairments 31.3.2016	21 211	1 138 752	21 949	1 181 911
Book value 31.3.2016	1 696 158	1 379 167	14 506	3 089 831
Acquisition cost 31.3.2016	1 717 368	2 517 919	36 455	4 271 742
Additions	218 005	73 247	1 135	292 387
Reclassification*	-56 830	56 801		-30
Acquisition cost 30.6.2016	1 878 543	2 647 967	37 590	4 564 100
Accumulated depreciation and impairments 30.6.2016	1 566	1 234 260	23 193	1 259 019
Book value 30.6.2016	1 876 976	1 413 707	14 397	3 305 081
Depreciation Q2 2016	-	95 508	1 244	96 753
Depreciation 01.01.2016 - 30.6.2016	-	190 106	2 445	192 551
Impairments/reversal of impairments Q2 2016	-19 644	-	-	-19 644
Impairments/reversal of impairments 01.01.2016 - 30.6.2016	-10 418	548	-	-9 870

* The recalssification is related to the BoaKamNorth well which started producing in Q2 2016

Capitalized exploration expenditures are reclassified to "Fields under development" when the field enters into the development phase. If development plans are subsequently reevaluated, the associated costs remain in assets under development and are not reclassified back to exploration assets. Fields under development are reclassified to "Production facilities" from the start of production. Production facilities, including wells, are depreciated in accordance with the Unit of Production Method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3-5 years. Removal and decommissioning costs are included as production facilities or fields under development.

INTANGIBLE ASSETS - GROUP

	Other intangible assets			Exploration
(USD 1 000)	Licences etc.	Software	Total	wells	Goodwill
Book value 31.12.2015	646 487	1 543	648 030	289 980	767 571
Acquisition cost 31.12.2015	789 316	9 149	798 465	289 980	1 561 880
Additions	595	-	595	20 633	-
Disposals/expensed dry wells	-	-	-	16 451	-
Acquisition cost 31.3.2016	789 911	9 149	799 059	294 161	1 561 880
Accumulated depreciation and impairments 31.3.2016	161 142	7 812	168 954	-	822 498
Book value 31.3.2016	628 769	1 336	630 105	294 161	739 383
Acquisition cost 31.3.2016 Additions Disposals/expensed dry wells	789 911 2 583 -	9 149 - -	799 059 2 583 -	294 161 41 427 17 938	1 561 880 -
Reclassification	767	-	767	-737
Acquisition cost 30.6.2016	793 260	9 149	802 409	316 913	1 561 880
Accumulated depreciation and impairments 30.6.2016	184 446	8 019	192 466	-	822 498
Book value 30.6.2016	608 814	1 129	609 943	316 913	739 383
Depreciation Q2 2016	23 305	207	23 512	-	-
Depreciation 01.01.2016 - 30.6.2016	41 617	414	42 031	-	-
Impairments Q2 2016	-	-	-	-
Impairments 01.01.2016 - 30.6.2016	-	-	-	-	28 189

See Note 4 for information regarding impairment charges.

	Group
	Q2		01.01.-30.06.
Depreciation in the Income statement (USD 1 000)	2016	2015	2016	2015
Depreciation of tangible fixed assets	96 753	97 597	192 551	200 724
Depreciation of intangible assets	23 512	19 757	42 031	38 855
Total depreciation in the Income statement	120 264	117 354	234 582	239 578

	Group
	Q2		01.01.-30.06.
Impairment in the Income statement (USD 1 000)	2016	2015	2016	2015
Impairment/reversal of tangible fixed assets	-19 644	-	-9 870	-
Impairment of goodwill	-	-	28 189	52 773
Total impairment in the Income statement	-19 644	-	18 319	52 773

Note 6 Financial items

	Group
		Q2	01.01.-30.06.
(USD 1 000)	2016	2015	2016	2015
Interest income	1 523	913	2 340	1 175
Realised gains on derivatives	1 237	193	1 737	193
Return on financial investments	-	14	-	24
Change in fair value of derivatives	-	7 928	39 457	27 232
Currency gains	9 200	-	-	28 311
Total other financial income	10 437	8 135	41 194	55 759
Interest expenses	39 599	29 242	77 234	54 308
Capitalized interest cost, development projects	-22 761	-15 666	-42 804	-27 266
Amortized loan costs	4 287	5 077	7 396	11 679
Total interest expenses	21 125	18 653	41 826	38 721
Currency losses	-	8 527	1 509	-
Realised loss on derivatives	1 239	18 324	5 029	40 498
Change in fair value of derivatives	9 564	130	-	12 396
Accretion expenses	6 063	6 551	11 875	12 947
Other financial expenses	2 921	-	4 627	-
Total other financial expenses	19 786	33 532	23 040	65 841
Net financial items	-28 951	-43 136	-21 331	-47 628

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

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

Note 7 Taxes

	Group
	Q2		01.01.-30.06.
Taxes for the period appear as follows (USD 1 000)	2016	2015	2016	2015
Calculated current year tax/exploration tax refund	-22 745	68 083	-28 835	76 163
Change in deferred taxes in the Income statement	56 840	-10 622	15 262	63 018
Prior period adjustments	4 951	-1 564	4 752	-4 557
Tax expenses (+)/tax income (-)	39 046	55 897	-8 821	134 624

		Group
Calculated tax receivable (+)/tax payable (-) (USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Tax receivable/payable at 1.1.	126 391	-189 098	-189 098
Current year tax (-)/tax receivable (+)	28 835	-76 163	-49 776
Tax receivable related to acquisition of Svenska Petroleum Exploration AS/Premier Oil Norge AS	60 379	-	108 047
Tax receivable related to acquisition of licences	4 075	-	-
Tax payment/tax refund	1 268	190 506	232 956
Prior period adjustments	4 729	10 664	11 580
Revaluation of tax receivable	9 163	16 950	12 682
Total tax receivable (+)/tax payable (-)	234 840	-47 142	126 391
Tax receivable included as non-current assets	28 090
Tax receivable included as current assets	206 749

		Group
Deferred taxes (-)/deferred tax asset (+) (USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Deferred taxes/deferred tax asset 1.1.	-1 356 114	-1 286 357	-1 286 357
Change in deferred taxes in the Income statement	-15 262	-63 018	-153 927
Reclassification of loss carried forward from Premier Oil Norge AS	-60 379	-	-
Deferred tax related to acquisition of Svenska Petroleum Exploration AS/Premier Oil Norge AS	-	-	91 151
Deferred tax related to impairment, disposal and licence transactions	1 401	1 504	-
Prior period adjustment	-9 587	-6 107	-6 921
Deferred tax charged to OCI and equity	-	-	-59
Net deferred tax (-)/deferred tax asset (+)	-1 439 940	-1 353 978	-1 356 114

	Group
	Q2		01.01.-30.06.
Reconciliation of tax expense (USD 1 000)	2016	2015	2016	2015
25%/27% company tax on profit before tax	11 338	17 057	7 430	38 972
53%/51% special tax on profit before tax	24 037	32 219	15 752	73 614
Tax effect on uplift	-26 527	-23 044	-51 124	-47 445
Permanent difference on impairment	-		21 987	41 163
Foreign currency translation of NOK monetary items	-3 955	15 435	4 719	-13 693
Foreign currency translation of USD monetary items	-23 445	39 260	102 174	-82 196
Tax effect of financial and other 25%/27% items	33 235	1 466	-52 635	71 356
Revaluation of tax balances*	20 018	-28 695	-59 926	51 623
Other items (other permanent differences and prior period adjustment)	4 344	2 199	2 801	1 231
Total taxes (+)/tax income (-)	39 046	55 898	-8 821	134 624

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

In accordance with statutory requirements, the calculation of current tax is required to be based on NOK functional currency. This may impact the tax rate when the functional currency is different from NOK.

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

Note 8 Other non-current assets

		Group
(USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Shares in Alvheim AS	10	10	10
Shares in Det norske oljeselskap AS	1 021	1 021	1 021
Shares in Sandvika Fjellstue AS	1 814	1 814	1 814
Investment in subsidiaries	2 845	2 845	2 845
Tenancy deposit	1 589	1 679	1 512
Other non-current assets	9 110	-	8 272
Total other non-current assets	13 545	4 523	12 628

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

Det norske oil AS and Det norske Exploration AS have been liquidated during Q2 2016.

Note 9 Other short-term receivables

		Group
(USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Receivables related to deferred volume at Atla	3 457	7 087	5 673
Pre-payments, including rigs	29 814	29 136	21 634
VAT receivable	8 760	5 716	6 121
Underlift of petroleum	28 942	24 797	3 696
Accrued income from sale of petroleum products	43 297	53 233	1 866
Other receivables, mainly from licenses	113 035	40 239	66 200
Total other short-term receivables	227 306	160 209	105 190

Note 10 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.

		Group
Breakdown of cash and cash equivalents (USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Bank deposits	62 411	182 802	86 201
Restricted funds (tax withholdings)	5 983	5 126	4 398
Cash and cash equivalents	68 393	187 928	90 599
Unused revolving credit facility (see Note 15)	550 000	550 000	550 000
Unused reserve-based lending facility (see Note 15)	403 000	1 010 000	731 370

Note 11 Share capital

		Group
(USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Share capital	37 530	37 530	37 530
Total number of shares (in 1 000)	202 619	202 619	202 619
Nominal value per share in NOK	1.00	1.00	1.00

Note 12 Derivatives

	Group
(USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Unrealized gain currency contracts	2 287	-	-
Long-term derivatives included in assets	2 287	-	-
Unrealized gain on commodity derivatives	6 774	-	45 217
Unrealized gain currency contracts	-	639	-
Short-term derivatives included in assets	6 774	639	45 217
Total derivatives included in assets	9 061	639	45 217
Unrealized losses currency contracts	-	173	7 840
Unrealized losses interest rate swaps	38 117	16 911	54 172
Unrealized losses commodities	-	452	-
Long-term derivatives included in liabilities	38 117	17 536	62 012
Unrealized losses currency contracts	230	56	13 506
Unrealized losses interest rate swaps	-	78	-
Unrealized losses commodities	-	5 686	-
Short-term derivatives included in liabilities	230	5 820	13 506
Total derivatives included in liabilities	38 347	23 356	75 518

The company has different types of hedging instruments. The commodity derivatives are used to hedge the risk of oil price reduction. The company manages its interest rate exposure using interest rate derivatives, including a cross currency interest rate swap. Foreign currency exchange contracts are used to swap USD into foreign currencies, mainly NOK, EUR, GBP and SGD, in order to reduce currency risk related to expenditures. Currently all these derivatives are marked to market with changes in market value recognized in the Income statement.

Note 13 Other current liabilities

	Group
Breakdown of other current liabilities (USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Current liabilities related to overcall in licences	46 506	26 700	33 444
Share of other current liabilities in licences	264 533	143 295	184 010
Overlift of petroleum	4 192	12 223	17 088
Fair value of contracts assumed in acquisition of Marathon Oil Norge AS*	3 160	21 888	12 009
Other current liabilities**	36 478	102 310	64 125
Total other current liabilities	354 870	306 416	310 675

* The negative contract value is related to a rig contract entered into by Marathon Oil Norge AS, which was different from current market terms at the time of acquisition at 15 October 2014. The fair value was based on the difference between market price and contract price. The balance was initially split between current and non-current liabilities based on the cash flows in the contract, and amortized over the lifetime of the contract, which expires later in 2016.

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

Note 14 Long-term bonds

		Group
(USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Principal, bond Nordic Trustee 1)	220 255	234 269	208 744
Principal, bond Nordic Trustee 2)	295 231	294 532	294 696
Total bond	515 486	528 800	503 440

1) The loan is denominated in NOK and runs from July 2013 to July 2020 and carries an interest rate of 3 month NIBOR + 6.5 per cent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The loan is unsecured.

In May 2016 the bondholders of DETNOR02 accepted the same covenant amendment package as for the RBL and RCF loans, as described in note 15 below. As compensation, the DETNOR02 bonds will be repaid at 104 percent of par at maturity in 2020.

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

Note 15 Other interest-bearing debt

	Group
(USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Reserve-based lending facility	2 336 361	1 818 148	2 118 935
Total other interest-bearing debt	2 336 361	1 818 148	2 118 935

The RBL Facility was established in 2014 and is a senior secured seven-year USD 3.0 billion facility and includes an additional uncommitted accordion option of USD 1.0 billion. The interest rate is from 1 - 6 months LIBOR plus a margin of 2.75 per cent, with a utilization fee of 0.5 per cent on outstanding loan. In addition a commitment fee of 1.1 per cent is paid on unused credit.

In March 2016, the company completed an interim redetermination process with its bank consortium in connection with the process to amend the levels on certain of its covenants. The borrowing base availability in the first half of 2016 was reset to USD 2.8 billion, which is USD 0.1 billion below the availability resulting from the redetermination in December 2015. Furthermore, the borrowing base availability in the second half of 2016 has been set to USD 2.9 billion, in line with the redetermination process completed in December 2015. As a result of this exercise, no additional redetermination was performed during Q2 2016. The next scheduled redetermination process for the company will be in December 2016.

A revolving credit facility ("RCF") of USD 550 million was completed with a consortium of banks at June 2015. The loan has a tenor of four years with extension options of one plus one year at the lenders discretion. The loan carries a margin of 4 per cent, stepping up by 0.5 per cent annually after 3, 4 and 5 years, plus a utilization fee of 1.5 per cent. In addition a commitment fee of 2.2 per cent is paid on unused credit. This facility is undrawn as of 30 June 2016.

In April 2016 the company obtained acceptance for a covenant amendment package from its bank consortium, and as a result the covenants levels in the RBL and RCF was updated as follows: Leverage Ratio shall be maximum 6 in the quarters starting from 30 June 2016 and ending 31 December 2017, thereafter maximum 5.5 between 31 March 2018 up to and including 31 December 2018, further maximum 6 between 31 March 2019 upt to and including 31 December 2019, and thereafter maximum 3.5. The Interest Coverage Ratio shall be minimum 2 in the quarters starting from 30 June 2016 and ending 30 September 2017, thereafter minimum 2.3 from 31 December 2017 up to and including 30 September 2018, further minimum 2 from 31 December 2018 up to and including 31 December 2019, and thereafter minimum 3.5.

Note 16 Provision for abandonment liabilities

		Group
(USD 1 000)	30/06/2016	30/06/2015	31/12/2015
Provisions as of 1 January	423 325	489 051	489 051
Incurred cost removal	-3 020	-3 176	-12 508
Accretion expense - present value calculation	11 875	12 947	26 351
Change in estimates and incurred liabilities on new fields*	30 409	10 410	-79 569
Total provision for abandonment liabilities	462 589	509 233	423 325
Break down of the provision to short-term and long-term liabilities
Short-term	17 504	7 894	10 520
Long-term	445 085	501 339	412 805
Total provision for abandonment liabilities	462 589	509 233	423 325

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

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

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

Note 17 Contingent liabilities

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

Note 18 Subsequent events

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

Note 19 Investments in joint operations

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

Fields operated:	30/06/2016	31/03/2016	Fields non-operated:	30/06/2016	31/03/2016
Alvheim	65.000 %	65.000 % Atla		10.000 %	10.000 %
Bøyla	65.000 %	65.000 % Enoch		2.000 %	2.000 %
Ivar Aasen Unit	34.786 %		34.786 % Gina Krog	3.300 %	3.300 %
Jette Unit	70.000 %		70.000 % Johan Sverdrup ****	11.573 %	11.573 %
Vilje	46.904 %	46.904 % Jotun		7.000 %	7.000 %
Volund	65.000 %	65.000 % Varg		5.000 %	5.000 %

Production licences in which Det norske is the operator:			Production licences in which Det norske is a partner:
Licence:	30/06/2016	31/03/2016	Licence:	30/06/2016	31/03/2016
PL 001B	35.000 %		35.000 % PL 006C***	15.000 %	0.000 %
PL 026B***	92.130 %		62.130 % PL 018DS***	13.338 %	0.000 %
PL 027D	100.000 %	100.000 % PL 019C		30.000 %	30.000 %
PL 028B	35.000 %		35.000 % PL 026***	30.000 %	0.000 %
PL 036C	65.000 %		65.000 % PL 029B	20.000 %	20.000 %
PL 036D	46.904 %	46.904 % PL 035		50.000 %	50.000 %
PL 088BS	65.000 %		65.000 % PL 035C	50.000 %	50.000 %
PL 103B	70.000 %	70.000 % PL 038		5.000 %	5.000 %
PL 150	65.000 %		65.000 % PL 038D	30.000 %	30.000 %
PL 150B	65.000 %		65.000 % PL 048D	10.000 %	10.000 %
PL 169C	50.000 %		50.000 % PL 102C	10.000 %	10.000 %
PL 203	65.000 %		65.000 % PL 102D	10.000 %	10.000 %
PL 203B	65.000 %		65.000 % PL 102F	10.000 %	10.000 %
PL 242	35.000 %		35.000 % PL 102G	10.000 %	10.000 %
PL 340	65.000 %	65.000 % PL 265		20.000 %	20.000 %
PL 340BS	65.000 %	65.000 % PL 272		50.000 %	50.000 %
PL 364	100.000 %	100.000 % PL 457		40.000 %	40.000 %
PL 406	50.000 %		50.000 % PL 457BS	40.000 %	40.000 %
PL 407	50.000 %		50.000 % PL 492***	60.000 %	40.000 %
PL 442***	90.000 %	60.000 % PL 502		22.222 %	22.222 %
PL 460	100.000 %		100.000 % PL 507***	25.000 %	0.000 %
PL 494*	0.000 %	30.000 % PL 533		35.000 %	35.000 %
PL 494B*	0.000 %	30.000 % PL 550		10.000 %	10.000 %
PL 494C*	0.000 %	30.000 % PL 554		30.000 %	30.000 %
PL 504	47.593 %		47.593 % PL 554B	30.000 %	30.000 %
PL 539	40.000 %		40.000 % PL 554C	30.000 %	30.000 %
PL 626	50.000 %	50.000 % PL 574*		0.000 %	10.000 %
PL 659	20.000 %	20.000 % PL 583*		0.000 %	45.000 %
PL 663*	0.000 %	30.000 % PL 613		20.000 %	20.000 %
PL 677	60.000 %		60.000 % PL 616***	20.000 %	0.000 %
PL 690***	50.000 %	30.000 % PL 617		35.000 %	35.000 %
PL 701***	40.000 %	0.000 % PL 627		20.000 %	20.000 %
PL 709	40.000 %		40.000 % PL 627B	20.000 %	20.000 %
PL 715	40.000 %	40.000 % PL 653		30.000 %	30.000 %
PL 724	40.000 %	40.000 % PL 672		25.000 %	25.000 %
PL 724B	40.000 %	40.000 % PL 689		20.000 %	20.000 %
PL 736S	65.000 %		65.000 % PL 689B	20.000 %	20.000 %
PL 748***	50.000 %	30.000 % PL 694		20.000 %	20.000 %
PL 762***	20.000 %		0.000 % PL 722***	20.000 %	10.000 %
PL 777	40.000 %	40.000 % PL 730*		0.000 %	30.000 %
PL 777B	40.000 %		40.000 % PL 730B*	0.000 %	30.000 %
PL 790	30.000 %	30.000 % PL 778		20.000 %	20.000 %
PL 814	40.000 %		40.000 % PL 782S	20.000 %	20.000 %
PL 818	40.000 %		40.000 % PL 782SB	20.000 %	20.000 %
PL 821	60.000 %	60.000 % PL 797		25.000 %	25.000 %
PL 822S	60.000 %	60.000 % PL 804		30.000 %	30.000 %
PL 843	40.000 %	40.000 % PL 813		3.300 %	3.300 %
PL 858**	40.000 %	0.000 % PL 842		30.000 %	30.000 %
Number	44		45 PL 844	20.000 %	20.000 %
			PL 852**	40.000 %	0.000 %
* Relinquished licences or Det norske has withdrawn from the licence.			PL 857**	20.000 %	0.000 %
** Interest awarded in the 23 Licensing round announced in May 2016.			Number	47	44

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

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

Note 20 Results from previous interim reports

		2016	2015			2014
(USD 1 000)	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Total operating income	255 665	204 848	254 634	316 393	321 850	328 924	345 670	18 334
Exploration expenses	36 214	36 115	18 867	18 066	24 949	14 523	51 491	71 778
Production costs	39 116	34 374	24 077	26 888	50 686	39 349	44 400	7 906
Depreciation	120 264	114 318	111 590	129 790	117 354	122 224	104 183	28 080
Impairments	-19 644	37 964	191 939	185 756	-	52 773	319 018	-
Other operating expenses	5 410	5 330	3 228	11 433	22 550	14 397	10 679	993
Total operating expenses	181 360	228 101	349 701	371 932	215 539	243 266	529 772	108 757
Operating profit/loss	74 305	-23 253	-95 067	-55 539	106 310	85 658	-184 102	-90 423
Net financial items	-28 951	7 620	-56 138	-51 205	-43 136	-4 492	-12 788	-30 143
Profit/loss before taxes	45 353	-15 633	-151 205	-106 744	63 174	81 166	-196 889	-120 567
Taxes (+)/tax income (-)	39 046	-47 866	4 980	59 441	55 897	78 727	89 997	-103 615
Net profit/loss	6 308	32 233	-156 184	-166 185	7 277	2 439	-286 887	-16 952

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

STATEMENT BY THE BOARD OF DIRECTORS AND CHIEF EXECUTIVE OFFICER

Pursuant to the Norwegian Securities Trading Act section § 5-5 with pertaining regulations, we hereby confirm that, to the best of our knowledge, the company's interim financial statements for the period 1 January to 30 June 2016 have been prepared in accordance with IFRS, as provided for by the EU, and in accordance with the requirements for additional information provided for by the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair picture of the company's liabilities, financial position and results overall.

To the best of our knowledge, the Board of Directors' half-yearly report together with the yearly report, gives a true and fair picture of the development, performance and financial position of the company, and includes a description of the principal risk and uncertainty factors facing the company.

The Board of Directors and the CEO of Det norske oljeselskap ASA

Oslo, 13 July 2016

Øyvind Eriksen, Chair of the Board Kjell Inge Røkke, Board member

Gro Kielland, Board member Kjell Pedersen, Board member

Lone Margrethe Olstad, Board member Karl Johnny Hersvik, Chief Executive Officer

Anne Marie Cannon, Deputy Chair Trond Brandsrud, Board member

Bjørn Thore Synsvoll Ribesen, Board member Terje Solheim, Board member

Katherine Jessie Martin (also known as Kitty Hall), Board member

Alternative performance measures

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

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

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

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

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

Equity ratio is total equity divided by total assets

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

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

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

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

NOTES