Quarterly Report • Jul 9, 2014
Quarterly Report
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Trondheim, July 09, 2014 Restated
| First quarter summary3 | |
|---|---|
| Summary of financial results and operating performance 5 |
|
| Financials6 | |
| Field performance and oil prices6 | |
| Health, safety and the environment6 | |
| PDO approved projects 7 |
|
| Other projects 7 |
|
| Exploration7 | |
| Business development8 | |
| Other issues8 | |
| Events after the quarter 8 |
|
| Outlook10 | |
| Financial Statements 11 |
This report replaces the first quarter financial reporting announced by Det norske oljeselskap ASA ("Det norske" or "the company") 30 April 2014. The reissuance of these condensed interim financial statements has been triggered by a rights offering involving the preparation of a prospectus in connection to the acquisition of Marathon Oil Norge AS (refer to note 21), including an ISRE 2410 limited review performed by the Company's independent auditor. As a result, the Company evaluated events subsequent to the original approval date of 30 April 2014 by the board of directors of the Q1 2014 interim financial statements for new information that, if known at the original approval date, would have resulted in adjustments to the financial statements and for other information that would have resulted in additional disclosures. These events have been considered through the date of this report. Subsequent events which have occurred since 30 April 2014 that have resulted in additional disclosures are described in note 21. There has been one matter which has resulted in the recognition of an impairment charge on the Jette field, during the three months ended 31 March 2014, as described in note 4.
(All figures in brackets apply to the first quarter 2013)
Det norske reported revenues of NOK 158 (80) million in the first quarter. Exploration expenses amounted to NOK 110 (234) million, contributing to an operating loss of NOK 268 (251) million. Net financial expenses were NOK 60 (32) million. Net result for the first quarter was NOK -16 (-20) million, following a tax income of NOK 313 (262) million.
Det norske's four producing assets – Jette, Atla, Varg and Jotun – produced 2,895 boepd on average during the quarter, with about half of this coming from Jette. The average realized oil price was USD 107 (112) per barrel.
The Ivar Aasen development project, where Det norske is operator with a 35 percent interest, is on schedule. Fabrication has commenced on the living quarters at Stord, the jacket in Sardinia and the topside in Singapore.
On the Johan Sverdrup project, the formal partner decision to pass Decision Gate 2 (DG2) was made. The plan is to submit a Plan for Development and Operations (PDO) that can be approved by the Norwegian Parliament in the first half of 2015, with first oil production in late 2019. The pre-unit operator Statoil has estimated gross field contingent resources in the range of 1,800 to 2,900 million barrels of oil equivalents. In the first quarter, an appraisal well on Geitungen encountered a gross oil column of six metres and subsequently a sidetrack well was drilled approximately 1 km to the southwest.
Additionally, Det norske participated in the drilling of two wildcat exploration wells in the quarter. On the Trell prospect in the North Sea, a small oil discovery was made. The Langlitinden prospect in the Barents Sea encountered oil-bearing channel sands, but Det norske deems the discovery non-commercial.
On 21 January, Det norske announced that Gro G. Haatvedt had been appointed as the new SVP Exploration in Det norske. She comes from the job as SVP Exploration for the NCS in Statoil.
On 21 January, Det norske was awarded six new licenses in the APA 2013, of which two as operator.
| MNOK= NOK million | Q1 14 | Q4 13 | Q3 13 | Q2 13 | Q1 13 | 2013 |
|---|---|---|---|---|---|---|
| Jette (boepd), 70% | 1 458 | 2 710 | 4 378 | 3 594 | 0 | 2 683 |
| Atla (boepd), 10% | 750 | 1 031 | 981 | 1 446 | 1 253 | 1 177 |
| Varg (boepd), 5% | 500 | 412 | 377 | 398 | 425 | 403 |
| Glitne (boepd), 10% | 0 | 0 | 0 | 0 | 43 | 11 |
| Enoch (boepd), 2% | 0 | 0 | 0 | 0 | 0 | 0 |
| Jotun Unit (boepd), 7% | 188 | 175 | 204 | 175 | 209 | 191 |
| Total production (boepd) | 2 895 | 4 328 | 5 940 | 5 613 | 1 929 | 4 463 |
| Oil and gas production (Kboe) | 261 | 398 | 547 | 511 | 174 | 1 629 |
| Oil price realised (USD/barrel) | 107 | 109 | 112 | 103 | 112 | 107 |
| Operating revenues (MNOK) | 158 | 254 | 324 | 286 | 80 | 944 |
| EBITDA (MNOK) | -12 | -400 | -348 | -127 | -216 | -1 091 |
| Cash flow from production (MNOK) | 112 | 151 | 269 | 227 | 37 | 684 |
| Exploration expenses (MNOK) | 110 | 544 | 588 | 271 | 234 | 1 637 |
| Total exploration expenditures (expensed and capitalised) (MNOK) |
151 | 400 | 581 | 373 | 306 | 1 659 |
| Operating loss (MNOK) | -268 | -1 182 | -518 | -277 | -251 | -2 227 |
| Net profit/loss(-) for the period (MNOK) |
-16 | -329 | -158 | -41 | -20 | -548 |
| No of licences (operatorships) | 77 (27) | 80 (33) | 74 (30) | 72 (30) | 69 (28) | 80 (33) |
Operating revenues in the first quarter was NOK 158 (80) million. The main cause of increase is that Jette commenced production in the second quarter 2013. Production in the quarter increased by 50 percent from 1,929 barrels of oil equivalents per day (boepd) in the first quarter 2013 to 2,895 boepd this quarter. Jette accounted for 1,458 (0) boepd and Atla for 750 (1,253) boepd.
Exploration expenses amounted to NOK 110 (234) million. The company expensed costs relating to the Langlitinden well in PL 659 as well as other exploration costs.
The operating loss increased to NOK 268 (251) million, as a result of an impairment on the Jette field.
Net financial expenses in the first quarter amounted to NOK 60 (32) million.
The net profit/(loss) for the period was NOK -16 (-20) million after a tax income of NOK 313 (262) million. This translates to a tax rate of 95 percent due to uplift, a special income deduction in the basis for calculation of petroleum tax, on previous years' investments.
Net cash flow from operating activities was NOK -489 (-267) million. Net cash flow from investment activities amounted to NOK -707 (-699) million, mainly caused by investments in fields under development. Net cash flow from financing activities totalled NOK 308 (548) million as the company had net withdrawal of debt.
The company's cash and cash equivalents amounted to NOK 821 (736) million as of 31 March. Tax receivables for disbursement in December 2014 amounted to NOK 1,417 (1,278) million and tax receivable for disbursement in December 2015 amounted to NOK 148 (261) million.
The equity ratio as of 31 March was 30.3 (42.3) percent. Discoveries and fields under development contributed to a total asset balance of NOK 10,467 (8,794) million as of 31 March.
Det norske produced 260,569 barrels of oil equivalents (boe) in the first quarter of 2014. This corresponds to 2,895 (1,929) boepd.
The average realized oil price was USD 107 (112) per barrel, while gas revenues were recognised at market value of NOK 2.3 (2.3) per standard cubic metre (scm).
Jette (70 percent operator) came on stream in May 2013 and produced 1,458 boepd net on average in the first quarter, accounting for 50 percent of total production. During March, Jette's main producer was shut for 10 days and the other well for four days. This was to test whether more optimal production could be achieved by producing one well at a time in order to reduce watercut and allow pressure build-up. For the time being, it has proved more effective to continue to produce from both wells simultaneously. In the second quarter, the Jette field has had stable operations from both wells. However, following a revision of the Jette reservoir, the estimate for ultimate recoverable reserves has been reduced from about 5 mmboe to 3.3 mmboe.
Atla (10 percent partner) produced 750 (1,253) boepd net on average in the first quarter and accounted for 26 percent of the total production. Atla's production was somewhat restricted in January and February 2014 due to priority to the Skirne field, but was stable in March.
Varg (5 percent partner) produced 500 (425) boepd net to Det norske in the first quarter, or 17 percent of total production. Gas export commenced from the field in early February 2014. The gas is exported through the Rev gas field to the Armada platform and transported to the UK via the CATS pipeline.
The average production rate on Jotun (7% partner) was 188 (209) boepd net to Det norske in the first quarter, which represented about 6 percent of total production. Production remained stable during the quarter.
The company is devoted to securing that all its projects are developed under the highest HSE standards in the oil industry.
During the first quarter, Det norske drilled the PL 659 Langlitinden exploration well in the Barents Sea. One notification was made to the Petroleum Safety Authority to inform that Det norske had to leave a radioactive source in the well as it got stuck and was not possible to retrieve. The Environmental Directorate carried out an audit of Det norske during the drilling operations, without finding any deviations.
In February 2014, the Ivar Aasen project experienced a near-miss hazardous situation with a dropped object at a yard on contract with Det norske. Det norske has investigated the incident and measures have been implemented.
The Ivar Aasen field development project is progressing according to schedule towards planned start up in Q4 2016.
Ivar Aasen is being developed with a steel jacket platform. The topside will include living quarters and a processing facility for first stage separation. The detailed engineering for the topside is being carried out by Mustang Engineering outside London, UK. First steel cutting for jacket and topside fabrication was performed in November 2013 and in March 2014 for the living quarter.
In December 2012, the partners in PL 457 encountered oil in the 16/1-16 and 16/1-16A wells. PL 457 is located adjacent and to the east of Ivar Aasen. The Ivar Aasen partners have signed a pre-unitization agreement with the partners in PL 457. The agreement allows for a coordinated development of the discoveries and sets out principles for the work processes towards an initial unitization split. The unitization agreement was finalised in June 2014 (refer to events after the quarter section below).
The Gina Krog field is progressing according to schedule with planned start up in 2017.
The development plan for the field includes a steel jacket and integrated topside with living quarters and processing facilities. Oil from Gina Krog will be exported to the markets with shuttle tankers while exit for the gas is via the Sleipner platform.
Statoil, as the pre-unit operator on the Johan Sverdrup field, announced the key parts of the field concept selection in February 2014, as Decision Gate 2 (DG2) for the first development phase was passed in the Johan Sverdrup preunit partnership. The concept for future phases will be decided in a separate process after the phase 1 PDO.
Statoil communicated full field production capacity is expected to be in the range 550,000 to 650,000 barrels of oil equivalents and gross field recoverable contingent resources between 1,800 and 2,900 million barrels oil equivalents. Total investments for the first phase are estimated to be between NOK 100 and 120 billion, including contingencies and provisions for market adjustments. Phase 1 has capacity to produce more than 70% of the resources.
The plan is to submit a Johan Sverdrup PDO to the authorities by the first quarter of 2015, with first oil expected in the fourth quarter of 2019. A unitization negotiation process has commenced between the Johan Sverdrup licensees and will be finalised at the same time as the PDO.
During the first quarter an appraisal well (16/2-19) was drilled on Geitungen on the northern margin of the Johan Sverdrup field in PL 265. The well encountered six metres of oil-bearing sandstone of medium to good quality assumed to constitute part of the Statfjord group. The well was drilled to a vertical depth of 2,024 metres and was terminated in basement rocks. Following this, the partnership decided to drill a sidetrack well approximately 1 km to the southwest with the objective to clarify the northern extent of the Johan Sverdrup main reservoir of the Draupne formation sandstones.
During the quarter, the company's cash spending on exploration was NOK 151 million, of which NOK 110 million was recognised as exploration expenses.
Drilling of exploration well 25/5-9 on the Trell prospect in the North Sea was completed in February this year. The well encountered a gross oil column of 21 meters in the Heimdal formation, of which 19 meters had good reservoir quality. Basic data acquisition and sampling indicate very good production properties, in line with expectations.
Preliminary estimates indicate between 0.5 and 2.0 million standard cubic meters of recoverable oil. The licensees will evaluate the discovery together with other nearby prospects and consider further follow-up.
Drilling of exploration well 7222/11-2 on the Langlitinden prospect in the Barents Sea was completed in February this year. The well encountered an oil-bearing channel sand of Triassic age. Extensive data sampling, including cores, wireline logs and fluid samples have been performed.
Hydrocarbons were proved in the main target for the well, but a mini-drillstem test proved poor reservoir properties. Det norske is of the opinion that the volumes proven in this well, as of today, are insufficient to justify a field development.
In the Awards in Predefined Areas (APA) 2013, Det norske was awarded six new licenses, of which two as operator. All six licenses are located in the North Sea.
In January 2014, Gro Haatvedt accepted an offer to become Senior Vice President Exploration in Det norske oljeselskap ASA. Haatvedt was previously Senior Vice President for Exploration on the Norwegian Continental Shelf in Statoil.
As part of a continuous program to optimise its portfolio, Det norske relinquishes exploration licenses, and farms in and out of licenses on a regular basis.
In the fourth quarter 2013, Det norske entered into an agreement with Atlantic Petroleum Norge AS concerning the sale of a 10 percent interest in PL 659 in the Barents Sea. The licence contains the Langlitinden prospect, which drilled in the first quarter. Det norske is the operator and holds 20 percent in the license following the transaction. As compensation, Atlantic Petroleum carried part of Det norske's drilling costs related to the exploration well.
Det norske's Corporate Assembly in March re-elected Tom Røtjer as member of the Board of Directors and elected Gro Kielland, formerly CEO of BP Norway, as new member of the Board of Directors in replacement of Maria Moræus Hanssen, who resigned from the Board of Directors in the autumn of 2013.
In the Geitungen sidetrack well, a 12-metre oil-bearing sandstone / siltstoneinterval of medium good reservoir development was encountered in the Draupne formation. The well was drilled to a vertical depth of 1 971 metres and was terminated in basement rocks. Extensive data acquisition and sampling have been carried out in both wells. The well results will be incorporated into the Johan Sverdrup field development work.
The General Assembly in April gave the Board of Directors an authorisation to increase the share capital, in one or more rounds, by a total of up to NOK 14,070,730. The Board of Directors were also authorised to acquire up to NOK 14,070,736 in treasury shares. The mandates are valid to the ordinary general meeting in 2015, but no later than June 30, 2015.
In the second quarter 2014, Det norske entered into an agreement with Petrolia Norway AS to farm out 10 percent of PL558 for a partial carry agreement. The transaction is approved by the partnership, pending approval by the authorities.
In June, Det norske entered into an agreement with Spike Exploration to swap a 10 percent interest in licence 554/B/C containing the Garantiana oil discovery for a 20 percent interest in license 457 containing parts of the Ivar Aasen deposit. Licence 457 is located adjacent and to the east of licence
001B (Ivar Aasen, DETNOR 35 percent and operator) on the Utsira High in the North Sea. Following drilling of the Asha discovery in late 2012 it was established that Ivar Aasen extends into licence 457. The transaction is subject to approval from the relevant authorities.
Moreover, Det norske subsequently signed an agreement with E.ON E&P Norge AS (E.ON) in June to swap two exploration licenses plus a cash consideration for a 20 percent interest in license 457. After completion of the agreement and the Spike transaction, Det norske will hold 40 percent in PL457. As a result of the transaction, the company's share in license 613 in the Barents Sea decreases from 35 percent to 20 percent and the company's share in license 676 S in the North Sea decreases from 20 percent to 10 percent.
In June, Det norske signed a unit agreement for the Ivar Aasen development on the Utsira High in the North Sea with the licencees in PL001B, PL242, PL457 and PL338. Det norske is operator and will have 34.7862 percent interest in the unit, following completion of the announced acquisition of 40 percent interest in PL457 from Spike Exploration and E.ON E&P Norge AS.
The unit comprises the Ivar Aasen and West Cable deposits, while the Hanz deposit remains in PL028B, where Det norske is operator and has 35 percent working interest. Hanz is planned to be developed in phase 2 of the Ivar Aasen development.
Det norske estimates that gross proven and probable (P50) reserves for the Ivar Aasen development (including Hanz) are about 210 million barrels of oil equivalents (mmboe), an increase of approximately 35 percent compared to end 2013 P50 reserves. Net to Det norske, this amounts to about 74 mmboe. The reserve increase is a result of the inclusion of volumes from PL457 and PL338, as well as positive results from well 16/1-16 in PL457 and ocean-bed seismic (OBS) processed in conjunction with an updated drainage strategy submitted to the Ministry of Petroleum and Energy on June 30, 2014.
The updated drainage strategy has not identified a need for additional wells to develop the Ivar Aasen reserves. Total investments for the Ivar Aasen development are estimated at NOK 27.4 billion (nominal), unchanged from the Plan for Development and Production (PDO).
The Ivar Aasen field development project is progressing according to schedule towards a planned start-up in the fourth quarter 2016. Partners in the development are Statoil, Bayerngas, Wintershall, VNG, Lundin and OMV.
Drilling of exploration well31/2-21 S on the Gotama prospect in PL550 offshore Norway was completed in May. The well did not encounter reservoir quality sandstones in the Upper Jurassic main target. The well encountered reservoir quality sandstones in secondary targets, but these were water wet. Det norske held a 10 percent carried interest in the well.
Drilling of exploration well 6507/5-7 on the Terne prospect in PL558 in the Norwegian Sea was completed in June. The well did not encounter hydrocarbons. Det norske farmed out 10 percent in the license for a partial carry agreement with Petrolia Norway AS, retaining a 10 percent partially carried interest in the license.
On June 2, 2014 Det norske announced that the Company had entered into an agreement to acquire Marathon Oil Norge AS ("MONAS") for a cash consideration of USD 2.1 billion.
The cash consideration is based on a gross asset value of USD 2.7 billion and is adjusted for debt, net working capital and interest on the net purchase price. The effective date of the transaction is 1 January 2014 and it is expected to close in the fourth quarter 2014, subject to regulatory approvals.
Marathon Norway represents an excellent strategic fit for Det norske:
After the transaction, Det norske will have 202 mmboe in 2P reserves (end 2013). In addition, the combined Company will have contingent resources amounting to 101 mmboe, excluding Johan Sverdrup. Further identified upside in Marathon's portfolio is estimated at approximately 80 million boe. Combined 2013 production for the two companies amounted to approximately 84 thousand boe per day, making Det norske one of the largest listed independent E&P companies in Europe in terms of output.
Det norske secured a fully committed and underwritten acquisition loan facility for the full cash consideration. This facility was provided by BNP PARIBAS, DNB, Nordea and SEB. On July 8, 2014 the Company signed a reservebased lending facility ("RBL Facility"), fully underwritten by the same banks. The RBL Facility is a senior secured seven-year USD 3.0 billion facility and includes an additional uncommitted accordion option of USD 1.0 billion. This long-term facility will replace the USD 2.2 billion acquisition bridge facility upon closing of the Marathon Oil Norway acquisition and refinance Det norske's current revolving credit facility.
As an integral component of the long-term financing plan, the company will strengthen its equity base by issuing the NOK equivalent of USD 500 million in new equity through a rights issue. The company's largest shareholder Aker Capital AS has pre-committed to subscribe for its 49.99% pro rata share of such rights issue. The remaining 50.01% is fully underwritten by a consortium of banks. With this equity issue, the company has secured the financing of its current work program until first production from the Johan Sverdrup field. The rights issue was resolved at an Extraordinary General Meeting on July 3, 2014 and the subscription period is expected to commence in mid-July.
The acquisition of Marathon Norway will increase Det norske's financial robustness and its ability to absorb the impact of any changes in future capital spend. This will improve the company's credit profile and reduce the cost of capital.
After the acquisition Det norske will have more than 450 employees. No redundancies are expected as a result of the transaction given the breadth of opportunities across the growing organisation
The completion of the transaction is subject to approval by the relevant Norwegian and European Union authorities.
The acquisition of Marathon Norway is a transformational transaction for Det norske. Marathon Norway's material portfolio of oil-producing assets, together with Det norske's development projects, provide a diversified and balanced asset base and creates a strong platform for future organic growth. Work to integrate the two organisations is well underway and closing of the transaction is expected in the fourth quarter 2014.
With the new reserve-based lending facility and the upcoming equity issue, the company has secured the financing of its current work program until first production from the Johan Sverdrup field.
Ivar Aasen and Johan Sverdrup are the most important field development projects for Det norske and both projects are progressing according to plan. The unitisation discussions at Johan Sverdrup are ongoing.
Based on current plans, Det norske will participate in around 10 exploration wells through 2014. Det norske will further revisit its exploration strategy going forward in light of the Marathon acquisition.
| Q1 | 1.1 - 31.03 | Q1 | 1.1 - 31.03 | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| (All figures in NOK 1,000) | Note | (Restated) 2014 |
2013 | (Restated) 2014 |
2013 | (All figures in NOK 1,000) | (Restated) 2014 |
2013 | (Restated) 2014 |
2013 |
| Petroleum revenues Other operating revenues |
2 2 |
155 101 3 241 |
78 709 1 630 |
155 101 3 241 |
78 709 1 630 |
Profit/loss for the period | -15 783 | -20 326 | -15 783 | -20 326 |
| Total operating revenues | 158 342 | 80 339 | 158 342 | 80 339 | Total comprehensive income in period |
-15 783 | -20 326 | -15 783 | -20 326 | |
| Exploration expenses | 3 | 109 582 | 233 738 | 109 582 | 233 738 | |||||
| Production costs Payroll and payroll-related expenses Depreciation |
5 4 |
42 949 4 559 88 863 |
41 512 1 527 34 997 |
42 949 4 559 88 863 |
41 512 1 527 34 997 |
|||||
| Impairment losses Other operating expenses |
4 5 |
167 373 13 305 |
19 208 | 167 373 13 305 |
19 208 | |||||
| Total operating expenses | 426 631 | 330 983 | 426 631 | 330 983 | ||||||
| Operating profit/loss | -268 289 | -250 644 | -268 289 | -250 644 | ||||||
| Interest income Other financial income |
6 6 |
12 145 34 663 |
7 202 20 602 |
12 145 34 663 |
7 202 20 602 |
|||||
| Interest expenses Other financial expenses |
6 6 |
86 753 20 530 |
12 748 47 153 |
86 753 20 530 |
12 748 47 153 |
|||||
| Net financial items | -60 475 | -32 097 | -60 475 | -32 097 | ||||||
| Profit/loss before taxes | -328 764 | -282 741 | -328 764 | -282 741 | ||||||
| Taxes (+)/tax income (-) | 7 | -312 981 | -262 415 | -312 981 | -262 415 | |||||
| Net profit/loss | -15 783 | -20 326 | -15 783 | -20 326 | ||||||
| Weighted average no. of shares outstanding Weighted average no. of shares fully diluted |
140 707 363 140 707 363 |
140 707 363 140 707 363 |
140 707 363 140 707 363 |
140 707 363 140 707 363 |
||||||
| Earnings/(loss) after tax per share Earnings/(loss) after tax per share fully diluted |
-0,11 -0,11 |
-0,14 -0,14 |
-0,11 -0,11 |
-0,14 -0,14 |
| Q1 | 1.1 - 31.03 | Q1 | 1.1 - 31.03 | |||||
|---|---|---|---|---|---|---|---|---|
| (Restated) | (Restated) | (Restated) | (Restated) | |||||
| Total comprehensive income in period |
| Q1 (Restated) |
1.1 - 31.03 (Restated) |
(Restated) | Q1 Q1 (Restated) |
(Restated) | 1.1 - 31.03 1.1 - 31.03 (Restated) |
||||
|---|---|---|---|---|---|---|---|---|---|
| (All figures in NOK 1,000) (All figures in NOK 1,000) |
Note Note |
2014 31.03.2014 |
2013 31.03.2013 |
2014 31.12.2013 |
(All figures in NOK 1,000) (All figures in NOK 1,000) 2013 (All figures in NOK 1,000) |
Note 2014 Note |
2014 2013 31.03.2014 |
2013 2014 31.03.2013 |
2014 2013 2013 31.12.2013 |
| Petroleum revenues ASSETS Other operating revenues |
2 2 |
155 101 3 241 |
78 709 1 630 |
155 101 3 241 |
78 709 Petroleum revenues Profit/loss for the period EQUITY AND LIABILITIES 1 630 Other operating revenues |
-15 783 2 2 |
155 101 -20 326 3 241 |
78 709 -15 783 1 630 |
155 101 -20 326 3 241 |
| Intangible assets | Total comprehensive Paid-in capital |
||||||||
| Total operating revenues Goodwill |
4 | 158 342 321 120 |
80 339 387 551 |
158 342 321 120 |
80 339 Total operating revenues Share capital income in period |
-15 783 12 |
158 342 -20 326 140 707 |
80 339 -15 783 140 707 |
158 342 -20 326 140 707 |
| Capitalised exploration expenditures | 4 | 1 555 348 | 2 247 718 | 2 056 100 | Share premium | 3 089 542 | 3 089 542 | 3 089 542 | |
| Other intangible assets | 4 | 643 050 | 660 581 | 646 299 | |||||
| Exploration expenses Deferred tax asset |
3 7 |
109 582 795 400 |
233 738 | 109 582 630 423 |
233 738 Exploration expenses |
3 | 109 582 | 233 738 | 109 582 233 738 |
| Production costs | 42 949 | 41 512 | 42 949 | 41 512 Production costs Total paid-in equity |
42 949 3 230 249 |
41 512 3 230 249 |
42 949 3 230 249 |
||
| Payroll and payroll-related expenses Tangible fixed assets |
5 | 4 559 | 1 527 | 4 559 | 1 527 Payroll and payroll-related expenses |
5 | 4 559 | 1 527 | 4 559 |
| Depreciation Property, plant, and equipment Impairment losses |
4 4 4 |
88 863 3 536 285 167 373 |
34 997 2 486 607 |
88 863 2 657 566 167 373 |
34 997 Depreciation Retained earnings Impairment losses Other equity |
4 4 |
88 863 167 373 -57 563 |
34 997 485 600 |
88 863 167 373 -41 780 |
| Other operating expenses Financial assets |
5 | 13 305 | 19 208 | 13 305 | 19 208 Other operating expenses |
5 | 13 305 | 19 208 | 13 305 |
| Long term receivables | 10 | 138 078 | 67 240 | 125 432 | Total Equity | 3 172 687 | 3 715 849 | 3 188 470 | |
| Total operating expenses Calculated tax receivables |
7 | 426 631 148 004 |
330 983 261 139 |
426 631 | 330 983 Total operating expenses |
426 631 | 330 983 | 426 631 330 983 |
|
| Other non-current assets | 8 | 282 472 | 200 559 | 285 399 | |||||
| Operating profit/loss Total non-current assets |
-268 289 7 419 757 |
-250 644 6 311 395 |
-268 289 6 722 340 |
-250 644 Operating profit/loss Provisions for liabilities |
-268 289 | -250 644 | -268 289 -250 644 |
||
| Pension obligations | 36 375 | 54 625 | 66 512 | ||||||
| Deferred taxes | 7 | 125 113 | |||||||
| Interest income Inventories |
6 | 12 145 | 7 202 | 12 145 | 7 202 Interest income Abandonment provision |
6 19 |
12 145 829 720 |
7 202 867 895 |
12 145 828 529 |
| Other financial income Inventories |
6 | 34 663 39 549 |
20 602 21 059 |
34 663 40 880 |
20 602 Other financial income Provisions for other liabilities |
6 | 34 663 696 |
20 602 325 |
34 663 780 |
| Interest expenses Other financial expenses Receivables |
6 6 |
86 753 20 530 |
12 748 47 153 |
86 753 20 530 |
12 748 Interest expenses 47 153 Other financial expenses Non current liabilities |
6 6 |
86 753 20 530 |
12 748 47 153 |
86 753 20 530 |
| Account receivables | 14 | 128 239 | 86 452 | 134 221 | Bonds | 17 | 2 475 559 | 589 939 | 2 473 582 |
| Net financial items Other short term receivables |
9 | -60 475 617 286 |
-32 097 337 720 |
-60 475 499 419 |
-32 097 Net financial items Other interest-bearing debt |
18 | -60 475 2 150 288 |
-32 097 1 453 035 |
-60 475 -32 097 2 036 907 |
| Short-term deposits | 24 375 | 23 625 | 24 075 | Derivatives | 13 | 48 228 | 48 693 | 49 453 | |
| Calculated tax receivables | 7 | 1 416 550 | 1 278 297 | 1 411 251 | |||||
| Profit/loss before taxes | -328 764 | -282 741 | -328 764 | -282 741 Profit/loss before taxes Current liabilities |
-328 764 | -282 741 | -328 764 -282 741 |
||
| Cash and cash equivalents | Short-term loan | 15 | 680 794 | 969 819 | 478 050 | ||||
| Cash and cash equivalents | 11 | 821 069 | 735 706 | 1 709 166 | Trade creditors | 218 370 | 230 398 | 452 435 | |
| Taxes (+)/tax income (-) | 7 | -312 981 | -262 415 | -312 981 | -262 415 Taxes (+)/tax income (-) Accrued public charges and indirect taxes |
7 | -312 981 24 457 |
-262 415 18 881 |
-312 981 -262 415 23 579 |
| Total current assets | 3 047 067 | 2 482 859 | 3 819 011 | Abandonment provision | 19 | 156 397 | 147 375 | ||
| Net profit/loss | -15 783 | -20 326 | -15 783 | -20 326 Net profit/loss Other current liabilities |
16 | -15 783 673 254 |
-20 326 719 684 |
-15 783 -20 326 795 680 |
|
| Weighted average no. of shares outstanding | 140 707 363 | 140 707 363 | 140 707 363 | Total liabilities 140 707 363 Weighted average no. of shares outstanding |
7 294 137 140 707 363 |
5 078 405 140 707 363 |
7 352 882 140 707 363 140 707 363 |
||
| Weighted average no. of shares fully diluted Earnings/(loss) after tax per share TOTAL ASSETS |
140 707 363 -0,11 10 466 824 |
140 707 363 -0,14 8 794 255 |
140 707 363 -0,11 10 541 352 |
140 707 363 Weighted average no. of shares fully diluted -0,14 Earnings/(loss) after tax per share TOTAL EQUITY AND LIABILITIES |
140 707 363 -0,11 10 466 824 |
140 707 363 -0,14 8 794 255 |
140 707 363 140 707 363 -0,11 10 541 352 |
||
| Earnings/(loss) after tax per share fully diluted | -0,11 | -0,14 | -0,11 | -0,14 Earnings/(loss) after tax per share fully diluted |
-0,11 | -0,14 | -0,11 |
| Other equity | |||||||
|---|---|---|---|---|---|---|---|
| (All figures in NOK 1,000) | Share capital Share premium | Other paid-in capital |
Other com prehensive income |
Retained earnings |
Total other equity |
Total equity | |
| Equity as of 31.12.2012 | 140 707 | 3 089 542 | 3 600 107 | -2 188 | -3 091 994 | 505 926 | 3 736 175 |
| Total loss for 2013 Equity as of 31.12.2013 |
140 707 | 3 089 542 | 3 600 107 | 894 -1 294 |
-548 600 -3 640 594 |
-547 706 -41 780 |
-547 706 3 188 469 |
| Profit/loss for the period 1.1.2014 - 31.03.2014 Equity as of 31.03.2014 |
140 707 | 3 089 542 | 3 600 107 | -1 294 | -15 783 -3 656 377 |
-15 783 -57 563 |
-15 783 3 172 687 |
| Q1 | Year | |||
|---|---|---|---|---|
| (All figures in NOK 1,000) | Note | 2014 | 2013 | 2013 |
| Cash flow from operating activities | ||||
| Profit/loss before taxes | -328 764 | -282 741 | -2 545 327 | |
| Taxes paid during the period | -26 585 | |||
| Tax refund during the period | 1 318 430 | |||
| Depreciation | 4 | 88 863 | 34 997 | 470 529 |
| Net impairment losses | 4 | 167 373 | 666 135 | |
| Accretion expenses | 19 | 12 920 | 9 924 | 42 765 |
| Losses on sale of license | 734 | |||
| Changes in derivatives | 6 | -2 383 | 2 708 | 3 174 |
| Amortization of interest expenses and arrangement fee | 6 | 10 064 | 9 291 | 88 458 |
| Expensed capitalized dry wells | 3,4 | 73 601 | 163 563 | 1 150 541 |
| Changes in inventories, accounts payable and receivables | -226 752 | -12 661 | 141 786 | |
| Changes in other current balance sheet items | -283 796 | -191 924 | -394 934 | |
| Net cash flow from operating activities | -488 876 | -266 843 | 915 707 | |
| Cash flow from investment activities | ||||
| Payment for removal and decommissioning of oil fields | 19 | -2 706 | -2 056 | -36 739 |
| Disbursements on investments in fixed assets | 4 | -589 611 | -461 186 | -1 495 709 |
| Disbursements on investments in capitalised exploration expenditures and other intangible assets | 4 | -114 942 | -236 007 | -1 358 941 |
| Sale/farmout of tangible fixed assets and licenses | 86 472 | |||
| Net cash flow from investment activities | -707 260 | -699 249 | -2 804 917 | |
| Cash flow from financing activities | ||||
| Repayment of short-term debt | 15 | -1 500 000 | ||
| Repayment of long-term debt | 17,18 | -290 927 | -2 185 102 | |
| Proceeds from issuance of long-term debt | 17,18 | 398 966 | 147 616 | 4 729 297 |
| Proceeds from issuance of short-term debt | 15 | 200 000 | 400 000 | 1 400 000 |
| Net cash flow from financing activities | 308 039 | 547 616 | 2 444 195 | |
| Net change in cash and cash equivalents | -888 097 | -418 476 | 554 985 | |
| Cash and cash equivalents at start of period | 11 | 1 709 166 | 1 154 182 | 1 154 182 |
| Cash and cash equivalents at end of period | 821 069 | 735 706 | 1 709 166 | |
| Specification of cash equivalents at end of period: | ||||
| Bank deposits, etc. | 810 723 | 725 109 | 1 693 319 | |
| Restricted bank deposits | 10 346 | 10 597 | 15 847 | |
| Cash and cash equivalents at end of period | 11 | 821 069 | 735 706 | 1 709 166 |
These condensed 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". The interim financial statements do not include all information required by IFRS. These interim financial statements have been subject to a review in accordance with the International Standard on Review Engagements 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity. These condensed interim financial statements replace and restate the condensed interim financial statements as at and for the three months ended 31 March 2014 released on 30 April 2014.
The reissuancee of these condensed interim financial statements has been triggered by a rights offering involving the preparation of a prospectus in connection to the acquisition of Marathon Oil Norge AS (refer to note 21), including an ISRE 2410 limited review performed by the Comapny's independent auditor. As a result, the Company evaluated events subsequent to the original approval date of 30 April 2014 by the board of directors of the Q1 2014 interim financial statements for new information that, if known at the original approval date, would have resulted in adjustments to the financial statements and for other information that would have resulted in additional disclosures. These events have been considered through the date of this report.
Subsequent events which have occurred since 30 April 2014 that have resulted in additional disclosures are described in note 21. There has been one matter which has resulted in the recognition of an impairment charge on the Jette field, during the three months ended 31 March 2014, as described in note 4.
The accounting principles used for this interim report are in all material respect consistent with the principles used in the Financial statement for 2013. There are some new and amended standards effective from 1 January 2014, as mentioned in the annual report 2013. These standards are implemented in Q1 2014, but do not have material impact on the interim Financial Statements.
| Q1 | ||||
|---|---|---|---|---|
| Breakdown of revenues: | 2014 | 2013 | ||
| Recognized income oil | 128 541 | 47 299 | ||
| Recognized income gas | 21 891 | 25 815 | ||
| Tariff income | 4 668 | 5 595 | ||
| Total petroleum revenues | 155 101 | 78 709 | ||
| Breakdown of produced volumes (barrel of oil equivalents): | ||||
| Oil | 195 760 | 85 330 | ||
| Gas | 64 810 | 88 310 | ||
| 260 569 | ||||
| Total produced volumes | 173 639 |
| Q1 | |||
|---|---|---|---|
| Breakdown of exploration expenses: | 2014 | 2013 | |
| Seismic, well data, field studies, other exploration costs | 17 222 | 60 345 | |
| Recharged rig costs | -47 047 | -38 418 | |
| Exploration expenses from license participation incl. seismic | 37 857 | 37 985 | |
| Expensed capitalized wells previous years | 13 434 | 13 993 | |
| Expensed capitalized wells this year | 60 166 | 149 570 | |
| Payroll and other operating expenses classified as exploration | 23 359 | 8 000 | |
| Exploration-related research and development costs | 4 590 | 2 263 | |
| Total exploration expenses | 109 582 | 233 738 |
| Other intangible assets | ||||||
|---|---|---|---|---|---|---|
| Intangible assets | Licenses etc.* |
Software | Total | Exploration exp ** |
Goodwill | |
| Book value 31.12.2012 | 661 642 | 3 899 | 665 541 | 2 175 492 | 387 550 | |
| Acquisition cost 31.12.2012 | 1 104 425 | 45 180 | 1 149 604 | 2 175 492 | 644 570 | |
| Additions | 219 | 235 788 | ||||
| Disposals/Expensed dry wells | 163 563 | |||||
| Acquisition cost 31.03.2013 | 1 104 425 | 45 399 | 1 149 824 | 2 247 718 | 644 570 | |
| Acc. depreciation and impairments 31.03.2014 | 447 333 | 41 910 | 489 243 | 257 019 | ||
| Book value 31.03.2013 | 657 093 | 3 488 | 660 581 | 2 247 718 | 387 551 | |
| Acquisition cost 31.12.2013 | 902 705 | 48 099 | 950 804 | 2 056 100 | 465 653 | |
| Additions | 46 | 46 | 114 896 | |||
| Disposals/Expensed dry wells | 73 601 | |||||
| Reclassification | -542 047 | |||||
| Acquisition cost 31.03.2014 | 902 705 | 48 145 | 950 850 | 1 555 348 | 465 653 | |
| Acc. depreciation and impairments 31.03.2014 | 263 821 | 43 977 | 307 798 | 144 532 | ||
| Book value 31.03.2014 | 638 884 | 4 168 | 643 050 | 1 555 348 | 321 120 | |
| Depreciation Q1 2014 | 2 732 | 563 | 3 295 |
Software is depreciated linearly over the software's lifetime, which is three years. Licences related to fields in production is depreciated using the Unit of Production method.
*The Ivar Aasen-field has an obligation related to investments to enable the Edvard Grieg facilites to receive fluids from the Ivar Aasen field. These processing rights are considered as an "Intangible asset" and included with NOK 89.8 million as of 31.03.2014.
| Tangible fixed assets | Fields under development |
Production facilities including |
Fixtures and fittings, office |
|
|---|---|---|---|---|
| ** | wells | machinery | Total | |
| Book value 31.12.2012 | 1 364 097 | 577 290 | 51 882 | 1 993 269 |
| Acquisition cost 31.12.2012 | 3 163 747 | 1 232 676 | 126 062 | 4 522 486 |
| Additions | 430 005 | 90 942 | 2 209 | 523 156 |
| Acquisition cost 31.03.2013 | 3 593 752 | 1 323 617 | 128 271 | 5 045 641 |
| Accumulated depreciation and impairments 31.03.2013 | 1 799 650 | 680 125 | 79 259 | 2 559 034 |
| Book value 31.03.2013 | 1 794 102 | 643 493 | 49 012 | 2 486 606 |
| Acquisition cost 31.12.2013 | 1 647 173 | 4 399 452 | 156 375 | 6 203 000 |
| Additions | 567 662 | 9 635 | 12 314 | 589 611 |
| Reclassification | 542 047 | 542 047 | ||
| Acquisition cost 31.03.2014 | 2 756 883 | 4 409 087 | 168 689 | 7 334 659 |
| Accumulated depreciation and impairments 31.03.2014 | 3 700 075 | 98 299 | 3 798 374 | |
| Book value 31.03.2014 | 2 756 883 | 709 012 | 70 390 | 3 536 285 |
| Depreciation Q1 2014 | 81 206 | 4 361 | 85 567 | |
| Impairments 1.1 - 31.03.2014 | 167 373 | 167 373 |
Capitalized exploration expenditures are reclassified to "Fields under development" when the field enteres into the development phase. Fields under development are reclassified to "Production facilities" from start of production. Production facilities, including wells, are depreciated in accordance with the Unit of Production Method. Office machinery, fixtures and fittings etc. are depreciated using the straight-line method over their useful life, i.e. 3-5 years. Removal and decommisioning costs are capitalized and included as "Production facilities".
**The Johan Sverdrup Field has entered into the development phase in the first quarter 2014. All costs relating to the development are thus recognised as tangible assets and previously capitalised exploration expenditures have been reclassified accordingly from intangible assets.
The Company has experienced lower than forecast production on the Jette field, which has led to reassessment and reduction of the reserves. Consequently, Det norske has performed an impairment assessment and has recorded an impairment charge in the first quarter of NOK 167 million before tax. The net after tax effect of this charge is NOK 36 million. The impairment is entirely related to tangible fixed assets.
The effect of the impairment is to restate previously reported figures as at and for the three months ended 31 March 2014 as follows: Impairment losses NOK 167 million (previously NOK nil), tax income NOK 313 million (previously NOK182 million), deferred tax asset NOK 795 million (previously NOK 665 million), property plant & equipment NOK 3 536 million (previously NOK 3 704 million), other equity NOK 58 million deficit (previously NOK 21 million deficit).
For producing licenses and licenses in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves. The following assumptions have been applied:
* discount rate of 8.2 percent nominal after tax
* a long term inflation of 2.5 percent
* a long term exchange rate of NOK/USD 6.00
* oil prices are based on forward curve
| Q1 | 01.01.-31.03 | ||||
|---|---|---|---|---|---|
| Reconciliation of depreciation in the income statement: | 2014 | 2013 | 2014 | 2013 | |
| Depreciation of tangible fixed assets | 85 567 | 29 818 | 85 567 | 29 818 | |
| Depreciation of intangible assets | 3 295 | 5 180 | 3 295 | 5 180 | |
| Total depreciation in the income statement | 88 863 | 34 997 | 88 863 | 34 997 |
| Q1 | ||
|---|---|---|
| Breakdown of payroll expenses: | 2014 | 2013 |
| Gross payroll expenses | 127 559 | 107 527 |
| Share of payroll expenses classified as exploration, development or production expenses, and expenses invoiced to licences |
-123 000 | -106 000 |
| Net payroll expenses | 4 559 | 1 527 |
| Q1 | ||
|---|---|---|
| Breakdown of other operating expenses: | 2014 | 2013 |
| Gross other operating expenses | 85 486 | 73 298 |
| Share of other operating expenses classified as exploration, | ||
| development or production expenses, and expenses invoiced | ||
| to licences | -72 181 | -54 090 |
| Net other operating expenses | 13 305 | 19 208 |
| Q1 | ||
|---|---|---|
| 2014 | 2013 | |
| Interest income | 12 145 | 7 202 |
| Return on financial investments | 300 | 488 |
| Currency gains | 31 981 | 20 114 |
| Fair value of derivatives | 2 383 | |
| Total other financial income | 34 663 | 20 602 |
| Interest expenses | 105 120 | 57 895 |
| Capitalized interest cost development projects | -28 431 | -54 439 |
| Amortized loan costs and accretion expence | 10 064 | 9 291 |
| Total interest expenses | 86 753 | 12 748 |
| Currency losses | 16 847 | 41 454 |
| Realised loss on derivatives | 3 683 | 2 991 |
| Fair value of derivatives | 2 707 | |
| Total other financial expenses | 20 530 | 47 153 |
| Net financial items | -60 475 | -32 097 |
| Q1 | ||
|---|---|---|
| Taxes for the period appear as follows: | 2014 | 2013 |
| Calculated current year exploration tax refund | -148 004 | -261 139 |
| Change in deferred taxes | -157 209 | -2 093 |
| Prior period adjustments | -7 768 | 818 |
| Total taxes (+) / tax income (-) | -312 981 | -262 415 |
A full tax calculation has been carried out in accordance with the accounting principles described in the annual report for 2013. The calculated exploration tax receivable as result of exploration activities in 2014 is recognised as a long-term item in the balance sheet. The tax refund for this item is expected to be paid in December 2015. The calculated exploration tax receivable as result of exploration activities in 2013 is recognised as a current asset in the balance sheet. The exploration tax refund for this item is expected to be paid in December 2014.
| Calculated tax receivables | 31.03.2014 | 31.03.2013 | 31.12.2013 |
|---|---|---|---|
| Tax receivables included as non-current assets | 148 004 | 261 139 | |
| Tax receivables included as current assets | 1 416 550 | 1 278 297 | 1 411 251 |
| Deferred taxes/deferred tax asset: | 31.03.2014 | 31.03.2013 | 31.12.2013 |
|---|---|---|---|
| Deferred taxes 1.1. | 630 423 | -126 604 | -126 604 |
| Change in deferred taxes | 157 209 | 2 093 | 567 368 |
| Prior period adjustments | 7 768 | -602 | |
| Deferred tax related to impairment and disposal of licenses | 192 830 | ||
| Deferred tax recorded towards OCI | -3 170 | ||
| Total deferred taxes asset | 795 400 | -125 113 | 630 423 |
| Applied tax | ||||
|---|---|---|---|---|
| Tax effect of tax losses carryforward: | rate | 31.03.2014 | 31.03.2013 | 31.12.2013 |
| Tax losses carryforward | 27 % | -560 954 | -375 008 | -479 558 |
| Tax losses carryforward | 51 % | -1 136 874 | -700 205 | -939 713 |
Temporary differences of tax losses carryforward is incuded in the deferred taxes.
| Q1 | ||
|---|---|---|
| Reconciliation of tax income | 2014 | 2013 |
| 27% company tax on result before tax | 88 766 | 76 340 |
| 51% special tax on result before tax | 167 670 | 144 198 |
| Tax effect of financial items - 27% only | -20 842 | 257 |
| Tax effect on uplift | 62 189 | 31 025 |
| Interest of tax losses carryforward | 6 343 | 4 017 |
| Other items (permanent differences and previous period adjustment) | 8 854 | 6 578 |
| Total tax income | 312 981 | 262 415 |
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Shares in Sandvika Fjellstue AS | 12 000 | 12 000 | 12 000 |
| Debt service reserve | 257 518 | 175 865 | 260 446 |
| Tenancy deposit | 12 954 | 12 694 | 12 954 |
| Total other non-current assets | 282 472 | 200 559 | 285 399 |
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Receivables related to deferred volume at Atla | 5 256 | 3 103 | |
| Pre-payments, including rigs | 195 660 | 33 648 | 146 977 |
| VAT receivable | 25 055 | 21 289 | 11 444 |
| Underlift | 43 540 | 23 318 | 18 611 |
| Other receivables, including operator licences | 347 775 | 259 465 | 319 283 |
| Total other short-term receivables | 617 286 | 337 720 | 499 419 |
For information about receivables related to deferred volume at Atla, see note 10.
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Receivables related to deferred volume at Atla | 138 078 | 67 240 | 125 432 |
| Total long term receivables | 138 078 | 67 240 | 125 432 |
The physical production volumes from Atla were higher than the commercial production volumes. This was caused by the high pressure from the Atla-field which temporarily has stalled the production from the neighbouring field Skirne. This is expected to continue through 2014 and into 2015. Income is recognised based on physical production volumes measured at market value. This deferred compensation is recorded as a long term or short term receivable, depending on when the income will occur, see Note 9.
The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the company's liquidity.
| Breakdown of cash and cash equivalents: | 31.03.2014 | 31.03.2013 | 31.12.2013 |
|---|---|---|---|
| Cash | 5 | 5 | 5 |
| Bank deposits | 810 718 | 725 104 | 1 693 314 |
| Restricted funds (tax withholdings) | 10 346 | 10 597 | 15 847 |
| Short-term placements | 821 069 | 735 706 | 1 709 166 |
| Unused exploration facility loan | 758 947 | 435 525 | 815 991 |
| Unused revolving credit facility | 3 740 648 | 1 401 120 | 3 945 286 |
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Share capital | 140 707 | 140 707 | 140 707 |
| Total number of shares (in 1.000) | 140 707 | 140 707 | 140 707 |
| Nominal value per share in NOK | 1.00 | 1.00 | 1.00 |
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Unrealized losses interest rate swaps | 48 228 | 48 693 | 49 453 |
| Total derivatives | 48 228 | 48 693 | 49 453 |
The company has entered into three interest rate swaps. The purpose is to swap floating rate loans to fixed rate. These rate swaps are market to market and with changes in market value recognized in the Statement of income.
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Receivables related to sale of petroleum | 13 202 | 15 399 | 70 885 |
| Receivables related to license transaction | 99 271 | 70 542 | 1 284 |
| Invoicing related to expense refunds including rigs | 15 766 | 511 | 62 052 |
| Total accounts receivable | 128 239 | 86 452 | 134 221 |
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Exploration facility | 680 794 | 969 819 | 478 050 |
| Total short-term loans | 680 794 | 969 819 | 478 050 |
The current facility of NOK 3,500 million was established in December 2012 and the company can draw on the facility until 31 December 2015 with a final date for repayment in December 2016. The maximum utilization including interest is limited to 95 percent of tax refund related to exploration expenses. The lenders have security in the company's tax receivable. The calculated exploration tax receivable as result of exploration activities in 2013 is expected to be paid in December 2014, and will be used to repay this loan. See note 7.
The interest rate is three months' NIBOR plus a margin of 1.75 percent, with a utilization fee of 0.25 percent on outstanding loan up to NOK 2,750 million and 0.5 percent if the utilized credit exceeds NOK 2,750 million. In addition a commitment fee of 0.7 percent is also paid on unused credit.
For information about the unused part of the credit facility for exploration purposes, see Note 11 - "Cash and cash equivalents".
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Current liabilities related to overcall in licences | 10 960 | 31 551 | 202 037 |
| Share of other current liabilities in licences | 443 729 | 503 576 | 310 673 |
| Overlift of petroleum | 9 588 | ||
| Other current liabilities | 218 565 | 184 556 | 273 382 |
| Total other current liabilities | 673 254 | 719 684 | 795 680 |
Other current liabilities includes unpaid wages and vacation pay, accrued interest and other provisions.
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Principal, bond Norsk Tillitsmann 1) | 593 240 | 589 939 | 592 304 |
| Principal, bond Norsk Tillitsmann 2) | 1 882 319 | 1 881 278 | |
| Total bond | 2 475 559 | 589 939 | 2 473 582 |
1)The loan runs from 28 January 2011 to 28 January 2016 and carries an interest rate of 3 month NIBOR + 6.75 percent. The principal falls due on 28 January 2016 and interest is paid on a quarterly basis. The loan is unsecured.
2)The loan runs from July 2013 to July 2020 and carries an interest rate of 3 month NIBOR + 5 percent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The loan is unsecured.
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Revolving credit facility | 2 131 650 | 1 449 131 | 1 992 055 |
| Unrealized currency | 18 639 | 3 904 | 44 852 |
| Total other interest-bearing debt | 2 150 288 | 1 453 035 | 2 036 907 |
In September 2013, the company entered into a USD 1 billion revolving credit facility with a group of nordic and international banks. The revolving credit facility can be increased with USD 1 billion on certain future conditions. The company can draw on the facility until September 2018 with a final date for repayment as of September 2018. The facility replaced the company's USD 500 million tranche which originally matured on 31 December 2015.
The interest rate on the revolving credit facility is from 1 - 6 months NIBOR/LIBOR plus a margin of 3 percent, with a utilization fee of 0.5 percent or 0.75 percent based on the amount drawn under the facility. In addition commitment fee of 1.20 percent is also paid on unused credit.
| 31.03.2014 | 31.03.2013 | 31.12.2013 | |
|---|---|---|---|
| Provisions as of 1 January | 975 904 | 798 057 | 798 057 |
| Incurred cost removal | -2 706 | -2 056 | -36 739 |
| Accretion expense - present value calculation | 12 920 | 9 924 | 42 765 |
| Change in estimates and incurred liabilities on new fields | 61 970 | 171 822 | |
| Total provision for abandonment liabilities | 986 117 | 867 895 | 975 904 |
Breakdown of the provision to short- and long-term liabilities
| Short term | 156 397 | 147 375 | |
|---|---|---|---|
| Long term | 829 720 | 867 895 | 828 529 |
| Total provision for abandonment liabilities | 986 117 | 867 895 | 975 904 |
The company's removal and decommissioning liabilities relate to the fields Jette, Glitne, Varg, Atla, Enoch, and Jotun. Time of removal is expected to be 2018 for Jette, 2014-2016 for Glitne, 2016-2018 for Varg, 2018- 2020 for Atla, 2017 for Enoch and in 2018-2021 for Jotun.
The estimate is based on executing a concept for removal in accordance with the Petroleum Activities Act and international regulations and guidelines.
During the second quarter 2012, the company announced that it had received a notice of reassessment from the Norwegian Oil Taxation Office (OTO) in respect of 2009 and 2010. Subsequently the notice has been extended to include 2011 and 2012. At the end of the third quarter 2012, the company responded to the notice of reassessment by submitting detailed comments.
During the normal course of its business, the company will be involved in disputes. The company provides accruals in its financial statements for probable liabilities related to litigation and claims based on the company's best judgement. Det norske does not expect that the financial position, results of operations or cash flows will be materially affected by the resolution of these disputes.
On June 2, 2014 Det norske announced that the Company had entered into an agreement to acquire Marathon Oil Norge AS for a cash consideration of USD 2.1 billion. The effective date of the transaction is 1 January 2014 and it is expected to close in the fourth quarter 2014, subject to regulatory approvals.
The transaction is partially financed by rights issue of new shares in Det norske, as approved by an Extraordinary General Meeting held July 3, 2014. The remaining financing is based on a reserve-based lending facility of USD 3 Billion. The loan agreement was signed on July 8, 2014.
During June, Det norske has entered into two license swaps which increase the company's share in the recently established Ivar Aasen unit.
Det norske entered into an agreement with Spike Exploration to swap a 10 percent interest in licence 554/B/C containing the Garantiana oil discovery for a 20 percent interest in license 457 containing parts of the Ivar Aasen deposit. Moreover, Det norske subsequently signed an agreement with E.ON E&P Norge AS (E.ON) to swap two exploration licenses plus a cash consideration for a 20 percent interest in license 457.
In June, Det norske signed a unit agreement for the Ivar Aasen development on the Utsira High in the North Sea with the licencees in PL001B, PL242, PL457 and PL338. Det norske is operator and will have 34.7862 percent interest in the unit, following completion of the announced swaps mentioned above.
Two wells have been completed in the second quarter. Gotama (PL550) and Terne (PL558) have not encountered hydrocarbons and the related capitalized cost has been expensed. As of March 31, 2014, the capitalized costs on these wells were immaterial.
For further information regarding the above matters, reference is made to notices published on the Oslo Stock Exchange.
Number 50 47
| License - partner-operated: | 31.03.2014 | 31.12.2013 | Licence - operatorships: | 31.03.2014 | 31.12.2013 |
|---|---|---|---|---|---|
| PL 019C | 30,0 % | 30,0 % | PL 001B | 35,0 % | 35,0 % |
| PL 019D | 30,0 % | 30,0 % | PL 026B*** | 62,1 % | 62,1 % |
| PL 029B | 20,0 % | 20,0 % | PL 027D | 100,0 % | 100,0 % |
| PL 035 | 25,0 % | 25,0 % | PL 027ES | 40,0 % | 40,0 % |
| PL 035B | 15,0 % | 15,0 % | PL 028B | 35,0 % | 35,0 % |
| PL 035C | 25,0 % | 25,0 % | PL 103B | 70,0 % | 70,0 % |
| PL 038 | 5,0 % | 5,0 % | PL 169C | 50,0 % | 50,0 % |
| PL 038D | 30,0 % | 30,0 % | PL 242 | 35,0 % | 35,0 % |
| PL 038E ** | 5,0 % | 0,0 % | PL 364 | 50,0 % | 50,0 % |
| PL 048B | 10,0 % | 10,0 % | PL 414 * | 0,0 % | 40,0 % |
| PL 048D | 10,0 % | 10,0 % | PL 414B * | 0,0 % | 40,0 % |
| PL 102C | 10,0 % | 10,0 % | PL 450 * | 0,0 % | 80,0 % |
| PL 102D | 10,0 % | 10,0 % | PL 460 | 100,0 % | 100,0 % |
| PL 102F | 10,0 % | 10,0 % | PL 494 | 30,0 % | 30,0 % |
| PL 102G | 10,0 % | 10,0 % | PL 494B | 30,0 % | 30,0 % |
| PL 265 | 20,0 % | 20,0 % | PL 494C | 30,0 % | 30,0 % |
| PL 272 | 25,0 % | 25,0 % | PL 497 * | 0,0 % | 35,0 % |
| PL 332 * | 0,0 % | 40,0 % | PL 497B * | 0,0 % | 35,0 % |
| PL 362 | 15,0 % | 15,0 % | PL 504 | 47,6 % | 47,6 % |
| PL 438 | 10,0 % | 10,0 % | PL 504BS | 83,6 % | 83,6 % |
| PL 442 | 20,0 % | 20,0 % | PL 504CS | 21,8 % | 21,8 % |
| PL 453S | 25,0 % | 25,0 % | PL 512 * | 0,0 % | 30,0 % |
| PL 492 | 40,0 % | 40,0 % | PL 542 * | 0,0 % | 45,0 % |
| PL 502 | 22,2 % | 22,2 % | PL 542B * | 0,0 % | 45,0 % |
| PL 522 | 10,0 % | 10,0 % | PL 549S | 35,0 % | 35,0 % |
| PL 531 | 10,0 % | 10,0 % | PL 553 | 40,0 % | 40,0 % |
| PL 533 | 20,0 % | 20,0 % | PL 573S | 35,0 % | 35,0 % |
| PL 535 | 10,0 % | 10,0 % | PL 626 | 50,0 % | 50,0 % |
| PL 535B | 10,0 % | 10,0 % | PL 659 *** | 20,0 % | 30,0 % |
| PL 550 | 10,0 % | 10,0 % | PL 663 | 30,0 % | 30,0 % |
| PL 551 | 20,0 % | 20,0 % | PL 677 | 60,0 % | 60,0 % |
| PL 554 | 20,0 % | 20,0 % | PL 709 | 40,0 % | 40,0 % |
| PL 554B | 20,0 % | 20,0 % | PL 715 | 40,0 % | 40,0 % |
| PL 554C ** | 20,0 % | 0,0 % | PL 724** | 40,0 % | 0,0 % |
| PL 558 | 20,0 % | 20,0 % | PL 748** | 40,0 % | 0,0 % |
| PL 563 | 30,0 % | 30,0 % | Number | 27 | 33 |
| PL 567 | 40,0 % | 40,0 % | |||
| PL 568 | 20,0 % | 20,0 % | * Relinquised licenses or Det norske has withdrawn from the license. | ||
| PL 571 | 40,0 % | 40,0 % | |||
| PL 574 | 10,0 % | 10,0 % | ** Interest awarded in APA-round (Application in Predefined Areas) in 2013. Offers were announced in 2014. | ||
| PL 613 | 35,0 % | 35,0 % | |||
| PL 619 | 30,0 % | 30,0 % | *** Aqcuired/changed through license transaction or license is split. | ||
| PL 627 | 20,0 % | 20,0 % | |||
| PL 667 | 30,0 % | 30,0 % | |||
| PL 672 | 25,0 % | 25,0 % | |||
| PL 676S | 20,0 % | 20,0 % | |||
| PL 678BS ** | 25,0 % | 0,0 % | |||
| PL 678S | 25,0 % | 25,0 % | |||
| PL 681 | 16,0 % | 16,0 % | |||
| PL 706 | 20,0 % | 20,0 % | |||
| PL 730 ** | 30,0 % | 0,0 % |
| 2014 | 2013 | 2012 | ||||||
|---|---|---|---|---|---|---|---|---|
| Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | |
| Total operating revenues | 158 342 | 254 353 | 323 563 | 285 626 | 80 339 | 116 797 | 49 014 | 69 603 |
| Exploration expenses | 109 582 | 544 400 | 588 289 | 270 635 | 233 738 | 194 924 | 402 635 | 417 140 |
| Production costs | 42 949 | 97 602 | 53 419 | 57 086 | 41 512 | 74 027 | 45 515 | 46 154 |
| Payroll and payroll-related expenses | 4 559 | 3 854 | 4 129 | 28 515 | 1 527 | 267 | 1 280 | 703 |
| Depreciation | 88 863 | 124 021 | 163 666 | 147 844 | 34 997 | 56 505 | 15 056 | 19 780 |
| Impairments | 167 373 | 657 597 | 6 837 | 1 700 | 127 155 | 1 880 953 | 140 669 | |
| Other operating expenses | 13 305 | 8 811 | 25 247 | 56 619 | 19 208 | 21 995 | 21 140 | 16 050 |
| Total operating expenses | 426 631 | 1 436 285 | 841 588 | 562 400 | 330 983 | 474 873 | 2 366 579 | 640 497 |
| Operating profit/loss | -268 289 | -1 181 933 | -518 025 | -276 773 | -250 644 | -358 076 | -2 317 565 | -570 894 |
| Net financial items | -60 475 | -105 851 | -131 089 | -48 915 | -32 097 | -13 763 | -45 784 | -23 065 |
| Profit/loss before taxes | -328 764 | -1 287 784 | -649 114 | -325 688 | -282 741 | -371 839 | -2 363 349 | -593 959 |
| Taxes (+)/tax income (-) | -312 981 | -959 137 | -490 975 | -284 200 | -262 415 | -324 575 | -1 774 462 | -376 558 |
| Net profit/loss | -15 783 | -328 647 | -158 139 | -41 488 | -20 326 | -47 264 | -588 887 | -217 401 |
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