Quarterly Report • Apr 29, 2016
Quarterly Report
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QUARTERLY REPORT FOR DET NORSKE OLJESELSKAP
TRONDHEIM, 29 APRIL 2016
| • | 18 January: | Det norske announced a reduced CAPEX estimate for Johan Sverdrup phase 1 of NOK 14.5 billion from PDO |
|---|---|---|
| • | 18 January: | Det norske announced year-end 2015 P50 reserves of 498 mmboe |
| • | 19 January: | Det norske was offered ownership in ten new licenses, including six operatorships in the 2015 Awards in Pre-defined Areas |
| • | 2 March: | Det norske announced the acquisition of Noreco's Norwegian licence portfolio, including a NOK 45 million cash balance |
| • | 11 March: | The Corporate Assembly of Det norske elected Øyvind Eriksen as Chairman of Det norske's Board of Directors and Trond Brandsrud was elected as member of the Board |
• 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
| Unit | Q1 2016 | Q1 2015 | 2016 YTD | 2015 YTD | |
|---|---|---|---|---|---|
| Operating income | USDm | 205 | 329 | 205 | 329 |
| EBITDA | USDm | 129 | 261 | 129 | 261 |
| Net result | USDm | 32 | 2 | 32 | 2 |
| Earnings per share (EPS) | USD | 0.16 | 0.01 | 0.16 | 0.01 |
| Production cost per barrel | USD/boe | 6 | 7 | 6 | 7 |
| Depreciation per barrel | USD/boe | 21 | 21 | 21 | 21 |
| Cash flow from operations | USDm | 189 | 281 | 189 | 281 |
| Cash flow from investments | USDm | -232 | -261 | -232 | -261 |
| Total assets | USDm | 5 387 | 5 480 | 5 387 | 5 480 |
| Net interest-bearing debt | USDm | 2 584 | 1 965 | 2 584 | 1 965 |
| Cash and cash equivalents | USDm | 155 | 412 | 155 | 412 |
| Unit | Q1 2016 | Q1 2015 | 2016 YTD | 2015 YTD | |
|---|---|---|---|---|---|
| Production | |||||
| Alvheim (65%) | boepd | 38 416 | 37 736 | 38 416 | 37 736 |
| Atla (10%) | boepd | 306 | 467 | 306 | 467 |
| Bøyla (65%) | boepd | 9 084 | 8 341 | 9 084 | 8 341 |
| Enoch (2%) | boepd | - | - | - | - |
| Jette (70%) | boepd | 622 | 794 | 622 | 794 |
| Jotun (7%) | boepd | 106 | 149 | 106 | 149 |
| Varg (5%) | boepd | 460 | 322 | 460 | 322 |
| Vilje (46.9%) | boepd | 5 177 | 6 429 | 5 177 | 6 429 |
| Volund (65%) | boepd | 6 445 | 10 703 | 6 445 | 10 703 |
| SUM | boepd | 60 615 | 64 941 | 60 615 | 64 941 |
| Oil price | USD/bbl | 37 | 58 | 37 | 58 |
| Gas price | USD/scm | 0.18 | 0.29 | 0.18 | 0.29 |
Det norske oljeselskap ASA ("the company" or "Det norske") reported revenues of USD 205 (329) million in the first quarter of 2016. Production in the period was 60.6 (64.9) thousand barrels of oil equivalent per day ("mboepd"), realising an average oil price of USD 37 (58) per barrel.
EBITDA amounted to USD 129 (261) million in the quarter and EBIT was USD -23 (86) million, following an impairment of USD 38 (53) million in the quarter. Net profit for the quarter was USD 32 (2) million, translating into an EPS of USD 0.16 (0.01). Net interest-bearing debt amounted to USD 2,584 (1,965) million per March 31, 2016.
Production from the Alvheim area in the first quarter achieved a production efficiency of 99.3 percent. Drilling of the tri-lateral BoaKamNorth well was completed in January and the Viper well was spudded in February.
The drilling program at Ivar Aasen continues to progress ahead of schedule, with five oil producer wells and
one water injector well finalised. Construction of the topside is close to completion in Singapore and sail away is planned for first week of June. The project remains on schedule and budget towards the planned start-up in Q4 2016.
The Johan Sverdrup project is progressing according to plan. In February, the project passed a major milestone with the first steel cut for the drilling platform and drilling operations commenced in March.
The Uptonia exploration well in the Tampen area was completed as a dry well in March. Drilling operations commenced in the Krafla/Askja area in the quarter.
In March, Det norske announced an agreement to acquire Noreco's Norwegian license portfolio, including a NOK 45 million cash balance with effective date 1 January, 2016.
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.
| (USD million) | Q1 2016 | Q1 2015 |
|---|---|---|
| Operating income | 205 | 329 |
| EBITDA | 129 | 261 |
| EBIT | -23 | 86 |
| Pre-tax profit/loss | -16 | 81 |
| Net profit | 32 | 2 |
| EPS (USD) | 0.16 | 0.01 |
| (USD million) | Q1 2016 | Q1 2015 |
|---|---|---|
| Goodwill | 739 | 1 134 |
| PP&E | 3 090 | 2 679 |
| Cash & cash equivalents | 155 | 412 |
| Total assets | 5 387 | 5 480 |
| Equity | 371 | 654 |
| Interest-bearing debt | 2 739 | 2 376 |
Total operating revenues in the first quarter were USD 205 (329) million, lower than first quarter 2015 mainly due to lower oil prices. Petroleum revenues accounted for USD 201 (324) million, while other revenue was USD 4 (5) million, primarily relating to net realised and unrealised gains on commodity hedges.
Exploration expenses amounted to USD 36 (15) million in the quarter, reflecting dry hole costs, seismic costs, area fees and G&G activities. Production costs were USD 34 (39) million, equating to 6.2 USD/boe, including shipping and handling of 1.1 USD/boe. Other operating expenses amounted to USD 5 (14) million and depreciation was USD 114 (122) million, corresponding to 20.7 USD/boe.
Non-cash impairment losses were USD 38 (53) million, which is primarily related to impairment of technical goodwill that arose from the acquisition of Marathon Oil Norge AS. The impairment is primarily caused by decreasing oil futures prices compared to the previous quarter and is detailed in note 4.
The company recorded an operating loss of USD 23 (-86) million in the first quarter. The net profit for the period was USD 32 (2) million after net financial items of USD 8 (-4) million and a tax income of USD 48 (-79) million. Earnings per share were USD 0.16 (0.01).
Total intangible assets amounted to USD 1,664 (2,074) million, of which goodwill was USD 739 (1,134) million.
Property, plant and equipment increased to USD 3,090 (2,679) million and are detailed in note 5. Current tax receivables amounted to USD 215 (0) million at the end of the quarter, and details can be found in note 7.
The company's cash and cash equivalents were USD 155 (412) million as of 31 March. Total assets were USD 5,387 (5,480) million at the end of the quarter.
Equity increased to USD 371 (654) million at the end of the quarter, reflecting the net profit in the period.
Deferred tax liabilities amounted to USD 1,384 (1,363) million and are detailed in note 7. The main part of this tax liability relates to differences between tax value and book value on fixed assets.
Interest-bearing debt increased to USD 2,739 (2,376) million, consisting of the DETNOR02 bond of USD 223 million, the DETNOR03 bond of USD 295 million and the Reserve Based Lending ("RBL") facility of USD 2,221 million.
| (USD million) | Q1 2016 | Q1 2015 |
|---|---|---|
| Cash flow from operations | 189 | 281 |
| Cash flow from investments | -232 | -261 |
| Cash flow from financing | 100 | 100 |
| Net change in cash & cash eq. | 57 | 120 |
| Cash and cash eq. EOQ | 155 | 412 |
Net cash flow from operating activities was USD 189 (281) million.
Net cash flow from investment activities were USD -232 (-261) million. Investments in fixed assets amounted to USD 209 (239) million for the quarter, mainly reflecting CAPEX on Ivar Aasen, Alvheim and Johan Sverdrup. Investments in intangible assets including capitalised exploration were 21 (21) million in the quarter.
Net cash flow from financing activities totalled USD 100 (100) million, reflecting the amount drawn on the company's RBL facility in the quarter.
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") have agreed to ease covenant levels to the end of 2019. Following this, the company expects to continue to meet the covenant requirements in its RBL and RCF, even in a "lower for longer" oil price scenario. The new covenant thresholds are detailed in note 19.
In addition, the company is working to obtain an amicable solution with the DETNOR02 bondholders.
As part of the process, the company volunteered to conduct an interim redetermination of its borrowing base in the RBL facility. The borrowing base was set at USD 2.8 billion until July 2016 and to USD 2.9 billion from July to December 2016. Consequently, the next redetermination will be in December 2016.
At the end of the first quarter 2016, the company had cash and undrawn credit facilities of USD 1.23 billion.
The company seeks to reduce the risk connected to both foreign exchange rates, interest rates and commodity prices through hedging instruments.
During the first 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.
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 did not have any recordable injuries nor any serious or high potential incidents during the first quarter.
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 no supervisory activities from the authorities during the first quarter.
Det norske produced 5.5 (5.8) million barrels of oil equivalents ("mmboe") in the first quarter of 2016, corresponding to 60.6 (64.9) mboepd. The average realized oil price was USD 37 (58) per barrel, while gas revenues were recognized at market value of USD 0.18 (0.29) per standard cubic metre (scm).
The producing fields Alvheim (65 percent), Volund (65 percent), Bøyla (65 percent) and Vilje (46.9 percent) are all tied back to the production vessel Alvheim FPSO.
The production efficiency for the Alvheim FPSO in the first quarter was very high at 99.3 percent, significantly above the previous quarter (86.7), which was impacted by the failure of one of the gas export compressors.
The operator of the SAGE gas terminal is planning a 10-day planned shutdown in August 2016, which will cause Alvheim to shut down during this period.
The Transocean Winner drilling rig completed work on the tri-lateral BoaKamNorth well in January, ahead of schedule and budget. The BoaKamNorth project consists of one well and a new subsea manifold tied back to the Boa manifold. The well will be tied in to the existing Alvheim infrastructure in connection with the manifold tie-in campaign planned to commence in Q2 2016. Production start from BoaKamNorth is also expected in Q2 2016.
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 Viper well commenced in February and the Kobra well was spudded in April. The partnership also approved to drill an exploratory pilot hole into the Kobra East prospect as part of the Kobra well.
Production from Jette, Jotun, Varg and Atla was stable in the quarter with slightly higher volumes compared to the previous quarter. Atla stopped producing in late March and will be produced intermittently as reservoir pressure allows. Enoch has not been restarted since the shutdown on Brae in December.
Key activities for the Ivar Aasen project are progressing according to plan and budget with first oil scheduled for Q4 2016. Ivar Aasen is being developed with a manned production platform. The topside will include living quarters and a processing facility for first stage separation.
The Maersk Interceptor jack-up rig has continued to perform very well and the drilling program is progressing ahead of schedule. To date, five producers and one water injector have been drilled. The pre-drilling program will continue through Q2 2016. In April, Maersk Interceptor drilled two geo-pilot wells in the West Cable area to explore potential upsides. Results are currently being evaluated.
Topside construction in Singapore is now 98 percent complete. Hand-over of sub systems from SMOE construction to commissioning continued through the quarter. Scheduled sail-away from Singapore has been pushed to early June 2016, which will allow for an extra week of onshore commissioning to minimise the offshore carry over work. This will not impact the installation of the topside in the North Sea which is planned to take place in July 2016.
The construction of the living quarters at Stord in Norway is 98 percent complete. Hand-over of sub systems from Apply Leirvik construction to commissioning has continued. Scheduled sail-away from Stord is July 2016.
Installation of the subsea power cable between Edvard Grieg and Ivar Aasen was carried out by EMAS in April.
The project is progressing according to plan towards production start-up in the fourth quarter 2019. Contract awards continued through the first quarter. In February, Technip Norway A/S was awarded the contract for pipe laying. Ocean Installer was awarded the contract for marine construction and installation.
In February, the project passed a major milestone with the first steel cut for the drilling platform. In March, the drilling rig Deepsea Atlantic commenced drilling of the first production well for The Johan Sverdrup field development. In total 35 wells are planned to be
drilled in the first phase of the development project. The construction of the utility and living quarter platform started up in March.
Debottlenecking measures have been decided with aim to increase the phase 1 production capacity above the PDO design capacity of 315 – 380 mboepd.
The capital expenditures for phase 1 was in the PDO estimated at NOK 123 billion (nominal value). As a consequence of the macro environment and project improvements the operator announced in February that the estimate of capital expenditures has been reduced by 12 percent to NOK 108.5 billion (nominal value), based on the same FX-assumptions as in the PDO. The operator estimates that phase 1 for Johan Sverdrup now has a break-even price below 30 USD/bbl. For the full field development, capital expenditures are by the operator projected to be between NOK 160 and 190 billion (real 2015, reduced from NOK 170 to 220 billion in the PDO), based on the same FX-assumptions as in the PDO.
The PDO for all future phases is scheduled to be submitted late 2017, and start-up of production from phase 2 is expected in 2022.
Det norske is currently in the process of evaluating decision made by the King in Council regarding the distribution of the participating interests, and whether this decision should be contested in the court system.
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.
Pre-drilling of production wells is ongoing by use of the Maersk Integrator jack-up rig. The topside is scheduled to be installed during summer 2016, and start-up of production is planned for mid-2017.
During the quarter, the company's cash spending on exploration was USD 40 million. USD 36 million was recognized as exploration expenses in the period, relating to dry wells, seismic, area fees and G&G costs.
Drilling of the Uptonia well in PL554 at the Tampen area commenced in December 2015. The well was classified as dry.
In January 2016, The Ministry of Petroleum and Energy announced that Det norske was offered ownership in 10 new licenses, including six operatorship, in the 2015 Awards in Pre-defined Areas (APA).
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-metre oil column in the upper part of the Tarbert formation, of which 22 metres had moderate to good reservoir properties. A preliminary estimate of the discovery is 1 – 3 mmboe. A side track well was subsequently drilled in to Viti prospect, however this well was dry.
The results from Madam Felle and Viti does not affect future drilling of the exploration campaign in the area. In April, the exploration campaign continued with drilling of the Askja South East prospect.
In January, Det norske acquired a 10 percent interest in PL722 and a 25 percent interest in PL507 from Explora Petroleum for a cash consideration. The agreement is subject to approval by the authorities.
In March, Det norske announced an agreement to acquire Noreco's Norwegian license portfolio, including a NOK 45 million cash balance with effective date 1 January, 2016.
The license portfolio consists of seven licenses on the Norwegian Continental Shelf, including a 20 percent interest in the Gohta discovery (PL492) in the Barents Sea. Noreco's 4.36 percent interest in the Enoch field was not included in the transaction.
The bondholder meeting in the NOR06 approved the transaction on March 16, 2016. The transaction is subject to regulatory approvals.
To adapt to the current market conditions, the company continues its work to strengthen its long-term competitiveness through a large number of improvement projects. Improvement measures have been implemented to reduce expenditures across all disciplines to enable the company to sanction new stand-alone projects at break-even prices below 40 USD/boe. To achieve this, a new project delivery model has been developed and will be piloted on new subsea tie-ins on Alvheim. Projects have also been established to further increase drilling performance and operational excellence.
The Ivar Aasen project is progressing well and remains on track for first oil in Q4 2016. Sail-away for the topside from Singapore is scheduled for early June and offshore lifting operations in July. Det norske continues to develop the Alvheim area with drilling of the Kobra well during the second quarter. The Johan Sverdrup project is moving forward according to plan and the company sees potential for further cost reductions.
In April, Det norske announced that the company had entered into an agreement with Centrica Resources Norge AS to acquire the company's licenses in the Frigg Gamma Delta and Rind discoveries. As compensation Det norske will cover the expenses of the licenses with effective date of 1 January 2016.
The portfolio consists of 30 percent ownership in the licenses PL442, PL026B and PL026, including the operatorship in Frigg Gamma Delta. The transaction is subject to regulatory approvals.
The exploration drilling campaign at Krafla/Askja will continue with drilling of the Beerenberg and Slemmestad prospects, while the Rovarkula prospect near Ivar Aasen is scheduled to be drilled in July.
The company has a robust and diversified capital structure and its debt facilities in place are sufficient to fund the current work program until first oil at Johan Sverdrup. Following the successful process with the bank consortium to ease covenant thresholds, discussions are progressing towards an amicable solution with the DETNOR02 bondholders.
No changes are made to the company's guidance for 2016. Production is expected to be between 55 and 60 mboepd, CAPEX is expected to be between USD 925 and 975 million and exploration expenditures is expected between USD 160 and 170 million. Production cost is expected to average in the range 8 to 9 USD per barrel of oil equivalent.
| Group | |||||
|---|---|---|---|---|---|
| Q1 | 01.01.-31.03. | ||||
| (USD 1 000) | Note | 2016 | 2015 | 2016 | 2015 |
| Petroleum revenues | 200 768 | 323 749 | 200 768 | 323 749 | |
| Other operating income | 4 080 | 5 176 | 4 080 | 5 176 | |
| Total operating income | 2 | 204 848 | 328 924 | 204 848 | 328 924 |
| Exploration expenses | 3 | 36 115 | 14 523 | 36 115 | 14 523 |
| Production costs | 34 374 | 39 349 | 34 374 | 39 349 | |
| Depreciation | 5 | 114 318 | 122 224 | 114 318 | 122 224 |
| Impairments | 4 | 37 964 | 52 773 | 37 964 | 52 773 |
| Other operating expenses | 5 330 | 14 397 | 5 330 | 14 397 | |
| Total operating expenses | 228 101 | 243 266 | 228 101 | 243 266 | |
| Operating profit/loss | -23 253 | 85 658 | -23 253 | 85 658 | |
| Interest income | 817 | 262 | 817 | 262 | |
| Other financial income | 49 521 | 56 150 | 49 521 | 56 150 | |
| Interest expenses | 20 701 | 20 068 | 20 701 | 20 068 | |
| Other financial expenses | 22 018 | 40 836 | 22 018 | 40 836 | |
| Net financial items | 6 | 7 620 | -4 492 | 7 620 | -4 492 |
| Profit/loss before taxes | -15 633 | 81 166 | -15 633 | 81 166 | |
| Taxes (+)/tax income (-) | 7 | -47 866 | 78 727 | -47 866 | 78 727 |
| Net profit/loss | 32 233 | 2 439 | 32 233 | 2 439 | |
| Weighted average no. of shares outstanding and fully diluted Earnings/(loss) after tax per share |
202 618 602 0.16 |
202 618 602 0.01 |
202 618 602 0.16 |
202 618 602 0.01 |
| Group | ||||||
|---|---|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||||
| (USD 1 000) | Note | 2016 | 2015 | 2016 | 2015 | |
| Profit/loss for the period | 32 233 | 2 439 | 32 233 | 2 439 | ||
| Items which will not be reclassified over profit and loss (net of taxes) | ||||||
| Currency translation adjustment | -59 | - | -59 | - | ||
| Total comprehensive income in period | 32 174 | 2 439 | 32 174 | 2 439 |
| Group | ||||||
|---|---|---|---|---|---|---|
| (USD 1 000) | Note | 31.03.2016 | 31.03.2015 | 31.12.2015 | ||
| ASSETS | ||||||
| Intangible assets | ||||||
| Goodwill | 5 | 739 383 | 1 133 930 | 767 571 | ||
| Capitalized exploration expenditures | 5 | 294 161 | 309 219 | 289 980 | ||
| Other intangible assets | 5 | 630 105 | 631 222 | 648 030 | ||
| Tangible fixed assets | ||||||
| Property, plant and equipment | 5 | 3 089 831 | 2 679 219 | 2 979 434 | ||
| Financial assets | ||||||
| Long-term receivables | 2 935 | 8 074 | 3 782 | |||
| Other non-current assets | 8 | 12 142 | 4 289 | 12 628 | ||
| Long-term derivatives (asset) | 12 | 6 222 | 1 518 | - | ||
| Total non-current assets | 4 774 778 | 4 767 471 | 4 701 425 | |||
| Inventories | ||||||
| Inventories | 31 018 | 24 874 | 31 533 | |||
| Receivables | ||||||
| Accounts receivable | 44 795 | 102 466 | 85 546 | |||
| Other short-term receivables | 9 | 129 894 | 166 867 | 105 190 | ||
| Other current financial assets | 2 989 | 3 032 | 2 907 | |||
| Tax receivables | 7 | 215 141 | - | 126 391 | ||
| Short-term derivatives (asset) | 12 | 33 349 | 3 229 | 45 217 | ||
| Cash and cash equivalents | ||||||
| Cash and cash equivalents | 10 | 154 618 | 411 691 | 90 599 | ||
| Total current assets | 611 804 | 712 158 | 487 384 | |||
| TOTAL ASSETS | 5 386 582 | 5 479 630 | 5 188 809 |
| Group | ||||
|---|---|---|---|---|
| (USD 1 000) | Note | 31.03.2016 | 31.03.2015 | 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 | -695 947 | -413 046 | -728 121 | |
| Total equity | 371 200 | 654 101 | 339 026 | |
| Non-current liabilities Deferred taxes |
7 | 1 384 031 | 1 362 959 | 1 356 114 |
| Long-term abandonment provision | 16 | 425 853 | 489 617 | 412 805 |
| Provisions for other liabilities | 1 648 | 8 632 | 1 638 | |
| Long-term bonds | 14 | 518 142 | 232 545 | 503 440 |
| Other interest-bearing debt | 15 | 2 220 836 | 2 143 703 | 2 118 935 |
| Long-term derivatives (liability) | 12 | 33 776 | 6 317 | 62 012 |
| Current liabilities | ||||
| Trade creditors | 135 295 | 120 245 | 51 078 | |
| Accrued public charges and indirect taxes | 6 105 | 4 965 | 9 060 | |
| Tax payable | 7 | - | 110 356 | - |
| Short-term derivatives (liability) | 12 | 205 | 17 107 | 13 506 |
| Short-term abandonment provision | 16 | 13 785 | 2 677 | 10 520 |
| Other current liabilities | 13 | 275 707 | 326 405 | 310 675 |
| Total liabilities | 5 015 382 | 4 825 528 | 4 849 783 | |
| TOTAL EQUITY AND LIABILITIES | 5 386 582 | 5 479 630 | 5 188 809 |
| Other equity | ||||||||
|---|---|---|---|---|---|---|---|---|
| Other comprehensive income | ||||||||
| Foreign currency | ||||||||
| Share | Other paid-in | Actuarial | translation | Retained | Total other | |||
| (USD 1 000) | Share capital | premium | capital | gains/(losses) | reserves* | earnings | equity | Total equity |
| Equity as of 31.12.2014 | 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 - 31.03.2016 | - | - | - | - | -59 | 32 233 | 32 174 | 32 174 |
| Equity as of 31.3.2016 | 37 530 | 1 029 617 | 573 083 | -88 | -115 550 | -1 153 391 | -695 947 | 371 200 |
* 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.
| Group | ||||
|---|---|---|---|---|
| Q1 | Year | |||
| (USD 1 000) | Note | 2016 | 2015 | 2015 |
| CASH FLOW FROM OPERATING ACTIVITIES | ||||
| Profit/loss before taxes | -15 633 | 81 166 | -113 607 | |
| Taxes paid during the period | - | -64 142 | -320 618 | |
| Tax refund during the period | - | - | 87 662 | |
| Depreciation | 5 | 114 318 | 122 224 | 480 959 |
| Net impairment losses | 4 | 37 964 | 52 773 | 430 468 |
| Accretion expenses | 16 | 5 812 | 6 396 | 26 351 |
| Interest expenses Interest paid |
6 | 37 635 -29 433 |
25 066 -25 463 |
127 620 -124 276 |
| Changes in derivatives | 2,6 | -35 890 | -11 784 | -793 |
| Amortized loan costs | 6 | 3 109 | 6 602 | 17 480 |
| Amortization of fair value of contracts assumed in the Marathon acquisition | - | - | -2 878 | |
| Expensed capitalized dry wells | 3 | 16 451 | -309 | 11 682 |
| Changes in inventories, accounts payable and receivables | 100 779 | -174 986 | -13 060 | |
| Changes in abandonment liabilities through income statement | - | - | -1 569 | |
| Changes in other current balance sheet items | -46 350 | 263 341 | 81 048 | |
| NET CASH FLOW FROM OPERATING ACTIVITIES | 188 762 | 280 884 | 686 467 | |
| CASH FLOW FROM INVESTMENT ACTIVITIES | ||||
| Payment for removal and decommissioning of oil fields | 16 | -1 306 | -1 134 | -12 508 |
| Disbursements on investments in fixed assets | 5 | -209 279 | -238 902 | -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 | -21 228 | -21 205 | -113 051 |
| NET CASH FLOW FROM INVESTMENT ACTIVITIES | -231 812 | -261 241 | -1 168 310 | |
| CASH FLOW FROM FINANCING ACTIVITIES | ||||
| Repayment of short-term debt | - | - | -70 938 | |
| Repayment of long-term debt | - | - | -330 000 | |
| Arrangement fee | - | - | -14 380 | |
| Proceeds from issuance of long-term debt | 100 000 | 100 000 | 700 000 | |
| NET CASH FLOW FROM FINANCING ACTIVITIES | 100 000 | 100 000 | 284 683 | |
| Net change in cash and cash equivalents | 56 950 | 119 642 | -197 160 | |
| Cash and cash equivalents at start of period | 90 599 | 296 244 | 296 244 | |
| Effect of exchange rate fluctuation on cash held | 7 069 | -4 195 | -8 485 | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 10 | 154 618 | 411 691 | 90 599 |
| SPECIFICATION OF CASH EQUIVALENTS AT END OF PERIOD | ||||
| Bank deposits and cash | 149 812 | 407 704 | 86 201 | |
| Restricted bank deposits | 4 806 | 3 987 | 4 398 | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 10 | 154 618 | 411 691 | 90 599 |
(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.
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 in Q1 2016. 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.
Det norske group interim financial statements include Det norske Exploration AS (previously Svenska Petroleum Exploration AS) and Det norske oil AS (previously Premier Oil Norge AS). The activity in Det norske Exploration AS was transferred to Det norske oljeselskap ASA during Q4 2015, while the activity in Det norske oil AS was transferred during Q1 2016.
| Group | ||||
|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||
| Breakdown of petroleum revenues (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Recognized income oil | 180 388 | 287 877 | 180 388 | 287 877 |
| Recognized income gas | 18 103 | 35 140 | 18 103 | 35 140 |
| Tariff income | 2 277 | 732 | 2 277 | 732 |
| Total petroleum revenues | 200 768 | 323 749 | 200 768 | 323 749 |
| Breakdown of produced volumes (barrels of oil equivalent) | ||||
| Oil | 4 819 146 | 5 094 389 | 4 819 146 | 5 094 389 |
| Gas | 696 793 | 750 346 | 696 793 | 750 346 |
| Total produced volumes | 5 515 939 | 5 844 735 | 5 515 939 | 5 844 735 |
| Other operating income (USD 1 000) | ||||
| Realized gain on oil derivatives | 17 073 | - | 17 073 | - |
| Unrealized gain on oil derivatives | -13 131 | 4 746 | -13 131 | 4 746 |
| Other income | 138 | 430 | 138 | 430 |
| Total other operating income | 4 080 | 5 176 | 4 080 | 5 176 |
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.
| Group | ||||
|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||
| Breakdown of exploration expenses (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Seismic | 1 024 | 3 214 | 1 024 | 3 214 |
| Area fee | 2 262 | 2 144 | 2 262 | 2 144 |
| Expensed capitalized wells this year | 13 733 | -300 | 13 733 | -300 |
| Expensed capitalized wells previous years | 2 718 | -9 | 2 718 | -9 |
| Other exploration expenses* | 16 378 | 9 474 | 16 378 | 9 474 |
| Total exploration expenses | 36 115 | 14 523 | 36 115 | 14 523 |
* Other exploration expenses in Q1 2016 are mainly related to field evaluation.
In Q1 2016 the group has done some changes in the subcategories within exploration expenses presented above. Comparable figures have been restated accordingly.
Impairment tests of individual cash-generating units are performed when impairment triggers are identified. As of 31 March 2016 there has been a decrease in the forward prices compared to 31 December 2015, which is considered as an impairment trigger. Two categories of impairment tests have been performed:
Impairment test of fixed assets and related intangible assets, other than goodwill
Impairment test of goodwill
Impairment is recognized when the book value of an asset or a cash-generating unit, including associated goodwill, exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and value in use. All impairment testing in Q1 2016 has been based on value in use. In the assessment of the value in use, the expected future cash flow is discounted to the net present value by applying a discount rate after tax that reflects the current market valuation of the time value of money, and the specific risk related to the asset. The discount rate is derived from the weighted average cost of capital (WACC) for a market participant. Cash flows are projected for the estimated lifetime of the fields, which may exceed periods greater than five years.
For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Below is an overview of the key assumptions applied for impairment testing purposes as of 31 March 2016.
Future price level is a key assumption and has significant impact on the net present value. Forecasted oil and gas prices are based on management's best estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. Information about future prices is less reliable on a long-term basis, as there are fewer observable market transactions going forward. In the impairment test, the oil price is therefore based on the forward curve for the remaining period of 2016 to the end of 2020. From 2021, the oil price is based on the company's long-term price assumptions.
The nominal oil price based on the forward curve applied in the impairment test is as follows:
| Year | USD/BOE |
|---|---|
| 2016 | 40.65 |
| 2017 | 45.28 |
| 2018 | 48.41 |
| 2019 | 50.81 |
| 2020 | 52.87 |
| From 2021 (in real terms) | 85.00 |
Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves. The recoverable amount is sensitive to changes in reserves.
The discount rate is derived from the company's WACC. The capital structure considered in the WACC calculation is derived from the capital structures of an identified peer group and market participants with consideration given to optimal structures. The cost of equity is derived from the expected return on investment by the company's investors. The cost of debt is based on the interest-bearing borrowings on debt specific to the assets acquired. The beta factors are evaluated annually based on publicly available market data about the identified peer group.
Based on the above, the post tax nominal discount rate is set to 8.5 per cent, which is the same discount rate used in Q4 2015.
As Det norske's functional currency changed to USD during 2014, the company is now exposed to exchange rate fluctuations between USD and non-USD cash flows with regard to the financial statements. In line with the methodology for future oil price, it has been concluded to apply the forward curve for the currency rate from 2016 until the end of 2020, and the company's long term assumption from 2021 and onwards. This results in the following currency rates being applied in the impairment test for Q1 2016:
| Year | NOK/USD |
|---|---|
| 2016 | 8.27 |
| 2017 | 8.25 |
| 2018 | 8.21 |
| 2019 | 8.16 |
| 2020 | 8.10 |
| From 2021 | 7.00 |
The long-term inflation rate is assumed to be 2.5 per cent.
The impairment test of assets other than goodwill has been performed prior to the quarterly goodwill impairment test. If these assets are found to be impaired, its carrying value will be written down before the impairment test of goodwill. The carrying value of the assets is the sum of tangible assets and intangible assets as of the valuation date.
Below is an overview of the impairment charge and the carrying value per cash generating unit where impairment has been recognized or reversed in Q1 2016:
| Impairment charged/reversal Recoverable amount/ |
|||
|---|---|---|---|
| Cash generating unit (USD 1 000) | Intangible | Tangible | carrying value |
| Gina Krog | - | 9 227 | 70 419 |
| Other CGU's | - | 548 | - |
| Total | - | 9 775 | 70 419 |
For the purpose of impairment testing, goodwill acquired through business combinations have, before any impairment charges in Q1 2016, been allocated as follows:
| Goodwill allocation (USD 1 000) | |
|---|---|
| Remaining technical goodwill from the acquisition of Marathon Oil Norge AS as of 1 January 2016 | 433 456 |
| Residual goodwill | 291 717 |
| Remaining technical goodwill from other business combinations | 42 399 |
Technical goodwill has been allocated to individual cash-generating units ("CGUs") for the purpose of impairment testing. All fields tied in to the Alvheim FPSO are assessed to be included in the same cash-generating unit ("Alvheim CGU"). The residual goodwill is allocated to group of CGUs including all fields acquired together with all existing Det norske fields, as this mainly relates to tax and workforce synergies. The technical goodwill from previous business combinations are mainly allocated to Johan Sverdrup (USD 23 million) and Ivar Aasen (USD 8 million). The remaining technical goodwill from prior year business combinations is not significant in comparison to the total carrying amount of goodwill.
As mentioned above, residual goodwill is allocated across all CGUs for impairment testing. The combined recoverable amount exceeds the carrying amount by a substantial margin. Based on this, no impairment of residual goodwill has been recognized.
The carrying value of the Alvheim CGU consists of the carrying values of the oilfield assets plus associated technical goodwill. In the impairment test performed, carrying value is adjusted by the remaining part of deferred tax from which the technical goodwill arose, to avoid an immediate impairment of all technical goodwill.
The carrying value of the Alvheim CGU is, in accordance with the above, calculated as follows:
| (USD 1 000) | |
|---|---|
| Carrying value of oilfield licences and fixed assets | 1 855 009 |
| + Technical goodwill | 433 456 |
| - Deferred tax related to technical goodwill | -1 077 452 |
| Net carrying value pre-impairment of goodwill | 1 211 012 |
The impairment charge is the difference between the recoverable amount and the carrying value.
| (USD 1 000) | |
|---|---|
| Net carrying value as specified above | 1 211 012 |
| Recoverable amount (including tax amortization benefit) | 1 182 823 |
| Impairment charge Q1 | 28 189 |
As depicted in the carry value table above, deferred tax (from the date of acquisition) reduces the net carrying value prior to the impairment charges. When deferred tax from the Marathon acquisition decreases, more goodwill is as such exposed for impairment. This may lead to future impairment charges even though other assumptions remain stable. In Q1 2016, the reduced deferred tax together with decreased forward prices are the main reasons for impairment.
The table below shows how the impairment of goodwill allocated to the Alvheim CGU would be affected by changes in the various assumptions, given that the remainders of the assumptions are constant.
| Change in goodwill impairment for Q1 2016 after | |||||
|---|---|---|---|---|---|
| Assumption (USD million) | Change | increase in assumption decrease in assumption |
|||
| Oil and gas price | +/- 20% | -28.2 | 227.3 | ||
| Production profiles (reserves) | +/- 5% | -28.2 | 58.6 | ||
| Discount rate | +/- 1% point | 31.7 | -28.2 | ||
| Currency rate USD/NOK | +/- 1.0 NOK | 17.7 | -21.9 | ||
| Inflation | +/- 1% point | -28.2 | 37.4 |
No impairment charge of technical goodwill from other business combinations have been recognized in Q1 2016.
| Group | ||||
|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||
| (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Impairment/reversal of tangible fixed assets | 9 775 | - | 9 775 | - |
| Impairment of goodwill | 28 189 | 52 773 | 28 189 | 52 773 |
| Total impairments | 37 964 | 52 773 | 37 964 | 52 773 |
| Assets under | Production facilities |
Fixtures and fittings, office |
||
|---|---|---|---|---|
| (USD 1 000) | development | including wells | machinery | Total |
| Book value 31.12.2014 | 1 324 556 | 1 206 077 | 18 639 | 2 549 271 |
| Acquisition cost 31.12.2014 | 1 324 556 | 1 856 371 | 35 684 | 3 216 612 |
| Additions | 225 960 | 5 875 | 1 230 | 233 065 |
| Reclassification | -397 990 | 398 000 | - | 9 |
| Acquisition cost 31.3.2015 | 1 152 526 | 2 260 246 | 36 914 | 3 449 686 |
| Accumulated depreciation and impairments 31.3.2015 | - | 752 409 | 18 058 | 770 467 |
| Book value 31.3.2015 | 1 152 526 | 1 507 836 | 18 857 | 2 679 219 |
| 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 |
| Depreciation Q1 2016 | - | 94 597 | 1 201 | 95 798 |
| Depreciation 01.01.2016 - 31.03.2016 | - | 94 597 | 1 201 | 95 798 |
| Impairments Q1 2016 | 9 227 | 548 | - | 9 775 |
| Impairments 01.01.2016 - 31.03.2016 | 9 227 | 548 | - | 9 775 |
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.
| Other intangible assets | Exploration | |||||
|---|---|---|---|---|---|---|
| (USD 1 000) | Licences etc. | Software | Total | wells | Goodwill | |
| Book value 31.12.2014 | 646 482 | 2 306 | 648 788 | 291 619 | 1 186 704 | |
| Acquisition cost 31.12.2014 | 712 237 | 9 064 | 721 301 | 291 619 | 1 556 468 | |
| Additions | 1 513 | 19 | 1 532 | 17 301 | - | |
| Disposals/expensed dry wells | - | - | - | -309 | - | |
| Reclassification | - | - | - | -9 | - | |
| Acquisition cost 31.3.2015 | 713 750 | 9 083 | 722 833 | 309 219 | 1 556 468 | |
| Accumulated depreciation and impairments 31.3.2015 | 84 718 | 6 893 | 91 611 | - | 422 538 | |
| Book value 31.3.2015 | 629 032 | 2 190 | 631 222 | 309 219 | 1 133 930 | |
| Acquisition cost 31.12.2015 Additions Disposals/expensed dry wells |
789 316 595 - |
9 149 - - |
798 465 595 - |
289 980 20 633 16 451 |
1 561 880 - - |
|
| Reclassification | - | - | - | - | - | |
| Acquisition cost 31.3.2016 Accumulated depreciation and impairments 31.3.2016 Book value 31.3.2016 |
789 911 161 142 628 769 |
9 149 7 812 1 336 |
799 059 168 954 630 105 |
294 161 - 294 161 |
1 561 880 822 498 739 383 |
|
| Depreciation Q1 2016 Depreciation 01.01.2016 - 31.03.2016 |
18 312 18 312 |
207 207 |
18 519 18 519 |
- - |
- - |
|
| Impairments Q1 2016 | - | - | - | - | 28 189 | |
| Impairments 01.01.2016 - 31.03.2016 | - | - | - | - | 28 189 |
See Note 4 for information regarding impairment charges.
| Group | ||||
|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||
| Depreciation in the Income statement (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Depreciation of tangible fixed assets | 95 798 | 103 126 | 95 798 | 103 126 |
| Depreciation of intangible assets | 18 519 | 19 098 | 18 519 | 19 098 |
| Total depreciation in the Income statement | 114 318 | 122 224 | 114 318 | 122 224 |
| Group | ||||
|---|---|---|---|---|
| Q1 | 01.01.-31.03. | |||
| (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Interest income | 817 | 262 | 817 | 262 |
| Realised gains on derivatives | 500 | - | 500 | - |
| Return on financial investments | - | 9 | - | 9 |
| Change in fair value of derivatives - income | 49 021 | 19 304 | 49 021 | 19 304 |
| Currency gains | - | 36 837 | - | 36 837 |
| Total other financial income | 49 521 | 56 150 | 49 521 | 56 150 |
| Interest expenses | 37 635 | 25 066 | 37 635 | 25 066 |
| Capitalized interest cost, development projects | -20 043 | -11 600 | -20 043 | -11 600 |
| Amortized loan costs | 3 109 | 6 602 | 3 109 | 6 602 |
| Total interest expenses | 20 701 | 20 068 | 20 701 | 20 068 |
| Currency losses | 10 996 | - | 10 996 | - |
| Realised loss on derivatives | 3 790 | 22 174 | 3 790 | 22 174 |
| Change in fair value of derivatives - expense | - | 12 266 | - | 12 266 |
| Accretion expenses | 5 812 | 6 396 | 5 812 | 6 396 |
| Other financial expenses | 1 420 | - | 1 420 | - |
| Total other financial expenses | 22 018 | 40 836 | 22 018 | 40 836 |
| Net financial items | 7 620 | -4 492 | 7 620 | -4 492 |
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 has changed the presentation of accretion expenses in Q1 2016. It is now included in the line item other financial expenses, while it has been presented as interest expenses prior to 2016. Comparable figures have been restated accordingly.
| Group | ||||
|---|---|---|---|---|
| Q1 01.01.-31.03. |
||||
| Taxes for the period appear as follows (USD 1 000) | 2016 | 2015 | 2016 | 2015 |
| Calculated current year tax/exploration tax refund | -6 090 | 8 080 | -6 090 | 8 080 |
| Change in deferred taxes in the Income statement | -41 577 | 73 640 | -41 577 | 73 640 |
| Prior period adjustments | -200 | -2 994 | -200 | -2 994 |
| Tax expenses (+)/tax income (-) | -47 866 | 78 727 | -47 866 | 78 727 |
| Group | |||
|---|---|---|---|
| Calculated tax receivable (+)/tax payable (-) (USD 1 000) | 31.03.2016 | 31.03.2015 | 31.12.2015 |
| Tax receivable/payable at 1.1. | 126 391 | -189 098 | -189 098 |
| Current year tax (-)/tax receivable (+) | 6 090 | -8 080 | -49 776 |
| Tax receivable from liquidation of Premier Oil Norge AS | 60 379 | - | - |
| Tax receivable related to acquisition of Svenska Petroleum Exploration AS/Premier Oil Norge AS | - | - | 108 047 |
| Tax payment/tax refund | - | 64 142 | 232 956 |
| Prior period adjustments | 8 817 | 10 123 | 11 580 |
| Revaluation of tax receivable | 13 465 | 12 557 | 12 682 |
| Total tax receivable (+)/tax payable (-) | 215 141 | -110 356 | 126 391 |
| Group | |||
|---|---|---|---|
| Deferred taxes (-)/deferred tax asset (+) (USD 1 000) | 31.03.2016 | 31.03.2015 | 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 | 41 577 | -73 640 | -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 | 1 758 | - | |
| Prior period adjustment | -7 129 | -6 921 | |
| Revaluation of losses carried forward | - | 2 410 | - |
| Deferred tax charged to OCI and equity | - | - | -59 |
| Net deferred tax (-)/deferred tax asset (+) | -1 384 031 | -1 362 959 | -1 356 114 |
| Group | |||||
|---|---|---|---|---|---|
| Q1 | 01.01.-31.03. | ||||
| Reconciliation of tax expense (USD 1 000) | 2016 | 2015 | 2016 | 2015 | |
| 25% company tax on profit before tax | -3 908 | 21 915 | -3 908 | 21 915 | |
| 53% special tax on profit before tax | -8 286 | 41 395 | -8 286 | 41 395 | |
| Tax effect on uplift | -24 402 | -24 597 | -24 402 | ||
| Permanent difference on impairment | 41 163 | 21 987 | 41 163 | ||
| Foreign currency translation of NOK monetary items | 8 674 | -29 128 | 8 674 | -29 128 | |
| Foreign currency translation of USD monetary items | 125 619 | -121 456 | 125 619 | -121 456 | |
| Tax effect of financial and other 25% items | -85 869 | 69 890 | -85 869 | 69 890 | |
| Revaluation of tax balances* | -79 945 | 80 319 | -79 945 | 80 319 | |
| Other items (other permanent differences and previous period adjustment) | -1 543 | -969 | -1 543 | -969 | |
| Total taxes (+)/tax income (-) | -47 866 | 78 727 | -47 866 | 78 727 |
* 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.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.03.2016 | 31.03.2015 | 31.12.2015 |
| Shares in Alvheim AS | 10 | 10 | 10 |
| Shares in Det norske oljeselskap AS | 1 021 | 835 | 1 021 |
| Shares in Sandvika Fjellstue AS | 1 814 | 1 814 | 1 814 |
| Investment in subsidiaries | 2 845 | 2 659 | 2 845 |
| Tenancy deposit | 1 610 | 1 630 | 1 512 |
| Other non-current assets | 7 687 | - | 8 272 |
| Total other non-current assets | 12 142 | 4 289 | 12 628 |
Alvheim AS, Det norske oljeselskap AS (previously Marathon Oil Norge AS) and Sandvika Fjellstue has been deemed immaterial for consolidation purposes.
Det norske oil AS and Det norske Exploration AS have been consolidated in this report and are therefore not included as investments in subsidiaries.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.03.2016 | 31.03.2015 | 31.12.2015 |
| Receivables related to deferred volume at Atla | 4 371 | 5 383 | 5 673 |
| Pre-payments, including rigs | 33 594 | 31 776 | 21 634 |
| VAT receivable | 10 004 | 10 086 | 6 121 |
| Underlift of petroleum | 15 091 | 31 969 | 3 696 |
| Accrued income from sale of petroleum products | -614 | - | 1 866 |
| Other receivables, including operated licences | 67 448 | 87 653 | 66 200 |
| Total other short-term receivables | 129 894 | 166 867 | 105 190 |
The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the company's transaction liquidity.
| Group | ||
|---|---|---|
| 31.03.2016 | 31.03.2015 | 31.12.2015 |
| 149 812 | 407 704 | 86 201 |
| 4 806 | 3 987 | 4 398 |
| 154 618 | 411 691 | 90 599 |
| 550 000 | - | 550 000 |
| 528 000 | 493 000 | 731 370 |
| (USD 1 000) | 31.03.2016 | 31.03.2015 | 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 |
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.03.2016 | 31.03.2015 | 31.12.2015 |
| Unrealized gain on commodity derivatives - LTA | - | 1 518 | - |
| Unrealized gain currency contracts - LTA | 6 222 | - | - |
| Long-term derivatives included in assets | 6 222 | 1 518 | - |
| Unrealized gain on commodity derivatives - STA | 32 086 | 3 229 | 45 217 |
| Unrealized gain currency contracts - STA | 1 263 | - | - |
| Short-term derivatives included in assets | 33 349 | 3 229 | 45 217 |
| Total derivatives included in assets | 39 571 | 4 747 | 45 217 |
| Unrealized losses currency contracts - LTL | - | 4 988 | 7 840 |
| Unrealized losses interest rate swaps - LTL | 33 776 | 1 328 | 54 172 |
| Long-term derivatives included in liabilities | 33 776 | 6 317 | 62 012 |
| Unrealized losses currency contracts - STL | 205 | 15 911 | 13 506 |
| Unrealized losses interest rate swaps - STL | - | 1 196 | - |
| Short-term derivatives included in liabilities | 205 | 17 107 | 13 506 |
| Total derivatives included in liabilities | 33 981 | 23 424 | 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.
| Breakdown of other current liabilities (USD 1 000) | 31.03.2016 | 31.03.2015 | 31.12.2015 |
|---|---|---|---|
| Current liabilities related to overcall in licences | 25 880 | 67 124 | 33 444 |
| Share of other current liabilities in licences | 183 250 | 158 430 | 184 010 |
| Overlift of petroleum | 909 | 5 816 | 17 088 |
| Fair value of contracts assumed in acquisition of Marathon Oil Norge AS* | 8 470 | 22 600 | 12 009 |
| Other current liabilities** | 57 198 | 72 435 | 64 125 |
| Total other current liabilities | 275 707 | 326 405 | 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.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.03.2016 | 31.03.2015 | 31.12.2015 |
| Principal, bond Nordic Trustee 1) | 223 135 | 232 545 | 208 744 |
| Principal, bond Nordic Trustee 2) | 295 007 | - | 294 696 |
| Total bond | 518 142 | 232 545 | 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. See Note 19 for information regarding financial covenants.
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.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.03.2016 | 31.03.2015 | 31.12.2015 |
| Reserve-based lending facility | 2 220 836 | 2 143 703 | 2 118 935 |
| Total other interest-bearing debt | 2 220 836 | 2 143 703 | 2 118 935 |
The RBL Facility was established in October 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 has been 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, there will be no redetermination in June 2016. The next scheduled redetermination process for the company will therefore be in December 2016.
A revolving credit facility ("RCF") of USD 550 million was also 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 31 March 2016.
See Note 19 for information regarding changes in financial covenants in April 2016.
| Group | |||
|---|---|---|---|
| (USD 1 000) | 31.03.2016 | 31.03.2015 | 31.12.2015 |
| Provisions as of 1 January | 423 325 | 489 051 | 489 051 |
| Incurred cost removal | -1 306 | -1 134 | -12 508 |
| Accretion expense - present value calculation | 5 812 | 6 396 | 26 351 |
| Change in estimates and incurred liabilities on new fields* | 11 807 | -2 019 | -79 569 |
| Total provision for abandonment liabilities | 439 638 | 492 294 | 423 325 |
| Break down of the provision to short-term and long-term liabilities | |||
| Short-term | 13 785 | 2 677 | 10 520 |
| Long-term | 425 853 | 489 617 | 412 805 |
| Total provision for abandonment liabilities | 439 638 | 492 294 | 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 relates 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.
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. Management is of the opinion that none of the disputes will lead to significant commitments for the company.
In 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 was extended to include 2011 and 2012. The company responded to the notice of reassessment in 2012 by submitting detailed comments, and has subsequently had further correspondence with OTO regarding the notice.
During March 2016 the company's Oslo office was relocated from Aker Brygge to Fornebu. In January, Det norske entered into the lease contract with Fornebuporten Næring AS for lease of premises at Fornebuporten. The transaction meets the IAS 24 definition of a related party transaction, though is not a transaction between closely related parties according to the Public Limited Liabilities Act section 3-8. A fairness opinion regarding the rental payment was obtained confirming that the rental payments are according to market prices.
In April 2016, the company obtained acceptance for a covenant amendment package from its bank consortium, and as a result the covenant levels in the RBL and RCF have been 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 up to and including 31 December 2019, and thereafter maximum 3.5. The Interest Cover 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. The company is working to obtain a similar agreement with the DETNOR02 bondholders.
The company's investments in licences on the Norwegian Continental Shelf as of:
| Fields operated: | 31.03.2016 | 31.12.2015 | Fields non-operated: | 31.03.2016 | 31.12.2015 |
|---|---|---|---|---|---|
| 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: | 31.03.2016 | 31.12.2015 | Licence: | 31.03.2016 | 31.12.2015 |
| PL 001B | 35.000 % | 35.000 % PL 019C | 30.000 % | 30.000 % | |
| PL 026B | 62.130 % | 62.130 % PL 019D* | 0.000 % | 30.000 % | |
| PL 027D | 100.000 % | 100.000 % PL 029B | 20.000 % | 20.000 % | |
| PL 028B | 35.000 % | 35.000 % PL 035 | 50.000 % | 50.000 % | |
| PL 036C | 65.000 % | 65.000 % PL 035B* | 0.000 % | 40.000 % | |
| PL 036D | 46.904 % | 46.904 % PL 035C | 50.000 % | 50.000 % | |
| PL 088BS | 65.000 % | 65.000 % PL 038 | 5.000 % | 5.000 % | |
| PL 103B | 70.000 % | 70.000 % PL 038D | 30.000 % | 30.000 % | |
| PL 150 | 65.000 % | 65.000 % PL 038E* | 0.000 % | 5.000 % | |
| PL 150B | 65.000 % | 65.000 % PL 048B* | 0.000 % | 10.000 % | |
| PL 169C | 50.000 % | 50.000 % PL 048D | 10.000 % | 10.000 % | |
| PL 203 | 65.000 % | 65.000 % PL 102C | 10.000 % | 10.000 % | |
| PL 203B | 65.000 % | 65.000 % PL 102D | 10.000 % | 10.000 % | |
| PL 242 | 35.000 % | 35.000 % PL 102F | 10.000 % | 10.000 % | |
| PL 340 | 65.000 % | 65.000 % PL 102G | 10.000 % | 10.000 % | |
| PL 340BS | 65.000 % | 65.000 % PL 265 | 20.000 % | 20.000 % | |
| PL 364 | 100.000 % | 50.000 % PL 272 | 50.000 % | 25.000 % | |
| PL406 | 50.000 % | 0.000 % PL 362* | 0.000 % | 40.000 % | |
| PL407 | 50.000 % | 0.000 % PL 438* | 0.000 % | 10.000 % | |
| PL 460 | 100.000 % | 100.000 % PL 442 | 60.000 % | 60.000 % | |
| PL 494 | 30.000 % | 30.000 % PL 457 | 40.000 % | 40.000 % | |
| PL 494B | 30.000 % | 30.000 % PL 457BS | 40.000 % | 40.000 % | |
| PL 494C | 30.000 % | 30.000 % PL 492 | 40.000 % | 40.000 % | |
| PL 504 | 47.593 % | 47.593 % PL 502 | 22.222 % | 22.222 % | |
| PL539 | 40.000 % | 0.000 % PL521* | 0.000 % | 25.000 % | |
| PL 626 | 50.000 % | 50.000 % PL 533 *** | 35.000 % | 35.000 % | |
| PL 659 | 20.000 % | 20.000 % PL 550 | 10.000 % | 10.000 % | |
| PL 663 | 30.000 % | 30.000 % PL 551* | 0.000 % | 20.000 % | |
| PL 677 | 60.000 % | 60.000 % PL 554 | 30.000 % | 30.000 % | |
| PL 709 | 40.000 % | 40.000 % PL 554B | 30.000 % | 30.000 % | |
| PL 715 | 40.000 % | 40.000 % PL 554C | 30.000 % | 30.000 % | |
| PL 724 | 40.000 % | 40.000 % PL 567* | 0.000 % | 40.000 % | |
| PL 724B | 40.000 % | 40.000 % PL 574 | 10.000 % | 10.000 % | |
| PL 736S | 65.000 % | 65.000 % PL583 | 45.000 % | 45.000 % | |
| PL 748*** | 30.000 % | 40.000 % PL 613 | 20.000 % | 20.000 % | |
| PL 777 | 40.000 % | 40.000 % PL617 | 35.000 % | 0.000 % | |
| PL777B** | 40.000 % | 0.000 % PL 627 | 20.000 % | 20.000 % | |
| PL 790 *** | 30.000 % | 50.000 % PL 627B | 20.000 % | 20.000 % | |
| PL814** | 40.000 % | 0.000 % PL 653 | 30.000 % | 30.000 % | |
| PL818** | 40.000 % | 0.000 % PL 672 | 25.000 % | 25.000 % | |
| PL821** | 60.000 % | 0.000 % PL 678S*** | 0.000 % | 25.000 % | |
| PL822S** | 60.000 % | 0.000 % PL 681* | 0.000 % | 16.000 % | |
| PL843** | 40.000 % | 0.000 % PL689 | 20.000 % | 20.000 % | |
| Number | 43 | 34 PL689B** | 20.000 % | 0.000 % | |
| PL690 | 30.000 % | 30.000 % | |||
| * Relinquished licences or Det norske has withdrawn from the licence. | PL 694 | 20.000 % | 20.000 % | ||
| PL722*** | 10.000 % | 10.000 % | |||
| ** Interest awarded in the APA Licensing round (Application in Predefined Areas) in 2015. The awards | PL 730 | 30.000 % | 30.000 % | ||
| were announced in 2016. | PL 730B | 30.000 % | 30.000 % | ||
| PL 778 | 20.000 % | 20.000 % | |||
| *** Acquired/changed through licence transactions or licence splits. | PL797 | 25.000 % | 25.000 % | ||
| PL 804** | 30.000 % | 30.000 % | |||
| **** According to a ruling by Ministry of Oil and Energy. | PL813** | 3.300 % | 0.000 % | ||
| PL842** | 30.000 % | 0.000 % | |||
| PL844** | 20.000 % | 0.000 % | |||
| Number | 44 | 50 |
| 2016 | 2015 | 2014 | ||||||
|---|---|---|---|---|---|---|---|---|
| (USD 1 000) | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 |
| Total operating income | 204 848 | 254 634 | 316 393 | 321 850 | 328 924 | 345 670 | 18 334 | 74 304 |
| Exploration expenses | 36 115 | 18 867 | 18 066 | 24 949 | 14 523 | 51 491 | 71 778 | 21 027 |
| Production costs | 34 374 | 24 077 | 26 888 | 50 686 | 39 349 | 44 400 | 7 906 | 7 417 |
| Depreciation | 114 318 | 111 590 | 129 790 | 117 354 | 122 224 | 104 183 | 28 080 | 13 443 |
| Impairments | 37 964 | 191 939 | 185 756 | - | 52 773 | 319 018 | - | - |
| Other operating expenses | 5 330 | 3 228 | 11 433 | 22 550 | 14 397 | 10 679 | 993 | 12 896 |
| Total operating expenses | 228 101 | 349 701 | 371 932 | 215 539 | 243 266 | 529 772 | 108 757 | 54 782 |
| Operating profit/loss | -23 253 | -95 067 | -55 539 | 106 311 | 85 658 | -184 102 | -90 423 | 19 522 |
| Net financial items | 7 620 | -56 138 | -51 205 | -43 137 | -4 492 | -12 788 | -30 143 | -23 865 |
| Profit/loss before taxes | -15 633 | -151 205 | -106 744 | 63 174 | 81 166 | -196 889 | -120 567 | -4 343 |
| Taxes (+)/tax income (-) | -47 866 | 4 980 | 59 441 | 55 897 | 78 727 | 89 997 | -103 615 | -31 627 |
| Net profit/loss | 32 233 | -156 184 | -166 185 | 7 277 | 2 439 | -286 887 | -16 952 | 27 284 |
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.
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