Annual Report • Mar 20, 2015
Annual Report
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THE TRANSFORMATION OF
ANNUAL REPORT 2014
The story about Det norske is the story about entrepreneurship and a small start-up company from Trondheim that grew to be a major player on the Norwegian Continental Shelf. Through listing on the stock exchange, mergers, acquisitions and organic growth, Det norske has been transformed into one of Europe's largest listed independent E&P companies.
The current company was established in Trondheim in 2005, through reestablishment of the E&P company Pertra.
In 2006, the company was listed on Oslo Børs as Pertra ASA. By yearend 2006, the company had 29 employees.
Pertra and DNO decided to carry out a merger of Pertra and the Norwegian interests of DNO, organized through the company NOIL Energy. As a result of the merger, Pertra changed its name to Det norske oljeselskap ASA. NOIL Energy's licence portfolio comprised inter alia the Ivar Aasen and Johan Sverdrup licences. By year-end 2007,
the company had 78
employees.
In 2009, negotiations regarding a merger with Aker Exploration commenced. Aker ASA was a new major owner of Det norske, and the merger was effective from 23 December 2009. By yearend 2009, the company had 176 employees.
As operator and with startup of production on the Jette field, Det norske became in May 2013 a fully-fledged oil company with activities in the entire chain of value creation; exploration, development and production. By yearend 2013, the company had 230 employees.
2014 In the summer of 2014,
Det norske announced its acquisition of Marathon Oil Norge AS. Effective as of 15 October 2014, Det norske emerged as a new and larger company with considerable production from the Alvheim area and an experienced operational organization in Stavanger. As of 31 December, the company employed 507 people.
| 4 | Five years with Det norske |
|---|---|
| 5 | Key figures |
| 6 | About Det norske |
| 8 | Key events in 2014 |
| 9 | Quarterly financial results |
| 10 | A great leap forward |
| 12 | Hand in glove |
| 16 | Licences and exploration |
| 18 | Ivar Aasen |
| 24 | A giant project creating major ripple effects |
| 28 | Production |
| 34 | Finance |
| 36 | Health, safety and the environment |
| 40 | Corporate social responsibility (CSR) |
| 42 | A challenging year for the oil industry |
| 44 | Organization and the working environment |
| 48 | The Executive Management Team |
| 50 | Board of Directors |
| 52 | Words and phrases |
| Board of Directors' Report | |
| 56 | Board of Directors' Report |
| Financial Statements | |
| 84 | Financial Statements with Notes |
| 140 | Auditor's Report |
72 The Board of Directors' Report on Corporate Governance
139 Statement from the Board of Directors and the Chief Executive Officer
Number of employees Number of employees Total production
4
144 5
ANNUAL REPORT 2014
| 2014 | 2013 | 2012 | 2011 | 2010 | |
|---|---|---|---|---|---|
| No. of licence interests as of 31 December | 79 | 80 | 67 | 65 | 66 |
| No. of operatorships | 35 | 33 | 26 | 28 | 30 |
| Total production per year (boe) | 5 704 900* | 1 629 115 | 544 734 | 548 268 | 763 494 |
| Average production per day (boe) | 15 630* | 4 463 | 1 488 | 1 502 | 2 092 |
| Reserves (P50) as of 31 December (boe) | 206 mill. | 66 mill. | 65 mill. | 68 mill. | 1 mill. |
| Total operating revenues (USD million) | 464 | 161 | 57 | 78 | 61 |
| Operating profit/loss before depreciation and amortization (USD million) |
208 | -185 | -272 | -151 | -214 |
| Operating profit/loss (USD million) | -299 | -379 | -660 | -192 | -263 |
| Income/loss before taxes (USD million) | -376 | -433 | -678 | -234 | -287 |
| Net income/loss (USD million) | -279 | -93 | -164 | -66 | -93 |
| Exploration costs (USD million) | 158 | 279 | 276 | 181 | 234 |
| Total exploration costs (expensed and capitalized) (USD million) |
199 | 282 | 284 | 323 | 405 |
| Cash flow before financing activities (USD million) | -2 003 | -321 | -370 | -47 | -183 |
| Book value of equity (USD million) | 652 | 524 | 671 | 614 | 522 |
| Market capitalization as of 31 December (USD million) | 1 087 | 1 543 | 2 085 | 1 878 | 512 |
| No. of shares as of 31 December | 202 618 602 | 140 707 363 | 140 707 363 | 127 915 786 | 111 111 111 |
| Nominal value per share as of 31 December (NOK) | 1.00 | 1.00 | 1.00 | 1.00 | 1.00 |
| Share price as of 31 December (NOK) | 39.87 | 66.70 | 82.50 | 88.00 | 27.00 |
| No. of employees as of 31 December | 507 | 230 | 214 | 173 | 193 |
*Production volumes from Marathon Oil Norge AS are included from 15.10.2014
ANNUAL REPORT 2014
Since its establishment, Det norske has made bold choices on the Norwegian Continental Shelf.
We have embraced the possibilities and not succumbed to limitations. We have gone further than others. With our history, our expertise and our ambitions, we will challenge conventional truths.
We shall continue to explore and develop the opportunities on the Norwegian Continental Shelf to deliver the highest possible value to our employees, to our investors and to society. We will always be moving forward.
"Always moving forward to create value on the Norwegian shelf"
Det norske is a fully-fledged oil company engaged in exploration, development and production on the Norwegian Continental Shelf. We are building one of Europe's largest independent E&P companies.
Det norske is the operator for the producing fields Alvheim, Bøyla, Vilje, Volund and Jette. We are also the operator of the development of the Ivar Aasen field. The company is partner in the Johan Sverdrup field and has an active exploration programme on the Norwegian Continental Shelf. The company has an ambitious strategy for continued growth.
Det norske's headquarters are located in Trondheim, with offices in Stavanger, Oslo and Harstad. Det norske is listed on Oslo Børs under the ticker 'DETNOR'.
We are always curious and aiming for new and better solutions.
RESPONSIBLE We always put safety first and strive to create the highest possible value for our owners and for society.
We always build trust and reputation through reliability and consistent behaviour.
We are always committed to each other, to the company and to society.
Operator Partner Office
8
ANNUAL REPORT 2014
30 June
Unitization agreement and increased volumes
for Ivar Aasen
The board of directors approves the allocation of offer shares in the rights issue
Det norske announces Marathon Oil Norge AS
2014 Acquires Marathon Oil Norge AS and becomes one of the largest independent listed E&P companies in Europe. A new executive management team take up their appointments
Environmental impact assessment for Johan Sverdrup is announced and shows that the project progresses according to plan
Oil and gas discovery in the Askja prospect in the North Sea
Six new licences and two new operatorships awarded in the licensing round for mature areas on the Norwegian Continental Shelf (APA 2013)
21 February Oil discovery in the Trell and Langlitinden
prospects
Det norske spuds Langlitinden, the company's first operated well in the Barents Sea
Announces the development concept for the Johan Sverdrup field
Karl Johnny Hersvik takes up the position of Chief Executive Officer
| Q4 | Q3 | Q2 | Q1 | |
|---|---|---|---|---|
| Total production (barrels of oil equivalent per day)* | 54 175 | 2 335 | 2 698 | 2 895 |
| Oil and gas production (Kboe = thousand barrels of oil equivalent) | 4 984 | 215 | 245 | 261 |
| Oil price realized (USD/barrel) | 74 | 104 | 108 | 107 |
| Operating revenues (USD million) | 346 | 18 | 74 | 26 |
| EBITDA (USD million) | 239 | -62 | 33 | -2 |
| Cash flow from production (USD million) | 299 | 10 | 16 | 18 |
| Exploration expenses (USD million) | 50 | 70 | 20 | 18 |
| Total exploration expenditures (expensed and capitalized) (USD million) | 33 | 91 | 50 | 25 |
| Operating profit/loss(-) (USD million) | -184 | -90 | 19 | -44 |
| Net profit/loss(-) for the period (USD million) | -287 | -17 | 27 | -2 |
| No. of licences (operatorships) | 79 (35) | 70 (25) | 74 (27) | 77 (27) |
*Production volumes from Marathon Oil Norge AS are included from 15.10.2014
10
11
Visions and values can easily be degraded only to posters on a wall or put aside in a drawer once they have been presented. I believe in organizations that challenge each other while working to achieve one common goal, and this is what I observe in Det norske. The art of creating value is not merely a vision; it is an essential part of everyday life.
In 2014, we doubled our staff and significantly increased our production through the transformational acquisition of Marathon Oil Norge AS. As far as I am aware, this is the first time a Norwegian E&P company acquired an American E&P company on the Norwegian Continental Shelf. I was also proud to see that the acquisition was completed in only four and a half months without affecting neither safety nor production. This demonstrates agility and an ability to convert possibilities into concrete results quickly when an opportunity arises.
Det norske is well positioned in Johan Sverdrup, the largest industrial project in Norwegian history. The project will generate solid cash flows for Det norske from its start-up in 2019. This will give us a good basis for further development of the company and for encountering fluctuating oil prices going forward. In the process of unitization and submission of the Plan for Development and Operation for the Johan Sverdrup development, we believe that the ownership interests must be divided in a just manner, based on the actual values in the licenses.
In Ivar Aasen the reserve estimates increased in 2014. We are steering a steady course toward start-up of production in the fourth quarter 2016. With our position on the Norwegian Continental Shelf, Det norske is confident that we will deliver good results to our owners. We have a strong belief in the potential of the Norwegian Continental Shelf and are revising our exploration strategy to utilize this potential.
As the company's major shareholder, Aker has, with its strong industry competence and financial muscles, contributed significantly to our rapid transformation over the last years. Aker led the way to ensure a successful rights issue when we acquired Marathon, clearly demonstrating its long-term ownership perspective. In combination with the new seven-year USD 3 billion debt facility and considerably improved cash flows, this significantly strengthened the company's financial robustness.
Det norske opened the year with the announcement of a new vision for the company: «Always moving forward to create value on the Norwegian shelf». The vision illustrates the drive and enthusiasm that has characterized the company during its first nine years. In 2014, we took another important step forward.
Therefore, Det norske was well equipped when oil prices dropped and the environment in which we operate became more challenging last autumn. The oil price plummeted to around half of the prices we realized during the summer and the volatility in the markets increased. With this in mind, I am pleased that we in Det norske are fortunate to benefit from a word-class, low break-even cost asset base. Alvheim operations have proved extraordinary uptime and are generating strong cash flows from operations, even at today's oil prices. Our developing assets, mainly being the Det norske operated Ivar Aasen field and the giant Johan Sverdrup development, will continue to grow returns further when they come on stream.
We are nevertheless taking steps to strengthen our business to adapt to the current market situation and make sure that we come out of this downturn as a stronger and more robust company. Consequently, we are working at full speed to optimize the organization and improve our work processes, aiming to reduce expenditures and strengthen our efficiency and flexibility.
Our two major developments, Ivar Aasen and Johan Sverdrup, are in the middle of the investment cycle and ensuring financial robustness is important to safeguard the value of these projects. We are therefore working to further bolster our financial flexibility through a more diversified capital structure. Overall, I am confident that this will give us an edge that will enable Det norske to make new, great leaps going forward.
We will always be moving forward to create value on the Norwegian shelf!
Karl Johnny Hersvik Chief Executive Officer
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On 2 June 2014, it was announced that Det norske oljeselskap ASA was to take over Marathon Oil Norge AS. The integration was formally implemented on 15 October. Two different companies were merged to form one bigger and stronger company with 507 employees – almost twice as many as before the acquisition. Det norske is now actively engaged in exploration operations, is responsible for a major development as operator for Ivar Aasen, and has extensive production – primarily from the Alvheim area.
"Det norske will be a major operator and a robust company with ambitions on the Norwegian Continental Shelf. We are taking over a substantial portfolio, with high production rates and considerable operating experience. That complements Det norske's expertise in exploration and development. This is a major step forward for Det norske," said a proud CEO Karl Johnny Hersvik, after the acquisition.
It only took four and a half months from the acquisition was announced until the two companies had completed
Through the acquisition of Marathon Oil Norge AS, Det norske made a quantum leap that has taken the company into a new phase. The integrated company is one of the biggest independent, listed exploration and production companies in Europe.
the first phase of the integration. The new organization was in place on 15 October. The integration was carried out at the same time as operations carried on as usual in both companies – in both production and development. All the official requirements were met and the acquisition was approved by both the Norwegian and the European competition authorities.
The two companies fit well. Marathon Oil Norge AS's portfolio was sound, with limited investment commitments, low historical tax balances and high production in the short term. This fits well with the planned production start-up on the Ivar Aasen field in the fourth quarter 2016 and the development of the Johan Sverdrup field, where production is scheduled to start in 2019. Marathon Oil Norge AS's extensive operating experience from the Alvheim field complements Det norske's expertise. The activity is concentrated geographically, with the well-run Alvheim FPSO being the core producer. The company's producing fields are rich in oil, with 80 per cent oilbased reserves.
212 % INCREASE IN RESERVES 120 % INCREASE IN NUMBER OF EMPLOYEES
Det norske paid USD 2.1 billion for the shares in Marathon Oil Norge AS. The acquisition was financed by a combination of equity and debt. A new reserve-based lending facility (RBL facility) of USD 3 billion was established and drawn amount on the revolving credit facility (RCF) of USD 1 billion has been repaid. The cash contribution was based on a gross valuation of USD 2.7 billion (NOK 16.2 billion), and it was adjusted for liabilities, net working capital and interest on the net purchase price.
In connection with the acquisition, the company's equity was also strengthened through a share issue of USD 500 million (NOK 3 billion) to existing shareholders. The company's biggest shareholder, Aker ASA, subscribed for the company's proportionate share of 49.9 per cent. The share issue was oversubscribed by 43 per cent.
Following the integration of Marathon Oil Norge AS, Det norske had 206 million barrels of oil equivalent in proven and probable reserves (2P) by year-end 2014. After the submission of the PDO for Johan Sverdrup, Det norskes reserves more than doubled. Full-field 2P reserves are 279 million barrels of oil equivalent (assuming 11.8933 per cent interest to Det norske). The combined company had contingent resources of 72 to 113 million barrels of oil equivalent at year-end, in addition to Johan Sverdrup.
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It is important to have access to acreage in order to discover oil and gas. As of 31 December 2014, Det norske held ownership interests in 79 licences on the Norwegian Continental Shelf. At the turn of the year, the company was the operator for 35 of these licences.
During the year, Det norske was awarded six new licences in the APA 2013 licensing round, including two operatorships. With the acquisition of Marathon Oil Norge AS, Det norske took over interests in twelve licences, whereof ten were operatorships.
About two thirds of the Det norskes's exploration budget is invested in the mature areas in the North Sea, where the infrastructure is good and the discovery rate still high. The remaining resources are invested primarily in the Barents Sea and in the more immature areas in the North Sea.
More discoveries
The exploration year got off to a good start with an oil and gas discovery in the Askja West and Askja East prospects in licence 272 in the North Sea. A 90-metre gas column was proved in Askja West, whereas a 40-metre oil column was encountered in Askja East.
In December, Det norske made a discovery in licence 035 in the Krafla North prospect in the same area. The well encountered two oil columns of 20 metres and 80 metres, respectively. The licensees in licences 035 and 272 will assess development of the discoveries together with previous discoveries in the licences. Preliminary estimates of the discoveries in these licences are estimated to be between 140 and 220 million barrels of oil equivalent.
Det norske also made two non-commercial discoveries in 2014. The company participated in a total of eleven wells (including Askja): eight exploration wells and three appraisal wells. The company was the operator for three of these. In 2014, total exploration expenditures amounted to USD 157.5 million.
Det norske has good access to licences and operatorships on the Norwegian Continental Shelf and is an active explorer. In 2014, the exploration activity was concentrated to the North Sea.
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The Ivar Aasen field grew significantly in size in 2014. The reserves increased from 158 to 204 million barrels, an increase of around 35 per cent. This was the result of an upward adjustment of the reserves and the inclusion of two new licences, 457 and 338, in the field development. Through the acquisition of interests in licences, Det norske maintained its ownership interest in the field at around 35 per cent. That means that Det norske has net reserves of about 71 million barrels of oil equivalent from the Ivar Aasen field.
The first oil from the field will be produced in the fourth quarter 2016. Production will be around 70 000 barrels of oil equivalent in 2020. At plateau level, Det norske's production will be about 24 000 barrels a day. The lifetime of the Ivar Aasen field is expected to be 20 years, depending on oil prices and production trends.
The development of the Ivar Aasen field now includes resources in five licences: 001B, 028 B, 242, 338 and 457, and it comprises the discoveries Ivar Aasen, Hanz, West Cable and Asha. In June 2014, the licensees in the five licences signed an agreement on the ownership distribution. The unitization includes the deposits in Ivar Aasen, West Cable and Asha. The Hanz deposit in licence 028 B is not part of the agreement. Det norske is the operator for 028 B and has a 35 per cent interest. Hanz will be developed in phase 2 of the Ivar Aasen development.
Activity has now started on the Ivar Aasen field in the North Sea. The drilling of pilot wells started in the first quarter 2015, and it is being carried out by the rig Maersk Interceptor. The rig came to Norway in October 2014 and was christened in Stavanger. It was in place and ready on the field late in December. The drilling of the pilot wells is important in order to learn more about the reservoir, its thickness and other properties. This information will help to clarify the geomodels and drainage strategy early on and it will help to optimize the location of the production and injection wells.
The rig Maersk Interceptor is on a five-year contract with Det norske, with an option for a two-year extension. Maersk Interceptor was delivered from the Keppel FELS yard in Singapore. With a height of 206 metres,
The Ivar Aasen development has grown, both in size and in number of partners. Moreover, the development is proceeding as planned.
it is the biggest jack-up rig in the world. It is designed for all-year operation in the North Sea at water depths of up to 150 metres, and both the uptime and drilling efficiency have been maximized through double handling of pipe operations. On Ivar Aasen, the rig stands at a water depth of 112 metres, with 38 metres between the water surface and the deck.
In summer 2014, the project reached an important milestone when one of the main parts of the jacket was rolled up. Six such operations have subsequently been carried out, which means that the jacket as a whole could stand on its own feet at the turn of the year. The last big roll-up was carried out on 12 December. The jacket was completed and delivered from Saipem's yard in Arbatax on Sardinia in the first quarter 2015. It will be put in place on the Ivar Aasen field in the second quarter of 2015, where it will stand 25 metres above the water surface.
The platform deck is also gradually taking shape at SMOE's yard in Singapore. The lower deck has been sandblasted and painted. New steps are being taken every day on this complicated structure that will sail to the Utsira High in the first half-year 2016.
The living quarters are being built by Apply Leirvik at Stord. The living quarters will consist of three modules. They are scheduled for completion in 2015. The helideck from Singapore and the lifeboats from Kvinnherad will also be brought there for completion. The living quarters will have a total floor space of 3 267 square metres and will contain 70 cabins and many facilities. The living quarters are scheduled to depart for the North Sea in May 2016.
The development of the Ivar Aasen field is a global project, involving deliveries from more than 200 locations worldwide. Several hundred employees and consultants from Det norske are working on the Ivar Aasen project. Including all the contractors and subcontractors, there will at most be several thousand people working on the development.
At the end of December, cargo ships carrying equipment packages worth approximately NOK 300 million set sail for Singapore. In total, there were more than
500 tonnes of advanced equipment on board, most of it manufactured in Norway. The delivery of packages from Norway shows that Norwegian suppliers are competitive in relation to the most advanced products: cranes, pumps, tanks, generators, control systems and metering systems for oil and gas.
Ivar Aasen is coordinated with the neighbouring field Edvard Grieg, which will receive partially processed oil and gas from the Ivar Aasen field for further processing and export. The oil will be exported via Grane, and the gas via Sage on the UK continental shelf. Edvard Grieg also supplies Ivar Aasen with power and lift gas.
The Ivar Aasen field is situated on the Utsira High in the same area as the Johan Sverdrup and Edvard Grieg fields. Ivar Aasen was the first licence awarded on the Norwegian Continental Shelf in 1965, then with Esso as operator.
Aker Solutions was awarded the front-end engineering design (FEED) contract.
SMOE and Mustang Engineering are delivering the platform deck, with engineering in Woking/Kuala Lumpur and building in Singapore and Batam.
Apply Leirvik is building the living quarters at Stord. Saipem has the contract for construction of the steel jacket. Engineering is carried out in Kingston, UK, and building in Sardinia, Italy.
Saipem also has the contract for lifting operations and transport of the steel jacket.
EMAS is delivering the pipelines and the subsea cable. Siemens has been awarded the contract for delivery of an integrated electric power, instrumentation, controls and communication system.
Aibel has the contract for hook-up, operations support, maintenance and modifications.
Prosafe is responsible for the living quarters during the work offshore.
Maersk Drilling will drill the wells using the rig Maersk Interceptor.
Schlumberger has the contract for well completion.
| DET NORSKE (operator ) |
34.7862 % |
|---|---|
| STATOIL | 41.4730 % |
| BAYERNGAS NORGE | 12.3173 % |
| WINTERSHALL NORGE | 6.4651 % |
| VNG NORGE | 3.0230 % |
| LUNDIN NORWAY | 1.3850 % |
| OMV NORGE | 0.5540 % |
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On Friday 13 February 2015, the partnership submitted the Plan for Development and Operation (PDO) for Phase 1 to the Minister of Petroleum and Energy, Tord Lien.
"Johan Sverdrup is an exceptional project denoting optimism for the Norwegian Continental Shelf. With a breakeven price of under USD 40 per barrel, it will generate great value and ensure solid cash flows for Det norske for many decades to come. Today is a great and important day for Det norske", said the Chief Executive Officer, Karl Johnny Hersvik, in connection with the submission of the PDO.
The estimated lifetime of the field is 50 years, creating major positive ripple effects for society. The expected recoverable reserves are estimated at between 1.7 and 3.0 billion barrels of oil equivalent, of which between 1.4 and 2.4 billion barrels of oil equivalent in Phase 1. On plateau, production from the Johan Sverdrup field will constitute approximately 40 per cent of all Norwegian oil production.
The revenues from the Johan Sverdrup field are estimated at approximately NOK 1 350 billion. Approximately half of this will be paid to the State in the form of taxes. The
project will secure many Norwegian jobs. According to preliminary estimates, close to 51 000 man-years will be generated in the first phase of development alone, in the 2014 – 2019 period. When the project enters Phase 1 Operations, it is expected to generate approximately 2 700 man-years of employment, increasing to 3 400 man-years at peak field development, planned from 2022.
The Norwegian Parliament will decide on the development of the Johan Sverdrup field during the first six months of 2015. The start-up is planned for December 2019.
The partnership, consisting of Det norske, Statoil, Lundin Norway, Petoro and Maersk Oil, has recommended Statoil as operator for all phases of field development and operation. At the time of submission of the PDO, Det norske had not succeeded in reaching an agreement about the distribution of ownership interests with the other partners. The other partners have thus asked the Ministry of Petroleum and Energy to conclude on the final unitization in the Johan Sverdrup field. Until this conclusion is made, the Ministry of Petroleum and Energy has decided that Statoil's recommendation for distribution of the resources be used as a basis.
"For Det norske, it has always been a decisive principle that the ownership interests in Johan Sverdrup be distri- buted according to a combination of volume and value. When it proved impossible to reach an agreement about this with the partnership, we cannot sign a unitization agreement", said Karl Johnny Hersvik in February.
Prior to submission of the PDO, Det norske held a 20 per cent interest in licence 265 and a 22.22 per cent interest in licence 502. Upon submission of the PDO, Statoil recommended that Det norske's interest in the field be 11.8933 per cent.
The field is planned developed in several phases. Approximately 80 per cent of the total reserves in the field can be produced with the facilities installed in the first phase. The production capacity in the first phase will be between 315 000 and 380 000 barrels of oil equivalent per day. In the first years, before start-up of any substantial water production, the expected effective capacity is 380 000 barrels per day. The capital expenditures for development of the first phase are estimated at NOK 117 billion. This includes the field centre (with processing platform, drilling platform, riser platform and living quarters), wells, three subsea water injection templates, export of oil and gas and power supply. This estimate includes provisions for unforeseen changes and for any increase in prices in the market.
The oil and gas is planned to be exported to shore through dedicated pipelines. The oil will be transported to the Mongstad terminal in the county of Hordaland. The gas will be transported through Statpipe to Kårstø in the county of Rogaland for processing and onward
transportation. Johan Sverdrup Phase 1 will be supplied
with power from shore.
Future phases
Future development phases shall ensure good utilization of the areas that combined constitute the Johan Sverdrup field. The plan for development of future phases is expected to be submitted to the authorities for approval in autumn 2017 at the latest, and production is planned to commence no later than 2022. The development of future phases will also include supply of power from shore to the neighbouring fields Ivar Aasen, Edvard Grieg and Gina Krog. There are uncertainties related to the future developments as no concept selection or investment decisions have as of yet been made.
Johan Sverdrup is of great importance and value to Det norske. The field spans an area of more than 200 square kilometres and extends into three licences. The first discovery of the field was made in 2010 on the Avaldsnes prospect in licence 501. In August 2011, a considerable oil discovery was announced, in exploration well 16/2-8 in the neighbouring licence 265, where Det norske holds ownership interests. The discovery was made in the Aldous Major South prospect in a 62-metre oil column with very good properties. It was ascertained that the two discoveries are in communication and constitute one giant oil field. Overall, 32 wells have been drilled to appraise the size and extraordinary quality of the field.
The Johan Sverdrup field spans an area of more than 200 square kilometres.
Here, the map of the field has been placed over Oslo.
STATOIL (operator) 40 % PETORO 30 % DET NORSKE OLJESELSKAP 20 % LUNDIN PETROLEUM 10 %
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This increase means that Det norske is now one of the biggest independent listed oil companies in Europe, measured by production.
The core of the company's production is from the Alvheim area in the northern part of the North Sea. The Alvheim Asset consists of the producing fields Alvheim, Volund and Vilje. On 19 January 2015, production started from the Bøyla field. These four fields have been developed as subsea fields tied back to the Alvheim FPSO.
At the turn of the year, the Alvheim Asset consisted of seven separate clusters of wells connected to the FPSO by pipelines. The area then had a total of 23 production wells and two water injection wells and two produced water disposal wells. The oil from Alvheim is transported from the field to market by shuttle tanker, and gas is exported through the pipeline system Scottish Area Gas Evacuation (SAGE) to St Fergus in Scotland.
Production on the Alvheim field started in June 2008, from the Kneler and Boa structures. In July the same year, production started from the Vilje field, and in September 2009 from the Volund field. The Alvheim FPSO operates with world-class regularity, and debottlenecking has increased the production vessel's production capacity from the original 120 000 barrels of oil per day to more than 150 000 barrels per day. At the end of 2014, 280 million gross barrels of oil (309 million gross barrels of oil equivalent) had been produced over the Alvheim facilities. In 2014, Alvheim contributed to 97 per cent of the company's production.
As operator for the Alvheim, Bøyla, Volund and Vilje fields, Det norske has become a major producer of oil and gas. The Alvheim FPSO (floating production, storage and offloading unit) is a flagship, both for the company and for the area. From 1.63 million barrels of oil equivalent produced in 2013, Det norske's production had an enormous increase to 24.3 million barrels of oil equivalent in 2014.
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In February 2015, Det norske was awarded the "Field Operator of the Year" award for the work done to operate and develop the Greater Alvheim Area. The award, Gullkronen 2015, organized by Rystad Energy, is an acknowledgement by the jury that "Det norske has delivered on many levels simultaneously, such as reserve replacement, regularity, HSE and the establishment of a new hub in the area". to start in spring 2016, and production start-up is provisionally forecast to 4Q 2016. Currently Det norske is executing a programme of Alvheim infill wells that will add three new producers during the course of 2015 and early 2016. Production from several fields
At the end of 2014, Det norske and its partners sanctioned the development of the Viper and Kobra structures, which are located within the Alvheim licence. The two separate discoveries are geographically located close to Volund. They are both part of licence 203. Combined, the two reservoirs contain recoverable reserves of approximately 9 million barrels of oil equivalent. Viper and Kobra will be developed with subsea facilities tied back to the existing Volund subsea facilities, and with processing on the Alvheim FPSO. Drilling is scheduled production in 2013. In all, the company had ownership interests in seven producing fields at the turn of the year. The company is operator for Alvheim (65 per cent interest), Vilje (46.9 per cent), Volund (65 per cent) and Jette (70 per cent). The company is a partner in Atla (10 per cent), Jotun (7 per cent) and Varg (5 per cent).
Det norske is also operator for the Jette field. This is the company's first operated development project. It started
ALVHEIM BOA KNELER B KNELER A EAST KAMELEON VOLUND ALVHEIM FPSO
The Alvheim field consists of five discoveries, three of which have started production: Kneler, Boa and Kameleon. It has been decided to develop the remaining Viper and Kobra discoveries, and production is expected to start in 2016. In all, the expected recoverable reserves from the field (net for Det norske) are approx. 90 million barrels of oil equivalent.
The Alvheim field has been developed in several phases. In the first phase, the field was developed with ten production wells and two water injection wells. Today, the Alvheim field consists of 16 production wells and two water injection wells.
Licences: 088 BS, 203 and 036 C
Year of discovery: 1997 (Kobra), 1998 (Kameleon), 2003 (Boa and Kneler), 2009 (Viper) Start of production: 2008
Bøyla is the fourth field in the Alvheim area and is developed with two production wells and one water injection well. It is connected to existing infrastructure on the Alvheim FPSO via a 26-kilomtere-long pipeline. Recoverable reserves totalling 23 million barrels of oil equivalent have been proven, of which 15 million barrels of oil equivalent net for Det norske.
Licence: 340 Year of discovery: 2009 Start of production: 2015
Volund is located roughly 10 kilometres south of Alvheim. The field has been developed with four production wells and one water injection well. Volund is tied back to the Alvheim FPSO via an eight-kilometre-long pipeline. The expected reserves are approx. 12 million barrels of oil equivalent net for Det norske.
Year of discovery: 1994 Start of production: 2009
The Vilje field is located 20 kilometres east of Alvheim. The field produces from three subsea wells that are connected to the Alvheim FPSO. Vilje is estimated to contain recoverable reserves of around 11 million barrels of oil equivalent net for Det norske.
Licence: 036 C
Year of discovery: 2003 (Vilje), 2013 (Vilje South) Start of production: 2008
Alvheim is the name of Det norske's core area of production, and the name of the production vessel. The Alvheim area consists of the producing fields Alvheim, Bøyla, Volund and Vilje.
| DET NORSKE OLJESELSKAP ASA | 65 % (OPERATOR) |
|---|---|
| CONOCOPHILLIPS AS | 20 % |
| LUNDIN NORWAY AS | 15 % |
DET NORSKE OLJESELSKAP ASA 65 % (OPERATOR) CORE ENERGY AS 20 % LUNDIN NORWAY AS 15 %
DET NORSKE OLJESELSKAP ASA 65 % (OPERATOR) LUNDIN NORWAY AS 35 %
DET NORSKE OLJESELSKAP ASA 49.904 % (OPERATOR) STATOIL PETROLEUM AS 28.853 % PGNIG UPSTREAM INTERNATIONAL AS 24.243 %
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ANNUAL REPORT 2014
The acquisition of Marathon Oil Norge AS was financed through a combination of debt and equity. A new seven-year USD 3 billion reserve-based lending (RBL) facility was put in place in June and subsequently entered into with a consortium of 17 banks, replacing the company's previous bank debt. The RBL facility was secured by a package consisting of a pledge over the company's interests in development and production licences in Norway. The loan carries an interest of LIBOR plus a margin of 2.75 per cent per annum, plus an utilization fee of 0.25 or 0.50 per cent, depending on the amount drawn under the facility.
The available amount under the USD 3 billion RBL facility will be determined twice a year from the value of the company's borrowing base assets based on certain assumptions. At year-end 2014 the borrowing base was 2.7 USD billion. Subject to certain conditions, the RBL facility may be expanded to USD 4 billion. Financial covenants under the RBL facility include inter alia a leverage ratio covenant and an interest cover ratio as well as short-term and long-term liquidity tests.
In addition to the RBL, the company had a NOK 1.9 billion bond outstanding at year-end 2014. The bond matures in 2020 and carries a coupon of 3 months NIBOR + 5.00 per cent, payable in quarterly instalments. Financial covenants for the bond include, inter alia, an adjusted equity ratio of minimum 25 per cent and a minimum cash position of NOK 250 million.
During July, the company strengthened its equity base by issuing NOK 3 billion in new equity through a rights issue of 61.9 million shares at NOK 48.50 per share. Existing shareholders were granted transferable subscription rights that could either be sold in the market or used to subscribe in the offering. The rights issue was oversubscribed by about 43 per cent.
Both these financing initiatives, along with increased cash flows, significantly strengthened the company's financial robustness after the acquisition of Marathon Oil Norge AS.
Det norske is listed on Oslo Børs under ticker code DETNOR. The share price for Det norske ended in 2014 at NOK 39.87 per share, corresponding to a market value of NOK 8.1 billion. That was lower than the market value at the beginning of the year, following weak share price development in the second half of the year.
The share is part of the OBX Index, making it one of the most liquid shares on Oslo Børs. At year-end 2014, shares in Det norske were divided between 7 693 accounts. Ownership is nonetheless fairly concentrated, as the top 20 accounts own approximately 72 per cent of the share
Efforts to strengthen Det norske's financial robustness have been important in 2014. The acquisition of Marathon Oil Norge AS secured access to production and cash flow, reducing the company's funding need ahead of the Ivar Aasen and Johan Sverdrup development projects.
capital. Det norske has a strong industrial owner, Aker Capital AS, which holds 49.99 per cent of the shares in the company. The geographical composition of the company's shareholder base has been relatively stable throughout the year. Norwegian citizens and companies registered in Norway controlled 88.6 per cent of the shares outstanding at year-end 2014.
Det norske aims to ensure that the share is attractive and easily negotiable. Each share carries one vote at the general meeting and equal rights to dividends. The company is currently not in a position to pay dividends.
Det norske wishes to promote transparency in society. Nominee accounts conceal who the real owners of the shares are, and the company believes that to be unfortunate. As of 31 December 2014, approximately 9 per cent of the share capital was registered to nominee accounts.
Following the acquisition of Marathon Oil Norge AS, Det norske changed its functional currency to U.S. Dollar (USD). The change in functional currency from Norwegian Kroner (NOK) had effect from 15 October 2014, which was the closing date for the acquisition of Marathon Oil Norge AS. The balance sheet was converted to USD at a rate of 6.6161 per 15 October 2014.
| No. of shares Percentage | ||
|---|---|---|
| Aker Capital AS | 101 289 038 | 49.99 |
| Folketrygdefondet | 11 221 352 | 5.54 |
| Odin Norge | 3 848 325 | 1.90 |
| Verdipapirfondet DNB Norge (IV) | 2 828 328 | 1.40 |
| VPF Nodrea Norge Verdi | 2 706 932 | 1.34 |
| KLP Aksje Norge VPF | 2 484 537 | 1.23 |
| The Northern Trust Co. | 2 448 577 | 1.21 |
| Verdipapirfondet DNB Norge Selekti | 2 422 966 | 1.20 |
| Fondsfinans Spar | 2 200 000 | 1.09 |
| VPF Nordea Kapital | 2 151 115 | 1.06 |
| JP Morgan Chase Bank, NA | 1 784 114 | 0.88 |
| Tvenge | 1 600 000 | 0.79 |
| Danske Invest Norske Instit. II. | 1 589 736 | 0.78 |
| Kommunal Landspensjonskasse | 1 573 682 | 0.78 |
| Statoil Pensjon | 1 264 905 | 0.62 |
| Morgan Stanley & Co. LLC | 1 188 849 | 0.59 |
| Danske Bank | 1 024 893 | 0.51 |
| Credit Suisse Securities | 981 828 | 0.48 |
| KLP Aksje Norge Indeks VPF | 926 955 | 0.46 |
| SEB Private Bank S.A. (Extended) | 889 025 | 0.44 |
ANNUAL REPORT 2014
Cooperation with the Norwegian authorities and audits by supervisory bodies are important if the company is to live up to this standard. Hence, Det norske's HSE&Q programme reflects the main priorities of the Petroleum Safety Authority Norway (PSA) - barriers, management and major accident risk, the far North and groups at particular risk.
Det norske must also ensure that all its suppliers undertake to comply with, and actually comply with, the company's requirements and standards. We do this through maintaining good contact and participating in collaborative forums with suppliers, including contract follow-up, a cultural programme to promote HSE and annual HSE conferences.
Det norske did not receive any mandatory orders or notifications from the PSA in 2014. The PSA carried out nine audits of the company's operations / activities in
Det norske did not have any incidents with severe consequences in its operations in 2014.
The company's emergency response organization consists of a continuously operational standby system that covers all our operations in Norway and abroad. A significant number of people are on standby duty at all times in order to deal with any incidents. They are well-trained and practise how to deal with incidents through regular emergency response drills.
In connection with the integration of Marathon Oil Norge AS, the company has done a lot of work on the coordination of HSE, emergency response and control and management systems. An extensive emergency
response programme has been implemented in the new organization. Among other things, it includes weekly practices in the autumn months in order to ensure continuity, role understanding and operational know-how about the company's new, expanded activities. must undertake to comply with. HSE is a natural topic at all meetings, and a forum has also been established, HSE SUMMIT, at which all managers from the contract partners and personnel from Det norske meet to discuss and agree on important matters.
gas turbines to supply power, and the platform is prepared for connection to a possible future power plant that will supply the fields on the Utsira High with electricity from shore. The project has established a set of cardinal HSE rules that all contractors and project participants
Det norske is a member of the Norwegian Operators' Association for Emergency Preparedness (OFFB). OFFB has played an important role in Det norske's emergency response organization by taking part in the planning and implementation of drills. Ivar Aasen Det norske is developing the Ivar Aasen platform without Four incidents were registered in 2014, three instances of dropped objects and one incident involving unsecured work at heights. They have been investigated and changes have been implemented. Three minor injuries that led to sickness absence have also been registered. With more than 4.6 million hours worked, this means a Serious Incident Frequency of 0.9, which we regard as a good result.
As operator for Alvheim, Det norske has experienced a change in its environmental impact. The field has been
As an employer and partner, Det norske will ensure that all activities are carried out in accordance with the highest health, safety and environment (HSE) standards in the oil industry. We aim to be a driving force for healthy attitudes and a culture that promotes HSE as the most important priority. Our philosophy is that all undesirable incidents are avoidable.
developed using technical solutions that minimize emissions and its potential environmental impact. An enclosed flaring system, turbines with low NOx technology, waste heat recovery and a design for the reinjection of produced water are all examples of the technology that has been introduced.
Det norske works systematically to prevent major accidents in connection with the company's operations.
In connection with the operation of Alvheim and the development of Ivar Aasen, the company is working systematically on risk reduction measures. Barrier management has a central place in the prevention of major accidents on both Alvheim and Ivar Aasen. Good management of technical, operational and organizational barriers, and ensuring that the importance of this is understood at all management levels, is a crucial part of this work.
Det norske has sound oil-spill response expertise and it plays an active role in NOFO (the Norwegian Clean Seas Association for Operating Companies). NOFO is specially trained in the handling of oil-spill response
situations. Det norske has been a member of NOFO since it was established and duty personnel from the company are part of NOFO's resource pool.
Emissions to the natural environment and the consumption of chemicals in drilling operations are reported annually to the Norwegian Environment Agency. Det norske endeavours to reduce the amount of chemicals used and to replace potentially environmentally harmful chemicals. Det norske also tries to reduce the amount of waste it produces.
Planned emissions in 2014 were within the limits in the permits granted. Acute discharges for the company were approximately 15 m3 of firewater foam and 900 litres of hydraulic oil from the Alvheim FPSO, in addition to 2 m3 oil-based mud during drilling operations on the Kvithola well.
Det norske is a member of the business sector's NOx fund. Through its contribution to the NOx fund, the company also helps to make funds available for measures aimed at reducing emissions in other industries, and in shipping and fisheries.
Det norske's business shall be conducted in a manner that ensures that we:
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Det norske complies with the guidelines in the Norwegian Code of Practice for Corporate Governance. In line with the Code of Practice, ethical guidelines have been adopted for the company, its officers and employees. Det norske places great emphasis on complying with laws and ethical guidelines. We demonstrate corporate social responsibility in the way we behave, the quality of our work, our products and in all our activities. The company's ethics go further than mere compliance, however.
Det norske does not tolerate any form for corruption. The company's ethical guidelines are updated annually. Procurements made by Det norske are based on competitive tendering and the principle of non-discrimination, equal treatment and transparent tender processes. The company is committed to using suppliers that consistently operate in accordance with Det norske's values and applicable Norwegian laws. Suppliers also have to meet all Det norske's requirements concerning health, safety and the environment, corporate social responsibility, ethics, anti-corruption, a quality assurance system, human rights and labour standards.
In 2014, Det norske placed emphasis on ethics and anti-corruption by carrying out risk assessments and introducing an anti-corruption programme for employees. Det norske also assessed how the principles of the UN Global Compact are relevant to the company's activities. This work will continue in 2015, in collaboration with Aker.
Research aimed at improving technology and developing new work methods is crucial to the development of both Det norske and the industry. Det norske wishes
to raise the level of expertise in the industry, and the company is particularly concerned with geological interpretation and with improving tools for the analysis of geophysical data.
In 2014, the company supported research and development projects in the amount of NOK 65 million. Of a total of 69 projects, 33 concerned issues relating to the subsurface, while 15 were related to development. Fourteen projects concerned operations, drilling and well operations, while seven were related to HSE and R&D administration. Around 80 per cent of the R&D funds went to external suppliers and research institutes, most of them Norwegian.
Det norske is involved in several research projects that are looking at how the company can develop the expertise that is required for oil recovery in the High North. The company has been working for five years to qualify the oil service industry in Northern Norway. Four new companies were ISO-certified by DNV GL in 2014, all for ISO 9001, an ISO standard for quality management and a particularly good tool for quality assurance of production and errors.
Det norske also wishes to play a major role in the local community. The company sponsors culture, sport and socially beneficial initiatives and it prioritizes initiatives that can also benefit our employees. In 2014, the company cooperated with the theatre Det Norske Teatret in Oslo, the Norwegian Petroleum Museum in Stavanger, Trøndersk matfestival, Nidaros Cathedral's boys' choir and Trondheim Jazz Festival. As part of the company's acquisition of Marathon Oil Norge AS, Det norske also entered into a collaboration with the ice hockey team Stavanger Oilers.
Building schools in Rwanda was another important collaborative project in 2014. Through its partnership with UNICEF, Det norske sponsors the Schools for Africa project and, since it started up, it has contributed to building more than ten schools in the Kamonyi district in Rwanda. As a result of this project, more than 10 000 pupils now have better schools, a better learning environment and teachers who have taken further education.
The company also sponsors local amateur sporting activities, and cultural and community projects initiated by employees. In 2014, the company sponsored more than 60 such projects, mostly related to sport and culture for children and young people throughout Norway.
More detailed comments on corporate governance can be found in the Board of Directors' Report and in the annual accounts.
Ethical guidelines, corporate social responsibility – and our commitment – constitute an important part of the foundation Det norske is built on. As a company, we are conscious of how we impact society.
Det norske has since 2008 sponsored UNICEF's Schools for Africa project in Rwanda. Photo: Det norske
Photo: Thor Nielsen
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42
High costs have long been a challenge to the profitability of the oil industry, and this was further reinforced by the dramatic fall in the oil price. There was therefore extensive restructuring and cost-cutting in the industry in 2014 – restructuring that is absolutely necessary, according to the Norwegian Petroleum Directorate. Even though the cuts can lead to a lower activity level in the short term, the Directorate believes that the process the industry is now undergoing can lay the foundations for a more robust and profitable industry in the long run.
Activity was nonetheless high on the Norwegian Continental Shelf in 2014. A total of 56 exploration wells were started, and 22 new discoveries were made – two more than in 2013. Eight of the discoveries were made in the North Sea, five in the Norwegian Sea and nine in the Barents Sea. The resources in the new discoveries amount to 251-692 million barrels of oil/condensate and 157-472 million barrels o.e. of recoverable gas.
The total production of oil and gas reached 1363.7 million barrels of oil equivalent (o.e.) That is 298.3 million fewer than in the record year 2004, and 1.4 per cent more than in 2013. In 2014, oil production increased for the first time since the turn of the millennium. It reached 552.52 million barrels, which is 3 per cent higher than the year before. There are currently 79 fields in operation on the Norwegian Continental Shelf. Production started up on four new fields.
Eleven fields were being developed at the turn of the year, nine in the North Sea, one in the Norwegian Sea and one in the Barents Sea. According to provisional figures from the Norwegian Petroleum Directorate, NOK 172 billion was invested in the petroleum activities on the Norwegian Continental Shelf in 2014. The investments are estimated to fall by around 15 per cent from 2014 to 2015, and by a further 8 per cent by 2017, before levelling out and moderately increasing from 2018.
Production wells Existing facilities New fixed and floating facilities New subsea facilities Pipelines and terminals
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Karl Johnny Hersvik took over as the new chief executive officer on 1 May 2014. A couple of months later, he presented the new executive management team, who took up their positions on 15 October 2014. The new executive management team consists primarily of executives with experience from Det norske and from the former Marathon Oil Norge AS. The changes to the executive management team marked the beginning of a large-scale reorganization of the company, with the aim of achieving a more seamless, efficient and flexible organization.
The organizational changes have been noticeable in many areas. Now, Det norske's second largest office is located in Stavanger, and the company also has its own offshore organization. With regard to the number of employees, the staff almost doubled, from 279 to 507. In addition, the reorganization has resulted in new unit business units and restructuring of departments.
The company has cooperated well with the employee representatives in the integration process to reduce
uncertainty and work-related stress. Several measures have been implemented to ensure continuous information and transparency in the processes. The integration work is still ongoing, and follow-up will continue well into 2015.
Other initiatives include two gatherings in late autumn, where Det norske invited all employees to get to know the company, the new organization and each other better. The departments have also organized their own gatherings, giving attention to topics such as building of company culture and development of the company.
Det norske carries out a working environment survey every other year, the last one in March 2014. The psychosocial and physical working environment is perceived as good, and the employees are motivated and thriving at work. The improvement areas that were identified by the survey were followed up in 2014. A new working environment and organization survey is planned conducted in the fall of 2015. The company endeavours to achieve a balanced working environment in which everyone has equal opportunities based on qualifications and irrespective of gender, ethnicity, sexual orientation or disability. In December 2014, the proportion of female employees was 25 per cent. The proportion of women on the board of directors is 40 per cent.
| Det norske continues to have a record low sickness absence rate, confirming that people like working for Det norske and enjoy each other's company. The total sickness absence was 1.6 per cent in 2014, down from 1.8 per cent in 2013, and 2.4 per cent in 2012. |
|---|
| The employees of Det norske are organized in the trade unions Tekna, Industri Energi and Lederne. |
| Not including the acquisition of Marathon Oil Norge AS, Det norske recruited 59 new employees in 2014. Three employees resigned. |
A new executive management team, a doubling of the number of employees, a new office in Stavanger, its own offshore organization, reorganization and structural changes. For Det norske, 2014 has been a year characterized by large-scale organizational changes.
Photo: Kilian Munch
Det norske focuses on developing employee competency and encourages all employees to update their competence regularly through courses, seminars and the possibilities offered internally through a rotation system. The development of the Det norske school will continue in 2015. The company has a mandatory introductory course for new employees. This initiative reflects the company's focus on creating a common understanding, culture and identity.
Det norske has an active company sports team with local clubs in all office locations. The company supports a wide range of activities and encourages employees to be physically active. In 2014, there were more than 30 active groups in the company's office locations in Norway and abroad.
Chief Executive Officer
Karl Johnny Hersvik (born 1972) has been CEO of Det norske since May 2014. Prior to joining Det norske, he served as head of research for Statoil. Mr Hersvik has held a number of specialist and executive positions with Norsk Hydro and StatoilHydro. He holds a number of directorships, including chair of the board of directors of OG21, and is a member of several boards whose objective is to promote cooperation between industry and academia. Mr Hersvik holds a Cand. Scient. (second cycle) degree in Industrial Mathematics from the University of Bergen.
Øyvind Bratsberg (born 1959) joined Det norske in 2008 as Chief Operating Officer. He has 25 years' experience from several companies in the areas of marketing, business development and operations. Before taking up his position with Det norske, he was responsible for early-phase field development on the Norwegian Continental Shelf for StatoilHydro. Mr Bratsberg holds an MSc degree in Mechanical Engineering from NTH, now the Norwegian University of Science and Technology, NTNU.
SVP Company Development Elke Njaa (born 1954) comes from the position of Commercial Manager with Marathon Oil Norge AS. She has previously held various management positions with Statoil and has worked as a geologist for the Norwegian Petroleum Directorate. Ms Njaa holds a master's degree in Geology, specializing in biostratigraphy, from the University of Tübingen in Germany. She also holds an MBA degree in Strategy and Management from the Norwegian School of Management (BI) in Oslo. In addition, Ms Njaa served as the company's SVP Special Projects from 15 October 2014 to 4 February 2015, when this business unit was phased out.
Kjetil Kristiansen (4) SVP Human Resources
Prior to joining Det norske, Kjetil Kristiansen (born 1969) served as head of Human Resources with Aker ASA, where he was involved in developing boards of directors and management teams in the various Aker companies. Since 1998, he has held several HR positions with Aker Solutions, including four years as head of HR for the Subsea Business Area. Mr Kristiansen holds a degree in Clinical Psychology from the University of Oslo, in addition to a BSc degree in philosophy and
intellectual history.
SVP Communication
Rolf Jarle Brøske (born 1980) comes from the position of Industrial Policy Director with Det norske. Previous professional experience includes a management position with Fokus Bank, and he has inter alia served as adviser to the former Minister of Industry, Børge Brende, and the Mayor of Trondheim. Mr Brøske has studied Political Science and History at Molde University College and at NTNU.
Alexander Krane (born 1976) took up the position of CFO with Det norske in 2012. Prior to joining Det norske, he held the position of Corporate Controller with Aker ASA. He has also worked as a public accountant with KPMG, both in Norway and in the US. Mr Krane holds a Bachelor of Commerce degree ("siviløkonom") from Bodø Graduate School of Business and an MBA degree from the Norwegian School of Economics in Bergen. He is also a state-authorized public accountant in Norway.
SVP Exploration
Gro Gunleiksrud Haatvedt (born 1957) joined Det norske in 2014. She came from the position of exploration manager for the Norwegian Continental Shelf with Statoil ASA, where she also served as country manager in Libya. She has held several positions with Norsk Hydro (head of geology, technology and competence). She has been responsible for business development in Iran, head of Oseberg, and Exploration Manager NCS. Ms Haatvedt holds a master's degree in Applied Geophysics from the University of Oslo.
In 2014, the corporate assembly of Det norske consisted of the following members: Øyvind Eriksen (chair), Anne Grete Eidsvig, Odd Reitan, Finn Berg Jacobsen, Leif O. Høegh, Olav Revhaug, Jens Johan Hjort, Nils Bastiansen, Hugo Breivik, Hanne Gilje, Ifor Roberts and Kjell Martin Edin.
Geir Solli (born 1960) comes from the position of deputy CEO with Marathon Oil Norge AS. He has previously served as Operations Manager for the Alvheim area, and Asset Manager for the Gulf of Mexico in the same company. Mr Solli has also worked as project manager and offshore installation manager for BP. He holds an MSc degree in Electrical Engineering from NTH, now the Norwegian University of Science and Technology, NTNU.
SVP Drilling and Well
Kjetil Ween (born 1976) comes from the position of Drilling Manager Norway with Marathon Oil Norge AS. He has experience as a drilling engineer on the Alvheim and the Gulf of Mexico assets, and as drilling manager in Equatorial Guinea and Norway. He has also worked as drilling engineer for Schlumberger. Mr Ween holds an MBA degree and a BSc degree in International Finance from Griffith University in Australia. In addition, he holds a BSc degree in Petroleum Technology from Stavanger University College.
SVP HSEQ
Leif Gunnar Hestholm (born 1968) comes from the position of HSE and Quality Manager with Marathon Oil Norge AS. He has experience from Kværner Engineering, Safetec (risk analyses and risk management), IRIS (management systems and quality assurance) and BP. Mr Hestholm holds an MSc degree in Industrial Mathematics from NTH, now the Norwegian University of Science and Technology, NTNU.
Kjell Inge Røkke (born 1958) is an entrepreneur and industrialist, and has been a driving force in the development of Aker since the 1990s. Mr Røkke owns 67.8 percent of Aker ASA through The Resource Group TRG AS and subsidiaries, which he co-owns with his wife. He is Chairman of Aker ASA and a member on the boards of Aker Solutions ASA, Kværner ASA, Akastor ASA, Det norske oljeselskap ASA and Ocean Yield ASA. He holds no shares in Det norske oljeselskap ASA, and has no stock options. Mr Røkke is a Norwegian citizen.
Sverre Skogen (born 1956) holds an MSc and an MBA from the University of Colorado. Mr Skogen has previously held several executive positions in the oil and gas industry, including as CEO of Aker Maritime ASA (1997-2001), of the amalgamated Aker Kværner O&G (2001-2002), of PGS Production (2003-2005), and of AGR ASA (2005-2013). He has served on several boards in non-executive positions, including Chair of the Board of Intsok (1999 -2001) and of Rosenberg Verft (2003-2005). Mr Skogen is a Norwegian citizen.
Deputy Chair
Anne Marie Cannon (born 1957) has over 30 years' experience in the oil and gas sector across industry and investment banking. From 2000 to 2014, she was a Senior Advisor to the Natural Resources Group with Morgan Stanley, focusing on upstream M&A. Ms Cannon has previously held financial and commercial positions with J Henry Schroder Wagg, Shell UK Exploration and Production and with Thomson North Sea. She was an executive director on the boards of Hardy Oil and Gas and British Borneo. She served on the Board of Directors of Aker ASA from 2011 to 2013. She is a non-executive director of Premier Oil and of STV Group plc. She holds a BSc Honours Degree from Glasgow University. Ms Cannon is a British citizen.
Kitty Hall (born 1956) has headed various technology companies within the geophysics sector for 25 years. She serves on the board of Seabird Exploration and is Vice Chairman of the Petroleum Group of the Geological Society. Previous directorships include ARKeX Ltd., Polarcus, Sevan Drilling, Petroleum Exploration Society of Great Britain, Eastern Echo, ARK Geophysics Ltd. and The International Association of Geophysical Contractors. Ms Hall holds a bachelor's degree in geology from the University of Leeds and an MSc in stratigraphy from Birkbeck College, University of London. She is a British citizen.
Jørgen C. Arentz Rostrup (born 1966) is Managing Director of Yara Ghana Ltd. at Yara International. He held management positions with Hydro for more than 20 years, where he inter alia headed the energy business area and the Norwegian production and sale of oil, gas and power. He held the position of CFO and served as member of the corporate management with Hydro from 2009 until March 2013. He played a key role in the merger between Saga Petroleum and Hydro. He has also held a number of management positions in Norway, Singapore and New York. Mr Rostrup is a Norwegian citizen.
Tom Røtjer (born 1953) is Senior Vice President Projects with Norsk Hydro. Mr Røtjer has held a variety of management positions with Hydro since 1980 and has been responsible for several large development projects. From 2007 to 2012, he was Executive Vice President Projects and member of the corporate management board in Hydro. In 2004, Mr Røtjer was appointed Project Director for the Ormen Lange and Langeled gas development projects in the Norwegian Sea. He holds a master's degree in Mechanical Engineering from NTNU (1977). Mr Røtjer is a Norwegian citizen.
Board member
Inge Sundet (born 1963) is Senior Manager D&W Ivar Aasen with Det norske. He has been with Det norske since 2008 and has held several positions in the drilling department. Mr Sundet holds an MSc in Mechanical Engineering from NTNU (1988). He was with Statoil from 2001 to 2008, primarily working with well completions (Heidrun and Kristin). He has also worked offshore as a drilling supervisor. From 1989 to 2001, he was employed with SINTEF as Senior Researcher within Safety and Reliability. Mr Sundet is a Norwegian citizen.
Gudmund Evju (born 1972) is Senior Manager Concept Development with Det norske. He has been with Det norske since 2004, and has held several positions in the department. From 2011 to 2013, he was Project Manager for the Jette development. Evju holds an MSc in Mechanical Engineering from NTNU (1996). Before he joined Det norske, he worked for PGS Production (1998-2004), where he primarily followed up the process plant on the FPSO Petrojarl Varg. In the period from 1996 to 1998, he was employed with NTNU and worked on different projects for SINTEF. Mr Evju is a Norwegian citizen.
Kristin Gjertsen (born 1969) is Manager Non-operated Assets with Det norske. She has been with the company since 2010. Ms Gjertsen has more than 15 years' experience from various management positions in the oil and gas industry. She has held various positions with StatoilHydro ASA (including Hydro ASA and Saga Petroleum ASA) from 1998 to 2008. From 2008 to 2010, she held the position of Director Business Development & Online Business Group with Microsoft Norge. Ms Gjertsen holds an MSc from NTNU (1992) and an MBA from NHH (2004). She is also a member on the board of Western Bulk ASA. Ms Gjertsen is a Norwegian citizen.
Board member Gro Kielland (born 1959) holds an MSc in Mechanical Engineering from the Norwegian University of Science and Technology (NTNU). Ms Kielland has held a number of leadership positions in the oil and gas industry both in Norway and abroad, among others as CEO of BP Norway. Her professional experience includes work related to both operations and development of fields, as well as responsibility for the HSE discipline for operators. Ms Kielland currently serves as an Operational Partner with HitecVision. In addition to her duties and responsibilities at the non-executive level for HitecVision, she also serves as a non-executive Chairman and Director for several other companies. Ms Kielland is a Norwegian citizen.
Det norske's nomination committee in 2014 consisted of Kjetil Kristiansen (chair), Finn Haugan and Hilde Myrberg.
Appraisal well – An exploration well drilled to determine the extent and size of a petroleum deposit that has already been discovered by a wildcat well.
Awards – Companies that are approved as operators or licensees on the Norwegian shelf may apply to be awarded production licences. The awards take place through licensing rounds and annual allocations in predefined areas. The authorities decide which areas of the Norwegian shelf are to be opened for petroleum activity and which companies are to be awarded production licences after having submitted applications.
Awards in Pre-defined Areas (APA) – These licensing rounds comprise new calls for applications in mature areas of the Norwegian shelf. The APA rounds are usually conducted on an annual basis.
Barrel of oil – This is an American volumetric measurement. One barrel of oil equals 159 litres.
Barriers – Technical, operational and organizational elements which are intended individually or collectively to reduce possibility/ for a specific error, hazard or accident to occur, or which limit its harm/disadvantages.
Barrier management – Coordinated activities to establish and maintain barriers so that they maintain their function at all times.
Block – A geographical unit of division used in the petroleum activities on the continental shelf. The maritime areas within the outermost limit of the continental shelf are divided into blocks measuring 15 minutes of latitude and 20 minutes of longitude, unless adjacent areas of land, borders with the continental shelves of other nations, or other factors decree otherwise.
Bond issue – When you buy a bond, you lend money to the organisation that issues it. The company, in return, promises to pay payments to you for the length of the loan. Bonds are usually long-term, and investing in bonds usually entails less risk than investing in shares.
Contingent resources – Recoverable petroleum volumes that have been discovered, but for which no decision has been taken, or permission given, to recover.
Corporate governance – The system by which corporations are directed and controlled. The governance structure specifies the distribution of rights and responsibilities among different participants in the corporation (such as the board of directors, managers, shareholders, creditors, auditors, regulators, and other stakeholders) and specifies the rules and procedures for making decisions in corporate affairs.
Coupon / coupon rate – The interest rate stated on a bond when it is issued, expressed as a percentage of the principal (face value).
Cretaceous period – A geological period from about 146 to 66 million years ago. The name Cretaceous was derived from creta, meaning chalk. Due to the high sea level and overall warm climate, marine limestone is the dominating rock type of this period in the North Sea area.
Discovery – A petroleum deposit, or several petroleum deposits combined, which testing, sampling or logging have shown probably contain mobile petroleum. The definition covers both commercial and technical discoveries. The discovery receives the status of a field, or becomes part of an existing field when a plan for development and operation (PDO) is approved by the authorities.
Drilling programme – This is a description that contains specific information concerning wells and well paths relating to planned drilling and well activities.
Environmental impact assessment (EIA) – The formal process used to predict the environmental consequences (positive or negative) of a plan, policy, program, or project prior to the decision to move forward with the proposed action.
Exploration facility – A loan facility that a company has with a group of banks that can be used to fund the company's exploration activities. The facility has security in the tax refund for exploration costs and in exploration licences.
Exploration well – A well drilled in order to establish the existence of a possible petroleum deposit or to acquire information in order to delimit an established deposit. Exploration well is a generic term for wildcat and appraisal wells.
Fault – A fracture separating two rock bodies that have been displaced relative to each other.
Field – One discovery, or a number of concentrated discoveries, which the licensees have decided to develop and for which the authorities have approved, or granted exemption for, a plan for development and operation (PDO).
floading) – An FPSO unit is a floating vessel used by the offshore oil and gas industry for the production and processing of hydrocarbons, and for the storage of oil. An FPSO can be a conversion of an oil tanker or can be a vessel built specially for the application.
Geologic model – In the oil and gas industry, geologic models are used to identify which recovery options offer the safest and most economic, efficient, and effective development plan for a particular reservoir.
High North – This concept encompasses an area consisting of the entire circumpolar Arctic region, including the Barents region and the Barents Sea area.
Hydrocarbons – Organic compounds based on molecular chains of carbon and hydrogen atoms. Oil and gas consist mainly of hydrocarbons.
Immature areas – The immature areas on the Norwegian shelf are characterized by unfamiliar geology, lack of infrastructure and often new technological challenges. The uncertainty pertaining to the resource base is larger than in mature areas. However, it is still possible to make large discoveries in immature areas. ISO certification – ISO standards are published by the International Organization for Standardization. The standards have been developed to provide guidance to enterprises within quality management. ISO certificates are issued by approved certification bodies such as e.g. TI, Dovre, Nemko or DNV.
Jack-up rig – A self-elevating unit is a type of mobile platform that consists of a buoyant hull fitted with a number of movable legs, capable of raising its hull over the surface of the sea. The buoyant hull enables transportation of the unit and all attached machinery to a desired location. Once on location the hull is raised to the required elevation above the sea surface supported by the seabed.
Jurassic period – The Jurassic is a geological period, from about 200 to 146 million years ago. On the timescale, the period follows the Triassic period and was followed by the Cretaceous period. The Jurassic period is well known due to the fact that it was dominated by dinosaurs.
LIBOR – (London Interbank Offered Rate), the interest rate at which banks offer to lend funds (wholesale money) to one another in the international interbank market.
Licence – A production licence is the concession, or right, to explore for petroleum resources and then recover / produce petroleum deposits in a stated geographical area on the Norwegian Continental Shelf for a certain period. This concession is granted by the authorities, represented by the Ministry of Petroleum and Energy, to one or more qualified oil companies, i.e. "licensees". The cooperation between the oil companies in a licence is regulated by agreements stipulated by the authorities and signed by the parties.
Licensee – Physical person or body corporate, or several such persons or bodies corporate, holding a licence according to the Petroleum Act or previous legislation to carry out exploration, production, transportation or utilization activities. If a licence has been granted to several such persons jointly, the term licensee may comprise the licences collectively as well as the individual licensee. A licensee must have been qualified by the authorities.
Lifting gas / gas lift – Gas that is pumped into the well deep into the vertical section of the well. This gas is then produced back together with oil and water in the well. The effect of the gas lift is that it contributes to a lighter column (lower density), which facilitates and increases the production of oil.
Low NOx technology – Technology ensuring low emission of NOx. NOx is a generic term for the mono-nitrogen oxides NO and NO2 (nitric oxide and nitrogen dioxide).
Major accident – An acute incident, such as a major discharge/emission or a fire/explosion, which immediately or subsequently causes several serious injuries and/or loss of human life, serious harm to the environment and/or loss of substantial material assets.
Mature areas – Mature areas are characterized by known geology and well developed or planned infrastructure. It is likely that discoveries will be made, but less likely that these new discoveries will be large. These areas often include fields in the later stages of their lifetime, or fields that are shut down. Most new projects in mature areas are expected to be relatively small, often necessitating tie-in to existing fields to ensure profitability.
NIBOR – Norwegian Interbank Offered Rate. This is the rate that Norwegian banks indicate they are willing to lend to other banks for a specified term.
Nominee account – An account set up by a nominee (the registered owner) for administering securities or other assets held on behalf of the actual owner (the 'beneficial owner') under a custodial agreement. The use of nominee accounts complicates access to reliable information about the ownership.
Norwegian Continental Shelf – The seabed and subsoil of the marine areas extending beyond the Norwegian territorial sea, throughout the natural prolongation of the Norwegian land territory to the outer edge of the continental margin, but no less than 200 nautical miles from the base lines from which the breadth of the territorial sea is measured, however, not beyond the median line to another state.
OBX Index – The OBX Index consists of the 25 most traded securities on Oslo Børs.
Ocean Bottom Seismic (OBS) – This entails placing the acquisition system on the seafloor rather than employing conventional towed streamer techniques. Placing the system on the seafloor results in better data, but is more time and cost consuming. Ocean bottom seismic is recognized as the best technology available for mapping the seafloor geology in connection with oil and gas exploration.
Oil equivalent (o.e.) – Used when oil, gas, condensate and NGL are to be totalled. The term is either linked to the amount of energy liberated by combustion of the various types of petroleum or to the sales values, so that everything can be compared with oil.
Oil reservoir – An underground mass of porous rock, usually sandstone or limestone, which contains deposits of petroleum that can be produced.
Operator – One of the licensees in a licence who, on behalf of all the licensees, is in charge of the day-to-day management of the petroleum activity. The operator is appointed by the Ministry of Petroleum and Energy, but may change in connection with e.g. sale and purchase of ownership interests.
Palaeogene period – This is a geologic period that extends from 66 to 56 million years ago.
Permian period – Permian is a geologic period that extends from 299 to 251 million years ago. Several of the petroleum fields in the southern part of the North Sea are connected to reservoirs in Permian rocks or structures linked to these.
Petroleum – This is a collective term for hydrocarbons. The term covers all liquid and gaseous hydrocarbons found in a natural state in the substrate, and other substances recovered in connection with such hydrocarbons.
Petroleum activity – All activity linked to subsea petroleum deposits, including investigation, exploratory drilling, recovery, transport, utilization and termination, and the planning of such activities, but not the transportation of petroleum in bulk by ship.
Plan for development and operation (PDO) – If a licensee decides to develop a petroleum deposit, the licensee shall submit to the Ministry of Petroleum and Energy for approval a plan for development and operation of the petroleum deposit. The plan shall contain an account of economic aspects, resource aspects, technical, safety related, commercial and environmental aspects, as well as information as to how a facility may be decommissioned and disposed of when the petroleum activities have ceased.
Plateau production – The maximum level of production over a period of time.
Play – A geographically and stratigraphically delimited area where a specific set of geological factors is present so that petroleum should be able to be proven in producible volumes. Such geological factors are a reservoir rock, trap, mature source rock, migration routes, and that the trap was formed before the migration
of petroleum ceased. All discoveries and prospects in the same play are characterized by the play's specific set of geological factors.
Porosity – The porosity of a rock is the ratio of the volume of all the pores in a material to the volume of the whole rock.
Private placement – The sale of securities to a relatively small number of select investors as a way of raising capital.
Production rate – The quantity of oil / gas that is produced during a given period, inter alia how many barrels of oil are produced per day.
Prospect – A possible petroleum trap with an identifiable, delimited rock volume.
Recovery factor – The relationship between the volume of petroleum that can be recovered from a deposit and the volume of petroleum originally in place in the deposit.
Reserve-based lending facility (RBL facility) – A type of financing where a loan is secured by the undeveloped reserves of oil and gas of a borrower.
Reserves – Remaining, recoverable, saleable volumes of petroleum which the licensees have decided to recover and the authorities have given permission to recover.
Revolving credit facility – A loan facility that a company has with a group of banks that can be used to fund the company's development projects. The facility has security in the development licences.
Riser platform – A platform that receives the wellstreams from various production wells. The wellstream from each well is received via a manifold for further transport to shore or to other installations.
Sandstone – A common sedimentary rock consisting of grains of sand cemented together by various substances. Some sandstones are porous because they possess open spaces within their structures. These open spaces may contain water or petroleum. Sandstones are important reservoir rocks in connection with production of oil and gas.
Seismic (geophysical) investigations – Seismic profiles are acquired by transmitting sound waves from a source above or in the substratum. The sound waves travel through the rock layers which reflect them up to sensors on the sea bed or at the surface, or down in a borehole. This enables an image of formations in the substratum to be formed. The seismic mapping of the Norwegian Continental Shelf started in 1962.
Sidetrack well – This is to drill a secondary well bore from an existing well bore towards a new well target or new well path because the first well path cannot be used due to technical reasons.
Subsea template – a structure that is used as a base for and protection of subsea trees, manifolds and other subsea equipment.
Ticker / ticker code – An arrangement of characters (usually letters) representing a particular security listed on an exchange or otherwise traded publicly.
Triassic period – Geologic period that extends from 250 to 200 million years ago. This period lies between the Permian and Jurassic periods.
Undiscovered resources – Recoverable volumes of petroleum that it is estimated may be discovered with further exploration.
UN Global Compact – A United Nation initiative to encourage businesses worldwide to adopt sustainable and corporate social responsibility policies, and to report on their implementation. The Global Compact is a principle-based framework for businesses, stating ten principles in the areas of human rights, labour relations, environment and anti-corruption.
Unitization – If a petroleum deposit extends over more than one block with different licensees, or onto the continental shelf of another state, efforts shall be made to reach agreement on the most efficient co-ordination of petroleum activities in connection with the petroleum deposit as well as on the apportionment of the petroleum deposit. Agreements on joint production, transportation, utilization and cessation of petroleum activities shall be submitted to the Ministry of Petroleum and Energy for approval.
Uptime – In the oil and gas industry, the term uptime refers to the active time during which an installation is either fully operational or is ready to perform its intended function. The opposite of uptime is downtime, e.g. the duration of maintenance.
Water injection – Refers to the method in the oil industry where water is injected into the reservoir, usually to increase pressure and thereby stimulate production. Water injection wells can be found both on- and offshore, to increase oil recovery from an existing reservoir. Water is injected to support pressure of the reservoir and to sweep or displace oil from the reservoir, and push it towards a production well.
Well – A well is a hole drilled to find or delimit a petroleum deposit and/or produce petroleum or water for injection purposes, inject gas, water or another medium, or map or monitor well parameters. A well may consist of one or more well paths and may have one or more terminal points.
Working environment committee (AMU) –
Pursuant to the Working Environment Act, undertakings which regularly employ at least 50 employees shall have a working environment committee, abbreviated AMU in Norwegian. The working environment committee shall make efforts to establish a fully satisfactory working environment in the undertaking.
Zero emissions and discharges – This means that, in principle, no environmentally hazardous substances, or other substances, are to be emitted or discharged if they can result in damage to the environment (detailed definition in White Paper no. 25 (2002-2003)). Special demands for emissions and discharges in the Barents Sea are that, in principle, no undesirable emissions or discharges are to take place during normal operations, irrespective of whether they may result in damage to the environment (detailed definition in White Paper no. 38 (2003-2004)).
Source: Most definitions are based on the Norwegian Petroleum Directorate's ABC of oil.
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54
ANNUAL REPORT 2014
Dear fellow shareholders
2014 was truly a transformational year for Det norske oljeselskap ASA ("Det norske" or "the company"). The acquisition of Marathon Oil Norge AS was a major milestone, transforming the company into one of Europe's largest independent oil and gas companies. Together with Det norske's development projects, the acquired assets provide a diversified and balanced asset base and create a strong platform for further organic growth.
P50 net reserves at year-end 2014 were estimated at 206 million barrels of oil equivalent, about three times higher than the previous year. Following the submission of the Plan for Development and Operation (PDO) for Johan Sverdrup on 13 February 2015, the company's P50 reserves more than doubled.
The acquisition of Marathon Oil Norge AS was financed through a combination of debt and equity. A new seven-year USD 3 billion reserve-based lending facility was entered into with a consortium of 17 banks, replacing the company's previous bank debt. In addition, the company strengthened its equity base by issuing NOK 3 billion in new equity through a rights issue. These financing initiatives, along with increased cash flows, significantly strengthened the company's financial robustness after the acquisition.
Amid the current challenging market conditions, Det norske is fortunate to benefit from a world-class, low break-even cost asset base. Our producing assets are generating strong cash flows and our developing assets will grow returns even further when they come on stream. The company is nevertheless taking steps to strengthen its business to adapt to the current market conditions, ensuring that the company is in a position to benefit when conditions improve. Exploration activities are scaled back and focused around core areas, while a cost efficiency program has been implemented with the purpose of streamlining processes and reducing expenditures.
Det norske is currently in the middle of the investment cycle on its two major developments, the Ivar Aasen and Johan Sverdrup fields. Financial robustness is important for safeguarding the value of these projects. The company is considering diversifying its capital structure going forward, as well as aligning loan agreements. The support from the company's bank group is considered to be strong and the company is confident that it will be able to meet its future obligations.
The year 2014 marked the completion of the extensive appraisal program of the Johan Sverdrup field. Decision Gate 2 (DG2) was formally passed in February 2014, outlining the concept for the first development phase. Production from the first phase could be as high as 380 000 barrels per day. Plateau production is estimated to be between 550 000 and 650 000 barrels per day.
Unitization discussions between the partners were completed in the first quarter 2015, and on 13 February 2015, the PDO was submitted to the Ministry of Petroleum and Energy (MPE). The PDO is further described in the section "Events after year-end". Det norske did not sign the unit agreement. For Det norske, it was always a decisive principle that the ownership interests in Johan Sverdrup be distributed according to a combination of volume and value. It proved impossible to reach an agreement about this with the partnership and the company could consequently not sign an agreement. The MPE is to conclude on the unitisation split. After the MPE has reached a decision, there is an option to challenge the decision in an appeal to the King in Council and in the Civil Court system.
Det norske carries out significant offshore operations on the Norwegian Continental Shelf (NCS). In addition, the company's development projects involve workers in different countries on different continents. As a result, HSE and CSR are important to the board of directors of Det norske. Accordingly, it recognizes its responsibility to the safety of people and the environment, and is devoted to spending time and resources to meet all regulations and the highest HSE standards in the oil industry.
Det norske is well positioned to participate in future growth on the NCS. In the short term, the company will prioritize exploration in existing core areas. The board is conscious of the risks associated with project execution and the changing market conditions in which we operate. The board is prioritizing to ensure capital discipline and mitigation of risk wherever possible throughout the organization.
In 2014, the share price for Det norske ended at NOK 39.87 per share, compared to NOK 60.29 per share at the end of 2013. During the year, 61.9 million shares were issued through a rights issue, which was completed in August. At the end of the year, 202.6 million shares were outstanding. Aker Capital AS remains the largest owner with 49.99 per cent.
Det norske is a fully-fledged E&P company with exploration, development and production activities on the NCS. Det norske holds no oil or gas assets outside Norway. All activities are thus within the Norwegian offshore tax regime, and to the extent the company has overseas activities, these are related to construction and engineering of field developments.
Det norske is active in all three main petroleum provinces on the NCS. We remain convinced that the NCS offers attractive opportunities for oil and gas exploration and this is also supported by the NPD's latest undiscovered resources estimates. Correspondingly, we plan to be an active industry player in the coming years.
The company's registered address is in Trondheim. The company also has offices in Oslo, Stavanger and Harstad. Karl Johnny Hersvik took over the position of CEO of Det norske in April 2014.
At the end of 2014, the company had 507 (230) employees. As operator for 35 licences and partner in an additional 44 licences, the company is a major licence holder on the NCS.
Looking back at the past seven years, Det norske has proved up about 600 million barrels of oil equivalent through the drill bit and has participated in some of the most important discoveries on the NCS. Going forward, the company will prioritize infrastructure-led exploration (ILX) in existing core areas, i.e. the Greater Alvheim and the Greater Utsira High areas. In both areas, the focus is on proving up additional reserves that can secure utilization of the production systems in place. Det norske aims to participate in five exploration wells in 2015.
In 2014, Det norske participated in ten exploration and appraisal wells, seven of which were wildcats. The 2014 exploration programme resulted in three wildcat discoveries, two of which were deemed non-commercial, and four were dry wells.
A small discovery was made on the Krafla North prospect in PL 035 in late 2014, where Det norske holds a 25 per cent interest. The Krafla Main well was completed in early 2015. Since 2011, five discoveries have been made in the Krafla area in PL 035 and PL 272: Krafla Main, Krafla West, Askja West, Askja East and Krafla North. Based on well results and updated evaluations of the licenses, recoverable resources in the two licenses are expected to be in a range of 140-220 million barrels of oil equivalent.
In addition to the discoveries made by the Geitungen appraisal well in PL 265 and the Gohta-2 appraisal well in PL 492, the Garantiana discovery in PL 554, where Det norske holds a 10 per cent interest, was successfully appraised during 2014. After drilling of the Garantiana-II appraisal well, the resource range estimate for PL 554 was updated to between 40 and 90 million barrels of oil equivalent.
In 2014, total investments in exploration amounted to USD 199 (282) million. The main reason for the decrease is that the Johan Sverdrup appraisal programme was completed in early 2014.
In 2014, Det norske participated in four field development projects: Bøyla (65 per cent and operator), Ivar Aasen (34.7862 per cent and operator), Gina Krog (3.3 per cent partner) and Johan Sverdrup (preliminary working interest of 11.8933 per cent).
The Bøyla field (65 per cent and operator) is located south of the Volund field, approximately 28 kilometres from Alvheim at a water depth of 120 metres. The field was discovered in 2009 and the PDO was approved in 2012. The field is developed with two horizontal production wells (targeting each of the eastern and western structural closures) and one water injection well, placed at the eastern edge of the western structural closure.
Pilot wells were drilled in order to optimize the horizontal section of the western structure producer. The field produces via a four-slot subsea production manifold and is tied back to the Alvheim FPSO via the existing Kneler A production manifold.
Subsurface evaluation and mapping conducted post exploration and appraisal drilling have resulted in a gross mean recoverable volume estimate of 23 million barrels of oil equivalent, with an incremental potential upside of 10 million barrels of oil equivalent.
Production at Bøyla commenced on 19 January 2015, and the field averaged about 18 000 barrels of oil equivalent per day in its first production month. Cessation of production from the Bøyla field is expected in 2030 together with abandonment activities relating to the other fields in the Alvheim area.
The Ivar Aasen field (34.7862 per cent interest and operator) is Det norske's first major development project as operator. A major milestone was passed on 21 May 2013, when the PDO was approved by the Norwegian Parliament. First oil is expected in the fourth quarter of 2016. The Ivar Aasen field is situated west of Johan Sverdrup in the Utsira High area, and is estimated to contain gross reserves (P50/2P) of 204 million barrels of oil equivalent. The Ivar Aasen development comprises production of the resources in three discoveries; Ivar Aasen (PL 001B) Hanz (PL 028B) and West Cable (PL 001B and PL 242).
In June 2014, Det norske signed a unit agreement with the licensees in PL 001B, PL 242, PL 457 and PL 338. Det norske is operator and holds a 34.7862 per cent interest in the unit. The unit comprises the Ivar Aasen and West Cable deposits, while the Hanz deposit remains in PL 028B, where Det norske is operator and holds a 35 per cent working interest.
Full field development costs (including Hanz) are estimated at NOK 27.4 billion (nominal). Det norske's ownership interest thus represents an investment of about NOK 9.6 billion.
Ivar Aasen is a two-stage development, with Ivar Aasen and West Cable being developed in Phase 1, with production scheduled to commence in the fourth quarter of 2016 at a rate (gross) of about 45 000 boepd. Hanz, located further north, will be developed in Phase 2 and is scheduled to start producing in 2019. The production is estimated to reach a peak level of approximately 75 000 boepd (gross). The development of Ivar Aasen is coordinated with the adjacent Edvard Grieg field, which will receive partially processed oil and gas from the Ivar Aasen field for further processing and export.
During 2014, key engineering and construction activities progressed according to plan and budget. The platform deck is being constructed by SMOE in Singapore, and is scheduled to sail away in the first half of 2016. Mustang is responsible for engineering. The living quarters module for Ivar Aasen is being built by Apply Leirvik at Stord. The steel jacket is being constructed by Saipem in Sardinia, while Siemens is responsible for the control and communication systems for the platform. Det norske took over the Maersk Interceptor rig in December 2014, and drilling of geo-pilot wells commenced in early 2015.
The PDO for the Gina Krog field (3.3 per cent, partner) was approved by the Norwegian Parliament in May 2013. The Gina Krog oil and gas field is operated by Statoil and is located in blocks 15/5 and 15/6 of PL 303, PL 048, PL 029B and PL 029C in the North Sea. Det norske holds a 20 per cent interest in PL 029B. Based on its interest in PL 029B, the company reached a unitization agreement with the other partners, resulting in a 3.3 per cent ownership share to Det norske.
Gina Krog will be developed with a steel jacket platform and will be tied back to the Sleipner platform for gas export. The oil will be shipped by shuttle tankers. Gross investments are estimated at NOK 31 billion (nominal) and the field holds gross proven and probable resources (P50/2P) of about 225 million barrels of oil equivalent.
Johan Sverdrup (11.8933 per cent preliminary in unit, partner) is the largest discovery on the Norwegian shelf since the 1980s and is located on the Utsira High in the middle of the North Sea. The field contains recoverable volumes between 1.7 and 3.0 billion barrels of oil equivalent, and the development of the field will be one of the largest industrial projects in modern history.
On Friday 13 February 2015, the PDO for Phase 1 and two Plans for Installation and Operation (PIOs) were submitted to the Minister of Petroleum and Energy, Tord Lien. Approval from the Norwegian Parliament is expected during the first half of 2015 and production is expected to commence in late 2019. The plan shows that the field will facilitate 50 years of production, and that the project will be of high socio-economic importance. The Johan Sverdrup oil field is planned to be developed in several phases. The capital expenditures for Phase 1 have been estimated at NOK 117 billion (2015 value). The expected gross recoverable resources from the Phase 1 investments are estimated at between 1.4 and 2.4 billion barrels of oil equivalent – corresponding to 80 per cent of the total resource basis. For the full field development, capital expenditures are projected at between NOK 170 and 220 billion (2015 value) with recoverable resources of between 1.7 and 3.0 billion barrels of oil equivalent. The ambition is a recovery rate of 70 per cent, taking into account advanced technology for increased oil recovery (IOR) in future phases. Phase 1 has a production capacity of 315 000 to 380 000 barrels of oil equivalent per day. Fully developed, the field can produce 550 000 to 650 000 barrels of oil equivalent per day. The PDO for future phases is expected to be submitted no later than the second half of 2017, and start-up of production in the second phase is expected in 2022.
Phase 1 consists of four bridge-linked platforms (processing platform, drilling platform, riser platform and a separate living quarter), in addition to three subsea water injection templates. The estimated capital expenditure also includes drilling, export of oil and gas and power from shore, as well as contingencies and allowances for market adjustments. Phase 1 also includes an export solution for oil and gas. The oil will be transported via a dedicated pipeline to the Mongstad terminal, whereas the gas will be transported via the Statpipe system to Kårstø for processing and onward transportation.
The partnership, consisting of Statoil, Lundin Norway, Petoro, Det norske oljeselskap and Maersk Oil, has recommended Statoil as the operator for all phases of field development and operation. Det norske has not succeeded in reaching an agreement about the unitization with the other partners. For Det norske, it was always a decisive principle that the ownership interests in Johan Sverdrup be distributed according to a combination of volume and value. It proved impossible to reach an agreement about this with the partnership and the company could consequently not sign an agreement. Thus, the other partners have asked the MPE to conclude on the unitization of Johan Sverdrup. After the MPE has reached a decision, there is an option to challenge the decision in an appeal to the King in Council and in the Civil Court system. Until this conclusion is made, the Ministry has decided that Statoil's proposal be used as a basis: Statoil 40.0267 per cent, Lundin Norway 22.12 per cent, Petoro 17.84 per cent, Det norske oljeselskap 11.8933 per cent and Maersk Oil 8.12 per cent. Following the submission of the Johan Sverdup PDO, Det norske more than doubled its total P50 net reserves.
Viper-Kobra (65 per cent, operator) is located within the Alvheim field approximately three kilometres south of the Kneler structure at a water depth of 120 to 130 metres. The discovery comprises the two discoveries Viper and Kobra, believed to be in pressure communication. Viper-Kobra will be developed by two wells, one targeting Viper and one targeting Kobra. A new subsea 4 –slot manifold will be installed and tied back to the Volund field. The two reservoirs each contain approximately 4 million barrels of recoverable oil. Together with gas, total recoverable reserves are estimated at 9 million barrels of oil equivalent. First oil is expected in late 2016.
In addition to the above-mentioned fields, Det norske is engaged in early phase projects such as Frigg GD, Krafla and Frøy.
As of 31 December 2014, Det norske had production from seven fields: Alvheim, (65 per cent and operator), Volund (65 per cent and operator), Vilje (46.9 per cent and operator), Jette (70 per cent and operator), Atla (10 per cent and partner), Jotun (7 per cent and partner) and Varg (5 per cent partner). The Bøyla field (65 per cent and operator) commenced production in January 2015.
Production in 2014 averaged 66.6 thousand barrels of oil equivalent (mboepd), with 88 per cent oil and 12 per cent gas. This represents a significant increase compared to 4.5 mboepd in 2013 due to the inclusion of the Alvheim fields after the acquisition of Marathon Oil Norge AS.
Alvheim (65 per cent, operator) is an oil and gas field operated by Det norske and is located in the Norwegian sector of the Northern North Sea at a water depth between 120 and 130 metres. The field is located in Blocks 24/6, 24/9, 25/4 and 25/7 and is comprised of the producing Alvheim field (Boa, Kneler, and the Kameleon/East Kameleon structures), the Viper-Kobra development and Gekko discoveries. The productive reservoir of the Alvheim field is the middle to late Palaeocene Heimdal Formation sandstone, which exists at a depth of approximately 2 100 metres. Alvheim was developed using a floating production, storage and offloading (FPSO) vessel. The development provides for the transport of oil by shuttle tanker and transportation of
gas to the SAGE system. The Alvheim FPSO is characterized by high regularity, more than 98 per cent uptime (excluding planned downtime for maintenance).
First production for the Alvheim field was in June 2008. The fields in the Alvheim area have seen significant year-on-year increases in the estimated recoverable volumes of oil and gas since the initial development of the Alvheim field. The amount of recoverable oil has increased due to greater in-place volumes than previously estimated, development of satellite fields, additional horizontal and multi-lateral wells, and better than anticipated flow rates. Furthermore, improved reliability combined with optimization work has increased the production capacity of the Alvheim FPSO to about 150 000 boepd, up from the original design of 120 000 boepd.
The Alvheim fields consist of the Kneler, Boa, Kameleon and East Kameleon structures. The Boa reservoir straddles the Norway-UK median line. The Boa reservoir is unitized with Maersk Oil & Gas and Verus Petroleum, who are the owners on the UK side.
Net production from Alvheim, including Boa, averaged 42.2 mboepd in 2014. Production from the Alvheim field is estimated to end in 2031, with subsequent abandonment between 2031 and 2033. Year-end 2014 P50 reserves for Alvheim, Boa and Viper-Kobra are estimated at 89.5 million barrels of oil equivalent net to Det norske.
The Volund field (65 per cent, operator) is located approximately eight km south of Alvheim, and was the second field developed as a subsea tieback to Alvheim. The field, comprising four production wells and one water injection well, started producing in 2009 and was utilized as a swing producer when the capacity of the Alvheim FPSO allowed it. The field was opened for regular production in 2010. The Volund reservoir is a large-scale injective feature, formed by sands of the Palaeocene Hermod Formation.
Net production at Volund averaged 13.4 mboepd in 2014. Production from the Volund field is expected to last until 2028. Year-end 2014 P50 reserves are estimated at 11.7 million barrels of oil equivalent net to Det norske.
The Vilje field (46.9 per cent, operator) is located northeast of Alvheim at a water depth of 120 metres. The productive reservoir of the Vilje field is the middle to late Palaeocene Heimdal Formation sandstone at a depth of approximately 2 100 metres. The field is tied back to the Alvheim FPSO. Production commenced in 2008. A third production well, Vilje South, was developed as a subsea tieback to the Vilje field, and production commenced in April 2014.
Net production from Vilje averaged 8.7 mboepd in 2014. Production from the Vilje field is expected to cease in 2030, with subsequent abandonment scheduled to take place between 2031 to 2033, which coincides with the expected cessation of production from the Alvheim area. Year-end 2014 P50 reserves are estimated at 10.5 million barrels of oil equivalent net to Det norske.
The Jette field (70 per cent, operator) is located in the central part of the North Sea at a water depth of 127 metres. The reservoir consists of a submarine fan system in the Heimdal Formation of Late Palaeocene age and lies at a depth of approximately 2 200 metres. The field was developed with a subsea installation tied back to the Jotun B platform. Jette continued to decline in 2014. The two producing wells are located close to the oil-water contact and there is uncertainty related to how fast the water cut will increase. Net production at Jette averaged 1.2 mboepd in 2014. It is estimated that the field will continue production until 2015.
Atla (10 per cent, partner) is an oil field located in the central part of the North Sea at a water depth of 119 metres. The reservoir contains gas/condensate in sandstones in the Brent Group of Middle Jurassic age at a depth of about 2 700 metres. The field is operated by Total and produces with a subsea installation tied back to the existing pipeline between the Heimdal and Skirne fields. Production started two years after the discovery was made in October 2010.
Net production from Atla averaged 0.5 mboepd in 2014. It is estimated that the field will continue commercial production until 2017.
Jotun (7 per cent, partner) is an oil field operated by ExxonMobil and is located in the central part of the North Sea at a water depth of approximately 126 metres. The Jotun unit comprises three structures; the easternmost structure has a small gas cap. The reservoirs, which are located at a depth of about 2 000 metres, consist of sandstones in the Heimdal Formation of Palaeocene age. The Jotun installations comprise an FPSO, Jotun A, and a wellhead platform, Jotun B. Production commenced in 1999 and is now in the tail-end phase.
Net production at Jotun averaged 0.1 mboepd in 2014. It is estimated that the field will continue production until late 2016.
The Varg field (5 per cent, partner) is an oil field operated by Talisman and is located in the central part of the North Sea at a water depth of 84 metres. The reservoir is in Upper Jurassic sandstones at a depth of approximately 2 700 metres. Varg was developed with a wellhead platform, Varg A, and an FPSO, Petrojarl Varg. After 15 years of producing oil, gas production commenced in 2013, which has contributed to extending the lifetime for the Varg facilities.
Net production from Varg averaged 0.5 mboepd in 2014. It is estimated that the field will cease production in 2016.
Year-end 2014 P50 reserves net to Det norske for the Jette, Atla, Jotun, Varg and Enoch fields (the latter field has not produced since early 2012) are estimated at 1.0 million barrels of oil equivalent.
Det norske collaborates both with leading research establishments and other companies to support the development of technology. A total of 69 projects were active in 2014. The gross research and development expenditures, prior to recharging to licence partners, were USD 10 (10) million.
(All figures in brackets refer to 2013)
The company prepares its financial statements in accordance with the International Financial Reporting Standards (IFRS) adopted by EU and the Norwegian Accounting Act.
The applied accounting principles are the same as for the previous financial year, except when it comes to consolidated financial statements, joint arrangements and disclosure of interest in other entities. The effect of the changes is described in Note 1. As described in the accounting principles, the company changed its functional currency from NOK to USD on 15 October 2014.
The company's total operating revenues amounted to USD 464 (161) million. Petroleum from the producing fields amounted to 5.7 (1.6) million barrels of oil equivalent. The production in 2014 came from the Alvheim (incl. Boa), Volund, Vilje, Jette, Atla, Jotun, and Varg fields, while the production in 2013 came from Jette, Atla, Jotun, Varg, and Glitne. The average realized oil price was USD 78 per barrel, which is down 27 per cent compared with an average price of USD 107 per barrel in 2013.
Exploration expenses amounted to USD 158 (279) million and are mainly related to dry and non-commercial wells, seismic data and general exploration activities.
Gross payroll expenses before recharges amounted to USD 79 (76) million. Net payroll expenses were USD -17 (6) million. The net reported payroll expense is a credit due to a gain related to the settlement of the defined benefit pension scheme and reclassified/ recharged expenses to exploration, development and production costs. A breakdown of payroll expenses is included in Note 9.
Depreciation amounted to USD 160 (80) million. The increase is mainly due to depreciations of the assets relating to the Marathon Oil Norge AS acquisition in 2014 (Alvheim, Boa, Volund and Vilje).
The net impairment of USD 346 (113) million is primarily related to impairment of goodwill. The main reason for the high impairment charge in 2014 is the decreased oil price assumptions from the acquisition date of Marathon Oil Norge AS to 31.12.2014. In addition, deferred tax on the asset values recognized in relation to the acquisition decreased during Q4 as a result of depreciation of these values. When deferred tax from the initial recognition decreases, more goodwill is exposed for impairment. A breakdown of the impairment charges is included in Note 15.
Other operating expenses amounted to USD 49 (19) million for the company. The majority of other operating expenses are relating to IT costs, area fee and consultants. A breakdown of other operating expenses is included in Note 10.
The company reported an operating loss of USD 299 (379) million.
The pre-tax loss amounted to USD 376 (433) million, and the tax income on the ordinary loss amounted to USD 96 (340) million. The tax rules and tax calculations are described in Notes 1 and 12 to the financial statements.
The after-tax loss was USD 279 (93) million.
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Total assets at year-end amounted to USD 5,384 (1,733) million and the increase was mainly caused by the acquisition of Marathon Oil Norge AS and capital expenditures in development projects.
Equity increased by USD 128 million to USD 652 million caused by a NOK 3 billion right issue and net loss for the period. At year-end, equity amounted to approximately 12 (30) percent of total assets.
At 31 December, total interest-bearing debt amounted to USD 2,290 (820) million, consisting of the DETNOR02 bond of USD 253 million and the drawn amount on the RBL of USD 2,037 million. The company established a new USD 3 billion credit facility in combination with the acquisition of Marathon Oil Norge AS. The facility replaced the company's existing revolving credit facility of USD 1 billion. For information about terms, see Note 20.
Cash and cash equivalents totalled USD 296 (281) million at the end of the year.
Net cash flow from operating activities amounted to USD 263 (156) million. This included tax refunds excluding interest of USD 191 (224) million.
Net cash flow from investment activities amounted to USD -2,266 (-477) million. This mainly relates to investments in fixed assets of USD -583 (-255) million, acquisition of Marathon Oil Norge AS of USD -1,514 (0) million and investments in intangible assets of USD -164 (-231) million. These investments are likely to result in a future increase of the company's production.
The net cash flow from financing activities amounted to USD 2,024 (416) million, mainly relating to repayment of debt and bond and proceeds from issuance of long-term debt.
In total, the company had a cash position USD 296 (281) million at the end of the year.
At year-end 2014, the company had an adjusted book equity ratio of 15.5 per cent, below the covenant level of 25 per cent for its DETNOR02 bond loan. A default only exists when the ratio is below 25 per cent on two consecutive quarter dates and the covenant breach is not remedied within the following quarter's reporting date. Work is ongoing to remedy the book equity covenant for the DETNOR02 bond loan.
Pursuant to the Norwegian Accounting Act section 3-3a, the board of directors confirms that the requirements of the going concern assumption are met and that the annual accounts have been prepared on that basis. The financial position and the liquidity of the company are considered to be good. The company is continuously considering various sources of funding to facilitate the expected growth of the company. In the short term, it is expected that liquid assets, revenues from the company's production and the unused parts of the established debt facilities will be sufficient to finance the company's commitments in 2015.
In the board of directors' view, the annual accounts give a true and fair view of the company's assets and liabilities, financial position and results. The board of directors is not aware of any factors that materially affect the assessment of the company's position as of 31 December 2014, or the result for 2014, other than those presented in the Board of Directors' Report or that otherwise follow from the financial statements.
Det norske complies with guidelines from Oslo Børs and the Society of Petroleum Engineers' (SPE) classification system for quantification of petroleum reserves and contingent resources. Total net P90/1P reserves are estimated at 143.0 (48.5) million barrels of oil equivalent at year-end, while net P50/2P reserves amounted to 205.6 (65.8) million barrels of oil equivalent at year-end. See Note 32 for a more detailed review of the resource accounts. Reserves and contingent resources have been certified by an independent third party.
The board of directors proposes that the loss for the year be covered by transferring USD 323 million from other equity.
Our business, results of operations, cash flow and financial condition depend significantly on the level of oil and gas prices and market expectations to these, and may be adversely affected by volatile oil and gas prices and by the general global economic and financial market situation.
Our profitability is determined in large part by the difference between the income received from the oil and gas that we produce and our operational costs, taxation costs relating to recovery (which are assessable irrespective of sales), as well as costs incurred in transporting and selling the oil and gas. Lower prices for oil and gas may thus reduce the amount of oil and gas that we are able to produce economically. They may also reduce the economic viability of the production levels of specific wells or of projects planned or in development to the extent that production costs exceed anticipated revenue from such production. At year-end 2014, we had not entered into derivative arrangements for our oil production, and the company is consequently particularly exposed to adverse fluctuations in commodity prices.
The economics of producing from some wells and assets may also result in a reduction in the volumes of our reserves. We might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in our net production revenue, causing a reduction in our oil and gas acquisition and development activities. In addition, certain development projects could become unprofitable because of a decline in price and could result in us having to postpone or cancel a planned project, or if it is not possible to cancel the project, carry out the project with negative economic impact.
In addition, a substantial material decline in prices from historical average prices could reduce our ability to refinance our outstanding NOK bonds and may result in a reduced borrowing base under credit facilities available to us, including the RBL facility, and possibly require that a portion of our bank debt be repaid. From time to time, we may enter into agreements to receive fixed prices on our oil and gas production to offset the risk of revenue losses if commodity prices decline. However, if commodity prices increase beyond the levels set in such agreements, we will not benefit from such increases and we may nevertheless be obligated to pay suppliers and others in the market based on such higher price. Changes in the oil and gas prices may thus adversely affect our business, results of operations, cash flow, financial condition and prospects.
Developing oil and gas resources and reserves into commercial production involves a high degree of risk. Our exploration operations are subject to all the risks common in our industry. These risks include, but are not limited to, encountering unusual or unexpected rock formations or geological pressures, geological uncertainties, seismic shifts, blowouts, oil spills, uncontrollable flows of oil, natural gas or well fluids, explosions, fires, improper installation or operation of equipment and equipment damage or failure. Given the nature of our offshore operations, our exploration and drilling facilities are also subject to the hazards inherent in marine operations, such as capsizing, sinking, grounding and damage from severe storms or other severe weather conditions.
The oil and gas industry is very competitive. Competition is particularly intense in the acquisition of (prospective) oil and gas licences. Our competitive position depends on our geological, geophysical and engineering expertise, financial resources, the ability to develop our assets and the ability to select, acquire, and develop proven reserves.
Our production of oil and gas is concentrated in a limited number of offshore fields. If mechanical or technical problems, storms or other events or problems affect the production on one of these offshore fields, it may have direct and significant impact on a substantial portion of our production. Also, if the actual reserves associated with any one of our fields are less than the estimated reserves, our results from operations and financial condition could be materially adversely affected.
Currently, a significant proportion of our production comes from the Greater Alvheim Area as production from Alvheim fields amounted to 64.3 boepd, or 96 per cent of our total production
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for the year ended 31 December 2014. We are especially sensitive to any shutdown or other technical issues on the Alvheim FPSO because all of the Alvheim Area fields are produced via the Alvheim FPSO. For that reason, we have entered into a "loss of production" insurance, reducing the impact of any shutdown on the Alvheim FPSO.
Further, we expect that a significant proportion of our future production will come from the Gina Krog, Ivar Aasen and Johan Sverdrup fields, and future production may not be substantially in line with our projections as there are risks attached to booked reserves and resources.
Unitization agreements relating to our production licences may include a redetermination clause, stating that the apportionment of the deposit between licences can be adjusted within certain agreed time periods. Any such redetermination of our interest in any of our licences may have a negative effect on our interest in the unitized deposit, including our tract participation and cash flow from production. No assurance can be made that any such redetermination will be satisfactorily resolved, or will be resolved within reasonable time and without incurring significant costs. Any redetermination negatively affecting our interest in a unit may have a material adverse effect on our business, results of operations, cash flow, financial condition and prospects.
Our ongoing development projects involve advanced engineering work, extensive procurement activities and complex construction work to be carried out under various contract packages at different locations onshore. Furthermore, we (together with our licence partners), must carry out drilling operations, install, test and commission offshore installations and obtain governmental approval to take them into use prior to commencement of production. The complexity of our development projects makes them very sensitive to circumstances that may affect the planned progress or sequence of the various activities, as this may result in delays or cost increases. In particular, this applies to our early stage development for Johan Sverdrup and the development of Ivar Aasen. Johan Sverdrup is a complicated multi-facility early stage development while the Ivar Aasen development is technically challenging and the first development we will complete as operator of a field. For example, the Johan Sverdrup development is currently in its first phase, which encompasses the installation of four fixed platforms and subsea infrastructure. The gross capital investment for the first development phase is estimated at NOK 117 billion and is expected to be completed in 2019.
Although we believe that the development projects will be completed on schedule in accordance with all licence requirements and within the estimated budgets, our current or future projected target dates for production may be delayed and cost overruns may incur.
Furthermore, our estimated exploration costs are subject to a number of assumptions that may not materialize. Any such inability to explore, appraise or develop petroleum operations or non-materialization of assumptions regarding exploration costs may have a material adverse effect on our growth ambitions, future business and revenue, operating results, financial condition and cash flow.
Where we are not the operator of a licence, although we may have consultation rights or the right to withhold consent in relation to significant operational matters depending on the level of our interest in such licence (as most decisions by the management committee only require a majority vote), we have limited control over management of the assets and mismanagement by the operator or disagreements with the operator as to the most appropriate course of action may result in significant delays, losses or increased costs to us.
Our reserve evaluations have been prepared in accordance with existing guidelines. The evaluation of our reserves and resources are carried out on an annual basis by an independent third party. These evaluations include a number of assumptions relating to factors such as initial production rates, recovery rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of oil and gas, operating costs, and royalties and other government levies that may be imposed over the producing life of the reserves and resources. Actual production and cash flows derived therefrom will vary from these evaluations, and such variations could be material. Hence, although we have an understanding of the life expectancy of each of our assets, the life of an asset may be shorter than anticipated. Among other things, evaluations are based, in part, on the assumed success of exploration activities intended to be undertaken in future years. The reserves, resources and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploration activities do not achieve the level of success assumed in the evaluations, and such reductions may have a material adverse effect on our business, results of operations, cash flow and financial condition.
The combination of Marathon Oil Norge AS and our business involved the integration of two companies that had previously operated independently; a challenging process which involved and still involves significant risk that the contemplated synergies will not be achieved. There can be no assurance that we will achieve the anticipated synergies or other benefits from the integration. For example, one of the key challenges in the integration of Marathon Oil Norge AS is the integration of the IT systems of the two companies with respect to both hardware and software. Our business depends on a well-functioning IT system for safe and effective operations. There are differences in the applications between the two companies, and successful adoption to a common system without disturbing ongoing business operations is necessary.
Moreover, under the Marathon SPA, the parties have agreed that the Marathon Oil Corporation shall provide certain transitional services for a prescribed period of time, including, but not limited to, marketing and sale of oil and gas, IT services and accounts and payment services. This arrangement was created to facilitate a smooth transition and complete separation of Marathon Oil Norge AS from its former parent company. Lack of cooperation, failure by the Marathon Oil Corporation to provide such services or unforeseen complications in this provision of services could increase integration costs and could adversely affect our business, operating result and financial condition.
In the Marathon SPA, Marathon Oil Corporation has given certain representations, warranties and indemnities regarding Marathon Oil Norge AS in our favour, and we have conducted a limited due diligence in connection with the acquisition. We may nevertheless discover issues relating to Marathon Oil Norge AS's business that may have a material adverse effect on our business, results of operations, cash flow and financial condition.
The company's future capital requirements depend on many factors, including an effective integration of the business of Marathon Oil Norge AS and on whether the company's cash flow from operations are sufficient to fund the company's business plans. The company may need additional funds in the longer term in order to further develop exploration and development programmes or to acquire assets or shares of other companies. In particular, the Ivar Aasen development project and the early stage Johan Sverdrup development project require significant capital expenditures in the years to come. Even though the company has taken measures to ensure a solid financial basis for the development projects, the company cannot assure that it will be able to generate or obtain sufficient funds to finance the projects. In particular, given the extensive scope of the projects, any unforeseen circumstances or actions to be dealt with that is not accounted for, may result in a substantial gap between estimated and actual costs. Thus, the actual costs necessary to carry out the projects may be considerably higher than currently estimated. These investments, along with the company's ongoing operations, may be financed partially or wholly with debt, which may increase the company's debt levels above industry standards.
The company may also have to manage its business in a certain way so as to service its debt and other financial obligations. Should the financing of the company not be sufficient to meet its financing needs, the company may, among other things, be forced to reduce or delay capital expenditures or research and development expenditures or sell assets or businesses at unanticipated times and/or at unfavourable prices or other terms, or to seek additional equity capital or to restructure or refinance its debt. There can be no assurance that such measures would be successful or would be adequate to meet debt and other obligations as they come due, or would not result in the company being placed in a less competitive position.
ANNUAL REPORT 2014
The general financial market conditions, stock exchange climate, interest level, the investors' interest in the company, the share price of the company, as well as a number of other factors beyond the company's control, may restrict the company's ability to raise necessary funds for future growth and/or investments. Thus, additional funding may not be available to the company or, if available, may not be available on acceptable terms. If the company is unable to raise additional funds as needed, the scope of its operations may be reduced and, as a result, the company may be unable to fulfil its long-term development programme, or meet its obligations under its contracts, which may ultimately be withdrawn or terminated for non-compliance. The company may also have to forfeit or forego various opportunities, curtail its growth and/or reduce its assets. This could have a material adverse effect on the company's business, prospects, financial condition, results of operations and cash flows, and on the company's ability to fund the development of its business.
The company's long-term debt is primarily based on floating interest rates. An increase in interest rates can therefore materially adversely affect the company's cash flows, operating results and financial condition and make it difficult to service its financial obligations. The company has, and will in the future have, covenants related to its financial commitments. Failure to comply with financial obligations, financial covenants and other covenants may entail several material adverse consequences, including the need to refinance, restructure, or dispose of certain parts of, the company's businesses in order to fulfil the company's financial obligations and there can be no assurances that the company in such event will be able to fulfil its financial obligations.
The company is exposed to market fluctuations in foreign exchange rates due to the fact that the company reports profit and loss and the balance sheet in USD. Revenues are in USD for oil and in GBP for gas, while operational costs and investment are in several other currencies than USD. The company had at year-end 2014 entered into some cross-currency swaps, but significant fluctuations in exchange rates between USD and NOK could adversely affect the liquidity position of the company. The company expects to increase its foreign exchange hedging activity in 2015.
The company's partners and counterparties consist of a diverse base with no single material source of credit risk. However, a general downturn in financial markets and economic activity may result in a higher volume of late payments and outstanding receivables, which may in turn adversely affect the company's business, operating results, cash flows and financial condition.
Det norske's HSE objectives are to conduct our operations in a manner so as to avoid harm and injuries to personnel, the environment and assets. The company shall carry out its operations in a manner ensuring that we avoid work-related illness, ensure the technical integrity of facilities, and avoid orders from the Norwegian authorities.
Det norske shall achieve these objectives through integrating HSE in all operations managed and carried out by the company. Tasks related to HSE and reducing the risk of major accidents shall be prioritized at all levels within the company.
Work has been initiated to develop a strong and common HSE culture in the company as a result of Det norske's acquisition of Marathon Oil Norge AS. This work will continue in 2015.
2014 has been a year characterized by a high level of activity for Det norske. The integration of Det norske and Marathon Oil Norge AS was one of the main activities, including integration of HSE-related systems, emergency preparedness and management systems. The company drilled three exploration wells, drilled production wells on Alvheim and Bøyla, conducted construction and installation activities on the Alvheim field, including several manned underwater operations and operated the Alvheim FPSO. There was also a high activity level in the Ivar Aasen project at several yards and offices in Norway and abroad. HSEQ has been integrated in all these activities and the company has achieved a strong HSE performance in 2014. The company's HSEQ programme has reflected the four main priorities of the PSA (barriers, management and major accident risk, the far North and groups at particular risk) also in 2014.
Det norske did not receive any mandatory orders or notifications from the Petroleum Safety Authority Norway (PSA) related to our operations in 2014. The PSA carried out nine audits of Det norske's operations/activities in 2014. The Norwegian Environment Agency conducted two audits of Det norske's operations in 2014.
In total, 24 events were reported to the PSA during 2014. Two of these involved minor personnel injuries with no serious consequences, three notifications involved unplanned spills to the environment and five events where dropped objects. All events were investigated according to procedures and lessons learned implemented. With the extraordinary high current activity level, special attention is paid to preventing injuries at all levels in the organization.
The management system has been subjected to a significant revision as a result of Det norske's acquisition of Marathon Oil Norge AS. Best practices from both companies are utilized to establish new HSEQ procedures, and a significant amount of work has been carried out to harmonize HSEQ processes and tools.
Det norske works actively to reduce the environmental footprint of our operations. This includes optimizing usage of energy as well as the principle of chemical substitution (to replace chemicals with less harmful ones). Det norske also strives to reduce the amount of waste from our operations.
Det norske incorporates safety measures to protect against unplanned incidents in all operations and activities carried out by the company. The company's management system constitutes a key foundation for this work. All activities nevertheless entail risk. Det norske has established a well-organized and prepared emergency response system in case of accidents. Location-specific emergency response analyses are carried out prior to all drilling operations, including analyses of environmental risk and emergency preparedness. This constitutes a key element in the planning of emergency preparedness pertaining to various predefined accident scenarios, including oil-spill preparedness.
In 2014, Det norske has also focused on establishing an emergency response system for our activities abroad related to the Ivar Aasen development. An emergency response plan has been prepared for the Ivar Aasen project, including specific plans for each location.
When acquiring the Marathon Oil Norge AS assets and organization in Norway, emergency preparedness constituted a key area in the integration work. A significant effort was made to ensure that the company would be able to respond to and handle any emergency event at or after the integration date, 15 October. The two companies operated two different models for their operational emergency response (second line). Marathon Oil Norge AS had an internal second line whereas Det norske had their second line with the Norwegian Operators' Association for Emergency Preparedness (OFFB). It was decided early on that until another decision was made, both organizations should continue to operate with their defined area of responsibility, with one common third line in Trondheim. In October, it was decided that the future second line emergency response solution should be the OFFB. OFFB's task is to manage and maintain a second line response on behalf of their member companies and as such be an integrated part of the respective companies' emergency response organizations.
In 2014, Det norske has completed four half-day exercises and one all-day exercise where the OFFB had the lead. In addition, the OFFB has organized smaller exercises and tabletops. Several activities for internal function-specific and task-specific training for the third line have been completed during the year.
Following the acquisition of the Marathon Oil Norge AS assets the company's total emergency response capabilities have increased, and our qualifications for handling any kind of event have been significantly strengthened. It is the intention of the company to maintain and to continue to strengthen this competence.
Det norske still maintains a high level of activity due to the Ivar Aasen project. This entails that the company has employed and hired several resources, especially in pre-ops, to ensure the right competence and capacity for the tasks pertaining to the development project.
Det norske has a long-standing collaboration with graduate schools, university colleges, universities and business and industries in order to recruit and retain both talents and experienced personnel for senior and executive positions. During 2014, a new
ANNUAL REPORT 2014
executive management team was established from 15 October. In addition to Karl Johnny Hersvik, two executives joined the management team in 2014 from external positions and four came from Marathon Oil Norway AS as part of the acquisition.
During the course of 2014, the number of employees doubled, mainly as a result of the inclusion of employees from Marathon Oil Norge AS following the acquisition. At year-end, the company had 507 (230) employees.
The company endeavours to maintain a working environment with equal opportunities for all based on qualifications and irrespective of gender, ethnicity, sexual orientation or disability.
In December 2014, women held 26.8 per cent of the positions (30.4 per cent in 2013). The percentage of women on the board of directors is 40 per cent (33.3 per cent in 2013). The percentage of women in the executive management is 18.2 (16.7 per cent in 2013), and in middle management with personnel responsibility 17.8 per cent (26.3 per cent in 2013).
Men and women with the same jobs, with equal professional experience and who perform equally well, shall receive the same pay in Det norske. The type of job, discipline area and number of years of work experience affect the pay level of individual employees.
As of 31.12.2014, 10.3 per cent of the employees were of non-Norwegian origin (5.7 per cent in 2013).
Det norske has a working environment committee (AMU) as described in the Norwegian Working Environment Act. The committee plays an important role in monitoring and improving the working environment and in ensuring that the company complies with laws and regulations in this area. Det norske conducts a survey of the working environment in the company every two years; the last one was conducted in 2014.
The company is committed to maintaining an open and constructive dialogue with the employee representatives and has arranged meetings on a regular basis throughout the year. Three local trade unions are registered as being represented in the company, Tekna, Lederne and Industri Energi.
In the board's view, the working environment in Det norske during 2014 was good.
In 2014, sickness absence in Det norske was 1.6 (1.8) per cent, including absence due to child's sickness.
Det norske's code of ethics sets out requirements for good business conduct and personal conduct for all employees of Det norske and members of its governing bodies. The code also applies to hired personnel, consultants and others who act on behalf of Det norske.
Corporate social responsibility is important to the board of Det norske and the board is of the opinion that Det norske has implemented our social responsibility in our values and in the manner in which the company operates, including governing documents and associated work processes. The company's employees shall be fully familiar with the company's values, the company's corporate social responsibility and good business ethics.
The activities in the Ivar Aasen development project that are carried out abroad (the greater part in Singapore) receive special attention with regard to corporate social responsibility, ethics and anti-corruption. The company is committed to use suppliers who operate consistently in accordance with the company's values, comply with applicable Norwegian laws and meet Det norske's requirements within HSE, CSR, ethics and anti-corruption and quality assurance systems, including human rights and labour standards. Procurements made by Det norske are based on competitive tendering and the principle of non-discrimination, equal treatment and transparent tender processes.
In 2014, Det norske continued its emphasis on ethics and anti-corruption by carrying out risk assessments and introducing an anti-corruption programme for employees. Det norske also assessed how the principles of the UN Global Compact are relevant for the company's activities.
As part of our continued efforts, Det norske will carry out a program related to corporate social responsibility, ethics and anti-corruption in cooperation with Aker ASA during 2015. Any changes to our guidelines will be implemented on the basis of this work and the amendments to the new accounting act relating to inter alia reporting of discharges to the environment.
The company has established good cooperation with schools, educational establishments and research both directly and via Norsk Olje og Gass. In 2014, Det norske has inter alia contributed actively to basic education in mathematics and the natural sciences from the fourth grade up to and including upper secondary school. The company has also participated actively in and contributed to the Research Centre for Arctic Petroleum Exploration (ARCEx), SAMCOT and NORUT sustainable cold climate technology (ColdTech). In addition, Det norske has maintained good cooperation with especially the universities in Stavanger, Trondheim and Tromsø. Through its partnership with UNICEF, Det norske also sponsors the Schools for Africa project, and the company has contributed to building more than ten schools in the Kamonyi district in Rwanda since the project started.
Det norske is an active contributor to society and sponsors a variety of Norwegian cultural initiatives in addition to local events relating to our office locations and fields of interest. These include among others Det Norske Teatret, athletic organizations, festivals and various associations and organizations.
Det norske is highly environmentally conscious in all its activities. In connection with operations on the shelf, we conduct detailed environmental risk and emergency preparedness analyses and implement all known preparedness measures. We carry out training and exercises relating to these measures prior to implementing our operations.
Det norske believes that good corporate governance with a clear distribution of roles and responsibility between the owners, the board and executive personnel is crucial in order to deliver value to its shareholders.
The board of Det norske is responsible for maintaining good corporate governance standards. The board carries out an annual review of the company's principles. The company complies with relevant rules and regulations for corporate governance, including the most recent version of the Norwegian Code of Conduct for Corporate Governance, published on 30 October 2014, unless otherwise specified.
An account of corporate governance is provided in a separate section of the annual report and on the company's website www.detnor.no.
Det norske has prepared a report on government payments in accordance with the Norwegian Accounting Act § 3-3 d) and the Norwegian Securities Trading Act § 5-5a, which represents a new requirement applicable from the fiscal year 2014. It states that companies engaged in activities within the extractive industries shall annually prepare and publish a report containing information about their payments to governments at country and project level.
The report is provided on page 82 of this annual report and on the company's website www.detnor.no.
In January 2015, Det norske announced that the company at year-end 2014 completed a semi-annual redetermination process with its bank consortium under the company's USD 3.0 billion reserve-based lending facility. Following the redetermination process, the borrowing base was reduced to USD 2.7 billion. For cash management purposes, Det norske reduced the drawn amount under the facility to USD 2.1 billion at year-end 2014.
Det norske and the licence partners decided to develop Viper-Kobra, which consists of two separate discoveries that constitute part of the Alvheim field. The two reservoirs contain approximately 9 mmboe in total, of which approximately 8 million barrels are oil. The estimated output of the wells is an average daily rate of 7 500 boepd from late 2016.
Production from the Bøyla field in the Greater Alvheim area commenced on 19 January 2015. Recoverable reserves from the field are estimated at approximately 23 million barrels of oil equivalent, whereof Det norske's share is 15 million barrels
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| Anne Marie Cannon Anne Marie Cannon, Deputy Chair |
|---|
| $\mathcal{U}$ Kjell Inge Røkke, Board member |
| Tom Røtjer, Board member |
| audmund Liju Gudmund Evju, Board member |
| Gro Kielland, Board member |
of oil equivalent. The Bøyla field is tied back to the Alvheim FPSO's existing infrastructure via a 28-kilometre pipeline.
On 20 January 2015, Det norske was offered nine new licences, of which two were new operatorships in the North Sea, in the Awards in Pre-defined Areas (APA) 2014 licensing round. Det norske was awarded eight licences in the North Sea and one in the Barents Sea.
The drilling rig Maersk Interceptor commenced the drilling pro gramme on the Ivar Aasen field in the North Sea in January 2015 with the drilling of three pilot wells for further mapping of the underground. The campaign has a duration of three years and comprises a total of 15 wells, in addition to the three pilot wells.
Drilling of the Krafla appraisal well resulted in an updated resources estimate for the Krafla Main discovery of 50 to 82 mmboe. Since 2011, five discoveries have been made in the Krafla area in PL 035 and PL 272: Krafla Main, Krafla West, Askja West, Askja East and Krafla North. Based on well results and updated evaluations of the licences, recoverable resources in the two licences are expected to be in the range of 140 to 220 million barrels of oil equivalent. Det norske holds a 25 per cent interest in the licence as partner.
On Friday 13 February 2015, the Plan for Development and Operation (PDO) for Phase 1 and two Plans for Installation and Operation (PIOs) were submitted to the Ministry of Petroleum and Energy. The MPE is to conclude on the unitization split. After the MPE has reached a decision, there is an option to challenge the decision in an appeal to the King in Council and in the Civil Court system. Planned production start-up is late 2019 and estimated capital expenditure for the first phase is NOK 117 billion (2015 value).
The board believes that Det norske is well positioned for furt her growth on the NCS. During 2014, the company established itself as one of Europe's leading independent exploration and production companies. The Alvheim area provides material near-term production at low operating cost, which together with the company's development projects represent a strong platform for further organic growth.
Driving execution is the company's main priority going forward, while building optionality for the future. Delivering the Ivar Aasen project on time and within budget and maximizing the value of the Alvheim area is key to the company, and the work is being closely monitored by the board.
A major milestone was passed with the submission of the Johan Sverdrup PDO in early 2015, confirming the project timeline to first oil in late 2019. With a breakeven price of under USD 40 per barrel, this field will generate great value and ensure solid cash flows for Det norske for many decades to come. The board now looks forward to approval of the PDO before summer and achieving a solution on the unitization.
Amid the current challenging macro environment, the compa ny is taking steps to strengthen its business to adapt to market conditions and to ensure that the company is in a position to benefit when conditions improve.
An efficiency program is being implemented across all discipli nes in order to increase productivity and reduce expenditures. Significant reductions have already been identified with an ambition to reduce 2015 expenditures by more than USD 100 million. Exploration activities have been scaled back and focused around core areas.
Through the acquisition of Marathon Oil Norge AS, the compa ny's financial robustness improved significantly. The company is working to increase its financial flexibility and is considering diversifying its capital structure going forward, as well as aligning loan agreements. The support from the company's bank group is considered to be strong and the company is confident that it will be able to fund its planned future developments.
The Board of Directors ('the Board') establishes the company's goals and strategy, while it is the executive management's task to implement the strategy in order to achieve the goals.
The Board of Det norske is responsible for actively adhering to sound corporate governance standards. The Board carries out a review of the company's principles for corporate governance on a regular basis.
Det norske is a Norwegian public limited liability company (ASA), listed on the Oslo Børs and established under Norwegian laws.
In accordance with the Norwegian Accounting Act, section 3-3b, Det norske includes a description of principles for corporate governance as part of the Board of Directors' Report in the annual report or alternatively makes a reference to where this information can be found.
The Norwegian Corporate Governance Board (NCGB) has issued the Norwegian Code of Practice for Corporate Governance ("the Code"). The Code can be found on www.ncgb.no. Adherence to the Code is based on the "comply or explain" principle, which means that a company must comply with all the recommendations of the Code or explain why it has chosen an alternative approach to specific recommendations.
Oslo Børs requires listed companies to publish an annual statement of their policy on corporate governance in accordance with the Code in force at the time. Continuing obligations for companies listed at Oslo Børs is available at www.oslobors.no.
Det norske complies with the above-mentioned rules and regulations. Det norske complies with the current edition of the Code, issued on 30 October 2014, unless otherwise specifically stated. The following statement on corporate governance is structured the same way as the Code, thus following the 15 chapters included in the Code.
The company has adopted a Code of Ethics to ensure that employees, hired personnel, consultants and others acting on behalf of Det norske, do so in a consistent manner with respect to ethics and good business practice. The Code of Ethics clarifies the company's fundamental ethical values and is a guideline for those making decisions on behalf of the company.
Corporate social responsibility is consistent with the Code of Ethics, which is established as principles for how the company and its employees shall act in relation to others.
The company shall demonstrate responsibility through actions, the quality of its work, the projects and products and all its activities. The company's ambition is that business activities shall integrate social, ethical and environmental goals and measures. As a minimum, Det norske will comply with laws, regulations and conventions in the areas where the company operates, but the established set of ethical guidelines extends beyond compliance. Established procurement procedures secure non-discrimination and transparency in the procurement processes. It is also stated in the Code of Ethics that any form of corruption is not tolerated.
In addition, the company has a sponsorship programme to promote the company and its activities. Guidelines for the use of sponsorships are included in the Code of Ethics. Det norske supports measures that are directly related to the company's business as an oil company, measures that provide significant exposure and measures that can be for the benefit of the employees. Ongoing sponsorships are available on the website: http://www.detnor.no/en/about-det-norske/sponsorship.
In general, the company shall achieve its goals in accordance with the adopted Code of Ethics, which are available on the website http://www.detnor.no/en/samfunnsansvar/sponsorater.
According to Det norske's Articles of Association article 3, its objective is "to carry out exploration for and recovery of petroleum and activities related thereto, and, by subscribing for shares or by other means, to participate in corresponding businesses or other business, alone or in cooperation with other enterprises and interests".
The vision for Det norske is "Always moving forward to create value on the Norwegian shelf". The following values are adopted by the company:
Through an annual strategy process, the Board defines and evaluates the company's goals. Together with the company's financial status, these goals are communicated to the market.
It is Det norske's goal to build up a substantial and profitable oil and gas production over time. In order to achieve this goal, the company will take part in exploration, development and production activities and be opportunistic in its approach to buying and selling interests in fields and discoveries.
On October 15, 2014, Det norske finalized the acquisition of Marathon Oil Norge AS. Following this acquisition, Det norske became a large and robust E&P company with close to 500 employees and activities through the exploration, development and production cycle. Measured by production, Det norske is among the leading listed independent European E&P compa-
Det norske oljeselskap ASA ('Det norske') aims to ensure the greatest possible value creation to the shareholders and society over time in a safe and prudent manner. A good management and control model with a clear division of responsibility and roles between the owners, represented by the shareholders in the general meeting, the Board of Directors and the corporate management is crucial to achieve this.
nies. New management systems as well as a new IT structure has been established and changes to the executive management team took effect from October 15. From the date of entering into the agreement, the two companies have successfully completed an ambitious integration process in just four and a half months.
There are risks associated with Det norske's oil and gas operations. Efficient operations, executed in a manner ensuring that we avoid harm and injuries to personnel, the environment and financial assets, is the company's number one priority.
Further information about the Articles of Association is available at: http://www.detnor.no/en/investors/corporate-governance/ articles-of-association
Further information about licences and activities is available at http://www.detnor.no/en/our-assets/portfolio
The Board seeks to optimize the capital structure by balancing risk, return on equity against lenders' security and liquidity requirements. The company aims to have a good reputation in all debt and equity markets. The Board continuously evaluates the company's capital structure, ensuring an optimal and diversified capital structure is a key priority to the Board. This involves monitoring available funding sources and related cost of capital.
Future developments will require substantial investments. Therefore, dividends to shareholders will not be given priority in the short term. In the current period, the Board's priority is rather to create value for shareholders by identifying the licence portfolio's underlying values, by maturing existing discoveries and development projects towards production, in addition to ensuring continued high production and cash flow.
At year-end 2014, the company's book equity was USD 652 million, which represents 12 per cent of the balance sheet total of USD 5,384 million. In the third quarter 2014, the company strengthened its equity by issuing 61.9 million new shares through a rights issue. All shareholders received tradable subscription rights ensuring equal treatment.
The financial liquidity is considered to be good. At 31 December 2014, the company's cash and cash equivalents were USD 296 million. In addition, available undrawn amount on credit facilities were about USD 600 million. In April 2014, the Annual General Meeting (AGM) authorized the Board to increase the share capital by a maximum of NOK 14,070,730, representing up to 10 per cent of the outstanding share capital at the time of the meeting. The mandate was sought with the aim to strengthen the company's equity. As of 31 December 2014, the mandate had not been used.
The general meeting in April 2014 provided the Board a mandate to re-purchase company shares equivalent to up to 10 per cent of the total share capital. The mandate is valid until the ordinary general meeting in 2015. As of 31 December 2014, the mandate has not been used.
Det norske is committed to equal treatment of all shareholders. The company faces a significant financing need to support the development plans in the years to come. When the company considers it to be in the best interest of shareholders to issue new equity there is a clear objective to limit the level of dilution. Det norske will carefully consider alternative financing options, its overall capital structure, the purpose and need for new equity, the timing of such an offering, the offer share price, the financial market conditions and the need for compensating existing shareholders in the event that pre-emption rights are waived. Arguments for waiving pre-emption rights will be clearly stated.
The company has one class of shares, and all shares carry the same rights.
As per 31 December 2014, Aker Capital AS owned 49.99 per cent of Det norske. Aker Capital AS is a wholly-owned subsidiary of Aker ASA. From the fiscal year 2011, Det norske oljeselskap ASA's accounts are consolidated in Aker ASA's accounts.
The Board is of the view that it is positive for Det norske that Aker ASA assumes the role of an active owner and is actively involved in matters of major importance to Det norske and to all shareholders. The cooperation with Aker ASA offers Det norske access to special know-how and resources within strategy, transactions and funding. Moreover, Aker ASA offers network and negotiation resources from which Det norske benefits in various contexts. This complements and strengthens Det norske without curtailing the autonomy of the company. It may be necessary to offer Aker ASA special access to commercial information in connection with such cooperation. Any information disclosed to Aker ASA's representatives in such a context will be disclosed in compliance with the laws and regulations governing the stock exchange and the securities market.
Applicable accounting standards and regulations require Aker ASA to prepare its consolidated financial statements to include accounting information of Det norske oljeselskap. Det norske is considered a subsidiary of Aker ASA under the applicable accounting standard. In order to comply with these accounting standards, Aker ASA has in the past received, and will going forward receive, unpublished accounting information of Det norske. Such distribution of unpublished accounting information from Det norske to Aker ASA is executed under strict confidentiality and in accordance with applicable regulations on handling of inside information.
The Board recognizes Aker Capital AS's contribution as an active shareholder. Investor communication seeks to ensure that any shareholders are able to contribute, and management will actively seek the views of shareholders. Investor activities are also directed at promoting higher stock liquidity to balance a shareholder structure with many long-term investors.
Det norske has established procedures to ensure that agreements with Aker-controlled companies and other related parties shall be premised on commercial terms and are entered into on an arm's-length basis. The transactions with Aker controlled companies are described in the financial statements' disclosure about transactions with related parties.
In the event that the Board decides to use its current authorization to re-purchase company shares, the transactions will be carried out through the stock exchange or at prevailing stock exchange prices if carried out in any other way.
The company's employees are prohibited from engaging in financial activities of a potentially competitive nature in relation to Det norske. The company's Code of Ethics provides clear guidelines as to how employees and representatives of the company's governing bodies should act in situations where there is a risk of conflicts of interest and partiality.
Det norske's shares are freely negotiable securities, and the company's Articles of Association do not impose any form of restriction on their negotiability.
The company's shares are listed on the Oslo Børs and the company works actively to attract the interest of new shareholders, both Norwegian and foreign investors. Strong liquidity in the company's shares is essential if the company is to be viewed as an attractive investment and thus achieve a low cost of capital.
The Annual General Meeting ('AGM') of Det norske The AGM is the company's highest authority. The Board strives to ensure that the AGM is an effective forum for communication between the shareholders and the Board, and encourages shareholders to participate in the meeting.
The Board can convene an extraordinary general meeting at any time. A shareholder or a group holding at least five per cent of the company's shares, can request an extraordinary general meeting. The Board is then obliged to hold the meeting within one month of receiving the request.
The AGM is normally held before the end of April each year, and no later than the end of June, which is the latest date permitted by the Companies Act. The AGM will be held on 13 April 2015. The date of the next AGM is normally included in the financial calendar.
The notice is sent to the shareholders and published on the company's website and the stock exchange no later than 21 days before the AGM.
Article 7 in the company's Articles of Association, about the general meeting, stipulates that documents concerning matters to be considered by the AGM, will be made available to the shareholders on the company's website. This also applies to documents that are required by law to be included in or enclosed with the notice of the AGM.
The supporting documentation provides the necessary information for shareholders to form a view on the matters to be considered.
According to Article 7 in the Articles of Association, the right to attend and vote at the general meeting can only be exercised when the share transaction is introduced in the shareholder register no later than the fifth business day prior to the general meeting (registration date).
Shareholders who are unable to attend the AGM are encouraged to vote by proxy. A form for the appointment of a proxy, which allows separate voting instructions to be given for each matter to be considered by the meeting are included in the notice. The deadline for registration is set as close as possible to the date of the meeting, normally the day before.
The Board proposes the agenda for the AGM. The main agenda items are determined by the requirements of the Public Limited Liability Companies Act and Article 7 in the company's Articles of Association.
At the meeting in April 2015, the Board will nominate an independent person who can vote on behalf of the shareholders as their authorized representative. The Board may decide that it shall be possible for shareholders to cast their votes in writing, including by means of electronic communication, in a given period prior to the general meeting. Satisfactory methods shall be used in order to authenticate the sender. Appropriate arrangements are made for shareholders to vote separately on candidates nominated for election to the company's corporate bodies.
Det norske's general meetings are normally chaired by the Chair of the Board, or a person appointed by the Chair of the Board. The code stipulates that the Board should have arrangements to ensure an independent chairman for the AGM, and the company will seek to adhere to this going forward.
The Code of Practice states that it is appropriate that all members of the Board should attend general meetings. Representatives from the Board, the nomination committee, the auditor and the executive management will attend the AGM. However, given the geographic distribution of the people, it is normal that only a few representatives from each of these bodies attend the AGM.
Minutes of the meeting are published on the company's website and through a stock exchange announcement.
Article 8 in the company's Articles of Association stipulates that the nomination committee shall consist of three members elected by the AGM. It also stipulates that the majority of the members shall be independent of the Board and the executive management and that the members shall be elected for a period of two years at a time. The committee's remuneration is determined by the AGM.
At the AGM in April 2013, Kjetil Kristiansen was elected as the Chair of the nomination committee. Finn Haugan and Hilde Myrberg were elected as members at the AGM in 2012 and re-elected at the AGM in 2014.
Committee member Kjetil Kristiansen is from 1.8.14 the SVP HR in Det norske. He previously held the same position in Aker ASA. Kjetil Kristiansen thus has a conflict of interest and will step down as Chair of the nomination committee at the next AGM. The other two members of the nomination committee are independent of the company's Board and its executive personnel.
The nomination committee should be composed in such a way that it represents a wide range of shareholders' interests. It should also be strived for both genders being represented in the committee. The nomination committee's duties are also stated by Article 8 in the Articles of Association. The committee shall propose candidates for - and remuneration to - the Board of Directors and the nomination committee. The committee's recommendation shall be well-grounded.
For its 2015 work, the nomination committee aims to publish on the company's website a request for submitting proposals regarding candidates to the Board of Directors, as well as sending out letters to the company's largest shareholders inviting them to provide input or suggestions.
Having passed 200 employees, Det norske established a corporate assembly at the AGM in 2013. The Corporate Assembly consists of twelve members, with eight members elected by the General Assembly and four elected by and among the employees. It pertains to the Corporate Assembly to elect directors and the Chairman of the Board. In addition, the Corporate Assembly shall supervise the Board of Director's and general manager's administration of the company.
The Board of Det norske consisted of ten members as of 31 December 2014. The company's Articles of Associations, Article 5, stipulates that the Board shall consist of between five and ten members and the members shall be elected for a period of up to two years.
Among the shareholder-elected board members, one (Kjell Inge Røkke) is affiliated with the company's largest shareholder Aker Capital AS. All other board members are considered independent of the company's main shareholder, as well as of the company's material business contacts. All board members are considered independent of the company's executive personnel.
The Board composition ensures alignment of interests with all shareholders and members of the board are encouraged to own shares in the company. It is the Board's view that the Board collectively meets the need for expertise, capacity and diversity. Board members possess strong experience from banking and finance, oil and offshore in general, and reservoir engineering, exploration and field development in particular.
An overview of the expertise of the board members is available on the website:
http://www.detnor.no/om-oss/styret/?lang=en
The Board has authority over and is responsible for supervising the company's business operations and management. The Board's objectives are to create value for the company's shareholders in both the short and long term and to ensure that Det norske fulfils its obligations at all times. While the CEO is responsible for the day-to-day management of the company's business activities, the Board acknowledges its responsibility for the overall management of the company. The Board is actively involved in:
B. Identifying significant risks to Det norske's activities and establishing appropriate systems to monitor and manage such risks,
C. Ensuring that shareholders have access to timely and correct information about financial circumstances and important business-related events in accordance with relevant legislation, and
In 2014, the Board has conducted a total of 16 board meetings, including a strategy meeting.
The Board recognizes the significant risks associated with the operations and in particular the transition period the company is in. Consequently, the Board has dedicated significant resources and time to understand and discuss not only general risks facing an E&P company, but also inherent risks connected to organization, culture and leadership. For a company like Det norske, the Board views the risks in taking on an operated development project like Ivar Aasen and meeting the required financing for its entire portfolio as well as taking on the Alvheim operations, to be among the most significant risks. Accordingly, this is where the mitigating efforts are concentrated.
The Board members contribute with extensive experience, knowledge and capabilities for the benefit of the company. Through regular meetings with the executive management, the Board is kept up-to-date about the company's development and performance. The division of roles between the Board and the company's management is clearly defined in the instructions for the Board and in the instructions for the CEO, with specific areas of responsibility and administrative procedures. The AGM elects the Chair of the Board. Det norske's Board appoints its own Deputy Chair. This person takes over the tasks of the chair when the latter cannot direct the Board's work.
Considering the size of the company and the scope of its activities, the Board finds it appropriate to keep all board members informed about all board matters, except for cases where board members may have conflicting interests with the company. The board members have attended all the meetings in 2014, with the following exceptions; five meetings had one member absent, two meetings had two members absent. The absence has been distributed among several board members.
The Board carried out a formal evaluation of its own performance for 2014, as recommended by the Code, and took note of the findings.
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The Board has established an audit committee consisting of the following board members:
All members are independent of Aker and the company's executive management.
The chair of the audit committee is considered to have experience and formal background qualifying as "financial expert" according to the requirement stated in the Public Limited Liability Company Act. Jørgen C Arentz Rostrup has been the Chief Financial Officer of Norsk Hydro ASA and served as a member of the corporate management in said company until March 2013. The audit committee holds regular meetings and reviews the quality of all interim and annual reports before they are reviewed by the Board of Directors and then published. In 2014, the committee held seven meetings. The company's auditor works closely with the audit committee on a regular basis. The committee is also involved in the company's financial risk management. The management and the audit committee evaluate the risk management on financial reporting and the effectiveness of established internal controls. Identified risks and effects of financial reporting are discussed on a quarterly basis.
All meetings in conjunction with quarterly reporting and accounts have taken place together with the company's auditor. It is the view of the audit committee that the cooperation with the auditor and management is good. The audit committee has worked together with management and auditor to improve the internal control environment according to the COSO (Committee of Sponsoring Organizations of the Treadway Commission) framework over the last years. The committee has also worked through accounting issues arising from the combination of Det norske and Marathon Oil Norge AS well as financial reporting improvements. In evaluating the performance for the year 2014, the committee is pleased to observe progress on the selected issues identified as priorities for the year. These are primarily connected to the financial statement closing process and enhanced documentation of procedures related to internal control of financial reporting.
Also, the Board has a remuneration committee consisting of the following three board members:
The remuneration committee is established to ensure that remuneration arrangements support the strategy of the business and enable the recruitment, motivation and retention of senior executives while complying with the requirements of regulatory and governance bodies, satisfying the expectations of shareholders and remaining consistent with the expectations of the wider employee population.
In addition to the audit committee and remuneration committee, the Board appoints various ad hoc sub-committees when required, with a limited timeframe and scope. The ad hoc sub-committees in 2014 were established to support management in key areas such as financing and Johan Sverdrup unitization negotiations.
Good internal control and risk management contributes to the transparency and quality reporting for the benefit of the company and the shareholders' long-term interests. The company works continuously and systematically with risk management, both at the overall company level as well as on the operational level. Det norske's operational activities are limited to Norway and are subject to Norwegian regulations. All activities taking place in a production licence are subject to audits from authorities, such as the Petroleum Safety Authority Norway, the Norwegian Environment Agency, as well as licence partners.
During 2014, Det norske participated in financial audit in 16 licence partnerships, while the company received audits on two of its operated licences, in addition to one well operated on behalf of others. Furthermore, several reports were purchased from financial audits in partner-operated licences. In addition to these financial audits, there were audits from authorities and licence partners on Det norske's management system and the planning and execution of our drilling operations and development projects. These audits, from external parties, contribute to the quality control of the company's internal systems. They are also valuable in the work to identify risks and weaknesses, To further ensure that Det norske's management system is in alignment with laws, regulations, standards and best practice within the industry, Det norske has identified specific areas for further improvements in 2015. These processes are stated in the company's HSEQ plan for 2015.
The Ivar Aasen project has established specific project control and risk management routines and procedures in line with industry practice of executing field development projects on the NCS. Internal audits and verifications at company level are included in the annual HSEQ plan. In addition, the Ivar Aasen project has a significant monitoring activity, including audits and quality follow-up of contractors, as an integral part of the project execution plan.
and in this way assist the company in its continuous work to improve the management system. of risks, opportunities and threats, and outlines how these shall be monitored and governed.
A significant portion of the company's production comes from the Greater Alvheim Area as production from Alvheim fields amounted to about 96 per cent of Det norske's total production for the year ended 31 December 31 2014. The company is especially sensitive to any shutdown or other technical issues on the Alvheim FPSO due to the fact that all of the Alvheim Area fields are produced via the Alvheim FPSO vessel. For that reason, Det norske has entered into a "Loss of Production" insurance, reducing the impact of any shutdown on the Alvheim FPSO. During an annual strategy meeting in 2014 the Board reviewed its risk management strategy, including how this is implemented throughout the company's activities. The Board considers risk in the context of growing a sustainable organization while meeting the highest levels of governance, safety and accountability sought by all of its stakeholders.
Det norske's internal procedures provide a good basis for monitoring and managing the company's activities.
The management system consists of four levels, which cover all important activity areas. The top level includes a description of the company's vision, the management system and the management's responsibilities. Governing documents and policies are at level two, procedures at level three, while guidelines and support documents are included in level four.
Key policy documents for risk management, internal control and financial reporting are included at level two and three. The company's risk management process covers a wide range The company's risk response includes monitoring of developing risks through constant analysis and engagement with operational management. It also includes, when appropriate, consultation with external advisors in order to mitigate risk to as great an extent as possible.
Det norske has established a framework for Internal Control for Financial Reporting based on COSO (Committee of Sponsoring Organizations of the Treadway Commission) and is operationalized as follows:
The established framework is an integrated part of the company's management system. The company's internal control environment is characterized by clearly defined responsibilities and roles between the Board of Directors, audit committee and management. The implemented procedure for financial reporting is integrated with the company's management system, including ethical guidelines that describe how the representatives of the company must act.
The company has established processes, procedures and controls for financial reporting, which are appropriate for an exploration and production company. The company's documented procedures enable:
A risk assessment related to financial reporting is performed and documented by the management. Risk assessments are monitored by the audit committee on a quarterly basis as part of the quarterly reporting process. The Board of Directors ap-
proves the overall risk assessment related to financial reporting on an annual basis. In 2014, the following main risk areas were identified related to financial reporting:
The company seeks to communicate transparently on its activities and its financial reporting is made after significant interaction with management responsible for exploration, development and production activities in the business. The audit committee meets to review the financial statements, with the auditor present, each quarter prior to the submission of the financial statements to the Board for approval.
Key events that may affect the financial reporting are identified and monitored continuously. An "Issue list" is established to address possible accounting and tax effects of events and activities. Both the auditor and the audit committee review the "Issue list" on a quarterly basis.
The Finance Department monitors the compliance with established procedures and reports any material deviations to the audit committee. It also identifies actions to improve procedures and conducts a self-assessment of its performance against objectives, which are then presented and discussed with the audit committee. The self-assessment of internal control for financial reporting carried out in 2014 has identified strengths, weaknesses, opportunities and threats. 2014 has been a transitional year due to the acquisition of Marathon Oil Norge AS. Goals for 2015 thus include implementing one common accounting system and fully integrate the previous Marathon Oil Norge AS system with that of Det norske and maintain the best of internal control environments from both companies.
In 2015, further improvements related to internal control will be conducted.
The remuneration of the board members is not performance-based, but based on a fixed annual fee with pro-rata reduction for absence from meetings. None of the shareholder-elected board members have pension schemes or termination payment agreements with the company. Information about all remuneration paid to individual board members is provided in Note 8 to the annual accounts.
The nomination committee proposes the remuneration of the Board and ensures that it is proportionate to the responsibility of its members and the time spent on board work. The Board must approve any board member's consultancy work for the company and remuneration for such work. No such work was carried out during 2014.
The Board stipulates the Chief Executive Officer's remuneration and other terms and conditions of employment. Note 9 to the annual accounts contain details about the remuneration of the Board and executive management, including payroll, bonus payments and pension expenses.
For 2014, the company had a bonus scheme based on company-wide performance and is capped at 20 per cent of the annual salary. The annual bonus is at the Board's discretion and applies to all company employees except executive management. All employees received the same percentage in bonus relative to his or her salary. The Code stipulates that bonus arrangements should incentivize performance and be based on quantifiable factors over which the employee in question can have influence. For 2014, the Board decided on a 16.5 per cent bonus based on an overall assessment of the company's performance. In addition to the performance bonus, the company had share savings program in 2014, which was terminated in 2015. The company's pension plan was changed from a defined benefit plan to a defined contribution plan, effective from 15 October 2014. This pension scheme is capped at 12G for all employees, including the executive management. Employees coming into the company through the Marathon Oil Norge AS acquisition retained their original bonus scheme throughout 2014. This bonus scheme was based on key performance indicators (KPIs) both on company, business unit and individual level with a bonus potential ranging from 6 to 80 per cent of annual base salary.
The executive management had a bonus scheme based on company-wide as well as individual performance, with a payment potential ranging from 40 to 100 per cent of base salary. The CEO had a similar bonus scheme with a payment potential of up to 100 per cent of base salary. The CEO is in addition to this on a long-term bonus programme linked to the performance of Det norske shares.
Following the integration with Marathon Oil Norge AS, certain changes have been made to remuneration in the company. The bonus for all employees except executive management is capped at two months' salary. Total bonus level is determined by a combination of company-wide key performance indicators (KPIs) (50 per cent) and KPIs specific to each employee's business unit (50 per cent). Members of executive management have individual KPIs to determine a maximum bonus potential varying from 40 per cent to 100 per cent of their base salary. Members of executive management with responsibilities relating to operations, plus the CFO participate in a three-year incentive program linked to the relative performance of the Det norske share price versus the OBX index. The pension scheme continued to be a defined contribution plan capped at 12G for all employees including the executive management.
Det norske maintains a proactive dialogue with analysts, investors and other stakeholders of the company. The company strives to continuously publish relevant information to the market in a timely, effective and non-discriminatory manner, and has a clear goal to attract both Norwegian and foreign investors and to promote higher stock liquidity.
The Board also recognizes the challenges related to estimating the underlying values in the company. The investor communication seeks to provide a balanced picture of the risks and opportunities related to the company's assets.
All stock exchange announcements are made available on the Oslo Børs website, www.newsweb.no, as well as the company's website (www.detnor.no) at the same time. The announcements are also distributed to news agencies and other online services through Cision.
Det norske publishes its preliminary annual accounts by the end of February, as part of its fourth quarter report. The complete annual report, including approved and audited accounts and the Board of Directors' Report, is available no later than three weeks before the AGM. Information sent to shareholders is published on the web site simultaneously.
The company's financial calendar for the coming year is published as a stock exchange announcement and made available on the company's website no later than 31 December each year, in accordance with the continuing obligations for companies listed at the Oslo Børs.
Det norske holds open presentations in connection with the publication of the company's quarterly results. The presentations are webcasted for the benefit of investors who are prevented from attending or do not wish to attend the presentations. At the presentations, the executive management review and comment on the published results, market conditions and the company's future activities.
The company's management gives high priority to communication with the investor market. Individual meetings are organized for a wide range of existing and potential new investors and analysts. The company also attends relevant industry and investor conferences.
Det norske will reduce its contacts with analysts, investors and journalists in the final two weeks before publication of its results. During this period, the company will limit meetings with investors or analysts, and will give no comments to the media or other parties about the company's results and future outlook. This is to ensure that all interested parties in the market are treated equally.
The company's objective is to create value for its shareholders. Any invitations or initiatives to participate in structural changes will be evaluated on the basis of this objective. The Board has
not established a separate set of guidelines for how it will act in the event of a takeover bid, as recommended by the Code. The Board will, as a main rule, follow the recommendations issued by the Code related to take-overs.
The Board of Directors is committed to equal treatment of all shareholders and will ensure openness with respect to any potential takeover of the company. Also, the Board will do its utmost to ensure that the shareholders are given sufficient information and time to form a view of the offer.
The Board will not, except on special grounds, seek to prevent or obstruct bids for the company's shares or individual business areas. In the event of a takeover bid, the Board will issue a statement evaluating the offer and making a recommendation as to whether or not the shareholders should or should not accept the offer. The Board's statement will state whether the views included are unanimous or not.
KPMG AS was elected new auditor of Det norske at the AGM in May 2014, replacing Ernst & Young.
The AGM elects the auditor and approves the auditor's fee. The Board of Directors will meet with the auditor regularly without representatives of the company management being present, to review internal control procedures and discuss any weaknesses and proposals for improvement. The auditor participates in board meetings to discuss the annual accounts.
The auditor participates in all meetings with the audit committee and meets the audit committee without the company's management being present. The auditor submits the main features of the plan for the annual audit of the company to the audit committee annually. The auditor's independence in relation to the company is evaluated annually. The auditor carries out certain consultancy services for the company, which is viewed not to be in conflict with its duties as auditor. The company has not established a policy for the use of the auditor for assignments not included in the statutory audit, but this is on the agenda for 2015.
This report is prepared in accordance with the Norwegian Accounting Act § 3-3 d), which is a new requirement applicable from the fiscal year 2014. It states that companies engaged in activities within the extractive industries shall annually prepare and publish a report containing information about their payments to governments at country and project level. The Ministry of Finance has issued a regulation (F20.12.2013 nr 1682 – "the regulation") stipulating that the reporting obligation only apply to reporting entities above a certain size and to payments above certain threshold amounts. In addition, the regulation stipulates that the report shall include other information than payments to governments, and provides more detailed rules with regard to definitions, publication and group reporting.
This report contains information for the activity in the whole fiscal year 2014 for Det norske oljeselskap AS (previously Marathon Oil Norge AS), including the period before it became a part of the Det norske group.
The management of Det norske has applied judgment in interpretation of the wording in the regulation with regard to the specific type of payment to be included in this report, and on what level it should be reported. When payments are required to be reported on a project-by-project basis, it is reported on a field-by-field basis. Only gross amounts on operated licences are reported, as all payments within the licence performed by none operators, normally will be cash calls transferred to the operator and will as such not be payments to the government. Since Det norske has no activities within the extractive industries outside the Norwegian Continental Shelf, only payments to the Norwegian government is deemed to be within the scope of this reporting.
The regulation § 2 no.5 defines the different types of payments subject to reporting. In the following sections, only those applicable to Det norske will be described.
The income tax is calculated and paid on corporate level and is therefore reported for the whole company rather than licence by licence. As described in the tax note (Note 12 to the financial statements), Det norske oljeselskap AS (previously Marathon Oil Norge AS) was consolidated for tax purposes from 1 January 2014. The tax payments performed in 2014 is partly related to income tax 2013 (last three instalments) and to income tax for 2014 (first three instalments), as well as some minor settlements related to previous years. Total tax payments were NOK 8 676 306 328. In addition, interests on tax payments amounted to NOK 17 710 970.
CO2 tax is to some extent included in the fuel price/rig rental paid to external rig companies. Of the operated licences, Det norske has only paid CO2 tax on the Alvheim field. This includes the fields tied in to the Alvheim FPSO (Vilje, Volund and Bøyla) as Alvheim performs the payment and charges the other fields via opex share. The CO2 tax paid on behalf of the Alvheim licence in 2014 amounted to NOK 71 476 536.
The company is a member of the NOX fund and all NOX payments are made to this fund rather than to the government.
The table below specifies the area fee paid by Det norske on behalf of the different licences in 2014:
| Name of field/licence | Area fee paid in 2014 (NOK) |
|---|---|
| Alvheim | 10 960 000 |
| Volund | 1 781 000 |
| Bøyla | 4 278 904 |
| Vilje | 760 000 |
| Ivar Aasen | 1 920 000 |
| PL 001B | 1 357 151 |
| PL 026B | 680 000 |
| PL 027D | 175 624 |
| PL 027ES | 2 144 376 |
| PL 028B | 1 200 000 |
| PL 103B | 1 370 000 |
| PL 242 | 2 877 000 |
| PL 364 | 4 384 000 |
| PL 460 | 6 439 000 |
| PL 504 | 685 310 |
| PL 504 BS | 170 000 |
| PL 504CS | 408 000 |
| PL 553 | 7 005 677 |
| Total | 48 596 042 |
In addition, Det norske paid NOK 14 728 in interest related to area fee payments in 2014.
When companies are required to report payments as the above, it is also mandatory to report on investments, sales income, production volumes and purchases of goods and services in the country of which companies have activities within the extractive industries. As mentioned above, Det norske operates on the Norwegian Continental Shelf only. This reporting requirement is therefore deemed to be met by the financial statements as specified below:
Since the information above is linked directly to the figures in the financial statements, the information is this section does not include the activity in Det norske oljeselskap AS (previously Marathon Oil Norge AS) before the acquisition date, i.e. 15 October 2014.
| Group | Parent company | |||||
|---|---|---|---|---|---|---|
| 1 January - 31 December (USD 1 000) | Note | 2014 | 2013 | 2014 | 2013 | |
| Petroleum revenues | 411 996 | 158 782 | 325 034 | 158 782 | ||
| Other operating revenues | 52 235 | 1 824 | 52 206 | 1 824 | ||
| Total operating revenues | 8 | 464 230 | 160 606 | 377 241 | 160 606 | |
| Exploration expenses | 6 | 157 578 | 278 554 | 157 497 | 278 554 | |
| Production costs | 8 | 66 754 | 42 474 | 59 173 | 42 474 | |
| Payroll expenses | 9 | -17 042 | 6 470 | -1 987 | 6 470 | |
| Depreciations and amortization | 14 | 160 254 | 80 063 | 142 562 | 80 063 | |
| Impairments | 15 | 346 420 | 113 346 | 346 420 | 113 346 | |
| Other operating expenses | 10 | 49 193 | 18 698 | 49 826 | 18 698 | |
| Total operating expenses | 763 157 | 539 605 | 753 491 | 539 605 | ||
| Operating profit/loss | -298 927 | -378 999 | -376 251 | -378 999 | ||
| Interest income | 7 009 | 6 934 | 7 003 | 6 934 | ||
| Other financial income | 19 435 | 168 | 22 899 | 168 | ||
| Interest expenses | 83 845 | 51 359 | 82 898 | 51 359 | ||
| Other financial expenses | 19 296 | 9 844 | 10 428 | 9 844 | ||
| Net financial items | 11 | -76 697 | -54 101 | -63 423 | -54 101 | |
| Loss before taxes | -375 624 | -433 100 | -439 674 | -433 100 | ||
| Taxes (+)/tax income (-) | 12 | -96 485 | -339 753 | -160 535 | -339 753 | |
| Net profit/loss | -279 139 | -93 347 | -279 139 | -93 347 | ||
| Weighted average no. of shares outstanding and fully diluted | 165 811 098 | 140 707 363 |
Weighted average no. of shares outstanding and fully diluted 165 811 098 140 707 363 Loss after taxes per share (in USD) 13 -1.68 -0.66
| Group | Parent company | ||||
|---|---|---|---|---|---|
| 1 January - 31 December (USD 1 000) | Note | 2014 | 2013 | 2014 | 2013 |
| Profit/loss for the period | -279 139 | -93 347 | -279 139 | -93 347 | |
| Items which will not be | |||||
| reclassified over profit and loss (net of taxes): | |||||
| Exchange differences on translation to USD | -43 069 | -53 906 | -43 069 | -53 906 | |
| Actuarial gain/loss pension plan | 22 | -897 | 152 | -897 | 152 |
| Total comprehensive income in period, attributable to | |||||
| equity holders of the parent company | -323 105 | -147 101 | -323 105 | -147 101 |
| OVERVIEW OF THE FINANCIAL STATEMENTS AND NOTES | PAGE |
|---|---|
| Income statement | 85 |
| Statement of comprehensive income | 85 |
| Statement of financial position | 86 |
| Statement of changes in equity | 88 |
| Statement of cash flow | 89 |
| Note 1: Summary of IFRS accounting principles | 90 |
| Note 2: Major transactions and key events | 102 |
| Note 3: Acquisition of Marathon Oil Norge AS | 103 |
| Note 4: Overview of subsidiaries | 105 |
| Note 5: Segment information | 105 |
| Note 6: Exploration expenses | 106 |
| Note 7: Inventories | 106 |
| Note 8: Petroleum revenues | 106 |
| Note 9: Remuneration and guidelines for remuneration of senior executives | |
| and the board of directors, and total payroll expenses | 107 |
| Note 10: Other operating expenses | 109 |
| Note 11: Financial items | 110 |
| Note 12: Tax | 111 |
| Note 13: Earnings per share | 113 |
| Note 14: Tangible fixed assets and intangible assets | 113 |
| Note 15: Impairments | 116 |
| Note 16: Accounts receivable | 120 |
| Note 17: Other short-term receivables | 120 |
| Note 18: Long-term receivables | 121 |
| Note 19: Other non-current assets | 121 |
| Note 20: Cash and cash equivalents | 121 |
| Note 21: Share capital and shareholders | 122 |
| Note 22: Pensions and other long-term employee benefits | 123 |
| Note 23: Provision for abandonment liabilities | 125 |
| Note 24: Derivatives | 125 |
| Note 25: Bonds | 125 |
| Note 26: Interest-bearing loans and assets pledged as security | 126 |
| Note 27: Other current liabilities | 127 |
| Note 28: Liabilities, lease agreements and guarantees | 127 |
| Note 29: Transactions with related parties | 129 |
| Note 30: Financial instruments | 130 |
| Note 31: Investments in joint operations | 136 |
| Note 32: Classification of reserves and contingent resources (unaudited) | 137 |
| Note 33: Events after the balance sheet date | 139 |
| Statement from the board of directors and the chief executive officer | 139 |
| Group | Parent company | |||||
|---|---|---|---|---|---|---|
| (USD 1 000) | Note 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | ||
| ASSETS | ||||||
| Intangible assets | ||||||
| Goodwill | 14,15 | 1 186 704 | 52 784 | 1 186 704 | 52 784 | |
| Capitalized exploration expenditures | 14,15 | 291 619 | 337 969 | 291 619 | 337 969 | |
| Other intangible assets | 14,15 | 648 788 | 106 235 | 648 788 | 106 235 | |
| Deferred tax asset | 12 | 103 625 | 103 625 | |||
| Tangible fixed assets | ||||||
| Property, plant and equipment | 14,15 | 2 549 271 | 436 834 | 2 549 271 | 436 834 | |
| Financial assets | ||||||
| Long-term receivables | 18 | 8 799 | 20 618 | 8 799 | 20 618 | |
| Other non-current assets | 19 | 3 598 | 46 912 | 4 619 | 46 912 | |
| Total non-current assets | 4 688 778 | 1 104 976 | 4 689 799 | 1 104 976 | ||
| Inventories | ||||||
| Inventories | 7 | 25 008 | 6 720 | 25 008 | 6 720 | |
| Receivables | ||||||
| Accounts receivable | 16 | 186 461 | 22 062 | 186 461 | 22 062 | |
| Other short-term receivables | 17 | 184 592 | 82 091 | 184 592 | 82 091 | |
| Other current financial assets | 3 289 | 3 957 | 3 289 | 3 957 | ||
| Tax receivables | 12 | 231 972 | 231 972 | |||
| Cash and cash equivalents | ||||||
| Cash and cash equivalents | 20 | 296 244 | 280 942 | 295 222 | 280 942 | |
| Total current assets | 695 594 | 627 745 | 694 573 | 627 745 | ||
| TOTAL ASSETS | 5 384 372 | 1 732 720 | 5 384 372 | 1 732 720 |
Equity
| Group | Parent company | ||||
|---|---|---|---|---|---|
| (USD 1 000) | Note 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | |
| EQUITY AND LIABILITIES | |||||
| Equity | |||||
| Share capital | 21 | 37 530 | 27 656 | 37 530 | 27 656 |
| Share premium | 21 | 1 029 617 | 564 736 | 1 029 617 | 564 736 |
| Other equity | -415 485 | -68 292 | -415 485 | -68 292 | |
| Total equity | 651 662 | 524 100 | 651 662 | 524 100 | |
| Provision for liabilities | |||||
| Pension obligations | 22 | 2 021 | 10 933 | 2 021 | 10 933 |
| Deferred taxes | 12 | 1 286 357 | 1 286 357 | ||
| Abandonment provision | 23 | 483 323 | 136 188 | 483 323 | 136 188 |
| Provisions for other liabilities | 12 044 | 128 | 12 044 | 128 | |
| Non-current liabilities | |||||
| Bonds | 25 | 253 141 | 406 592 | 253 141 | 406 592 |
| Other interest-bearing debt | 26 | 2 037 299 | 334 814 | 2 037 299 | 334 814 |
| Long-term derivatives | 24 | 5 646 | 8 129 | 5 646 | 8 129 |
| Current liabilities | |||||
| Short-term loan | 78 579 | 78 579 | |||
| Trade creditors | 152 258 | 74 368 | 152 258 | 74 368 | |
| Social security and other indirect taxes | 6 758 | 3 876 | 6 758 | 3 876 | |
| Tax payable | 12 | 189 098 | 189 098 | ||
| Short-term derivatives | 24 | 25 224 | 25 224 | ||
| Abandonment provision | 23 | 5 728 | 24 225 | 5 728 | 24 225 |
| Other current liabilities | 27 | 273 813 | 130 789 | 273 813 | 130 789 |
| Total liabilities and provision for liabilities | 4 732 710 | 1 208 620 | 4 732 710 | 1 208 620 | |
| TOTAL EQUITY AND LIABILITIES | 5 384 372 | 1 732 720 | 5 384 372 | 1 732 720 |
Anne Marie Cannon, Deputy Chair Kjell Inge Røkke, Board member Kitty Hall (Katherine Jessie Martin), Board member Jørgen C. Arentz Rostrup, Board member
Sverre Skogen, Chair of the Board Tom Røtjer, Board member Gudmund Evju, Board member Inge Sundet, Board member The Board of Directors and the CEO of Det norske oljeselskap ASA
| 1 January - 31 December (USD 1 000) Note 2014 2013 2014 Cash flow from operating activities |
2013 -433 100 -4 524 224 337 |
|---|---|
| Profit/loss before taxes -375 624 -433 100 -439 674 |
|
| Taxes paid during the period -109 068 -4 524 -109 068 |
|
| Tax refund during the period 190 532 224 337 190 532 |
|
| Depreciation 14 160 254 80 063 142 562 |
80 063 |
| Net impairment losses 15 346 420 113 346 346 420 |
113 346 |
| Accretion expenses 23 12 410 7 277 11 462 |
7 277 |
| Gain/loss on licence swaps without cash effect -49 765 125 -49 765 |
125 |
| Changes in derivatives 11 10 616 540 993 |
540 |
| Amortization of interest expenses and arrangement fee 11 26 711 15 052 26 711 |
15 052 |
| Expensed capitalized dry wells 6 99 061 195 770 99 069 |
195 770 |
| Changes in inventories, accounts payable and receivables -530 150 24 126 -485 603 |
24 126 |
| Changes in abandonment liabilities -1 952 |
|
| Changes in other current balance sheet items 483 345 -67 200 487 562 |
-67 200 |
| NET CASH FLOW FROM OPERATING ACTIVITIES 262 791 155 812 221 201 |
155 812 |
| Cash flow from investment activities | |
| Payment for removal and decommissioning of oil fields 23 -14 087 -6 251 -13 968 |
-6 251 |
| Disbursements on investments in fixed assets 14 -583 200 -254 502 -559 443 |
-254 502 |
| Acquisition of Marathon Oil Norge AS (net of cash acquired) 3 -1 513 591 -1 496 890 |
|
| Disbursements on investments | |
| in capitalized exploration expenditures and other intangible assets 14 -164 128 -231 230 -164 136 |
-231 230 |
| Sale of tangible fixed assets and licences 14 8 862 14 714 8 862 |
14 714 |
| NET CASH FLOW FROM INVESTMENT ACTIVITIES -2 266 144 -477 270 -2 225 575 |
-477 270 |
| Cash flow from financing activities | |
| Net proceeds from equity issuance 474 755 474 755 |
|
| Repayment of short-term debt -162 434 -255 232 -162 434 |
-255 232 |
| Repayment of bond (detnor 01) -87 536 -87 536 |
|
| Repayment of long-term debt -1 147 934 -371 806 -1 147 934 |
-371 806 |
| Arrangement fee -67 350 -67 350 |
|
| Gross proceeds from issuance of long-term debt 2 897 354 804 713 2 897 354 |
804 713 |
| Proceeds from issuance of short-term debt 116 829 238 217 116 829 |
238 217 |
| NET CASH FLOW FROM FINANCING ACTIVITIES 2 023 684 415 892 2 023 684 |
415 892 |
| Net change in cash and cash equivalents 20 331 94 433 19 310 |
94 433 |
| Cash and cash equivalents at start of period 20 280 942 207 348 280 942 |
207 348 |
| Effect of exchange rate fluctuation on cash held -5 029 -20 839 -5 029 |
-20 839 |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD 296 244 280 942 295 222 |
280 942 |
| Specification of cash equivalents at end of period | |
| Bank deposits and cash 20 291 346 278 337 290 325 |
278 337 |
| Restricted bank deposits 20 4 897 2 605 4 897 |
2 605 |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD 20 296 244 280 942 295 222 |
280 942 |
| Other equity | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| Other equity Other comprehensive income Other comprehensive income |
|||||||||
| Foreign* | |||||||||
| Share | Share | Other paid-in | Actuarial | currency | Retained | Foreign* Total other |
|||
| Note | capital Note |
Share premium |
Share capital |
Other paid-in gains/(losses) |
Actuarial translation |
earnings | currency equity |
Total equity Retained Total other |
|
| (USD 1 000) | capital | premium | capital | gains/(losses) reserves |
translation | earnings | |||
| (USD 1 000) | reserves | ||||||||
| Equity as of 31.12.2012 | 25 278 | 555 034 | 646 757 | -393 | -555 474 | 90 889 | 671 201 | ||
| Translation difference due to change in Equity as of 31.12.2012 |
25 278 | 555 034 | 646 757 | -393 | -555 474 | ||||
| presentation currency to USD* | 2 378 | 9 702 | -73 674 | 18 | 5 573 | 56 004 | -12 080 | ||
| Translation difference due to change in | |||||||||
| presentation currency to USD* Equity as of 01.01.2013 |
27 656 | 2 378 564 736 |
9 702 573 083 |
-73 674 -375 |
5 573 | 18 -499 471 |
5 573 78 809 |
56 004 671 201 |
|
| Total loss for the period 1.1.2013 - 31.12.2013 Equity as of 01.01.2013 |
27 656 | 564 736 | 152 573 083 |
-53 906 -375 |
-93 347 | -147 101 5 573 |
-147 101 -499 471 |
||
| Equity as of 31.12.2013 | 27 656 | 564 736 | 573 083 | -223 | -48 334 | -592 818 | -68 292 | 524 100 | |
| Total loss for the period 1.1.2013 - 31.12.2013 | 152 | -53 906 | -93 347 | ||||||
| Rights issue | 9 874 | 469 249 | -24 350 | -24 350 | 454 773 | ||||
| Equity as of 31.12.2013 Transaction costs, rights issue |
27 656 -4 368 |
564 736 | 573 083 | -223 261 |
-48 334 261 |
-592 818 -4 107 |
|||
| Total loss for the period 1.1.2014 - 31.12.2014 | -897 | -43 069 | -279 139 | -323 105 | -323 105 | ||||
| Settlement of defined benefit plan Rights issue |
9 874 | 469 249 | 1 016 | -1 016 | -24 350 | ||||
| Equity as of 31.12.2014 Transaction costs, rights issue |
21 | 37 530 1 029 617 | 573 083 -4 368 |
-105 | -115 491 | -872 972 | -415 485 261 |
651 662 |
Total loss for the period 1.1.2014 - 31.12.2014 -897 -43 069 -279 139 -323 105 -323 105 Settlement of defined benefit plan 1 016 -1 016 Equity as of 31.12.2014 21 37 530 1 029 617 573 083 -105 -115 491 -872 972 -415 485 651 662 *The presentation currency has been changed to USD retrospectively as if USD has always been the presentation currency. For each category of the opening equity as at 1 January 2013, the historical rates have been used for translation to USD, and therefore an exchange reserve has been 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 currency rates at end of period.
Det norske oljeselskap ASA ('Det norske' or 'the company') is an oil company involved in exploration, development and production of oil and gas on the Norwegian Continental Shelf.
The company is a public limited liability company registered and domiciled in Norway. Det norske's shares are listed on the Oslo Børs. The company's registered business address is Føniks, Munkegata 26, 7011 Trondheim, Norway.
As per 31 December 2014, Aker Capital AS owned 49.99 per cent of Det norske. Aker Capital AS is a wholly-owned subsidiary of Aker ASA. From the fiscal year 2011, Det norske oljeselskap ASA's accounts are consolidated in Aker ASA's accounts. Aker ASA's registered business address is Fjordallèen 16 (at Aker Brygge) in Oslo, Norway. The consolidated financial statement is available at www.akerasa.com.
Det norske group's consolidated financial statements consist of the parent company Det norske oljeselskap ASA and the subsidiary Det norske oljeselskap AS (previously Marathon Oil Norge AS), after Det norske's completion of its acquisition of Marathon Oil Norge AS at 15 October 2014. Subsequently, all assets and liabilities in Marathon Oil Norge AS were transferred to Det norske as dividend in kind on 31 October 2014. Hence, the only difference between the group consolidated financial statements and the separate financial statement of Det norske oljeselskap ASA is related to the period between 15 and 31 October 2014. For more information regarding subsidiaries, see Note 4.
The financial statements were approved by the Board of Directors on 11 March 2015 and will be presented for approval at the Annual General Meeting on 13 April 2015.
The group consolidated and the company's financial statements have been prepared in accordance with the Norwegian Accounting Act and International Financial Reporting Standards (IFRS) as adopted by the EU.
The financial statements have been prepared on a historical cost basis with the exception of the following accounting items:
The financial statements have been prepared using uniform accounting principles for equivalent transactions and events taking place on otherwise equal terms.
All amounts have been rounded to the nearest thousand unless otherwise stated. As a result of rounding adjustments, the figures in one or more rows or columns included in the financial statements and notes may not add up to the total of that row or column.
Following the acquisition of Marathon Norge AS, the company made an assessment of the requirements in IAS 21 regarding functional currency and concluded that the functional currency has changed from NOK to USD with effect from 15 October 2014 as detailed in Section 1.3. The group also changed the presentation currency to USD from the same date, and the change in presentation currency has been treated as a change in accounting principles which in accordance with IAS 8 has been made retrospectively by translating comparative figures to USD as if this has always been the presentation currency.
Change in presentation currency is considered a voluntarily change in accounting principle which, according to IAS 1, requires a third statement of financial position as at the beginning of the preceding period, i.e. 1 January 2013. However, the only impact would be that all NOK balances are converted to USD at the currency rate of that day. The company believes that this provides limited useful information to the users of the financial statements of Det norske, and has therefore not presented a third statement of financial position. See Section 1.4 and the statement of changes in equity for further description of the method for the translation to presentation currency.
The preparation of financial statements in accordance with IFRS requires the management to make judgments, estimates and assumptions that have an effect on the application of accounting principles and on recognized amounts relating to assets and liabilities, to provide information relating to contingent assets and liabilities on the date of the Statement of financial position, and to report revenues and expenses in the course of the accounting period.
The important judgments management has made on the application of accounting principles relate to the following:
Functional currency: The application of IAS 21 requires management to use its judgment when determining the company's functional currency such that it most faithfully represents the economic effect of the underlying transactions, events and conditions that are relevant to the company. Management has determined that the acquisition of Marathon Oil Norge AS is a triggering event for a reassessment and change of the functional currency of Det norske oljeselskap ASA from NOK to USD, primarily due to the fact that the revenue from petroleum products will increase significantly and this revenue is mainly denominated in USD. Going forward, both the majority of revenues and financing activities will be denominated in USD.
Goodwill allocation and methodology for impairment testing: For the purpose of impairment testing, goodwill is allocated to cash- generating units, or groups of cash-generating units, that are expected to benefit from the synergies of the business combination from which it arose. The appropriate allocation of goodwill requires management's judgment and may impact the subsequent impairment charge significantly. Technical goodwill is a category of goodwill arising as an offsetting account to deferred tax in business combinations, as described in Section 1.8 below. There are no specific IFRS guidelines pertaining the allocation of technical goodwill, and management has therefore applied the general guidelines for allocating goodwill for the purpose of impairment testing.
The acquisition of Marathon Oil Norge AS has led to the recognition of both technical and residual goodwill as detailed in Note 3. Residual goodwill from this transaction of USD 290 million, representing tax synergies and the acquired workforce, has been allocated to all CGUs, reflecting the benefits these synergies will bring to the entire Det norske group. Technical goodwill from this transaction of USD 1 186 million reflects deferred tax recognized for the Alvheim CGU (see Note 3), and has been allocated to that CGU accordingly.
When performing the impairment test for technical goodwill, deferred tax from the date of acquisition reduces the net carrying value prior to the impairment charges. This is done to avoid an immediate impairment of all technical goodwill. When deferred tax from the initial recognition decreases, more goodwill is as such exposed for impairment. Going forward, depreciation of values calculated in the purchase price allocation will result in decreased deferred tax liability.
On selling a licence where the company historically has recognized deferred tax and goodwill in a business combination, both goodwill and deferred taxes from the acquisition are included when calculating gain/loss. When recording impairment of such licences as a result of impairment testing, the same assumptions are applied when measuring the impairment. This avoids tax grossing of the impairment, in that the impairment charged to the Income Statement will not be higher than the original posttax amount paid in the business combination.
Accounting estimates are used to determine reported amounts, including the possibility of realizing certain assets, the expected useful life of tangible and intangible assets, the tax expense, etc. Even though these estimates are based on the management's best judgment and assessment of previous and current events and actions, the actual results may deviate from the estimates. The estimates and underlying assumptions are reviewed regularly. Changes to the estimates are recognized when new estimates can be determined with sufficient certainty. Changes to accounting estimates are recognized in the period when they arise. If the effect of a change concerns future reporting periods, the effect is distributed between the current and future periods. The main sources of uncertainty when using estimates for the company relate to the following:
Proven and probable oil and gas reserves: Oil and gas reserves are estimated by the company's experts in accordance with industry standards. The estimates are based on Det norske's own assessment of internal information and information received from the operators. In addition, reserves are certified by an independent third party. Proven and probable oil and gas reserves consist of the estimated quantities of crude oil, natural gas and condensates shown by geological and technical data to be recoverable with reasonable certainty from known reservoirs under existing economic and operational conditions, i.e. on the date that the estimates are prepared. Current market prices are used in the estimates, except for existing contractual future price changes.
Proven and probable reserves and production volumes are used to calculate the depreciation of oil and gas fields by applying the unit of production methodology. Reserve estimates are also used as basis for impairment testing of licence-related assets. Changes in petroleum prices and cost estimates may change reserve estimates and accordingly economic cut-off, which may impact the timing of decommissioning and removal activities. Changes to reserve estimates can also be caused by updated production and reservoir information. Future changes to proven and probable oil and gas reserves can have a material effect on depreciation, life of field, impairment of licence-related assets, and operating results.
Successful Effort Method - exploration: Det norske's accounting policy is to temporarily recognize expenses relating to the drilling of exploration wells in the Statement of financial position as capitalized exploration expenditures, pending an evaluation of potential oil and gas discoveries. If resources are not discovered, or if recovery of the resources is considered technically or commercially unviable, the costs of exploration wells are expensed. Decisions as to whether this expenditure should remain capitalized or be expensed during the period may materially affect the operating result for the period.
Acquisition costs: Expenses relating to the acquisition of exploration licences are capitalized and assessed for impairment if there are indications of impairment. See Items 1.11 and 1.12 for further details.
Fair value measurement: From time to time, the fair values of non-financial assets and liabilities are required to be determined, e.g. when the entity acquires a business, or where an entity measures the recoverable amount of an asset or cash-generating unit at fair value less cost to sell. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest.
A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset in its highest and best use or by selling it to another market participant that would use the asset in its highest and best use. The group uses valuation techniques that are appropriate in the circumstances and for which sufficient data are available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. The fair value of oil fields in production and development phase is normally based on discounted cash flow models, where the determination of the different input in the model requires significant judgment from management, as described in the section below regarding impairment.
Impairment/reversal of impairment: Det norske has significant investments in long-lived assets. Changes in the expected future value/cash flow of individual assets can result in the book value of some assets being impaired to estimated recoverable value. Impairment losses must be reversed if the conditions for the impairment are no longer present. Considerations regarding whether an asset is actually impaired or whether the impairment losses should be reversed can be complicated and are based on judgement and assumptions. The complexity of the issue can, for example, relate to the modelling of relevant future cash flows to determine the asset's value in use, decide on measurement units and establish the asset's net sales value.
The evaluation of impairment requires long-term assumptions concerning a number of often volatile economic factors, including future oil prices, oil production, currency exchange rates and discount rates. Such assumptions require the estimation of relevant factors such as forward price curves (oil), production estimates and, finally, residual asset values. Likewise, establishing an asset's net sales value requires careful assessment unless information about net sales value can be obtained from an actual observable market. See Note 14 'Property, plant and equipment and intangible assets' and Note 15 'Impairment of goodwill and other assets' for details about impairment.
Decommissioning and removal obligations: The company has considerable obligations relating to decommissioning and removal of offshore installations at the end of the production period. Obligations associated with decommissioning and removal of long-term assets are recognized at present value of future expenditures on the date they are incurred. At the initial recognition of an obligation, the estimated cost is capitalized as production plant and depreciated over the useful life of the asset (typically by unit of production). It is difficult to estimate the costs for decommissioning and removal at initial recognition as these estimates are based on currently applicable laws and regulations, and are dependent on technological developments. Many decommissioning and removal activities will take place in the distant future, and the technology and related costs are constantly changing. The estimates include costs based on expected removal concepts and estimated costs of maritime operations, hiring of heavy-lift barges and drilling rig. As a result, the initial recognition of the obligation in the accounts, the related costs capitalized in the Statement of financial position for decommissioning and removal and subsequent adjustment of these items, involve careful consideration. Based on the described uncertainty, there may be significant adjustments in estimates of liabilities that can affect future financial results. See Note 23 for further details about the value of decommissioning and removal obligations.
Income tax: The company incurs significant amounts of income tax payable, and recognizes significant changes to deferred tax or deferred tax assets. These figures are based on management's interpretation of applicable laws and regulations, and on relevant court decisions. The quality of these estimates is highly dependent on management's ability to properly apply a complex set of rules and identify changes to the existing legal framework. See Note 11 for details about the deferred tax and taxes payable.
Transactions in foreign currencies are translated using the exchange rate on the transaction date. Monetary items in foreign currencies in the Statement of financial position are translated using the exchange rates at the end of the period. Foreign exchange gains and losses are recognized on an ongoing basis in the accounting period. Non-monetary items that are measured in terms of historical costs in a foreign currency are translated using the exchange rates on the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates on the date when the fair value is determined.
The results and financial position of group companies that have a functional currency different from the presentation currency are translated into the presentation currency as follows:
(i) Assets and liabilities for each balance sheet presented are translated based on the exchange rates at the
(ii) Revenues and expenses for each income statement presented are translated at average exchange rate for the period. However, if this average is not a reasonable approximation of the cumulative effect on the prevailing rates on the actual transaction dates, revenues and expenses are translated using the foreign exchange rates
| balance sheet date. |
|---|
| on the specific transaction date. |
(iii) Equity transactions are translated at the exchange rate on the transaction date.
All resulting exchange differences are recognized in other comprehensive income. The same method has been used for translating the parent company financial statements to USD as presentation currency for periods prior to the change in functional currency to USD.
Revenues from petroleum products in which the company has an interest with other producers are recognized on the basis of the company's ideal share of production during the period, regardless of actual sales (entitlement method).
This is achieved by applying the following approach in dealing with imbalances between actual sales and entitlements: The excess of product sold during the period over the participant's ownership share of production from the property is recognized by the overlift party as a liability (deferred revenue) and not as revenue. Conversely, the underlift party would recognize an underlift asset (receivable) and report corresponding revenue.
Differences between oil lifted and sold (petroleum overlifts) are presented as current liabilities, while petroleum underlifts are presented as short-term receivables. The value of overlift/underlift is set at the estimated sales value, minus estimated sales costs.
Other revenues are recognized when the goods or services are delivered and material risk and control are transferred. Gain on asset disposals as described in Section 1.9 is included in other revenues.
Tariff revenue from processing of oil and gas is recognized as earned in line with underlying agreements.
Revenue is presented net of customs, excise taxes and royalties paid in kind on petroleum products.
Dividends are recognized when the shareholders' dividend rights are approved by the Annual General Meeting.
Interest is taken to income based on the effective interest method as it is earned.
IFRS defines a joint arrangement as an arrangement over which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities (being those that significantly affect the returns of the arrangement) require unanimous consent of the parties sharing control. A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement, have rights to the assets and obligations for the liabilities, relating to the arrangement.
The company has interests in licences on the Norwegian Continental Shelf. Under IFRS 11 Joint arrangements, a joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement. The company recognizes investments in joint operations (oil and gas licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the company's financial statements.
For those licences that are not deemed to be a joint arrangement pursuant to the definition in IFRS 11 as there is no joint control, the company recognizes its share of related expenses, assets, liabilities and cash flows on a line-by-line basis in the financial statements in accordance with applicable IFRSs.
1.7 CLASSIFICATIONS IN STATEMENT OF FINANCIAL POSITION Current assets and current liabilities include items that fall due for payment less than a year from 31 December and items 144 93
Current assets and current liabilities include items that fall due for payment less than a year from 31 December and items relating to the business cycle. Next year's instalments on long-term liabilities are classified as current liabilities. Financial investments in shares are classified as current assets, while strategic investments are classified as non-current assets. Other assets are classified as fixed assets.
In order to consider an acquisition as a business combination, the acquired asset or groups of assets must constitute a business (an integrated set of operations and assets conducted and managed for the purpose of providing a return to the investors). The combination consists of inputs and processes applied to these inputs that have the ability to create output.
Acquired businesses are included in the financial statements from the transaction date. The transaction date is defined as the date on which the company achieves control over the financial and operating assets. This date may differ from the actual date on which the assets are transferred.
Comparative figures are not adjusted for acquired, sold or liquidated businesses.
For accounting purposes, the acquisition method is used in connection with the purchase of businesses. Acquisition cost equals the fair value of the assets used as consideration, including contingent consideration, equity instruments issued and liabilities assumed in connection with the transfer of control. Acquisition cost is measured against the fair value of the acquired assets and liabilities. Identifiable intangible assets are included in connection with acquisitions if they can be separated from other assets or meet the legal contractual criteria. When calculating fair value, the tax implications of any re-evaluations are taken into consideration. If the acquisition cost at the time of the acquisition exceeds the fair value of the acquired net assets (when the acquiring entity achieves control of the transferring entity), goodwill arises.
If the fair value of the net identifiable assets acquired exceeds the acquisition cost on the acquisition date, the excess amount is taken to income at the time of the takeover.
Goodwill is allocated to the cash-generating units or groups of cash-generating units that are expected to benefit from synergy effects of the merger. The allocation of goodwill may vary depending on the basis for its initial recognition.
The main part of the company's goodwill is related to the requirement to recognize deferred tax for the difference between the assigned fair values and the related tax base ("technical goodwill"). The valuation at fair value of licences is based on cash flows after tax. This is because these licences are only sold in an after-tax market based on decisions made by the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act Section 10. The purchaser is therefore not entitled to deduction for the consideration with tax effect through depreciation. In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax corresponding to the difference between the acquisition cost and the transferred tax depreciation basis. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax. Technical goodwill is tested for impairment separately for each cash-generating unit which give rise to the technical goodwill. A cash-generating unit may be individual oil fields, or a group of oil fields that are connected to the same infrastructure/production facilities.
The estimation of fair value and goodwill may be adjusted up to 12 months after the takeover date if new information has emerged about facts and circumstances that existed at the time of the takeover and which, had they been known, would have affected the calculation of the amounts that were included from that date.
Acquisition-related costs, except costs to issue debt or equity securities, are expensed as incurred.
On acquisition of a licence that involves the right to explore for and produce petroleum resources, it is considered in each case whether the acquisition should be treated as a business combination (see Item 1.8) or an asset purchase. Generally, purchases of licences in a development or production phase will be regarded as a business combination. Other licence purchases regarded as asset purchases are described below.
For licences in development phase, the acquisition cost is allocated between capitalized exploration expenses, licence rights and production plant.
When entering into agreements regarding the purchase/swap of assets, the parties agree on an effective date for the takeover of the net cash flow (usually 1 January in the calendar year). In the period between the effective date and the completion date, the seller will include its sold share of the licence in the financial statements. In accordance with the purchase agreement, there is a settlement with the seller of the net cash flow from the asset in the period from the effective date to the completion date (pro & contra settlement). The pro & contra settlement will be adjusted to the seller's losses/gains and to the assets for the purchaser, in that the settlement (after a tax reduction) is deemed to be part of the consideration in the transaction. Revenues and expenses from the relevant licence are included in the purchaser's Statement of income from the completion date, as defined in 1.8 above.
For tax purposes, the purchaser will include the net cash flow (pro & contra) and any other income and costs as from the effective date.
When acquiring licences that are defined as asset acquisitions, no provision is made for deferred tax.
Farm-in agreements are usually entered into in the exploration phase and are characterised by the transferor waiving future financial benefits in the form of reserves, in exchange for reduced future financing obligations. For example, a licence interest is taken over in return for a share of the transferor's expenses relating to the drilling of a well. In the exploration phase, the company normally accounts for farm-in agreements on a historical cost basis, as the fair value is often difficult to determine.
Swaps of assets are calculated at the fair value of the asset being surrendered, unless the transaction lacks commercial substance, or neither the fair value of the asset received, nor the fair value of the asset surrendered, can be effectively measured. In the exploration phase the company normally recognizes swaps based on historical cost, as the fair value often is difficult to measure.
According to Norwegian law, a unitization is required if a petroleum deposit extends over several production licences and these production licences have a different ownership representation. Consensus must be achieved with regard to the most rational coordination of the joint development and ownership distribution of the petroleum deposit. A unitization agreement shall be approved by the Ministry of Petroleum and Energy.
The company recognizes unitizations in the exploration phase based on historical cost, as the fair value often is difficult to measure. For unitizations involving licences outside the exploration phase, it has to be considered whether the transaction has commercial substance. If so, the unitization is recognized at fair value.
Tangible fixed assets are recognized on a historical cost basis. Depreciation of assets other than oil and gas fields is calculated using the straight-line method over estimated useful lives and adjusted for any impairment or change in residual value, if applicable.
The book value of tangible fixed assets consists of acquisition cost after deduction of accumulated depreciation and impairment losses. Expenses relating to leased premises are capitalized and depreciated over the remaining lease period if the recognition criteria for an asset have been met.
The expected useful lives of tangible fixed assets are reviewed annually, and in cases where these differ significantly from previous estimates, the depreciation period is changed accordingly. Changes to estimates are included prospectively in that the change is recognized in the period in which it occurs, and in future periods if the change affects both.
The residual value of an asset is the estimated amount that the company would obtain from disposal of the asset, after deduction of the estimated costs of disposal, if the asset was already of the age and in the condition expected at the end of its useful life.
Ordinary repair and maintenance costs relating to day-to-day operations are charged to income in the period in which they are incurred. The costs of major repairs and maintenance are included in the asset's book value.
Gains and losses relating to the disposal of assets are determined by comparing the selling price with the book value, and are included in other operating expenses. Assets held for sale are reported at the lower of the book value and the fair value less cost to sell.
Exploration and development costs relating to oil and gas fields Capitalized exploration expenditures are classified as intangible assets and reclassified to tangible assets at the start of the development. For accounting purposes, the field is considered to enter the development phase when the technical feasibility and commercial viability of extracting hydrocarbons from the field are demonstrable, normally at the time of concept selection. All costs relating to the development of commercial oil and/or gas fields are recognized as tangible assets. Pre-operational costs are expensed as they are incurred.
The company employs the 'successful efforts' method to account for exploration and development costs. All exploration costs (including seismic shooting, seismic studies and 'own time'), with the exception of acquisition costs of licences and drilling costs for exploration wells, are expensed as incurred. When exploration drilling is ongoing in a period after a reporting date and the result of the drilling is subsequently not successful, the capitalized exploration cost as of the reporting date is expensed if the drilling is completed before the date when the financial statement are authorized for issue.
Drilling cost for exploration wells are temporarily capitalized pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalized for more than one year. The main criteria are that there must be definite plans for future drilling in the licence or that a development decision is expected in the near future. If no resources are discovered, or if recovery of the resources is considered technically or commercially unviable, expenses relating to the drilling of exploration wells are charged to expense.
Acquired licence rights are recognized as intangible assets at the time of acquisition. Acquired licence rights related to fields in the exploration phase remain as intangible assets also when the related fields enter the development or production phase.
Capitalized exploration and evaluation expenditures, development expenditures from construction, installation or completion of infrastructure facilities such as platforms, pipelines and production wells, and field-dedicated transport systems for oil and gas are capitalized as production facilities and are depreciated using the unit-of-production method based on proven and probable developed reserves expected to be recovered from the area during the concession or contract period. Acquired assets used for the recovery and production of petroleum deposits, including licence rights, are depreciated using the unit-of-production method based on proven and probable reserves. The reserve basis used for depreciation purposes is updated at least once a year. Any changes in the reserves affecting unit-of-production calculations are reflected prospectively.
Tangible fixed assets and intangible assets (including licence rights, exclusive of goodwill) with a finite useful life will be assessed for potential loss in value when events or changes in the circumstances indicate that the book value of the assets is higher than the recoverable amount.
The valuation unit used for assessment of impairment will depend on the lowest level at which it is possible to identify cash inflows that are independent of cash inflows from other groups of fixed assets. For oil and gas assets, this is carried out at the field or licence level. The loss in value for capitalized exploration costs is assessed for each well. Impairment is recognized when the book value of an asset or a cash-generating unit exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost of disposal and value in use. When assessing 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 producing licences and licences in a development phase, the recoverable amount is calculated by discounting future cash flows after tax. The source of data input for the various fields is normally the operator's reporting to the Revised National Budget (RNB), as this is considered to be the best available estimate. Future cash flows are determined in the various licences based on the production profile compared to estimated proven and probable remaining reserves. The lifetime of the field for the purpose of impairment testing, is normally determined by the point in time when the operating cash flow from the field becomes negative.
For acquired exploration licences, an initial assessment as described in Section 1.11 above is performed – an assessment of whether plans for further activities have been established or, if applicable, an evaluation of whether development will be decided in near future.
A previously recognized impairment can only be reversed if changes have occurred in the estimates used for the calculation of the recoverable amount. However, the reversal cannot be to an amount that is higher than it would have been if the impairment had not previously been recognized. Such reversals are recognized in the Income statement. After a reversal, the depreciation amount is adjusted in future periods in order to distribute the asset's revised book value, minus any residual value, on a systematic basis over the asset's expected remaining life.
Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired.
Impairment is recognized if the recoverable amount of the cash-generating unit (or group of cash-generating units) to which the goodwill is related is less than the book value, including associated goodwill and deferred tax as described in Section 1.8. Losses relating to impairment of goodwill cannot be reversed in future periods. The company performs its annual impairment test of goodwill in the fourth quarter.
On selling a licence where the company historically has recognized deferred tax and goodwill in a business combination, both goodwill and deferred taxes from the acquisition are included when calculating gain/loss. When recording impairment of such licences as a result of impairment testing, the same assumptions are applied when measuring the impairment. This avoids tax grossing of the impairment, in that the impairment charged to the Income Statement will not be higher than the original post tax amount paid in the business combination.
The company has classified the financial instruments into the following categories of financial assets and liabilities:
The company designates its current financial assets as being at fair value with changes in value through profit or loss or available
for sale.
Financial assets with fixed or determinable cash flows that are not quoted in an active market are classified as loans and receivables.
Financial liabilities that do not form part of the "held for trading purposes" category and which have not been designated as being at fair value with changes in value through profit or loss are classified as other financial liabilities.
For financial instruments not traded in an active market, the fair value is determined using appropriate valuation techniques. Such techniques may include using recent arm's length market transaction; reference to the current fair value of other instruments that is substantially the same; discounted cash flow analysis or other valuation models.
An analysis of fair values of financial instruments and further details as to how they are measured are provided in Note 30.
Financial assets that are assessed at amortized cost are impaired when, based on objective evidence, it is likely that the instrument's cash flows have been negatively affected by one or more events that have occurred after the initial recognition of the instrument. In addition, the loss event must have an impact on estimated future cash flows that can be reliably estimated. The impairment is recognized in the Income statement. Should the reason for the impairment subsequently cease to exist, and this can be objectively linked to an event taking place after the impairment of the asset, the previous impairment shall be reversed. The reversal shall not cause the book value of the financial asset to exceed the amount that the amortized cost would have been if the impairment had not been recognized at the time when the impairment was reversed. Reversals of previous impairments are presented on the same line item as the impairment.
Research consists of original, planned studies carried out with a view to achieving new scientific or technical knowledge or understanding. Development consists of the application of information gained through research, or of other knowledge, to a plan or design for the production of new or significantly improved materials, facilities, products, processes, systems or services before commercial production or use commences.
The licence system on the Norwegian Continental Shelf stimulates research and development activities. The company is only involved in research and development through projects financed by participants in the licences. It is the company's own share of the licence-financed research and development that is assessed with a view to capitalization. Development costs that are expected to generate future financial benefits are capitalized when the following criteria are met:
The company can demonstrate that the technical premises exist for the completion of the intangible asset with the aim
The company has available adequate technical, financial and other resources to complete the development and to put to
The company has the ability to measure the costs incurred in connection with the development of the intangible asset
All other research and development costs are expensed as incurred.
Costs that are capitalized include cost of materials, direct payroll expenses and a share of directly related joint expenses. Capitalized development costs are recognized in the Statement of financial position at acquisition cost minus accumulated depreciation.
Capitalized development costs are amortized over the asset's estimated useful life.
The company presents its payroll and operating costs based on the functions in development, operational and exploration activities respectively, based on allocation of registered hours worked. As a basis, the company uses gross payroll and operating expenses reduced by the amounts already invoiced to operated licences.
Lease agreements in which the company accepts the main risk and returns in connection with ownership of the asset are financial lease agreements. At the start of the lease period, financial lease agreements are calculated at an amount corresponding to the lowest of the fair value and the minimum present value of the lease. When calculating the lease agreement's net present value, the implicit interest rate expense in the lease agreement is used provided that it can be calculated; otherwise, the company's incremental borrowing rate is used. Direct costs in connection with the establishment of the lease agreement are included in the asset's cost price.
Financial lease agreements are treated as tangible fixed assets in the Statement of financial position and have the same depreciation period as the company's other depreciable assets. If it cannot be assumed with reasonable certainty that the company will take over ownership of the asset after the expiry of the lease, the asset is depreciated over whichever is the shorter of the contract period of the lease agreements and the asset's expected useful life.
Lease agreements in which the main risk and returns associated with the ownership of the asset are not transferred, are classified as operating lease agreements. Rental payments are classified as operating expenses and are recognized on a straightline basis over the contract period.
Trade debtors are recognized in the Statement of financial position at nominal value after a deduction for the provision for bad debt. The provision for bad debt is calculated on the basis of an individual valuation of each trade debtor. Known losses on receivables are expensed as incurred.
Borrowing costs that can be directly ascribed to procurement, processing or production of a qualifying asset shall be capitalized as part of the asset's acquisition cost. Interest is only capitalized during the development phase. Other borrowing costs are expensed in the period in which they are incurred.
A qualifying asset is one that necessarily takes a substantial period of time to be made ready for its intended use or sale. Qualifying assets are generally those that are subject to major development or construction projects.
Spare parts are valued at the lower of cost price and net realizable value on the basis of the first-in/first-out (FIFO) principle. Costs include raw materials, freight and direct production costs in addition to some indirect costs. Net realizable value is equal to the replacement cost of the materials.
Cash and cash equivalents include cash, bank deposits, and other short-term highly liquid investments with an original due date of three months or less. Bank overdrafts are included in the Statement of financial position as short-term loans.
All borrowings are initially recognized at acquisition cost, which equals the fair value of the amount received minus issuing costs relating to the loan.
Subsequently, interest-bearing borrowings are valued at amortized cost using the effective interest method; the difference between the acquisition cost (after transaction costs) and the face value is recognized in the Income statement during the period until the loan falls due. Amortized costs are calculated by considering all issue costs and any discount or premium on the settlement date.
Tax payable/tax receivable for the current and previous periods is based on the amounts receivable from or payable to the tax authorities.
Tax consists of tax payable and changes in deferred tax. Deferred tax/tax benefits are calculated on the basis of the differences between book value and tax basis values of assets and liabilities, with the exception of temporary differences relating to acquisition of licences that is defined as asset purchase.
The book value of deferred tax benefits is assessed on an annual basis and reduced insofar as it is no longer probable that future earnings or current tax regulations will make it possible to utilise the benefit. Deferred tax benefits that are not capitalized will be re-evaluated on each date of Statement of financial position and capitalized insofar as it is probable that future earnings or current tax regulations will make it possible to utilise the benefit.
Deferred tax and tax benefits are measured using the expected tax rate when the tax benefit is realised or the tax liability is met, based on tax rates and tax regulations that have been enacted or substantively enacted by the end of the reporting period.
Tax payable and deferred tax is recognized directly against equity insofar as the tax items are directly related to equity transactions.
Deferred tax and tax benefits are shown at net value, where netting is legally permitted and the deferred tax benefit and liability are related to the same tax subject and are payable to the same tax authorities.
As a production company, Det norske is subject to the special provisions of the Petroleum Taxation Act. Revenues from activities on the Norwegian Continental Shelf are liable to ordinary company tax and special tax. The tax rate for general corporate tax was 28 per cent until 1 January 2014, when it was changed to 27 per cent. The rate for special tax was 50 per cent until the same date, when it was changed to 51 per cent.
Pipelines and production facilities can be depreciated by up to 16 2/3 per cent annually, i.e., using the straight-line method over six years. Depreciation can be started when the expenses are incurred. When the field stops producing, the remaining cost price can be included as a deduction in the final year.
Uplift is a special income deduction in the basis for calculation of special tax. The uplift is calculated on the basis of investments in pipelines and production facilities, and can be regarded as an extra depreciation deduction in the special tax basis. The uplift constituted until 5 May 2013, 7.5 per cent per year over a period of four years, totalling 30 per cent of the investment. From 5 May 2013, the rate is 5.5 per cent per year over a period of four years, totalling 22 per cent of the investment. Transition rules apply for some of the company's fields in development phase, which allows for the old 7.5 per cent rate until the year of production start. Uplift is recognized in the year in which it is deducted in the companies' tax returns, and thus has a similar effect on the tax for the period as a permanent difference.
Interest on debt with associated currency losses/gains (net financial expenses on interest-bearing debt) is distributed between the offshore and onshore tax jurisdictions. The offshore interest deduction is calculated as the net financial costs of interestbearing debt multiplied by 50 per cent of the ratio between net asset value for tax purposes allocated to the offshore tax jurisdictions as of 31 December in the income year and the average interest-bearing debt through the income year.
Remaining financial expenses, currency losses and all interest-rate income are allocated to the onshore jurisdiction.
Uncovered losses in the onshore tax jurisdictions resulting from the distribution of net financial items can be allocated to the offshore tax jurisdictions and deducted from regular income.
Only 50 per cent of other losses in the onshore tax jurisdictions are permitted to be reallocated to the offshore tax jurisdictions as deductions in regular income.
Companies may claim a refund from the State for the tax value of exploration expenses incurred insofar as these do not exceed the year's tax-related loss allocated to the offshore activities. The refund is included under 'Calculated tax receivable' in the Statement of financial position.
Companies subject to special tax may, without time limitations, carry forward losses with the addition of interest. A corresponding rule also applies to unused uplift. The tax position can be transferred on realisation of the company or merger. Alternatively, disbursement of the tax value can be claimed from the State.
Every employee had until 30.09.2014 a pension scheme that was administered and managed by a Norwegian life insurance company. The calculation of the estimated pension liability for defined-benefit pensions was based on external actuary methods, and was compared to the value of the pension assets.
Pension costs and pension liabilities are recognized based on a calculation by independent actuary using the projected unit credit method. This is based on assumptions relating to discount rates, future salary, National Insurance benefits, future returns on pension assets and actuarial assumptions relating to mortality and voluntary retirement, etc. Pension assets are recognized at fair value. Pension commitments and pension assets are presented net in the Statement of financial position and expenses are classified mainly as payroll and payroll-related expenses, and a smaller part as other financial expenses. All actuarial gains and losses are recognized in the Statement of other comprehensive income (OCI). Net interest expense consists of interest on the obligation and return on assets, both calculated using the discount rate. The difference between the actual return on plan assets and the recognized return is recorded to OCI.
Gains and losses on curtailment or settlement of a defined-benefit pension scheme are included in the Income statement when the curtailment or settlement occurs. The settlement of the defined-benefit pension scheme at 30 September and 15 October 2014 is recognized in accordance with these principles. A defined contribution plan has replaced the benefit plan, and the company is making contributions to the pension plan for full-time employees equal to 3-5 per cent of the employee's salary. The pension premiums are charged to expenses as they are incurred.
An early retirement scheme (AFP) has been introduced for all employees. The scheme is a multi-employer defined benefit plan, but is accounted for as a defined contribution pension, and premiums are expensed as incurred.
A provision is recognized in the accounts when the company incurs an actual commitment (legal or self-imposed) as a result of a previous event and it is probable that financial settlement will take place as a result of this commitment, and the amount can be reliably calculated. Provisions are evaluated at each period end and are adjusted to reflect the best estimate.
If the time effect is considerable, the provisions are discounted using a discount rate before tax that reflects the market's pricing of the time value of the amount and the risk specifically associated with the commitment. On discounting, the book value of the provisions is increased in each period to reflect the change in time relative to the due date of the commitment. The increase is expensed as an interest expense.
In accordance with the licence terms and conditions for the licences in which the company participates, the Norwegian State can require licence owners to remove the installation in whole or in part when production ceases or the licence period expires.
In the initial recognition of the decommissioning and removal obligations, the company provides for the net present value of future costs related to decommissioning and removal. A corresponding asset is capitalized as a tangible fixed asset and depreciated using the unit of production method. Changes in the time value (net present value) of the obligation related to decommissioning and removal accretion are charged to income as financial expenses and increase the balance-sheet liability related to future decommissioning and removal expenses. Changes in the best estimate for expenses related to decommissioning and removal are recognized in the Statement of financial position. The discount rate used in the calculation of the fair value of the decommissioning and removal obligation is the risk-free rate with the addition of a credit risk element.
Since its formation, the company has conducted its entire business in one and the same segment, defined as exploration for and production of petroleum in Norway. The company conducts its activities on the Norwegian Continental Shelf, and management follows up the company at this level. The financial information relating to geographical distribution and large customers is presented in Note 5.
Earnings per share are calculated by dividing the ordinary profit/loss attributable to ordinary equity holders of the parent entity by the weighted average number of the total outstanding shares. Shares issued during the year are weighted in relation to the period in which they have been outstanding. Diluted earnings per share is calculated as the profit/loss for the year divided by the weighted average number of outstanding shares during the period, adjusted for the dilution effect of any share options.
Contingent liabilities are not recognized. A contingent liability is a possible obligation that arises from past events and whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the control of the entity; or a present obligation that arises from past events but is not recognized because it is not probable that an outflow of resources embodying economic benefits will be required to settle the obligation or the amount of the obligation cannot be measured with sufficient reliability.
Contingent liabilities are disclosed with the exception of contingent liabilities where the probability of the liability having to be settled is remote.
Contingent assets are recognized if it is virtually certain that the condition will occur. However, information about such contingent assets is provided if inflow of economic benefits is probable.
The accounting policies applied are consistent with those of the previous financial year, except for the following amendments to IFRS effective as of 1 January 2014 that were relevant for the group:
IFRS 10 replaced the portion of IAS 27 Consolidated and Separate Financial Statements that addresses the accounting for consolidated financial statements. IFRS 10 establishes a single control model that applies to all entities. The changes introduced by IFRS 10 require management to exercise significant judgment to determine which entities are controlled, and therefore are required to be consolidated by a parent, compared with the requirements that were in IAS 27. In the standard an investor controls an investee when it is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. The standard did not have any effect for the group.
The application of IFRS 11 and IAS 28 did not impact the group's accounting for its interests in joint arrangements because the Group determined that its joint arrangements that were previously classified as jointly controlled assets, were classified as joint operations under IFRS 11. As a result, the group's previous methods of accounting for its joint arrangements continue to be appropriate under IFRS 11.
IFRS 12 includes all of the disclosures that were previously in IAS 27 related to consolidated financial statements, as well as all of the disclosures that were previously included in IAS 31 Interests in Joint Ventures and IAS 28 Investment in Associates. These disclosures relate to an entity's interests in subsidiaries, joint arrangements, associates and unconsolidated structured entities. A number of new disclosures are also required. One of the most significant changes introduced by IFRS 12 is that an entity is now required to disclose the judgments made to determine whether it controls another entity. The new disclosures will assist the users of the financial statements to make their own assessment of the financial impact in cases where management were to reach a different conclusion regarding consolidation — by providing more information about unconsolidated entities. The standard did not have any significant effect for the group.
IAS 36 is amended to address the disclosure of information about the recoverable amount of impaired assets if that amount is based on fair value less costs of disposal. The change is not considered to have any major impact for Det norske, as the company does not use fair value less costs of disposal to estimate recoverable amount. The amendment also removes the requirement for an entity to disclose the recoverable amount of every cash-generating unit to which significant goodwill or indefinite-lived intangible assets have been allocated, instead such disclosure is required when an impairment loss has been recognized or reversed.
A number of standards and interpretations are issued, but not yet effective, up to the date of issuance of the company's financial statements. Those that are expected to impact the group are disclosed below. The company intends to adopt these standards, if applicable, when they become effective, provided that the amendments are endorsed by the EU before publication of the annual report.
In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments which reflects all phases of the financial instruments project and replaces IAS 39 Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. The standard introduces new requirements for classification and measurement, impairment, and hedge accounting. IFRS 9 is effective for annual periods beginning on or after 1 January 2018, with early application permitted, but is not endorsed by the EU yet. Retrospective application is required, but comparative information is not compulsory. Early application of previous versions of IFRS 9 (2009, 2010 and 2013) is permitted if the date of initial application is before 1 February 2015. The adoption of IFRS 9 may have an effect on the classification and measurement of the group's financial assets, but is not expected to impact the classification and measurement of the group's financial liabilities.
IFRS 15 was issued in May 2014 and establishes a new five-step model that will apply to revenue arising from contracts with customers. Under IFRS 15, revenue is recognized at an amount that reflects the consideration to which an entity expects to be entitled in exchange for transferring goods or services to a customer.
The principles in IFRS 15 provide a more structured approach to measuring and recognising revenue. The new revenue standard is applicable to all entities and will supersede all current revenue recognition requirements under IFRS. Either a full or modified retrospective application is required for annual periods beginning on or after 1 January 2017 with early adoption permitted, but it is not endorsed by the EU yet. There have been some early indicators that the entitlement method currently applied by the company will not be allowed under IFRS 15, but this has not yet been concluded. The company is currently assessing the impact of IFRS 15 and plans to adopt the new standard on the required effective date.
The amendments to IFRS 11 require that a joint operator accounting for the acquisition of an interest in a joint operation, in which the activity of the joint operation constitutes a business, must apply the relevant IFRS 3 principles for business combinations accounting. The amendments also clarify that a previously held interest in a joint operation is not re-measured on the acquisition of an additional interest in the same joint operation while joint control is retained. In addition, a scope exclusion has been added to IFRS 11 to specify that the amendments do not apply when the parties sharing joint control, including the reporting entity, are under common control of the same ultimate controlling party. The amendments apply to both the acquisition of the initial interest in a joint operation and the acquisition of any additional interests in the same joint operation and are prospectively effective for annual periods beginning on or after 1 January 2016, with early adoption permitted. These amendments are not expected to have any impact on the group, as acquisitions in scope of the amendments have been treated as business combinations under the current accounting policies of the group.
The changes are primarily in order to remove inconsistencies and to clarify the wording of standards and interpretations. There are separate transition provisions for each standard (and the 2012-2014 cycle is not yet approved by the EU). The changes are not expected to have significant effect for the group.
The formal partner decision on the development concept for the Johan Sverdrup field was made and the appraisal drilling program was completed. Unitization discussions commenced and preparations for submittal of the plan for development and operation (PDO) progressed. The Ivar Aasen partnership signed a unit agreement and construction activities moved forward in Norway, Singapore and Italy for production start-up in late 2016. The Bøyla development was completed and the Alvheim FPSO was prepared to receive production from the field. Production commenced in January 2015. The company participated in a discovery at Krafla North.
2014 was a transformational year for the company as a result of the acquisition of Marathon Oil Norge AS. Through the acquisition, the company became a strong E&P player with significant production and a diversified balanced asset base.
The company secured a facility of up to USD 3 billion in a seven year reserve-based lending facility, plus NOK 3 billion in new equity through a rights issue.
The recognized amounts of assets and liabilities assumed as at the date of the acquisition were as follows:
| Group | ||
|---|---|---|
| (USD 1 000) | Note | 15.10.2014 |
| Capitalized exploration expenditures | 14 | 37 899 |
| Other intangible assets | 14 | 515 966 |
| Property, plant and equipment | 14 | 1 641 117 |
| Inventories | 17 714 | |
| Accounts receivable | 83 206 | |
| Other short-term receivables | 71 436 | |
| Cash and cash equivalents | 589 107 | |
| Total assets | 2 956 445 | |
| Pension obligations | 12 071 | |
| Deferred taxes | 12 | 911 363 |
| Abandonment provision - long-term | 23 | 336 246 |
| Provision for other liabilities | 16 825 | |
| Trade creditors | 2 520 | |
| Accrued public charges and indirect taxes | 2 893 | |
| Abandonment provision - short-term | 23 | 4 651 |
| Other current liabilities | 129 531 | |
| Short-term derivatives | 13 393 | |
| Tax payable | 12 | 910 332 |
| Total liabilities | 2 339 825 | |
| Total identifiable net assets at fair value | 616 620 | |
| Goodwill arising on acquisition | 14 | 1 486 086 |
| Total consideration paid on acquisition | 2 102 706 |
On 15 October 2014, Det norske finalized the acquisition of 100 per cent of the shares in Marathon Oil Norge AS. The transaction was announced on 2 June 2014, and Det norske paid a cash consideration of USD 2.1 billion. The acquisition was financed through a combination of equity and debt, by issuing NOK 3 billion in new equity and securing a reserve-based lending facility of USD 3 billion. The main reasons for the acquisition were to diversify the asset base by getting access to production and cash flow and create a strong platform for future organic growth. The portfolio of licences from Marathon Oil Norge AS comes with limited capital expenditure commitments and high near-term production that complement the planned production start of Det norske's Ivar Aasen and Johan Sverdrup developments.
The acquisition date for accounting purposes corresponds to the finalization of the acquisition on 15 October 2014. For tax purposes, the effective date was 1 January 2014. The acquisition is regarded as a business combination and has been accounted for using the acquisition method of accounting in accordance with IFRS 3. A purchase price allocation (PPA) has been performed to allocate the cash consideration to fair value of assets and liabilities from Marathon Oil Norge AS. The PPA is performed as of the accounting date, 15 October 2014.
Each identifiable asset and liability is measured at its acquisition date fair value based on guidance in IFRS 13. The standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. This definition emphasizes that fair value is a market-based measurement, not an entity-specific measurement. When measuring fair value, the company uses the assumptions that market participants would use when pricing the asset or liability under current market conditions, including assumptions about risk. Acquired property, plant and equipment have been valued using the cost approach (replacement cost), while intangible assets have been valued using the income approach.
Accounts receivable are recognized at gross contractual amounts due, as they relate to large and credit-worthy customers. Historically, there has been no significant uncollectible accounts receivable in Marathon Oil Norge AS.
The above valuation is based on currently available information about fair values as of the acquisition date. If new information becomes available within 12 months from the acquisition date, the company may change the fair value assessment in the PPA, in accordance with guidance in IFRS 3.
The goodwill of USD 1 486 million arises principally because of the following factors:
| Reconciliation of goodwill from the acquisition of Marathon Oil Norge AS (USD 1 000) | 15.10.2014 |
|---|---|
| Goodwill as a result of deferred tax - technical goodwill | 1 196 458 |
| Goodwill related to synergies - residual goodwill | 289 628 |
| Total goodwill before impairment charges | 1 486 086 |
| Impairment charges, see Note 15 | 340 594 |
| Net goodwill from the acquisition of Marathon Oil Norge AS as of 31 December 2014 | 1 145 492 |
None of the goodwill recognized will be deductible for income tax purposes.
A dividend in kind was distributed on 31 October 2014 from Det norske oljeselskap AS to Det norske oljeselskap ASA, where all assets and liabilities previously held in Marathon Oil Norge AS were transferred to Det norske. The distribution was based on group continuity applying booked values in the group based on the PPA from 15 October 2014 described above. The only remaining asset in Det norske oljeselskap AS subsequent to the dividend is cash equivalents of USD 1.0 million which corresponds to its share capital.
Upon payment of the dividend in kind, the assets and liabilities of Marathon Oil Norge AS replaced the value of the shares of that company in the separate financial statements of Det norske oljeselskap ASA. However, the booked value of net assets in Marathon Oil Norge AS was USD 22.8 million higher at the time of the dividend compared to the PPA date. This amount corresponds to the net profit in the group financial statements in the period between the PPA and the dividend distribution, and is booked as financial income (dividend from subsidiaries - see Note 11) in the separate financial statements of Det norske oljeselskap ASA.
From the date of acquisition (15 October 2014) to 31 December 2014, the activity of Det norske oljeselskap AS (former Marathon Oil Norge AS) contributed USD 338 million to group revenue and USD 79 million to group profit (before impairment of USD 340 million related to the acquisition, see Note 6). If the acquisition had taken place at the beginning of the year, group revenue and net loss for the year 2014 would have been USD 2 395 million and USD 45 million, respectively. The acquisition has no impact on other comprehensive income for 2014.
The ability to capture synergies that can be realized from managing a portfolio of both acquired and existing fields on the Norwegian Continental Shelf. The synergies are mainly related to the utilization of Det norske's loss carried forward against tax payable in Marathon Oil Norge AS, as well as synergies from the workforce in the two organizations ("residual goodwill").
The requirement to recognize deferred tax assets and liabilities for the difference between the assigned fair values and the tax bases of assets acquired and liabilities assumed in a business combination. Licences under development and licences in production can only be sold in a market after tax, based on a decision made by the Norwegian Ministry of Finance pursuant to the Petroleum Taxation Act Section 10. The assessment of fair value of such licences is therefore based on cash flows after tax. Nevertheless, in accordance with IAS 12 Sections 15 and 19, a provision is made for deferred tax corresponding to the tax rate multiplied with the difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred tax ("technical goodwill").
Det norske oljeselskap AS, previously Marathon Oil Norge AS (100 per cent): This is the company acquired by Det norske in October 2014. All activity was transferred to Det norske as dividend in kind on 31 October 2014. As of year-end 2014, the only remaining asset in this company is cash equivalents reflecting the share capital amounting to USD 1.0 million.
Alvheim AS: The sole business of Alvheim AS is to act as legal owner of MST Alvheim, the floating production facility which is used to produce oil and gas from the Alvheim fields. The costs of and benefits from operating the MST Alvheim will be borne by the partners in the Alvheim field. Hence, Alvheim AS only has the formal ownership rather than the actual value of the production facilities. Det norske has a 65 per cent share in Alvheim AS, which corresponds to the ownership in the Alvheim field.
Alvheim AS and Sandvika Fjellstue AS are from a materiality consideration not consolidated in the group accounts. The activity in Det norske oljeselskap AS is included in the group accounts from the acquisition date 15 October 2014, see Note 2. In the separate financial statements, the activity is included from 31 October 2014 which was the date when all assets and liabilities in the former Marathon Oil Norge AS was transferred to Det norske oljeselskap ASA as dividend in kind. This transfer was measured based on group continuity and based on the same fair values as applied in the purchase price allocation described in Note 3. Hence, with regard to the statement of financial position there are no differences between the group financial statements and the separate financial statements except for the classification of the subsidiaries.
The company's business is entirely related to exploration for and production of petroleum in Norway. The company's activities are considered to have a homogeneous risk and return profile before tax, and the business is located in the geographical area Norway. Thus, the company operates within a single operating segment. This matches the internal reporting to the company's executive management. The revenue in 2014 in all material respect relates to two main customers, which accounted for sales of USD 289 million and USD 36 million (group) and USD 228 million and USD 28 million (parent), respectively.
*Expensing of exploration wells capitalized in previous years are mainly related to PL 362 Fulla and PL 029B Freke.
Breakdown of produced volumes (barrels of oil equivalent)
| Oil | 4 800 457 | 1 263 889 | 3 883 864 | 1 263 889 |
|---|---|---|---|---|
| Gas | 904 444 | 365 226 | 751 574 | 365 226 |
| Total produced volumes | 5 704 901 | 1 629 115 | 4 635 438 | 1 629 115 |
| Petroleum revenues | 411 996 | 158 782 | 325 034 | 158 782 |
| Production costs | 66 754 | 42 474 | 59 173 | 42 474 |
| Net revenues from production | 345 241 | 116 308 | 265 861 | 116 308 |
| Group Parent company |
||||
|---|---|---|---|---|
| Breakdown of exploration expenses (USD 1 000) | 2014 | 2013 | 2014 | 2013 |
| Seismic, well data, field studies and other exploration expenses | 24 846 | 53 207 | 24 833 | 53 207 |
| Recharged rig costs | -11 087 | -20 241 | -11 087 | -20 241 |
| Share of exploration expenses from licence participation, incl. seismic | 28 097 | 25 751 | 28 061 | 25 751 |
| Expensing of exploration wells capitalized in previous years* | 40 175 | 94 145 | 40 183 | 94 145 |
| Expensing of exploration wells capitalized this year | 58 886 | 101 625 | 58 886 | 101 625 |
| Share of payroll and other operating expenses classified as exploration | 14 104 | 20 759 | 14 064 | 20 759 |
| Research and development costs related to exploration activities | 2 556 | 3 309 | 2 556 | 3 309 |
| Total exploration expenses | 157 578 | 278 554 | 157 497 | 278 554 |
Total gain related to the swaps, including a 40 per cent share in PL 457, is calculated at approximately USD 49 million.
| Group | Parent company | |||
|---|---|---|---|---|
| Breakdown of revenues (USD 1 000) | 2014 | 2013 | 2014 | 2013 |
| Recognized income oil | 368 443 | 134 619 | 289 030 | 134 619 |
| Recognized income gas | 39 665 | 20 036 | 32 139 | 20 036 |
| Tariff income | 3 888 | 4 127 | 3 865 | 4 127 |
| Total petroleum revenues | 411 996 | 158 782 | 325 034 | 158 782 |
Other operating income consists in all material respect of gain on asset swaps. During June 2014, Det norske entered into two licence swaps including PL 457, which increased the company's share in the Ivar Aasen Unit. In accordance with the company's accounting principles, swaps of assets are recognized at fair value, unless the transaction lacks commercial substance or cannot be reliably measured. In these swaps, fair value have been calculated for the assets received, applying an income approach and present value technique to determine fair value.
Those parts of payroll and operating expenses that can be ascribed to production, development and exploration activities have been classified and presented as fixed assets, exploration and production expenses, respectively.
Production costs include costs associated with leasing, operation and maintenance of subsea installations, modifications, production vessels, platforms/FPSO, well intervention and workover activities, environmental tax, etc. Production cost, also include provision for onerous contract costs. The share of payroll and administration expenses that can be ascribed to operations is reclassified and shown as a production cost, see Note 10.
The inventory mainly consists of equipment for the drilling of exploration wells or spare parts for development and production licences.
Europe 333.0 220.6 333.0 220.6 At the start of the year, the number of employees was 230. As of 31 December 2014 the number of employees was 507.
| Remuneration of senior executives in 2014 At the start of the year, the number of employees was 230. As of 31 December 2014 the number of employees was 507. (USD 1 000) |
Salary | ment and bonus6) |
Other benefits |
pension costs |
Other | Total remuneration |
number of shares (in 1 000) |
Owning interest |
|---|---|---|---|---|---|---|---|---|
| Karl Johnny Hersvik (Chief Executive Officer)1) | 539 | 503 | Share 9 |
19 | 56 | 1 106 Accrued |
0 | 0.00 % |
| Øyvind Bratsberg (SVP Technology & Field Development) | 680 | 505 Salary |
invest 12 |
31 | Other 63 |
1 261 pension Other |
49 | Total 0.02 % |
| Alexander Krane (Chief Financial Officer) Remuneration of senior executives in 2014 |
474 | 268 | ment and 10 |
benefits 31 |
752 | 12 | remuneration 0.01 % |
|
| Gro G. Haatvedt (VP Exploration)2) (USD 1 000) |
260 | 201 | bonus6) 3 |
19 | 476 | costs 939 |
0 | 0.00 % |
| Odd R. Heum (SVP Asset Johan Sverdrup)5) | 349 | 177 | 4 | 29 | 529 | 90 | 0.04 % | |
| Bård Atle Hovd (SVP Ivar Aasen Project)5) | 686 | 235 | 3 | 34 | 924 | 16 | 0.01 % | |
| Karl Johnny Hersvik (Chief Executive Officer)1) Anita Utseth (SVP Business Support and Act. SVP Exploration)3) |
315 | 539 116 |
5 | 503 40 |
9 | 19 436 |
56 72 |
1 106 0.04 % |
| Øyvind Bratsberg (SVP Technology & Field Development) Kjetil Kristiansen (SVP HR)2) |
135 | 680 76 |
2 | 505 8 |
12 | 31 213 |
63 0 |
1 261 0.00 % |
| Alexander Krane (Chief Financial Officer) Rolf J. Brøske (SVP Comm.)7) |
177 | 474 63 |
5 | 268 24 |
10 | 31 244 |
3 | 752 0.00 % |
| Geir Solli (SVP Operations )4) Gro G. Haatvedt (VP Exploration)2) |
77 | 232 260 |
14 | 7 201 |
3 | 322 19 |
0 476 |
0.00 % 939 |
| Kjetil Ween (SVP Drilling and Wells)4) Odd R. Heum (SVP Asset Johan Sverdrup)5) |
51 | 111 | 8 | 6 | 171 | 0 | 0.00 % | |
| Elke R. Njaa (SVP Company Development/Special Projects)4) | 52 | 349 124 |
9 | 177 7 |
4 | 29 185 |
0 | 529 0.00 % |
| Bård Atle Hovd (SVP Ivar Aasen Project)5) Leif G. Hestholm (SVP HSE & Q)4) |
50 | 686 122 |
6 | 235 6 |
3 | 34 179 |
0 | 924 0.00 % |
| Anita Utseth (SVP Business Support and Act. SVP Exploration)3) Total remuneration of senior executives in 2014 |
3 843 | 315 2 733 |
90 | 116 262 |
5 595 |
40 7 261 |
243 | 436 0.00 % |
| Kjetil Kristiansen (SVP HR)2) 1) Joined 1 April 2014. The amount included in "other" relates to sign-on fee. |
135 | 76 | 2 | 8 | 213 | |||
| Rolf J. Brøske (SVP Comm.)7) 2) Joined 1 August 2014. The amount included in "other" relates to sign-on fee. |
177 | 63 | 5 | 24 | 244 | |||
| 3) Resigned from executive management 1 August 2014. Geir Solli (SVP Operations )4) |
77 | 232 | 14 | 7 | 322 | |||
| 4) Joined 15 October 2014 Kjetil Ween (SVP Drilling and Wells)4) |
51 | 111 | 8 | 6 | 171 | |||
| 5) Resigned from executive management 15 October 2014. | ||||||||
| Elke R. Njaa (SVP Company Development/Special Projects)4) 6) Share savings investment scheme earned in 2014, disbursed in 2015. |
52 | 124 | 9 | 7 | 185 | |||
| Leif G. Hestholm (SVP HSE & Q)4) 7) Joined executive management 15 October 2014. Total remuneration of senior executives in 2014 |
50 3 843 |
2 733 | 122 | 6 90 |
6 262 595 |
179 7 261 |
||
| Share | Total |
| Total Remuneration of senior executives in 2014 At the start of the year, the number of employees was 230. As of 31 December 2014 the number of employees was 507. (USD 1 000) |
Salary | Share invest ment and bonus6) |
Other benefits |
Accrued pension costs |
Other | 337.0 222.1 Total remuneration |
Total number of shares (in 1 000) |
Owning interest |
|---|---|---|---|---|---|---|---|---|
| Karl Johnny Hersvik (Chief Executive Officer)1) | 539 | 503 | Share 9 |
19 | 56 | 1 106 | 0 | 0.00 % |
| Øyvind Bratsberg (SVP Technology & Field Development) | 680 | 505 | invest 12 |
31 | Other 63 |
Accrued 1 261 |
49 | Total 0.02 % |
| Alexander Krane (Chief Financial Officer) | 474 | Salary 268 |
ment and 10 |
31 | benefits | pension Other 752 |
12 | remuneration 0.01 % |
| Remuneration of senior executives in 2014 Gro G. Haatvedt (VP Exploration)2) |
260 | 201 | bonus6) 3 |
19 | 476 | costs 939 |
0 | 0.00 % |
| (USD 1 000) Odd R. Heum (SVP Asset Johan Sverdrup)5) |
349 | 177 | 4 | 29 | 529 | 90 | 0.04 % | |
| Bård Atle Hovd (SVP Ivar Aasen Project)5) | 686 | 235 | 3 | 34 | 924 | 16 | 0.01 % | |
| Karl Johnny Hersvik (Chief Executive Officer)1) Anita Utseth (SVP Business Support and Act. SVP Exploration)3) |
315 | 539 116 |
5 | 503 40 |
9 | 19 436 |
56 72 |
1 106 0.04 % |
| Øyvind Bratsberg (SVP Technology & Field Development) Kjetil Kristiansen (SVP HR)2) |
135 | 680 76 |
2 | 505 8 |
12 | 31 213 |
63 0 |
1 261 0.00 % |
| Alexander Krane (Chief Financial Officer) Rolf J. Brøske (SVP Comm.)7) |
177 | 474 63 |
5 | 268 24 |
10 | 31 244 |
3 | 752 0.00 % |
| Geir Solli (SVP Operations )4) Gro G. Haatvedt (VP Exploration)2) |
77 | 232 260 |
14 | 7 201 |
3 | 322 19 |
0 476 |
0.00 % 939 |
| Kjetil Ween (SVP Drilling and Wells)4) | 51 | 111 | 8 | 6 | 171 | 0 | 0.00 % | |
| Odd R. Heum (SVP Asset Johan Sverdrup)5) Elke R. Njaa (SVP Company Development/Special Projects)4) |
52 | 349 124 |
9 | 177 7 |
4 | 29 185 |
0 | 529 0.00 % |
| Bård Atle Hovd (SVP Ivar Aasen Project)5) Leif G. Hestholm (SVP HSE & Q)4) |
50 | 686 122 |
6 | 235 6 |
3 | 34 179 |
0 | 924 0.00 % |
| Anita Utseth (SVP Business Support and Act. SVP Exploration)3) Total remuneration of senior executives in 2014 |
3 843 | 315 2 733 |
90 | 116 262 |
5 595 |
40 7 261 |
243 | 436 0.00 % |
| Group Group |
Parent company | ||||
|---|---|---|---|---|---|
| Breakdown of payroll expenses (USD 1 000) Breakdown of payroll expenses (USD 1 000) |
2014 | 2013 2014 |
2014 2013 |
2013 | |
| Payroll expenses | 78 739 58 030 | 78 784 | 58 030 | ||
| Payroll expenses Pension |
-15 529 | 78 739 6 558 |
58 030 184 |
6 558 | |
| Pension Social security tax |
12 682 | -15 529 8 208 |
6 558 12 138 |
8 208 | |
| Social security tax Other personnel costs |
2 753 | 12 682 2 757 |
8 208 2 274 |
2 757 | |
| Share of payroll expenses classified as exploration, development or production Other personnel costs |
2 753 | 2 757 | |||
| expenses, and expenses invoiced to licences | -95 688 -69 083 | -95 367 | -69 083 | ||
| Share of payroll expenses classified as exploration, development or production Total payroll expenses expenses, and expenses invoiced to licences |
-17 042 | 6 470 | -1 987 -95 688 -69 083 |
6 470 |
-17 042 6 470 -1 987 6 470 The company's pension plan for all employees is changed from a defined benefit plan to a defined contribution plan, effective from 1 October 2014. In addition, the acquired pension liability from Marathon Oil Norge AS was settled after the acquisition. The effect of the settlements is that the pension liability is removed, and the plan assets are Total payroll expenses The company's pension plan for all employees is changed from a defined benefit plan to a defined contribution plan, effective from 1 October 2014. In addition, the acquired pension liability from Marathon Oil Norge AS was settled after the acquisition. The effect of the settlements is that the pension liability is removed, and the plan assets are used to issue an insurance policy to each employee as settlement of the obligation. These settlements resulted in a gain which is recognized in payroll expenses by USD 26 million. This explains why total payroll expenses are an income item. Reference is made to Note 22 for further details about the pension cost.
| Europe | |
|---|---|
| $\mathcal{C}_{\text{out}}$ hongt $\Lambda$ |
| used to issue an insurance policy to each employee as settlement of the obligation. These settlements resulted in a gain which is recognized in payroll expenses by USD 26 | ||||||
|---|---|---|---|---|---|---|
| million. This explains why total payroll expenses are an income item. Reference is made to Note 22 for further details about the pension cost. | Group | Parent company | ||||
| Number of man-year equivalents employed during the year | 2014 | 2013 | 2014 | 2013 | ||
| Europe | 333.0 | 220.6 | Group 333.0 |
220.6 | ||
| Southeast Asia Number of man-year equivalents employed during the year |
4.0 | 1.5 2014 |
4.0 2013 |
1.5 | ||
| Total | 337.0 | 222.1 | 337.0 | 222.1 |
| 1) Joined 1 April 2014. The amount included in "other" relates to sign-on fee. 2) Joined 1 August 2014. The amount included in "other" relates to sign-on fee. Remuneration of senior executives in 2013 3) Resigned from executive management 1 August 2014. (USD 1 000) |
Salary | Share invest ment and bonus3) |
Other benefits |
Accrued pension costs |
Other | Total remuneration |
Total number of shares (in 1 000) |
Owning interest |
|---|---|---|---|---|---|---|---|---|
| 4) Joined 15 October 2014 5) Resigned from executive management 15 October 2014. Erik Haugane (Chief Executive Officer)1) |
552 | 229 | 14 | 160 | 59 | 853 | 360 | 0.26 % |
| Øyvind Bratsberg (Chief Operating Officer and Act. General Manager) | 573 | 223 | 4 | 40 | 800 | 44 | 0.03 % | |
| 6) Share savings investment scheme earned in 2014, disbursed in 2015. Alexander Krane (Chief Financial Officer) |
354 | 40 | 5 | 39 | 399 | 2 | 0.00 % | |
| 7) Joined executive management 15 October 2014. Bjørn Martinsen (VP Exploration) 2) |
296 | 96 | 4 | 41 | 39 | 436 | 15 | 0.01 % |
| Odd Ragnar Heum (SVP Asset Johan Sverdrup) | 352 | 98 | 5 | 37 | 455 | 59 | 0.04 % | |
| Bård Atle Hovd (SVP Ivar Aasen Project) | 469 | 133 | Share 5 |
44 | 606 | 7 | 0.01 % | |
| Anita Utseth (SVP Business Support and Act. SVP Exploration) | 313 | 81 | invest 3 |
51 | Other | Accrued 397 |
46 | Total 0.03 % |
| Remuneration of senior executives in 2013 Total remuneration of senior executives in 2013 |
2 909 | Salary 901 |
ment and 39 |
411 | benefits 98 |
pension Other 3 947 |
534 | remuneration 0.38 % |
| 1) Resigned 31 July 2013. As compensation, the company pays 70 per cent of wages from the age of 60 to 67. The liability is calculated using the same actuarial assumptions as (USD 1 000) the company's other pension obligations. At the time he resigned, he owned 565 032 shares in the company. |
bonus3) | costs | ||||||
| 2) Resigned 15 October 2013. Amount in the column 'Other' relates to holiday pay earned and paid in 2013. | ||||||||
| Erik Haugane (Chief Executive Officer)1) | 552 | 229 | 14 | 160 | 59 | 853 |
3) Share savings investment scheme earned in 2012, disbursed in 2013.
1) Mr. Røkke and wife own and control TRG, which owns 67.8 per cent of Aker ASA, which through a subsidiary owns 49.99 per cent of Det norske.
The board will submit a policy statement concerning salaries and other remuneration to senior executives to the annual general meeting.
The effect for the company of implementing the above mentioned guidelines, is that the company's result is affected by the related costs.
| Name | Comments | Fee | Total numbers of shares (in 1000) as of 31.12.2014 |
Owning interest as of 31.12.2014 |
|---|---|---|---|---|
| Sverre Skogen | Chair of the Board from 17 April 2013. Chair of the compensation committee. | 153 | 0.00 % | |
| Anne Marie Cannon | Deputy Chair from 17 April 2013. Member of the audit committee. | 105 | 4 | 0.00 % |
| Jørgen C. Arentz Rostrup | Board member from 17 April 2013. Chair of the audit committee. | 98 | 4 | 0.00 % |
| Kitty Hall (Kat J. Martin) | Board member from 17 April 2013. | 76 | 0.00 % | |
| Tom Røtjer | Board member from 19 April 2012. Member of the compensation committee. | 69 | 7 | 0.00 % |
| Kjell Inge Røkke1) | Board member from 17 April 2013. | 33 | 0.00 % | |
| Gro Kielland | Board member from 20 March 2014. | 33 | 0.00 % | |
| Gudmund Evju | Employee representative from 20 March 2014. | 17 | 89 | 0.06 % |
| Inge Sundet | Employee representative from 8 August 2012. | 31 | 15 | 0.01 % |
| Kristin Gjertsen | Employee representative from 20 March 2014. Member of the compens. committee. | 32 | 6 | 0.00 % |
| Terje Solheim (1. deputy) | Employee rep. Deputy board member from 20 March 2014. | 3 | 1 | 0.00 % |
| Tormod Førland (2. deputy) | Employee rep. Deputy board member from 20 March 2014. | 3 | 36 | 0.03 % |
| Camilla Oftebro (3. deputy) | Employee rep. Deputy board member from 20 March 2014. | 3 | 0.00 % | |
| Kjetil Kristiansen | Chair of the nomination committee from 17 April 2013. | 11 | 0.00 % | |
| Finn Haugan | Member of the nomination committee. | 5 | 0.00 % | |
| Hilde Myrberg | Member of the nomination committee. | 5 | 0.00 % | |
| Members before Annual General Meeting in April 2014: | ||||
| Ståle Gjersvold | Deputy board member. Resigned 20 March 2014. | 22 | 0.00 % | |
| Bjørn Thore Ribesen | Employee rep. board member. Resigned 20 March 2014. | 10 | 17 | 0.01 % |
| Peder Garten | Employee rep. Deputy board member. Resigned 20 March 2014. | 5 | 3 | 0.00 % |
| Kjell Martin E. Edin | Employee rep. Deputy board member. Resigned 20 March 2014. | 21 | 2 | 0.00 % |
| Øyvind Eriksen | Member of the nomination committee. Resigned 20 March 2014. | 19 | 0.00 % | |
| Tonje Foss | Employee rep. board member. Resigned 20 March 2014. | 14 | 0.00 % | |
| Total fee | 769 | 185 | 0.13 % |
The Board has established guidelines for 2015 and until the annual general meeting in 2016, for salaries and other remuneration to the chief executive officer and other senior executives. The guidelines will be reviewed at the company's annual general meeting in 2015.
In order to recruit new employees and match corresponding schemes offered by competing companies, a borrowing facility has been established for the company's employees, whereby all permanent employees can borrow up to 30 per cent of their gross annual salary at an interest rate corresponding to the taxable norm interest rate. The lender is one selected bank, and the company guarantees for the employees' loans. Guarantees furnished by the company for employee loans in 2014 amounted to USD 4.2 million . The corresponding figures for 2013 were USD 5.4 million. The company covers the difference between the market interest rate and the norm interest rate for tax purposes at any time. As security for such loans, the company signs additional contracts with the employees, entitling it to make deductions for defaulting payment from holiday pay and pay during notice periods. The bank manages the facility, collects interest payments/instalments and follows up any default. The company pays a small annual fee for this work.
It is up to the board to decide whether to pay bonuses, based on the previous year's performance. For 2014, the bonus was set to 16.5 per cent of the base salary. The bonuses were disbursed in February 2015.
Adjustment of the CEO's base salary is decided by the board. Adjustment of the base salaries for other senior executives is decided by the CEO within the wage settlement framework adopted by the board. See comments in the section 'Remuneration of senior executives in 2014'.
In 2014, the company's remuneration policy has been in accordance with the guidelines described in the Board of Directors' Report for 2013 and submitted to the annual general meeting for an advisory vote in April 2014.
Senior executives receive a basic salary, adjusted annually. The company's senior executives participate in the general arrangements applicable to all the company's employees as regards bonus programme, pension plans and other payments in kind such as free newspaper, free internet connection at home and subsidized fitness centre fees. In special cases, the company may offer other benefits in order to recruit personnel, including to compensate for bonus rights earned in previous employment.
The company's auditor's fees are allocated as follows:
| Group | Parent company | |||
|---|---|---|---|---|
| (USD 1 000) | 2014 | 2013 | 2014 | 2013 |
| Office costs, including rental of premises | 9 133 | 10 209 | 9 133 | 10 209 |
| IT costs | 17 463 | 15 198 | 17 234 | 15 198 |
| Advertising and profiling | 1 218 | 1 598 | 1 591 | 1 598 |
| Travel expenses | 4 858 | 2 881 | 4 901 | 2 881 |
| Underwriter's, consultant's and auditor's fees | 32 445 | 5 711 | 32 413 | 5 711 |
| Operating expenses charged to licences/ classified as fixed assets, exploration | ||||
| and production costs | -38 819 | -33 589 | -37 544 | -33 589 |
| Preparation for operation on development licences | 8 458 | 5 149 | 8 458 | 5 149 |
| Area fee | 6 758 | 9 822 | 6 758 | 9 822 |
| Other operating expenses | 7 679 | 1 719 | 6 880 | 1 719 |
| Other operating expenses | 49 193 | 18 698 | 49 826 | 18 698 |
| The increase in underwriter's, consultant's and auditor's fees compared to 2013 is mainly related to increased costs pertaining to the acquisition of | ||||
| Marathon Oil Norge AS. |
| Group | Parent company | ||||
|---|---|---|---|---|---|
| Auditor's fees (all figures are exclusive of VAT) | 2014 | 2013 | 2014 | 2013 | |
| Fees for statutory audit services - KPMG | 113 | 113 | |||
| Fees for statutory audit services - EY | 109 | 166 | 109 | 166 | |
| Other attestation services - EY | 3 | 5 | 3 | 5 | |
| Tax advice - KPMG | 1 | 1 | |||
| Tax advice - EY | 19 | 37 | 19 | 37 | |
| Audit-related fees - EY | 13 | 13 | |||
| Audit-related fees - PWC | 177 | 148 | |||
| Services other than audit services - EY | 12 | 24 | 12 | 24 | |
| Services other than audit services - PWC | 19 | 17 | |||
| Total auditor's fees | 466 | 231 | 434 | 231 |
EY was Det norske's statutory auditor until April 2014, and was then replaced by KPMG. PWC is the auditor of the subsidiary Det norske oljeselskap AS.
| Group | Parent company | |||
|---|---|---|---|---|
| (USD 1 000) | 2014 | 2013 | 2014 | 2013 |
| Interest income | 7 009 | 6 934 | 7 003 | 6 934 |
| Total interest income | 7 009 | 6 934 | 7 003 | 6 934 |
| Return on financial investments | 72 | 168 | 72 | 168 |
| Currency gains | 19 363 | |||
| Dividend from subsidiaries | 22 827 | |||
| Total other financial income | 19 435 | 168 | 22 899 | 168 |
| Interest expenses | 85 107 | 57 872 | 85 108 | 57 872 |
| Capitalized interest cost, development projects | -40 383 | -21 565 | -40 383 | -21 565 |
| Amortized loan costs and accretion expenses | 39 122 | 15 052 | 38 173 | 15 052 |
| Total interest expenses | 83 845 | 51 359 | 82 898 | 51 359 |
| Currency losses | 7 269 | 754 | 7 269 | |
| Realized loss on derivatives | 8 671 | 2 027 | 8 671 | 2 027 |
| Change in fair value of derivatives | 10 616 | 540 | 993 | 540 |
| Decline in value of financial investments | 9 | 9 | 9 | 9 |
| Total other financial expenses | 19 296 | 9 844 | 10 428 | 9 844 |
| Net financial income (+) / expenses (-) | -76 697 | -54 101 | -63 423 | -54 101 |
The currency gains and losses can mainly be ascribed to realized and unrealized exchange rate fluctuations relating to the company's credit facilities, bank accounts, tax payable, trade receivables and trade creditors in currencies other than USD.
The capitalized rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalization is 8.2 per cent. The corresponding rate for 2013 was 9.1 per cent.
| Group | Parent company | |||
|---|---|---|---|---|
| Tax base (USD 1 000) | 2014 | 2013 | 2014 | 2013 |
| Profit/loss (-) before tax | -375 624 | -433 100 | -439 674 | -433 100 |
| Permanent differences | 309 846 | -23 980 | 282 349 | -23 980 |
| Change in temporary differences | -465 750 | 52 042 | -455 352 | 52 042 |
| Basis for ordinary income tax (27%) | -531 528 | -405 038 | -612 677 | -405 038 |
| Current year uplift | -102 611 | -54 986 | -99 185 | -54 986 |
| Financial items subject to only 27% ordinary tax | -415 675 | 44 980 | -396 044 | 44 980 |
| Basis for special tax (51%) | -1 049 814 | -415 044 | -1 107 906 | -415 044 |
| Breakdown of the current year's tax income (-)/tax expense (+) | Group | Parent company | ||
|---|---|---|---|---|
| (USD 1 000) | 2014 | 2013 | 2014 | 2013 |
| Calculated current year tax/exploration tax refund | -581 667 | -240 456 | -633 204 | -240 456 |
| Prior periods' adjustments to tax refund | -916 | -2 851 | -916 | -2 851 |
| Current tax income/expense | -582 583 | -243 306 | -634 119 | -243 306 |
| Prior periods' adjustments to deferred tax | 1 738 | 26 | 1 738 | 26 |
| Change in deferred tax | 484 360 | -96 472 | 471 847 | -96 472 |
| Deferred tax income / expense (-) | 486 098 | -96 446 | 473 585 | -96 446 |
| Net tax expense (+)/tax income (-) | -96 485 | -339 753 | -160 535 | -339 753 |
| Effective tax rate in % | 26 % | 78 % | 37 % | 78 % |
The tax rate for general corporate tax changed from 28 to 27 per cent from 1 January 2014. The rate for special tax changed from the same date from 50 to 51 per cent. Also the uplift, a special income deduction in the basis for calculation of special tax, changed of 5 May 2013 to 5.5 per cent for four years, totalling 22 per cent of the investment. Before this date, the uplift was 7.5 per cent for four years, with a total of 30 per cent of the investment. Transitional rules allow uplift at the old rate to projects with PDO applications submitted prior to 5 May 2013. The old rate applies up to the year of production start of the project.
| Group | Parent company | |||
|---|---|---|---|---|
| Tax rate | 2014 | 2013 | 2014 | 2013 |
| 27% | -101 418 | -121 268 | -124 875 | -121 268 |
| 51% | -191 568 | -216 550 | -235 875 | -216 550 |
| -3 567 | -3 567 | |||
| 51% | -51 537 | -27 493 | -49 790 | -27 493 |
| 51% | 98 055 | 19 935 | 103 673 | 19 935 |
| 15 255 | 15 255 | |||
| 78% | -38 530 | -38 530 | ||
| 78% | 267 006 | -3 252 | 267 006 | -3 252 |
| 78% | -36 133 | -21 128 | ||
| 78% | -159 660 | -174 796 | ||
| 78% | 113 461 | 113 461 | ||
| 78% | 3 840 | -2 813 | 320 | -2 813 |
| -96 485 | -339 753 | -160 535 | -339 753 | |
The acquisition of Marathon Oil Norge AS was conducted with tax continuity. The exploration tax refund previously recognized in Det norske is deducted against the tax payable balance acquired from Marathon Oil Norge AS, and the net tax payable for 2014 is recognized as current liability in the balance sheet.
| Profit/loss (-) before tax |
|---|
| Permanent differences |
| Change in temporary differences |
| Basis for ordinary income tax (27%) |
| Current year uplift |
| Financial items subject to only 27% ordinary tax |
| Basis for special tax (51%) |
*Tax balances are fixed at the currency rate of the transaction date, 15 October 2014. When the NOK/USD currency rate increases, the tax rate increases as there is less remaining tax depreciation measured in USD.
According to statutory requirements, the calculation of current tax is required to be based on NOK currency. This may impact the tax rate when the functional currency is different from NOK. The main factor in Q4 is the foreign exchange losses of the RBL facility in USD, which is a taxable loss without any corresponding impact on profit before tax.
The revaluation of tax 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. 144
| Breakdown of tax effect of temporary differences and tax | Applied | Group | Parent company | ||
|---|---|---|---|---|---|
| losses carry forward (USD 1 000) | tax rate | 2014 | 2013 | 2014 | 2013 |
| Capitalized exploration costs | 78% | -227 463 | -263 616 | -227 463 | -263 616 |
| Other intangible assets | 78% | -459 953 | -57 930 | -459 953 | -57 930 |
| Other intangible assets | 27% | -96 | -106 | -96 | -106 |
| Tangible fixed assets | 78% | -975 581 | 54 667 | -975 581 | 54 667 |
| Overlift/underlift of oil | 78% | -20 683 | -2 254 | -20 683 | -2 254 |
| Pension liabilities | 78% | -1 741 | 8 528 | -1 741 | 8 528 |
| Other provisions | 78% | 395 006 | 139 677 | 395 006 | 139 677 |
| Other provisions | 27% | 18 | 38 | 18 | 38 |
| Arrangement fee, short-term loans | 78% | -985 | -985 | ||
| Arrangement fee, short-term loans | 27% | -633 | -633 | ||
| Arrangement fee, bond issue | 78% | -345 | -345 | ||
| Arrangement fee, bond issue | 27% | -667 | -1 053 | -667 | -1 053 |
| Arrangement fee, multicurrency loan | 78% | -21 513 | -4 767 | -21 513 | -4 767 |
| Arrangement fee, multicurrency loan | 27% | -9 482 | -3 092 | -9 482 | -3 092 |
| Financial instruments | 27% | 8 249 | 2 131 | 8 249 | 2 131 |
| Contract rights | 78% | 27 550 | 27 550 | ||
| Tax losses carry forward | 27% | 78 827 | 78 827 | ||
| Tax losses carry forward | 51% | 154 464 | 154 464 | ||
| Other | 76 | 76 | |||
| Total deferred tax liability (-)/deferred tax asset (+) | -1 286 357 | 103 625 | -1 286 357 | 103 625 |
| Reconciliation of change in deferred tax (-)/deferred tax | Group | Parent company | ||
|---|---|---|---|---|
| asset (+) (USD 1 000) | 2014 | 2013 | 2014 | 2013 |
| Deferred tax/ deferred tax assets as of 1.1 | 103 625 | -22 744 | 103 625 | -22 744 |
| Change in deferred taxes in Income statement | -484 360 | 96 540 | -471 847 | 96 540 |
| Deferred tax related to acquisition of Marathon Oil Norge AS | -911 363 | -923 876 | ||
| Deferred tax on current year's impairment booked directly to | ||||
| Statement of financial position | 15 255 | 15 255 | ||
| Deferred tax related to impairment and disposal of licences | 14 938 | 17 556 | 14 938 | 17 556 |
| Deferred tax charged to OCI and equity | 4 999 | -539 | 4 999 | -539 |
| Foreign currency translation reserve* | -14 195 | -2 443 | -14 195 | -2 443 |
| Total deferred tax liability (-) / deferred tax asset (+) | -1 286 357 | 103 625 | -1 286 357 | 103 625 |
| Group | Parent company | |||
|---|---|---|---|---|
| Reconciliation of tax receivable (+)/tax payable (-) (USD 1 000) | 2014 | 2013 | 2014 | 2013 |
| Tax receivable/payable at 1.1 | 231 972 | 228 826 | 231 972 | 228 826 |
| Current year tax in Income statement | 581 667 | 240 456 | 633 204 | 240 456 |
| Tax payable related to acquisition of Marathon Oil Norge AS | -910 332 | -937 304 | ||
| Tax payment/tax refund | -81 464 | -219 814 | -81 464 | -219 814 |
| Prior period adjustments | -528 | 6 956 | -528 | 6 956 |
| Revaluation of tax payable | 19 574 | -4 991 | ||
| Foreign currency translation reserve* | -29 988 | -24 451 | -29 988 | -24 451 |
| Tax receivable (+)/tax payable (-) | -189 098 | 231 972 | -189 098 | 231 972 |
*Foreign currency translation reserve arises on the difference between average and currency rates at end of period applied when deriving USD from NOK amounts, as described in the accounting principles, Section 1.2.
Note 14: Tangible fixed assets and intangible assets
| Acquisition cost 31.12.2013 |
|---|
| Acquisition of Marathon Oil Norge AS |
| Additions |
| Disposals |
| Reclassification |
| Acquisition cost 31.12.2014 |
| Acc. depreciations & impairment losses 31.12.2014 |
| Foreign currency translation reserve* |
| Book value 31.12.2014 |
| Group | Parent company | |||
|---|---|---|---|---|
| (USD 1 000) | 2014 | 2013 | 2014 | 2013 |
| Profit/loss for the year attributable to ordinary equity holders of the parent entity |
-279 139 | -93 347 | -279 139 | -93 347 |
| The year's average number of ordinary shares (in thousands) | 165 811 | 140 707 | 165 811 | 140 707 |
| Earnings per share in USD | -1.68 | -0.66 |
| 2014 - GROUP (USD 1 000) | Fields under development |
Production facilities, including wells |
Fixtures and fittings, office machinery etc. |
Total |
|---|---|---|---|---|
| Acquisition cost 31.12.2013 | 270 752 | 723 154 | 25 704 | 1 019 610 |
| Acquisition of Marathon Oil Norge AS | 432 338 | 1 205 199 | 3 581 | 1 641 117 |
| Additions | 585 592 | -13 345 | 9 196 | 581 443 |
| Disposals | 278 | 278 | ||
| Reclassification | 89 080 | -324 | 88 756 | |
| Acquisition cost 31.12.2014 | 1 377 762 | 1 914 683 | 38 203 | 3 330 648 |
| Acc. depreciations & impairment losses 31.12.2014 | 702 112 | 18 449 | 720 561 | |
| Foreign currency translation reserve* | -53 206 | -6 495 | -1 115 | -60 816 |
| Book value 31.12.2014 | 1 324 556 | 1 206 077 | 18 639 | 2 549 271 |
| Depreciation for the year | 138 089 | 3 008 | 141 097 | |
| Impairment losses for the year | -3 313 | -3 313 |
| 2014 - PARENT COMPANY (USD 1 000) | Fields under development |
Production facilities, including wells |
Fixtures and fittings, office machinery etc. |
Total |
|---|---|---|---|---|
| Acquisition cost 31.12.2013 | 270 752 | 723 154 | 25 704 | 1 019 610 |
| Acquisition of Marathon Oil Norge AS | 455 390 | 1 191 229 | 3 509 | 1 650 128 |
| Additions | 562 867 | -13 744 | 9 196 | 558 320 |
| Disposals | 278 | 278 | ||
| Reclassification | 88 752 | -5 | 88 747 | |
| Acquisition cost 31.12.2014 | 1 377 762 | 1 900 634 | 38 131 | 3 316 527 |
| Acc. depreciations & impairment losses 31.12.2014 | 688 063 | 18 377 | 706 440 | |
| Foreign currency translation reserve* | -53 206 | -6 495 | -1 115 | -60 816 |
| Book value 31.12.2014 | 1 324 556 | 1 206 077 | 18 639 | 2 549 271 |
| Depreciation for the year | 124 041 | 2 936 | 126 977 | |
| Impairment losses for the year | -3 313 | -3 313 |
Earnings per share is calculated by dividing the year's profit/loss attributable to ordinary equity holders of the parent entity, which was USD -279.1 million (USD -93.3 million in 2013) by the year's weighted average number of outstanding ordinary shares, which was 165.8 million (140.7 million in 2013). There are no option schemes or convertible bonds in the company. This means that there is no difference between the ordinary and diluted earnings per share.
*Foreign currency translation reserve arises on the difference between average and currency rates at end of period applied when deriving USD from NOK amounts, as described in the accounting principles, Section 1.2.
144 113
The negative addition in 2014 for producing assets mainly relates to decreased estimates for removal and decommissioning costs.
INTANGIBLE ASSETS:
| 2013 - GROUP and PARENT COMPANY (USD 1 000) | Fields under development |
Production facilities, including wells |
Fixtures and fittings, office machinery etc. |
Total |
|---|---|---|---|---|
| Acquisition cost 31.12.2012 | 568 365 | 221 449 | 22 647 | 812 461 |
| Additions | 231 078 | 47 502 | 5 158 | 283 738 |
| Reclassification | -489 131 | 491 340 | 2 209 | |
| Acquisition cost 31.12.2013 | 310 313 | 760 291 | 27 805 | 1 098 409 |
| Acc. depreciations & impairment losses 31.12.2013 | 587 289 | 15 984 | 603 273 | |
| Foreign currency translation reserve* | -39 561 | -17 184 | -1 558 | -58 303 |
| Book value 31.12.2013 | 270 752 | 155 819 | 10 263 | 436 834 |
| Depreciation for the year | 73 494 | 3 362 | 76 856 | |
| Impairment losses for the year | -306 219 | 402 299 | 96 080 |
| Other intangible assets | Exploration | ||||
|---|---|---|---|---|---|
| 2014 - GROUP (USD 1 000) | Licences, etc. Software | Total | Goodwill | wells | |
| Acquisition cost 31.12.2013 | 148 381 | 7 906 | 156 287 | 76 541 | 337 969 |
| Acquisition of Marathon Oil Norge AS | 515 966 | 515 966 | 1 486 086 | 37 899 | |
| Additions | 64 627 | 1 976 | 66 603 | 148 643 | |
| Disposals/expensed dry wells | 120 336 | ||||
| Reclassification | -88 756 | ||||
| Acquisition cost 31.12.2014 | 728 974 | 9 882 | 738 856 | 1 562 627 | 315 419 |
| Acc. depreciations & impairment losses 31.12.2014 | 69 280 | 7 346 | 76 626 | 371 676 | |
| Foreign currency translation reserve* | -13 212 | -231 | -13 443 | -4 248 | -23 800 |
| Book value 31.12.2014 | 646 482 | 2 306 | 648 788 | 1 186 704 | 291 619 |
| Depreciation for the year | 18 947 | 210 | 19 156 | ||
| Impairment losses for the year | 7 417 | 7 417 | 347 919 |
| Other intangible assets | |||||
|---|---|---|---|---|---|
| 2014 - PARENT COMPANY (USD 1 000) | Licences, etc. Software | Total | Goodwill | wells | |
| Acquisition cost 31.12.2013 | 148 381 | 7 906 | 156 287 | 76 541 | 337 969 |
| Acquisition of Marathon Oil Norge AS | 512 395 | 512 395 | 1 486 086 | 37 899 | |
| Additions | 64 627 | 1 976 | 66 603 | 148 643 | |
| Disposals/expensed dry wells | 120 345 | ||||
| Reclassification | -88 747 | ||||
| Acquisition cost 31.12.2014 | 725 403 | 9 882 | 735 285 | 1 562 627 | 315 419 |
| Acc. depreciations & impairment losses 31.12.2014 | 65 709 | 7 346 | 73 054 | 371 676 | |
| Foreign currency translation reserve* | -13 212 | -231 | -13 443 | -4 248 | -23 800 |
| Book value 31.12.2014 | 646 482 | 2 306 | 648 788 | 1 186 704 | 291 619 |
| Depreciation for the year | 15 375 | 210 | 15 585 | ||
| Impairment losses for the year | 7 417 | 7 417 | 347 919 |
Capitalized exploration expenditures are re-classified to 'Fields under development' when the field enters the development phase. Fields under development are re-classified 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 decommissioning cost for production facilities is included as 'Production facilities', and has increased by USD 341.0 million in 2014 (in all material respect related to the acquisition of Marathon Oil Norge AS) and USD 28.2 million in 2013, see Note 23.
| Reconciliation of depreciation in the Income statement - GROUP (USD 1 000) | 2014 | 2013 |
|---|---|---|
| Depreciation of tangible fixed assets | 141 097 | 76 856 |
| Depreciation of intangible assets | 19 156 | 3 207 |
| Total depreciations for the year | 160 254 | 80 063 |
| Other intangible assets | |||||
|---|---|---|---|---|---|
| 2013 - GROUP and PARENT COMPANY (USD 1 000) | Licences, etc. Software | Total | Goodwill | Exploration wells |
|
| Acquisition cost 31.12.2012 | 198 409 | 8 117 | 206 526 | 115 796 | 390 826 |
| Additions | 20 755 | 497 | 21 251 | 215 011 | |
| Disposals/expensed dry wells | 79 | 79 | 233 117 | ||
| Relinquished licences | 54 999 | 54 999 | 30 444 | ||
| Reclassification to tangible fixed assets | -2 209 | ||||
| Acquisition cost 31.12.2013 | 164 086 | 8 614 | 172 700 | 85 354 | 370 511 |
| Acc. depreciations & impairment losses 31.12.2013 | 44 426 | 7 387 | 51 813 | 24 593 | |
| Foreign currency translation reserve* | -14 196 | -457 | -14 653 | -7 977 | -32 543 |
| Book value 31.12.2013 | 105 465 | 770 | 106 234 | 52 784 | 337 969 |
| Depreciation for the year | 2 844 | 363 | 3 207 | ||
| Impairment losses for the year | 21 217 | 21 217 | 11 303 |
| Reconciliation of depreciation in the Income statement - PARENT (USD 1 000) | 2014 | 2013 |
|---|---|---|
| Depreciation of tangible fixed assets | 126 977 | 76 856 |
| Depreciation of intangible assets | 15 585 | 3 207 |
| Total depreciations for the year | 142 562 | 80 063 |
The lenders have security in form of pledge in all current licences (exploration, development and producing assets), insurance policies, floating charge and accounts receivable.
Book value of licences as of 31 December 2014 relates to fields in the exploration and evaluation phase, development phase and production phase with USD 114.0 million, USD 104.0 million, and USD 403.4 million, respectively. Corresponding figures for 2013 were USD 82.1 million, USD 20.0 million and USD 6.7 million.
*Foreign currency translation reserve arises on the difference between average and currency rates at end of period applied when deriving USD from NOK amounts, as described in the accounting principles, Section 1.2.
Software is depreciated over its useful life (three years), using the straight-line method. Licences related to fields in production is depreciated using the
Unit of Production method.
The nominal oil price based on the forward curve applied in the impairment test is as follows:
| (in real terms) | ||||||
|---|---|---|---|---|---|---|
| Year | 2015 | 2016 | 2017 | 2018 | 2019 | From 2020 |
| USD/BOE | 61.73 | 68.85 | 72.84 | 75.49 | 77.51 | 85.00 |
| Year | 2015 | 2016 | 2017 | 2018 | 2019 | From 2020 |
|---|---|---|---|---|---|---|
| NOK/USD | 7.48 | 7.47 | 7.38 | 7.31 | 7.22 | 7.00 |
Impairment tests of individual cash-generating units are performed when impairment triggers are identified. The significant decrease in market prices for oil and gas products is considered to represent an impairment trigger. Two categories of impairment tests have been performed:
Impairment is recognized when the book value of an asset or a cash-generating unit 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 2014 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 longer 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 December 2014.
Future price level is a key assumption and has significant impact on the net present value. Forecast oil and gas prices are based on the management's estimates and available market data. Information about market prices in the near future can be derived from the futures contract market. The 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 from the beginning of 2015 to the end of 2019. From 2020, the oil price is based on the company's long-term price assumptions.
Discount rates represent the current market assessment of the time value of money and individual risks of the underlying assets that have not been incorporated in the cash flow estimates. 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.
The reserves applied in the impairment testing are based on the proven and probable reserves. The recoverable amount is sensitive to changes in reserves. For more information about the determination of the reserves, reference is made to Note 1, Section 1.3 about important accounting assessments, estimates and assumptions.
As Det norske's functional currency changed to USD from 15 October 2014, the company is exposed to exchange rate fluctuations between USD and non-USD cash flows with regard to the financial statements. Significant cash flows are invoiced and paid in Norwegian kroner, including a large part of future capex and opex as well as all tax payments to the Norwegian State. In line with the methodology for future oil price, it has been concluded to apply the forward curve for the currency rate from 2015 until the end of 2019, and the company's long term assumption from 2020 and onwards. This results in the following currency rates being applied in the impairment tests for 2014:
Based on the above, the post tax nominal discount rate is set to 9.1 per cent. For the impairment test in 2013, the corresponding rate was 10.7 per cent. In 2013 the risk free rate was based on NOK, whereas it was based on USD in 2014 in line with the change in functional currency.
In the impairment tests above, no projected cash flows go beyond the forward period (i.e. 2019).
| Technical goodwill from the acquisition of Marathon Oil Norge AS (see Note 3) | 1 196 458 |
|---|---|
| Residual goodwill from the acquisition of Marathon Oil Norge AS (see Note 3) | 289 628 |
| Technical goodwill from previous business combinations | 48 537 |
| Impairment charge / (reversal) |
Carrying value after |
||
|---|---|---|---|
| Cash generating unit (USD 1 000) | Intangible | Tangible | impairment |
| Glitne | -15 242 | ||
| Jotun Unit | -12 051 | ||
| Jette | 20 478 | 38 210 | |
| Varg | -1 741 | ||
| Atla | 5 243 | 4 048 | |
| Fulla (PL 362) | 4 709 | ||
| Freke/Dagny (PL 029B) | 2 708 | ||
| Total | 7 417 | -3 313 | 42 258 |
Technical goodwill has been allocated to individual cash-generating units (CGUs) for the purpose of impairment testing. All fields tied back to the Alvheim FPSO are assessed to be included in the same cash-generating unit ("Alvheim CGU"), which means that all producing fields acquired with Marathon Oil Norge AS are included in one cash-generating unit. The residual goodwill from the acquisition is allocated to a group of CGUs including all fields acquired from Marathon Oil Norge AS and 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 with 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.
For the purpose of impairment testing, goodwill acquired through business combinations has, prior to any impairment charges in 2014, been allocated as follows:
In Q4 2014, the removal estimates for several fields were reduced. Some of these fields had previously been written down to zero, and a reduction in the removal asset therefore leads to an immediate impact in the Income statement presented as reversed impairment. The impact from the decreased removal estimates is offset by decreased prices and other changes in assumptions from previous impairment calculations. On Jette, the company experienced lower than forecast production in Q1 2014, which led to a reassessment and reduction of reserves, resulting in an impairment charge.
The impairment test of assets other than goodwill was performed prior to the annual goodwill impairment test. If these assets are found to be impaired, their 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.
The long-term inflation rate is assumed to be 2.5 per cent. This is equal to Norges Bank's long-term inflation target, and is therefore considered a reasonable estimate of the inflation rate for the cost level. The 2.5 per cent rate is slightly above the Federal Reserve's assumed USD inflation target of 2 per cent. The increase in oil prices have exceeded inflation over the past decades, and the company expects that this may continue going forward since oil is a non-renewable resource in limited supply.
The carrying value of some fields also included intangible assets (licence rights) from prior year business combinations. The related deferred tax impact from these balances is netted against the impairment charge rather than presented as tax in the Income statement. Below is an overview of the impairment charge and the carrying value per cash-generating unit where impairment has been recognized or reversed in 2014:
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 | 2 280 508 |
| + Technical goodwill | 1 196 458 |
| - Deferred tax related to technical goodwill | -1 178 484 |
| Net carrying value pre-impairment of goodwill | 2 298 482 |
The impairment charge is the difference between the recoverable amount and the carrying value.
| (USD 1 000) | |
|---|---|
| Net carrying value as specified above | 2 298 482 |
| Recoverable amount (including tax amortization benefit) | 1 957 888 |
| Impairment charge | 340 594 |
The main reason for the impairment charge is the decreased oil price assumptions from the acquisition date to 31 December 2014. In addition, deferred tax on the asset values recognized in relation to the acquisition decreased during Q4 as a result of depreciation of these values. As depicted in the table about carrying value above, deferred tax (from the date of acquisition) reduces the net carrying value prior to the impairment charges. When deferred tax from the initial recognition decreases, more goodwill is as such exposed for impairment. Going forward, depreciation of values calculated in the purchase price allocation (see Note 3) will result in decreased deferred tax liability.
| Total goodwill impairment after | |||
|---|---|---|---|
| Increase in assumption | Decrease in | ||
| Assumption (USD million) | Change | assumption | |
| Oil and gas price | +/- 20% | 720.8 | |
| Production profiles (reserves) | +/- 5% | 241.3 | 439.8 |
| Discount rate | +/- 1% point | 394.9 | 283.4 |
| Currency rate USD/NOK | +/- 1.0 NOK | 277.3 | 422.9 |
| Inflation | +/- 1% point | 273.6 | 403.2 |
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 remain constant.
Technical goodwill is included in the carrying amount of the two exploration fields (Fulla and Freke/Dagny) where intangible assets have been impaired during 2014. As the recoverable amount for these fields are assessed to be zero, the remaining technical goodwill is fully impaired, amounting to USD 3.2 million for Fulla and USD 1.9 million for Freke/Dagny. In addition, the remaining goodwill of USD 2.2 million on the producing field Atla has been impaired in 2014, resulting in a total impairment of goodwill from prior year business combinations of USD 7.3 million.
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 following impairments (reversals) have been recorded:
| Group and parent | |||
|---|---|---|---|
| (USD 1 000) | 2014 | 2013 | |
| Impairment of other intangible assets/licence rights | 7 417 | 21 217 | |
| Impairment of tangible fixed assets | -3 313 | 96 080 | |
| Impairment of technical goodwill | 347 919 | 11 303 | |
| Deferred tax | -5 604 | -15 255 | |
| Total impairments | 346 420 | 113 346 |
Impairment of tangible fixed assets was related to Jette, Varg, Jotun and Glitne with USD 59, 23, 11 and 3 million, respectively. The impairment was mainly due to reduction in reserves and increase in the estimate of the abandonment provision. The impairment losses related to intangible assets/ licence rights and goodwill of USD 21 and 11 million was mainly related to PL 522 and PL 332, as a result of being in the process of relinquishment. The remaining impairments relate to various exploration licences that have been or are in the process of being relinquished.
* discount rate of 10.7 per cent nominal after tax (weighted average cost of capital - WACC)
* oil prices were based on forward prices, and it was expected that 2017 would be the final year of production for fields that were currently under
production.
| Age distribution of accounts receivable as of 31.12. for the group was as follows: | ||||||
|---|---|---|---|---|---|---|
| Year (USD 1 000) | Total | Not due | <30 d | 30-60d | 60-90d | >90d |
| 2013 | 22 062 | 7 754 | 13 767 | -17 | 29 | 530 |
| 2014 | 186 461 | 116 838 | 62 741 | 6 869 | 14 |
| Group | Parent company | ||||
|---|---|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | |
| Receivables related to the sale of petroleum | 182 384 | 11 652 | 182 384 | 11 652 | |
| Receivables related to licence transactions | 285 | 211 | 285 | 211 | |
| Invoicing related to expense refunds, including rigs | 3 792 | 10 200 | 3 792 | 10 200 | |
| Total accounts receivable | 186 461 | 22 062 | 186 461 | 22 062 | |
| Group | Parent company | ||||
|---|---|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | |
| Receivables related to deferred volume at Atla* | 5 866 | 510 | 5 866 | 510 | |
| Pre-payments, including rigs | 41 682 | 24 159 | 41 682 | 24 159 | |
| VAT receivable | 7 986 | 1 881 | 7 986 | 1 881 | |
| Underlift | 22 896 | 3 059 | 22 896 | 3 059 | |
| Other receivables, including operated licences | 106 162 | 52 482 | 106 162 | 52 482 | |
| Total other short-term receivables | 184 592 | 82 091 | 184 592 | 82 091 |
The company's customers are large, financially sound oil companies. Trade debtors consist mainly of receivables related to the sale of oil and gas, sale and swap of licences and sublease of offices, and also recharging of expenses pertaining to other licence partners.
*For information about receivables related to deferred volume at Atla, see Note 18.
| JSD 1 000) |
|---|
| ------------ |
| USD 1 000) | |
|---|---|
| ------------ | -- |
| Group | Parent company | ||||
|---|---|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | |
| Receivables related to deferred volume at Atla | 8 799 | 20 618 | 8 799 | 20 618 | |
| Total long-term receivables | 8 799 | 20 618 | 8 799 | 20 618 | |
For information regarding shares in subsidiaries, see Note 4.
| Group | Parent company | ||||
|---|---|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | |
| Shares in Det norske oljeselskap AS | 1 021 | ||||
| Shares in Alvheim AS | 10 | 10 | |||
| Shares in Sandvika Fjellstue AS | 1 814 | 1 972 | 1 814 | 1 972 | |
| Investment in subsidiaries | 1 824 | 1 972 | 2 845 | 1 972 | |
| Debt service reserve | 42 810 | 42 810 | |||
| Tenancy deposit | 1 774 | 2 129 | 1 774 | 2 129 | |
| Total other non-current assets | 3 598 | 46 912 | 4 619 | 46 912 |
| Group | Parent company | ||||
|---|---|---|---|---|---|
| Breakdown of cash and cash equivalents (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | |
| Cash | 1 | 1 | |||
| Bank deposits | 291 346 | 278 336 | 290 325 | 278 336 | |
| Restricted funds (tax withholdings) | 4 897 | 2 605 | 4 897 | 2 605 | |
| Total cash and cash equivalents | 296 244 | 280 942 | 295 222 | 280 942 |
The company has unused amounts available for withdrawal on the reserve-based lending facility, described in more detail in Note 26.
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 stalled the production from the neighbouring field Skirne. The Skirne partners have therefore historically received and sold oil and gas from Atla, but from 2014 they started to deliver oil and gas back to the Atla partners. Revenue was recognized based on physical production volumes measured at market value, similar to over/underlift. This deferred compensation is recorded as long-term or short-term receivables, depending on when the delivery of oil and gas is expected.
The item 'Cash and cash equivalents' consists of bank accounts and short-term investments that constitute parts of the company's transaction liquidity.
All shares in the company carry the same voting rights.
| Parent company | |||
|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | |
| Share capital | 37 530 | 27 656 | |
| No. of shares (in 1 000) | 202 619 | 140 707 | |
| The nominal value per share is NOK | 1.00 | 1.00 |
| No. of shares | Owning | |
|---|---|---|
| Overview of the 20 largest shareholders registered as of 31.12.14: | (in 1 000) | interest |
| AKER CAPITAL AS | 101 289 | 49.99 % |
| FOLKETRYGDFONDET | 10 421 | 5.14 % |
| ODIN NORGE | 3 325 | 1.64 % |
| VERDIPAPIRFONDET DNB NORGE (IV) | 2 828 | 1.40 % |
| VPF NORDEA NORGE VERDI | 2 722 | 1.34 % |
| KLP AKSJE NORGE VPF | 2 485 | 1.23 % |
| THE NORTHERN TRUST CO. | 2 449 | 1.21 % |
| VERDIPAPIRFONDET DNB NORGE SELEKTI | 2 423 | 1.20 % |
| FONDSFINANS SPAR | 2 200 | 1.09 % |
| VPF NORDEA KAPITAL | 2 151 | 1.06 % |
| JP MORGAN CHASE BANK, NA | 1 784 | 0.88 % |
| MORGAN STANLEY & CO. LLC | 1 723 | 0.85 % |
| TVENGE | 1 600 | 0.79 % |
| DANSKE INVEST NORSKE INSTIT. II. | 1 590 | 0.78 % |
| KOMMUNAL LANDSPENSJONSKASSE | 1 574 | 0.78 % |
| MORGAN STANLEY & CO. INTERNATIONAL | 1 265 | 0.62 % |
| STATOIL PENSJON | 1 265 | 0.62 % |
| DANSKE BANK | 1 025 | 0.51 % |
| KLP AKSJE NORGE INDEKS VPF | 927 | 0.46 % |
| SEB PRIVATE BANK S.A. | 889 | 0.44 % |
| OTHER | 56 684 | 27.98 % |
| Total | 202 619 | 100 % |
During 2014, the company issued NOK 3 billion in new equity through a rights issue. 61 911 239 new shares were issued at NOK 48.50, with nominal value at NOK 1.00 and share premium at NOK 47.50.
The company is required to have an occupational pension scheme pursuant to the Act relating to compulsory occupational pensions. The company's pension plan satisfies the requirements of the Act.
| Components of net periodic pension cost recognized Unsecured scheme Secured scheme |
Total | ||||
|---|---|---|---|---|---|
| 2014 | 2013 | 2014 | 2013 | 2014 | 2013 |
| 29 | 5 642 | 6 137 | 5 642 | 6 166 | |
| -25 751 | -25 751 | ||||
| 104 | 90 | 121 | 227 | 224 | 317 |
| 104 | 119 | -19 988 | 6 364 | -19 884 | 6 483 |
| Cost of defined contribution pension | |||||
| Pension costs collective early-retirement pension scheme (AFP) | 371 | ||||
| Total pension costs | 6 875 | ||||
| 3 709 647 -15 529 |
The company's pension plan for all employees has changed from a defined benefit plan to a defined contribution plan during 2014, effective from 1 October 2014. Based on actuarial calculations, the settlement of the defined benefit plan is recorded per 30 September 2014. In addition, the defined benefit plan in Marathon Oil Norge AS was settled after the acquisition, resulting in a gain. The accounting consequences of the settlement are that previous gross pension liability is reset to zero and the pensions funds are used to issue an insurance policy to each employee. In the income statement the effect of settlement is recorded as part of the salary and pension costs by USD 25.7 million.
| Other comprehensive income | Unsecured scheme | Secured scheme | Total | |||
|---|---|---|---|---|---|---|
| R=Remeasurements loss (+) gain (-) (USD 1 000) | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 |
| R - change in discount rate | 582 | -30 | 5 277 | -1 009 | 5 859 | -1 039 |
| R - change in other financial assumptions | -495 | -2 250 | -2 971 | -2 745 | -2 971 | |
| R - change in mortality table | 29 | 1 161 | 1 191 | |||
| R - experience DBO | 3 | 588 | 921 | 2 869 | 924 | 3 457 |
| R - experience Assets | -209 | -1 509 | -209 | -1 509 | ||
| Investment management cost | 246 | 179 | 246 | 179 | ||
| OCI losses (+) gains (-) during period (pre-tax) | 90 | 588 | 3 986 | -1 279 | 4 076 | -692 |
The former CEO has an early retirement pension arrangement (unsecured). The pension obligation has been calculated based on actuarial assumptions as of 31 December 2014 and 2013.
As from 1 September 2011, the company has introduced a collective early-retirement pension scheme (AFP). In accordance with IAS 19.148, this pension scheme is recorded as a defined contribution plan. There is not sufficient information available to account the pension plan as a defined benefit plan. The premium paid is recorded as the pension cost and no pension obligation is recorded. Total premiums expensed in 2014 amounted to USD 0.6 million. Expected payment for 2015 will be at the same level but increased, as the activity of the former Marathon Oil Norge AS will be included for the whole year.
| The year's change in gross pension liability | Unsecured scheme | Secured scheme | Total | |||
|---|---|---|---|---|---|---|
| (USD 1 000) | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 |
| Gross pension liability (PBO) as of 01.01. | 2 859 | 2 611 | 23 560 | 19 234 | 26 420 | 21 845 |
| Service cost | 29 | 5 586 | 6 137 | 5 586 | 6 166 | |
| Interest cost | 104 | 90 | 694 | 630 | 798 | 720 |
| Pension payments | -509 | -220 | -15 | -7 | -524 | -228 |
| Payroll tax on premium payments | -998 | -662 | -998 | -662 | ||
| The year's actuarial loss/(gain) | 90 | 588 | 3 945 | 81 | 4 035 | 669 |
| Acquisition (disposal) | -33 030 | -33 030 | ||||
| Foreign currency translation* | -524 | -239 | 258 | -1 852 | -266 | -2 091 |
| Gross pension liability (PBO) as of 31.12 | 2 021 | 2 859 | 0 | 23 560 | 2 021 | 26 419 |
| The year's change in gross pension funds | Unsecured scheme | Secured scheme | Total | |||
|---|---|---|---|---|---|---|
| (USD 1 000) | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 |
| Gross pension funds as of 1.1. | 15 487 | 10 115 | 15 487 | 10 115 | ||
| Expected returns on pension funds/interest income | 517 | 403 | 517 | 403 | ||
| Actuarial loss/gain | -41 | 1 360 | -41 | 1 360 | ||
| Pension payments | -15 | -7 | -15 | -7 | ||
| Premium payments | 8 079 | 5 358 | 8 079 | 5 358 | ||
| Payroll tax on premium payments | -998 | -662 | -998 | -662 | ||
| Acquisition (disposal) | -23 029 | -23 029 | ||||
| Foreign currency translation* | -1 079 | -1 079 | ||||
| Fair value of pension funds | 0 | 15 487 | 0 | 15 487 |
| Net pension funds (+) / liability (-) as of 31.12. | Unsecured scheme | Secured scheme | Total | ||||
|---|---|---|---|---|---|---|---|
| (USD 1 000) | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |
| Net pension funds/liability (-) as of 31.12. | -1 771 | -2 506 | -7 076 | -1 771 | -9 582 | ||
| Social security tax | -250 | -353 | -998 | -250 | -1 350 | ||
| Net capitalized pension funds (+) / liability (-) | -2 021 | -2 859 | -8 073 | -2 021 | -10 932 |
| Unsecured scheme | Secured scheme | Total | ||||
|---|---|---|---|---|---|---|
| Change during period (USD 1 000) | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 |
| Net capitalized pension funds (+) / liability (-) as of 1.1. | -2 859 | -2 611 | -8 073 | -9 112 | -10 933 | -11 724 |
| Acquired pension liability | -16 618 | -16 618 | ||||
| The year's pension cost | -194 | -707 | 15 744 | -6 364 | 15 551 | -7 071 |
| Payments premium and pension | 509 | 220 | 8 079 | 5 351 | 8 587 | 5 571 |
| Foreign currency translation* | 524 | 239 | 868 | 2 052 | 1 392 | 2 291 |
| Net capitalized pension funds (+) / liability (-) | -2 021 | -2 859 | 0 | -8 073 | -2 021 | -10 932 |
| Financial assumptions | 2014 | 2013 |
|---|---|---|
| Discount rate | 2.30 % | 4.00 % |
| Return on pension funds | 2.30 % | 4.00 % |
| Wage and salary increase | 2.75 % | 3.75 % |
| Base amount adjustment | 2.50 % | 3.50 % |
| Pension adjustment | 1.50 % | 1.75 % |
| Actuarial assumptions | 2014 | 2013 |
| Mortality table used | K2013 BE K2013 BE | |
|---|---|---|
| Disability tariff used | IR-02 | IR-02 |
| Voluntary retirement before 40 years | 4-8% | |
| Voluntary retirement after 40 years | 0-2% |
*Foreign currency translation arises on the difference between average and periodend currency rates applied when deriving USD from NOK amounts, as described in accounting principles Section 1.2.
The main part of the company's removal and decommissioning liabilities relate to the producing fields.
| (USD 1 000) |
|---|
| Principal, bond Nordic Trustee 1) Principal, bond Nordic Trustee 2) |
| Total |
| Group | Parent company | |||
|---|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 |
| Provisions as of 1 January | 160 413 | 131 180 | 160 413 | 131 180 |
| Removal obligation from acquisition of Marathon Oil Norge AS | 340 897 | 341 727 | ||
| Incurred cost removal | -14 087 | -6 251 | -13 968 | -6 251 |
| Accretion expense - present value calculation | 12 410 | 7 277 | 11 462 | 7 277 |
| Foreign currency translation reserve* | -10 674 | -1 028 | -10 674 | -1 028 |
| Change in estimates and incurred liabilities on new fields | 93 | 29 236 | 93 | 29 236 |
| Total abandonment provision | 489 051 | 160 413 | 489 051 | 160 413 |
| Breakdown of the provision in short-term and long-term liabilities | ||||
| Short-term | 5 728 | 24 225 | 5 728 | 24 225 |
| Long-term | 483 323 | 136 188 | 483 323 | 136 188 |
| Total abandonment provision | 489 051 | 160 413 | 489 051 | 160 413 |
1)The loan runs from 28 January 2011 and have been repaid in Q4 2014. 2)The loan runs from July 2013 to July 2020 and carries an interest rate of threemonth NIBOR plus 5 per cent. The principal falls due in July 2020 and interest is paid on a quarterly basis. The loan is unsecured. One of the covenant requirements on this loan is the adjusted equity ratio which shall be maintained at minimum 25 per cent. A default only exists when the ratio is below 25 per cent on two consecutive quarter dates and the covenant breach is not remedied within the following quarter reporting date. Management is working to address certain adjustments to the loan agreement going forward.
| Group | Parent company | ||||
|---|---|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | |
| Long-term derivatives - interest rate swaps | 5 646 | 8 129 | 5 646 | 8 129 | |
| Short-term derivatives | 25 224 | 25 224 | |||
| Estimated fair value | 30 870 | 8 129 | 30 870 | 8 129 |
| Estimated fair value |
|---|
| Group | Parent company | ||
|---|---|---|---|
| 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 |
| 97 359 | 97 359 | ||
| 253 141 | 309 233 | 253 141 | 309 233 |
| 253 141 | 406 592 | 253 141 | 406 592 |
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 3.89 per cent and 5.66 per cent.
The long-term derivatives are related to three interest rate swaps. The purpose is to swap floating rate loans to fixed rate. These interest rate swaps are market-to-market and recognized in the Income statement.
| Group | Parent company | ||||
|---|---|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | |
| Provisions as of 1 January | 160 413 | 131 180 | 160 413 | 131 180 | |
| Removal obligation from acquisition of Marathon Oil Norge AS | 340 897 | 341 727 | |||
| Incurred cost removal | -14 087 | -6 251 | -13 968 | -6 251 | |
| Accretion expense - present value calculation | 12 410 | 7 277 | 11 462 | 7 277 | |
| Foreign currency translation reserve* | -10 674 | -1 028 | -10 674 | -1 028 | |
| Change in estimates and incurred liabilities on new fields | 93 | 29 236 | 93 | 29 236 | |
| Total abandonment provision | 489 051 | 160 413 | 489 051 | 160 413 | |
| Breakdown of the provision in short-term and long-term liabilities | |||||
| Short-term | 5 728 | 24 225 | 5 728 | 24 225 | |
| Long-term | 483 323 | 136 188 | 483 323 | 136 188 | |
| Total abandonment provision | 489 051 | 160 413 | 489 051 | 160 413 |
The short-term derivatives are related to foreign currency contracts. The purpose is to swap spot currency rate USD/NOK to fixed rate to decrease
the currency risk related to the tax payment in NOK.
*Foreign currency translation reserve arises on the difference between average and currency rates at end of period applied when deriving USD from NOK amounts, as described in the accounting principles, Section 1.2.
| Parent company | ||
|---|---|---|
| Available for withdrawal on credit/loan facilities (USD 1 000) | 31.12.2014 | 31.12.2013 |
| Available for withdrawal | 2 693 000 | 1 000 000 |
| Drawn amount | 2 100 000 | 344 126 |
| Unused amount available for withdrawal on credit/loan facilities | 593 000 | 655 874 |
| Group | Parent company | |||
|---|---|---|---|---|
| Breakdown of other interest-bearing debt (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 |
| Reserve-based lending facility | 2 037 299 | 2 037 299 | ||
| Revolving credit facility | 334 814 | 334 814 | ||
| Total other interest-bearing debt | 2 037 299 | 334 814 | 2 037 299 | 334 814 |
| Group | Parent company | ||||
|---|---|---|---|---|---|
| Breakdown of other current liabilities (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 | |
| Current liabilities related to overcall in licences | 195 | 33 210 | 195 | 33 210 | |
| Share of other current liabilities in licences | 163 369 | 51 066 | 163 369 | 51 066 | |
| Overlift of petroleum | 7 508 | 1 576 | 7 508 | 1 576 | |
| Fair value of contracts assumed in acquisition* | 22 903 | 22 903 | |||
| Other current liabilities, including accruals | 79 838 | 44 937 | 79 838 | 44 937 | |
| Total other current liabilities | 273 813 | 130 789 | 273 813 | 130 789 |
The interest rate is 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 also paid on unused credit.
The lenders have security in the form of pledge in all current licences (exploration, development and producing assets), insurance policies, floating charge and accounts receivable.
Other current liabilities include unpaid wages and vacation pay, provision for onerous contract costs and accrued interest. *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. The fair value was based on the difference between market price and contract price. The balance is split between current and non-current liabilities based on the cash flows in the contract, and is reduced over the lifetime of the contract, which ends in 2016.
In September 2013, the company entered into a USD 1 billion revolving credit facility with a group of Nordic and international banks. On 15 October, this revolving credit facility was repaid with the proceeds from a reserve-based lending facility (RBL facility) which has been fully underwritten by BNP Paribas, DNB, Nordea and SEB. 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. At year-end 2014, the company completed a semi-annual redetermination process. Following the redetermination process, the available amount was reduced to USD 2.69 billion. For cash management purposes, Det norske has reduced the drawn amount under the facility to USD 2.1 billion at year-end 2014.
The company's share of liabilities mentioned above are assumed to fall as follows:
The company has a lease agreement until 2016 for Transocean Winner, which is currently drilling in the Greater Alvheim Area. In addition, the company had a lease agreement for Transocean Barents which expired in July 2014. The rig contract was used for exploration drilling in the company's licences or sublett to other companies. There are no remaining lease obligations relating to Transocean Barents as at 31 December 2014. As of 31 December 2013, the future lease obligation due within one year was USD 105.0 million.
The company has entered into different operating leases for rig contracts, office premises and IT services. Most of the leases contain an option for extension. The leases do not contain any restrictions on the company's dividend policy or financing.
| Group | Parent company | |||
|---|---|---|---|---|
| The lease costs for rig contracts were as follows (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 |
| Minimum lease payments | 49 700 | 67 709 | 44 978 | 67 709 |
| Payments received on subleases | -10 624 | -21 200 | -10 624 | -21 200 |
| Total | 39 076 | 46 509 | 34 355 | 46 509 |
| The lease costs for IT services and office premises were as follows | Group | Parent company | ||
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 |
| Minimum lease payments | 13 373 | 11 377 | 13 373 | 11 377 |
| Payments received on subleases | -708 | -901 | -708 | -901 |
| Total | 12 664 | 10 476 | 12 664 | 10 476 |
| Group | Parent company | |||
|---|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 |
| Within one year | 140 322 | 27 202 | 140 322 | 27 202 |
| One to five years | 253 398 | 207 881 | 253 398 | 207 881 |
| After five years | 43 075 | 43 075 | ||
| Total | 393 719 | 278 158 | 393 719 | 278 158 |
The company's share of operational lease liabilities and other long-term liabilities pertaining to its ownership interests in oil and gas fields is shown in the table below. Liabilities related to the above-mentioned rig contracts where a rig decision has been made are included.
On behalf of the partners in Ivar Aasen, the company signed an agreement in 2013 with Maersk Drilling for the delivery of a jack-up rig for the development project on the Ivar Aasen field. The rig will be used to drill production wells on the Ivar Aasen field. The contract period is five years, with options for up to seven years.
On behalf of the partners in Ivar Aasen, the company has signed several commitments regarding the development project on the Ivar Aasen field. Det norske's commitments excluding the rig contract amount to USD 369 million. In addition, the company has entered into future capital commitments (other than leases) for the Alvheim fields amounting to approximately USD 234 million as of year-end 2014. These amounts are not included in any of the tables.
| ases do not contain any restrictions on the company's dividend policy or financing. | ||||
|---|---|---|---|---|
Det norske has provided the landlord KLP with a guarantee in the amount of USD 1.7 million to cover the rent for the company's premises in Oslo.
Guarantees have also been furnished in connection with the establishment of the debt facilities.
Just like other licencees on the Norwegian Continental Shelf, the company has unlimited liability for damage, including pollution damage. The company has insured its pro rata liability on the Norwegian Continental Shelf on a par with other oil companies. Installations and liability are covered by an operational liability insurance policy.
| Group | Parent company | |||
|---|---|---|---|---|
| (USD 1 000) | 31.12.2014 | 31.12.2013 | 31.12.2014 | 31.12.2013 |
| Within one year | 13 263 | 13 119 | 13 263 | 13 119 |
| One to five years | 37 254 | 56 501 | 37 254 | 56 501 |
| After five years | 2 083 | 5 482 | 2 083 | 5 482 |
| Total | 52 600 | 75 101 | 52 600 | 75 101 |
The company has established a loan scheme whereby permanent employees can borrow up to 30 per cent of their gross annual salary at the prescribed interest rate for tax purposes. The company covers the difference between the market interest rate and the prescribed interest rate for tax purposes at any time. The lender is one selected bank, and the company guarantees for the employees' loans. Guarantees furnished by the company for employees totalled USD 4.2 million at 31 December 2014. The corresponding amount for 2013 was NOK 5.4 million.
During the normal course of its business, the company will be involved in disputes, including tax disputes. Potential tax claims related to the taxable income of Marathon Oil Norge AS before 1 January 2014 will be reimbursed from the Marathon Group. The company has made accruals for probable liabilities related to litigation and claims based on the management's best judgment and in line with IAS 37. The management is of the opinion that none of the disputes will lead to significant commitments for the company.
The company's liabilities in connection with non-terminable agreements for lease of office premises and hire of IT services:
The company has entered into a rental agreement for office premises in Oslo, which expires in 2018. The company has sublet some parts of these premises. The company has two rental agreements for office space in Trondheim and one in Harstad, of which the longest both in Harstad and Trondheim expire in 2020. The company has a rental agreement for office premises in Stavanger, which expires in 2016. In 2013, the company signed a new contract for IT services. The hire period is five years, and the contract cannot be terminated during this period.
For more details about remuneration of key executive personnel, see Note 9.
Transactions with related parties are carried out on the basis of the "arm's length" principle.
| Related party (USD 1 000) | Receivables (+) / liabilities (-) | 31.12.2014 31.12.2013 31.12.2014 31.12.2013 | |||
|---|---|---|---|---|---|
| Aker Geo | Trade creditors | 296 | 296 | ||
| Aker Business Services | Trade creditors | 35 | 35 | ||
| Aker Subsea Solutions | Trade creditors | 596 | 596 | ||
| Group | Parent company | ||||
| Related party (USD 1 000) | Revenues (-) / expenses (+) | 2014 | 2013 | 2014 | 2013 |
| Aker Achievements | Other personnel costs | 46 | 46 | ||
| Aker ASA | Software & board remuneration | 1 069 | 246 | 1 069 | 246 |
| Aker Business Services | Development costs | 1 072 | 1 072 | ||
| Aker Engineering | Development costs | 576 | 576 | ||
| Aker Geo | Exploration expenses | 349 | 349 | ||
| Aker Kværner | Other operating expenses | 1 084 | 1 084 | ||
| Aker Pharma Holdco | Other operating expenses | 107 | 107 | ||
| Aker Solutions | Development costs | 10 488 | 9 365 | 10 488 | 9 365 |
| Other Aker companies | 299 | 299 |
At year-end 2014, Aker (Aker Capital AS) was the largest shareholder in Det norske, with a total ownership interest of 49.99 per cent. An overview
of the 20 largest shareholders is provided in Note 21.
In connection with our development projects, agreements have been entered into with Aker Solutions and its subsidiaries, which are subsidiaries of Aker ASA. Det norske's share of transactions in 2014 and 2013 has been included in the table below.
| Group | Parent company | |||||
|---|---|---|---|---|---|---|
The company's equity ratio (equity in relation to total capital) as of 31 December is shown in the table below;
The following financial covenant requirements are related to our credit facility:
2) Interest cover ratio : Ebitda / interest expense should be above 3.5.
3) Liquidity, short and long-term cash flow projection.
The company met all these requirements in 2014.
In addition there are covenant requirements related to our bond loan. These covenants include:
1) Adjusted equity ratio at minimum 25 per cent.
2) Liquidity, cash position or available credit line at minimum NOK 250 million.
The main objective of the company's management of the capital structure is to maximize return to the owners by ensuring competitive conditions for both the company's own capital and borrowed capital.
The company seeks to optimize its capital structure by balancing return on equity against lenders' security and liquidity requirements. The company aims to have a good reputation in all debt markets, including the bond market and the bank market.
1) Leverage, the ratio of total net debt/group EBITDAX ( Earnings Before Interest, Taxes, Depreciation, Amortizations and Exploration Expenses) should be below 3.5.
| Group | Parent company | |||
|---|---|---|---|---|
| 31.12.2014 31.12.2013 31.12.2014 | 31.12.2013 | |||
| Equity as of 31.12 | 651 662 | 524 100 | 651 662 | 524 100 |
| Total capital | 5 384 372 | 1 732 720 | 5 384 372 | 1 732 720 |
| Equity ratio | 12.1 % | 30.2 % | 12.1 % | 30.2 % |
The company monitors changes in financing needs, risk, assets and cash flows, and evaluates the capital structure continuously. To maintain the desired capital structure, the company considers various types of instruments, including refinancing of its debt, purchase or issue new shares or debt instruments, sell assets or pay back capital to the owners.
The size of the company's resource and reserve base is very important in relation to access to capital and borrowing terms. The increase in resources and reported reserves as a result of the Marathon Oil Norge AS acquisition has significantly strengthened the company's ability to obtain attractive terms and conditions for its debt portfolio.
The company met all these requirements in 2013. At year-end 2014, the adjusted equity ratio was below the 25 per cent requirement. However, a default only exists when the ratio is below 25 per cent on two consecutive quarter dates and the covenant breach is not remedied within the following quarter reporting date. Management is working to address certain adjustments to the loan agreement going forward.
| Financial assets at fair | Financial liabilities at | Financial | |||
|---|---|---|---|---|---|
| value | fair value | liabilities | |||
| measured at | |||||
| Designated as such | Loan and | Designated as such upon | amortized | ||
| 31.12.2014 | upon initial recognition | receivables | initial recognition | costs | Total |
| Assets | |||||
| Other current financial assets | 3 289 | 3 289 | |||
| Accounts receivable | 186 461 | 186 461 | |||
| Other short-term receivables1) | 142 910 | 142 910 | |||
| Other non-current assets | 3 598 | 3 598 | |||
| Cash and cash equivalents | 296 244 | 296 244 | |||
| Total financial assets | 3 289 | 629 213 | 632 502 | ||
| Liability | |||||
| Derivatives | 30 870 | 30 870 | |||
| Trade creditors | 152 258 | 152 258 | |||
| Bonds | 253 141 | 253 141 | |||
| Reserve-based lending facility | 2 037 299 | 2 037 299 | |||
| Other interest-bearing debt | |||||
| Other short-term liabilities | 469 669 | 469 669 | |||
| Total financial liabilities | 30 870 | 2 912 367 | 2 943 237 |
| Financial assets at fair value |
Financial liabilities at fair value |
Financial liabilities |
|||
|---|---|---|---|---|---|
| Designated as such | Loan and | Designated as such upon | measured at amortized |
||
| 31.12.2013 | upon initial recognition | receivables | initial recognition | costs | Total |
| Assets | |||||
| Other current financial assets | 3 957 | 3 957 | |||
| Trade receivables | 22 062 | 22 062 | |||
| Other short-term receivables1) | 57 932 | 57 932 | |||
| Tax receivable | 231 972 | 231 972 | |||
| Other non-current assets | 46 912 | 46 912 | |||
| Cash and cash equivalents | 280 942 | 280 942 | |||
| Total financial assets | 3 957 | 639 821 | 643 778 | ||
| Liability | |||||
| Derivatives | 8 129 | 8 129 | |||
| Trade creditors | 74 368 | 74 368 | |||
| Bonds | 406 592 | 406 592 | |||
| Reserve-based lending facility | 78 579 | 78 579 | |||
| Other interest-bearing debt | 334 814 | 334 814 | |||
| Other short-term liabilities | 134 665 | 134 665 | |||
| Total financial liabilities | 8 129 | 1 029 017 | 1 037 146 |
1)Prepayments are not included in other short-term receivables, as prepayments are not deemed to constitute financial instruments.
The company has the following financial assets and liabilities: financial assets and liabilities recognized at fair value through profit or loss, loans and receivables, and other liabilities. The latter two are recognized in the accounts at amortized cost, while the first item is recognized at fair value.
1)Prepayments are not included in Other short-term receivables, as prepayments are not deemed to constitute financial instruments.
| NOK/USD | Change in exchange rate | ||
|---|---|---|---|
| Effect on pre-tax profit/loss: | + 10% | -29 121 | |
| - 10% | 29 121 |
The table below shows the company's exposure in NOK as of 31 December:
| Exposure relating to: | 31.12.2014 |
|---|---|
| Receivables, cash and cash equivalents, other short-term receivables and deposits | 309 770 |
| Trade creditors, tax payable and other short-term liabilities | -493 987 |
| Bond loan | -253 414 |
| Net exposure in NOK | -437 631 |
| USD/NOK | Change in exchange rate | 31.12.2013 |
|---|---|---|
| Effect on pre-tax profit/loss: | + 10% - 10% |
-11 983 11 983 |
The table below shows the company's exposure in USD as of 31 December:
| Exposure relating to: | 31.12.2013 |
|---|---|
| Receivables, cash and cash equivalents, other short-term receivables and deposits | 87 213 |
| Trade creditors and other short-term liabilities | -19 858 |
| Bond loan | -187 184 |
| Net exposure in USD | -119 828 |
Det norske's revenues are derived from the sale of petroleum products, and the revenue flow is therefore exposed to oil and gas price fluctuations. Prior to the acquisition of Marathon Oil Norge AS, the company had limited production volumes of oil and gas and as a result, did not enter into any commodity hedging. Post the acquisition, the company's oil and gas production has become significant, and with the current unstable macro environment the company is continuously evaluating and assessing opportunities for hedging as part of a prudent financial risk management process.
Revenues from sale of petroleum and gas are in USD and GBP, while expenditures are mainly in NOK, USD, SGD, EUR, GBP, CHF and DKK. Exchange rate fluctuations and oil prices involve both direct and indirect financial risk exposure for the company, but because a significant portion of the expenses are in USD, some of this risk is mitigated. Currency derivatives may be used. Currency positions are only used to reduce the currency risk relating to the company's ordinary operations.
Liquid assets consist of NOK, USD, SGD, EUR, GBP, CHF and DKK. All bank deposits shall be placed in accounts with interest rates and prices denominated in NOK, EUR or USD.
The following table summarizes the sensitivity to a reasonably possible change in the NOK exchange rate in 2014 and USD exchange rate in 2013, with all other variables held constant, of the group's profit before tax (due to changes in the fair value of monetary assets and liabilities in the Statement of financial position as of 31 December). The company changed its functional currency from NOK to USD on 15 October 2014, and the sensitivity analysis is therefore disclosed in NOK for 2014 and in USD for 2013.
The company is also exposed to change in other exchange rates such as GBP/USD, EUR/USD, CHF/USD, SGD/USD and DKK/USD, but the amounts are not material.
The company does not trade in financial instruments, including derivatives. The most important financial risks which the company is exposed to relate to oil prices, foreign exchange rates, interest rates and access to funding.
The company has financed its activities with a reserve-based lending facility and one bond, both with floating interest rates. In addition, the company has financial instruments such as trade debtors, trade creditors etc., directly related to its day-to-day operations. For hedging purposes, the company has invested in three interest swaps to swap floating rate to fixed rate.
The company's risk management, including financial risk management, is designed to ensure identification, analysis and systematic and costefficient handling of risk. Established management procedures provide a good basis for reporting and monitoring of the company's risk exposure.
The terms of the company's loans are described in Notes 25 and 26.
The interest-rate risk relating to cash and cash equivalents is relatively limited
The following table shows the company's sensitivity to potential changes in interest rates which is reasonably possible: Change in interest rate level in basis points: 31.12.2014 31.12.2013
| Change in interest rate level in basis points: | 31.12.2014 | 31.12.2013 | |
|---|---|---|---|
| Effect on pre-tax profit/loss: | + 100 | -18 232 | 9 952 |
| - 100 | 18 167 | -10 110 |
The company's liquidity risk is the risk that it will not be able to meet its financial obligations as they fall due.
The company's objective for the placement and management of excess capital is to maintain a low risk profile and good liquidity.
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. At closing of the Marathon Oil Norge AS acquisition on October 15 2014, Det norske drew USD 2.65 billion on the facility. At year-end, the company completed a semi-annual redetermination process with its bank consortium under the company's USD 3.0 billion reserve-based lending (RBL) facility. Following the recent redetermination process, the new borrowing base has been reduced to USD 2.693 billion. Det norske has currently drawn USD 2.1 billion under the RBL at year-end 2014.
As of 31 December 2014, the company's excess liquid assets are mainly deposited in bank accounts. As of 31 December 2014, the company has cash reserves of USD 296 million (2013: USD 280 million). The company will focus on cash management and liquidity going forward. Significant development expenses combined with revenues from production must be carefully managed on a day-to-day basis for liquidity risk management purposes.
The table shows the effect on profit or loss in 2015 from changes in expected future interest rates. Such changes in expected future interest rates would have impacted the fair value of interest-rate swaps on the balance sheet date. However, the floating rate interest received on the interest rate swaps is associated with a corresponding floating rate interest payment on a bond or a loan. A change in fair value on the interest rate swaps has reduced the exposure to interest-rate risk by USD 3.6 million in the sensitivity presented.
There shall be sufficient liquidity in regular bank accounts at all times to cover expected payments relating to operational activities and investment activities for two months ahead.
In addition, short-term (12 months) and long-term (five years) forecasts are prepared on a regular basis to plan the company's liquidity requirements. These plans are updated regularly for various scenarios and form part of the decision basis for the company's management and board of directors.
The company is exposed to interest-rate risk to borrowings and cash deposits. Floating-interest loans involve risk exposure for the company's future cash flows. As of 31 December 2014, the company's total loan liabilities amounted to approximately USD 2.3 billion, distributed between one long-term bond issue and one reserve-based lending facility. The purpose of the reserve-based lending facility is to finance the acquisition of Marathon Oil Norge AS and the company's exploration and development activities. The corresponding loan liabilities as of 31 December 2013 amounted to USD 820 million.
Excess liquidity is defined as a portfolio consisting of liquid assets other than the funds deposited in regular operational bank accounts and unused credit facilities. This means that excess liquidity includes high-interest accounts and financial investments in banks, money-market instruments and bonds.
For excess liquidity, the requirement for low liquidity risk (i.e. the risk of realization on short notice) is generally more important than maximizing
the return.
In order to calculate sensitivity of interest rate changes, floating interest rates have been changed by + / - 100 basis points.
The fair value of interest-bearing loans has been calculated using market interest rates.
The fair value of forward exchange contracts is determined using the forward exchange rate at the end of the reporting period. The fair value of interest rate swaps is determined by using the expected floating interest rates at the end of the period. The fair value is confirmed by the financial institution with which the group has entered into contracts. See Note 24 for detailed information about the derivatives.
Items included in market-based financial investments are a listed bond issued by Sparebanken Midt-Norge. The fair value of the investments are determined using the price for tax purposes as defined by the Norwegian Securities Dealers Association. In the course of the year, the value of this asset decreased by USD 0.7 million (2013: USD 0.2 million increase), and the loss is recognized as Other financial expenses in the Income statement.
| Contract related cash flow | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Less than 1 | ||||||||||
| 31.12.2014 | Book value | 1-2 years | 2-5 years over 5 years | SUM | ||||||
| Non-derivative financial liabilities: Bond issue Reserve-based lending facility Trade creditors and other liabilities |
253 141 2 037 299 152 258 |
16 537 86 689 152 258 |
16 537 86 689 |
49 611 260 066 |
253 141 2 273 378 |
335 826 2 706 822 152 258 |
||||
| Derivative financial liabilities | ||||||||||
| Derivatives | 30 870 | 25 224 | 5 646 | 30 870 | ||||||
| Total as of 31.12.2014 | 2 473 568 | 280 707 | 108 872 | 309 677 | 2 526 519 | 3 225 775 |
The following of the company's financial instruments have not been valued at fair value: liquid assets, trade debtors, other short-term receivables, other long-term receivables, short-term loans and other short-term liabilities, bonds and other interest bearing liabilities.
| Less than 1 | ||||||
|---|---|---|---|---|---|---|
| 31.12.2013 | Book value | year | 1-2 years | 2-5 years over 5 years | SUM | |
| Non-derivative financial liabilities: | ||||||
| Bond issue | 406 592 | 29 176 | 29 176 | 161 904 | 351 941 | 572 197 |
| Exploration facility | 78 579 | 88 453 | 88 453 | |||
| Revolving credit facility | 334 814 | 22 616 | 22 616 | 413 693 | 458 925 | |
| Trade creditors and other liabilities | 209 033 | 209 033 | 209 033 | |||
| Derivative financial liabilities | ||||||
| Derivatives | 8 129 | 3 903 | 3 106 | 1 109 | 8 117 | |
| Total as of 31.12.2013 | 1 037 146 | 353 181 | 54 898 | 576 706 | 351 941 | 1 336 726 |
The bond issue from September 2013 is listed on Oslo Børs, and the fair value for disclosure purposes is determined using the quoted value as of 31 December.
The risk of counterparties being financially incapable of fulfilling their obligations is regarded as minor as there have not historically been any losses on accounts receivable. The company's customers and licence partners are large and credit worthy oil companies, and it has thus not been necessary to make any provision for bad debt.
In the management of the company's liquid assets, low credit risk is prioritized. Liquid assets are placed in bank deposits, bonds and funds that represent a low credit risk.
The maximum credit risk exposure corresponds to the book value of financial assets. The company deems its maximum risk exposure to correspond with the book value of trade debtors and other short-term receivables, non-current assets and investments, see Notes 16 and 17.
The table below shows the payment structure for the company's financial commitments, based on undiscounted contractual payments:
The carrying amount of cash and cash equivalents is approximately equal to fair value, since these instruments have a short term to maturity. Similarly, the carrying amount of trade debtors, other receivables, trade creditors and other short-term liabilities is virtually the same as their fair value as they are entered into on 'ordinary' terms and conditions. Other non-current assets mainly consist of deposits, and hence their value is virtually equal to their fair value.
| 31.12.2014 | |||||
|---|---|---|---|---|---|
| year | Fair value of financial instruments: | Book value Fair value Book value | |||
| Financial assets valued at fair value through profit or loss: | |||||
| Market-based financial investments 3 289 |
3 289 | ||||
| Total financial assets 3 289 |
3 289 | ||||
| 31.12.2014 | |||||
| Fair value of financial instruments: | Book value Fair value Book value | ||||
| Financial liabilities valued at fair value through profit or loss: | |||||
| Derivatives 30 870 |
30 870 | ||||
| Contract related cash flow | Financial liabilities measured at amortized cost: | ||||
| Bond issue 253 141 |
250 114 | ||||
| year | Other interest-bearing debt 2 037 299 |
2 037 299 | |||
| Total financial liabilities | 2 321 310 2 318 283 |
The company has no assets or liabilities in Level 3.
| 31.12.2014 | |||
|---|---|---|---|
| Financial instruments recognized at fair value | Level 1 | Level 2 | Level 3 |
| Financial assets or liabilities measured at fair value with changes in value | |||
| recognized through profit or loss | |||
| Derivatives | 30 870 | ||
| Market-based financial investments | 3 289 | ||
| 31.12.2013 | |||
| Financial instruments recognized at fair value | Level 1 | Level 2 | Level 3 |
| Financial assets or liabilities measured at fair value with changes in value | |||
| recognized through profit or loss | |||
| Derivatives | 8 129 | ||
| Market-based financial investments | 3 957 |
Level 1 - input in the form of listed (unadjusted) prices in active markets for identical assets or liabilities. Level 3 - input for assets or liabilities for which there is no observable market data (non-observable input). Level 2 - input other than listed prices of assets and liabilities included in Level 1 that is observable for assets or liabilities, either directly (i.e. as prices) or indirectly (i.e. derived from prices).
In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels.
The company classifies fair value measurements by employing a value hierarchy that reflects the significance of the input used in preparing the measurements. The fair value hierarchy consists of the following levels:
Market-based financial investments 3 957 Financial assets or liabilities measured at fair value with changes in value recognized through profit or loss
The following is a comparison between the book value and fair value of the company's financial instruments, except those where the carrying amount is a reasonable approximation of fair value (such as short-term trade receivables and payables).
| Fields operated: | 31.12.2014 | 31.12.2013 |
|---|---|---|
| Ivar Aasen Unit | 34.8 % | 35.0 % |
| Jette Unit | 70.0 % | 70.0 % |
| Alvheim | 65.0 % | 0.0 % |
| Bøyla | 65.0 % | 0.0 % |
| Vilje | 46.9 % | 0.0 % |
| Volund | 65.0 % | 0.0 % |
| Production licences for which Det norske is the operator: | Production licences in which Det norske is a partner: | |||||
|---|---|---|---|---|---|---|
| Licence | 31.12.2014 | 31.12.2013 | Licence | 31.12.2014 | 31.12.2013 | |
| PL 001B | 35.0 % | 35.0 % PL 019C | 30.0 % | 30.0 % | ||
| PL 026B*** | 62.1 % | 62.1 % PL 019D | 30.0 % | 30.0 % | ||
| PL 027D | 100.0 % | 100.0 % PL 029B | 20.0 % | 20.0 % | ||
| PL 027ES | 40.0 % | 40.0 % PL 035 | 25.0 % | 25.0 % | ||
| PL 028B | 35.0 % | 35.0 % PL 035B | 15.0 % | 15.0 % | ||
| PL 036 C *** | 65.0 % | 0.0 % PL 035C | 25.0 % | 25.0 % | ||
| PL 036 D *** | 46.9 % | 0.0 % PL 038 | 5.0 % | 5.0 % | ||
| PL 088 BS *** | 65.0 % | 0.0 % PL 038D | 30.0 % | 30.0 % | ||
| PL 103B | 70.0 % | 70.0 % PL 038E ** | 5.0 % | 0.0 % | ||
| PL 150 *** | 65.0 % | 0.0 % PL 048B | 10.0 % | 10.0 % | ||
| PL 150 B *** | 65.0 % | 0.0 % PL 048D | 10.0 % | 10.0 % | ||
| PL 169C | 50.0 % | 50.0 % PL 102C | 10.0 % | 10.0 % | ||
| PL 203 *** | 65.0 % | 0.0 % PL 102D | 10.0 % | 10.0 % | ||
| PL 203 B *** | 65.0 % | 0.0 % PL 102F | 10.0 % | 10.0 % | ||
| PL 242 | 35.0 % | 35.0 % PL 102G | 10.0 % | 10.0 % | ||
| PL 340 *** | 65.0 % | 0.0 % PL 265 | 20.0 % | 20.0 % | ||
| PL 340 BS *** | 65.0 % | 0.0 % PL 272 | 25.0 % | 25.0 % | ||
| PL 364 | 50.0 % | 50.0 % PL 332 * | 0.0 % | 40.0 % | ||
| PL 414 * | 0.0 % | 40.0 % PL 362 | 15.0 % | 15.0 % | ||
| PL 414B * | 0.0 % | 40.0 % PL 438 | 10.0 % | 10.0 % | ||
| PL 450 * | 0.0 % | 80.0 % PL 442 | 20.0 % | 20.0 % | ||
| PL 460 | 100.0 % | 100.0 % PL 453S* | 0.0 % | 25.0 % | ||
| PL 494 | 30.0 % | 30.0 % PL 457 *** | 40.0 % | 0.0 % | ||
| PL 494B | 30.0 % | 30.0 % PL 492 | 40.0 % | 40.0 % | ||
| PL 494C | 30.0 % | 30.0 % PL 502 | 22.2 % | 22.2 % | ||
| PL 497 * | 0.0 % | 35.0 % PL 522 | 10.0 % | 10.0 % | ||
| PL 497B * | 0.0 % | 35.0 % PL 531* | 0.0 % | 10.0 % | ||
| PL 504 | 47.6 % | 47.6 % PL 533 | 20.0 % | 20.0 % | ||
| PL 504BS | 83.6 % | 83.6 % PL 535* | 0.0 % | 10.0 % | ||
| PL 504CS | 21.8 % | 21.8 % PL 535B* | 0.0 % | 10.0 % | ||
| PL 512 * | 0.0 % | 30.0 % PL 550 | 10.0 % | 10.0 % | ||
| PL 542 * | 0.0 % | 45.0 % PL 551 | 20.0 % | 20.0 % | ||
| PL 542B * | 0.0 % | 45.0 % PL 554 | 10.0 % | 20.0 % | ||
| PL 549S* | 0.0 % | 35.0 % PL 554B | 10.0 % | 20.0 % | ||
| PL 553 | 40.0 % | 40.0 % PL 554C ** | 10.0 % | 0.0 % | ||
| PL 573S* | 0.0 % | 35.0 % PL 558 *** | 10.0 % | 20.0 % | ||
| PL 626 | 50.0 % | 50.0 % PL 563* | 0.0 % | 30.0 % | ||
| PL 659 *** | 20.0 % | 30.0 % PL 567 | 40.0 % | 40.0 % | ||
| PL 663 | 30.0 % | 30.0 % PL 568 | 0.0 % | 20.0 % | ||
| PL 677 | 60.0 % | 60.0 % PL 571 | 0.0 % | 40.0 % | ||
| PL 709 | 40.0 % | 40.0 % PL 574 | 10.0 % | 10.0 % | ||
| PL 715 | 40.0 % | 40.0 % PL 613 | 20.0 % | 35.0 % | ||
| PL 724** | 40.0 % | 0.0 % PL 619 | 30.0 % | 30.0 % | ||
| PL 736 S *** | 65.0 % | 0.0 % PL 627 | 20.0 % | 20.0 % | ||
| PL 748** | 40.0 % | 0.0 % PL 667 | 30.0 % | 30.0 % | ||
| Total | 35 | 33 PL 672 | 25.0 % | 25.0 % | ||
| PL 676S | 10.0 % | 20.0 % | ||||
| * Relinquished licences, or Det norske has withdrawn from the licence. | PL 678BS ** | 25.0 % | 0.0 % | |||
| ** Interest awarded in the APA licensing round (Application in Predefined Areas) in | PL 678S | 25.0 % | 25.0 % | |||
| 2013. The awards were announced in 2014. | ||||||
| PL 681 | 16.0 % | 16.0 % | ||||
| *** Acquired/changed through licence transaction or licence is split. | PL 706 | 20.0 % | 20.0 % | |||
| PL 730 ** | 30.0 % | 0.0 % |
Total 44 47
The company recognizes investments in jointly controlled operations (oil and gas licences) by reporting its share of related revenues, expenses, assets, liabilities and cash flows under the respective items in the company's financial statements.
• Varg – operated by Talisman, Det norske 5 per cent
Sub-class "Approved for Development":
Det norske oljeselskap ASA's reserve and contingent resource volumes have been classified in accordance with the Society of Petroleum Engineers' (SPE's) "Petroleum Resources Management System". This classification system is consistent with Oslo Børs's requirements for the disclosure of hydrocarbon reserves and contingent resources. The framework is illustrated in Figure 1.
In line with prior years' practise, the company's reserves and contingent resources have been certified by an independent third party, AGR Petroleum Services AS.
Total net proven reserves (P90/1P) as of 31 December 2014 to Det norske are estimated at 142.95 million barrels of oil equivalent. Total net proven plus probable reserves (P50/2P) are estimated at 205.64 million barrels of oil equivalent. The split between liquid and gas and between the different subcategories can be seen in Table 1.
Changes from 2013 are summarized in Table 2. The main reason for the increased net reserve estimate is the acquisition of Marathon Oil Norge AS. The reserves associated with this acquisition represent 84 per cent and 90 per cent of the reserve increase for proven (1P/P90) and proven plus probable reserves (2P/P50), respectively.
Det norske oljeselskap ASA has a working interest in 14 fields/projects containing reserves, see Table 1. Of these fields/projects, eight are in the sub-class "On Production", six are in the sub-class "Approved for Development". Note that parts of the Alvheim Field are classified as "Justified for Production". The reason being that these reserves represent a planned infill well drilling campaign. Note also that Boa is a part of the Alvheim field. The reason for this part being reported separately is that this part extends into the UK continental shelf. Unitization agreement with the UK parties has resulted in a net share of 57.622 per cent (65*0.8865) to Det norske. The share of the rest of Alvheim is 65.0 per cent.
RESERVES PROSPECTIVE RESOURCES UNRECOVERABLE UNRECOVERABLE CONTINGENT RESOURCES TOTAL PETROLEUM INITIALLY-IN-PLACE (PIIP) UNRECOVERED PIIP COMMERCIAL SUB-COMMERCIAL DISCOVERED PIIP PRODUCTION Range of uncertainty
Not to scale
| On production | Interest | 1P / P90 (low estimate) | 2P / P50 (best estimate) | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Gross oil/cond. Gross NGL Gross gas Gross oil equival. Net oil equival. Gross oil/cond. Gross NGL Gross gas Gross oil equival. Net oil equival. | |||||||||||
| 31.12.2014 | % (million barrels) Mton | (bcm) (million barrels) (million barrels) (million barrels) Mton | (bcm) (million barrels) (million barrels) | ||||||||
| Varg | 5.0 % | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 1.47 | 0.02 | 0.16 | 2.70 | 0.14 |
| Jotun | 7.0 % | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | ||||
| Atla | 10.0 % | 0.45 | 0.70 | 4.85 | 0.48 | 0.51 | 0.79 | 5.49 | 0.55 | ||
| Jette | 70.0 % | 0.28 | 0.28 | 0.20 | 0.36 | 0.36 | 0.25 | ||||
| Alvheim | 65.0 % | 39.39 | 0.26 | 41.05 | 26.68 | 62.45 | 1.19 | 69.95 | 45.47 | ||
| Boa | 57.6 % | 13.51 | 0.24 | 14.99 | 8.64 | 18.84 | 0.33 | 20.93 | 12.06 | ||
| Vilje | 46.9 % | 12.89 | 12.89 | 6.05 | 22.37 | 22.37 | 10.49 | ||||
| Volund | 65.0 % | 11.58 | 0.11 | 12.24 | 7.96 | 16.76 | 0.20 | 18.03 | 11.72 | ||
| Total | 50.01 | 80.68 |
| Approved for Development | Interest | 1P / P90 (low estimate) | 2P / P50 (best estimate) | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Gross oil/cond. Gross NGL Gross gas Gross oil equival. Net oil equival. Gross oil/cond. Gross NGL Gross gas Gross oil equival. Net oil equival. | |||||||||||
| 31.12.2014 | % (million barrels) Mton | (bcm) (million barrels) (million barrels) (million barrels) Mton | (bcm) (million barrels) (million barrels) | ||||||||
| Enoch Unit | 2.0 % | 1.71 | 1.71 | 0.03 | 2.61 | 2.61 | 0.05 | ||||
| Ivar Aasen | 34.8 % | 113.15 | 0.81 | 4.51 | 151.22 | 52.60 | 144.59 | 0.85 | 4.71 | 184.42 | 64.15 |
| Hanz | 35.0 % | 12.11 | 0.05 | 0.26 | 14.34 | 5.02 | 16.14 | 0.07 | 0.36 | 19.28 | 6.75 |
| Gina Krog | 3.3 % | 82.33 | 2.61 | 9.59 | 173.84 | 5.74 | 106.63 | 3.30 | 12.43 | 224.17 | 7.40 |
| Viper/Kobra | 65.0 % | 4.60 | 0.07 | 5.04 | 3.28 | 7.82 | 0.12 | 8.58 | 5.58 | ||
| Bøyla | 65.0 % | 11.70 | 0.09 | 12.27 | 7.98 | 21.32 | 0.19 | 22.54 | 14.65 | ||
| Total | 74.65 | 98.58 |
Table 2 - Aggregated reserves, production, developments, and adjustments
| Justified for Development | Interest | 1P / P90 (low estimate) | 2P / P50 (best estimate) | |||||||
|---|---|---|---|---|---|---|---|---|---|---|
| Gross oil/cond. Gross NGL Gross gas Gross oil equival. Net oil equival. Gross oil/cond. Gross NGL Gross gas Gross oil equival. Net oil equival. | ||||||||||
| 31.12.2014 | % (million barrels) Mton | (bcm) (million barrels) (million barrels) (million barrels) Mton | (bcm) (million barrels) (million barrels) | |||||||
| Alvheim Kam Phase 3 | 65.0 % | 0.00 | 3.01 | 18.96 | 12.32 | 0.00 | 3.30 | 20.73 | 13.48 | |
| Alvheim East Kam L4 | 65.0 % | 2.32 | 0.06 | 2.67 | 1.73 | 4.07 | 0.10 | 4.67 | 3.04 | |
| Alvheim Kneler 1 | 65.0 % | 2.30 | 0.03 | 2.47 | 1.60 | 5.18 | 0.06 | 5.55 | 3.61 | |
| Alvheim Boa Kam North | 62.4 % | 3.81 | 0.06 | 4.22 | 2.63 | 9.06 | 0.15 | 10.02 | 6.26 | |
| Total | 18.29 | 26.38 | ||||||||
| Total Reserves 31.12.2014 | 142.95 | 205.64 | ||||||||
| Total Reserves 31.12.2013 | 48.53 | 65.76 |
| Net attributed million barrels of oil equivalent | On Production | Approved for Dev. Justified for Dev. | Total | |||||
|---|---|---|---|---|---|---|---|---|
| (mmboe) | 1P/P90 2P/P50 | 1P/P90 | 2P/P50 1P/P90 2P/P50 1P/P90 | 2P/P50 | ||||
| Balance as of 31.12.2013 | 1.37 | 3.57 | 47.18 | 62.25 | 0.00 | 0.00 | 48.55 | 65.82 |
| Production | -4.06 | -4.06 | 0.00 | 0.00 | 0.00 | 0.00 | -4.06 | -4.06 |
| Acquisitions/disposals | 49.33 | 79.74 | 11.26 | 20.23 | 18.29 26.38 | 78.87 | 126.35 | |
| Extensions and discoveries | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 |
| New developments | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 | 0.00 |
| Revisions of previous estimates | 3.37 | 1.43 | 16.23 | 16.10 | 0.00 | 0.00 | 19.61 | 17.53 |
| Balance as of 31.12.2014 | 50.01 | 80.68 | 74.67 | 98.58 | 18.29 26.38 | 142.97 | 205.64 | |
| Delta | 48.64 | 77.11 | 27.49 | 36.33 | 18.29 26.38 | 94.42 | 139.82 |
In 2014, parts of the former Ivar Aasen field have been unitized. In the 2013 report, the Ivar Aasen field included the Ivar Aasen (former Draupne) discovery, the West Cable discovery and the Hanz discovery. In this year's report, Hanz is reported separately. The reason being that the PL 001B licence (the Ivar Aasen discovery) in 2014 has been unitized with PL 457 and PL 338 BS. Also West Cable (PL 242) was included in the unitization agreement forming the Ivar Aasen Unit, with a net share to Det norske of 34.7862 per cent.
Sverre Skogen, Chair of the Board Tom Røtjer, Board member Anne Marie Cannon, Deputy Chair Kjell Inge Røkke, Board member Katherine Jessie Martin (also known as Kitty Hall), Board member Gudmund Evju, Board member Gro Kielland, Board member Inge Sundet, Board member
Kristin Gjertsen, Board member Karl Johnny Hersvik, Chief Executive Officer
Jørgen C. Arentz Rostrup, Board member
Pursuant to the Norwegian Securities Trading Act section 5-5 with pertaining regulations we hereby confirm that, to the best of our knowledge, the company's financial statements for 2014 have been prepared in accordance with IFRS, as provided for by the EU, and in accordance with the requirements for additional information provided for by the Norwegian Accounting Act. The information presented in the financial statements gives a true and fair picture of the company's liabilities, financial position and results viewed in their entirety.
To the best of our knowledge, the Board of Directors' Report gives a true and fair picture of the development, performance and financial position of the company, and includes a description of the principal risk and uncertainty factors facing the company. Additionally, we confirm to the best of our knowledge that the report "Payments to governments" as provided in a separate section in this annual report has been prepared in accordance with the requirements in the Norwegian Securities Trading Act Section 5-5a with pertaining regulations.
The Board of Directors and the CEO of Det norske oljeselskap ASA
The company has identified the following events that have occurred between the end of the reporting period and the date of this report. None of the below points are deemed to have any material impact on the financial statements as at 31 December 2014.
Production from the Bøyla field in the Greater Alvheim Area commenced on 19 January 2015. In this annual report, the development cost of Bøyla is reported as under development. This will be transferred to production assets at the time of the start-up of production.
On 13 February 2015, the plan for development and operation (PDO) for phase one and two plans for installation and operation (PIOs) were submitted to the Ministry of Petroleum and Energy. Planned production start-up is late 2019, and the estimated gross capital expenditure for the first phase is NOK 117 billion (2015 value).
For Det norske, it has always been a decisive principle that ownership interests should be distributed according to a combination of volume and value. Agreement about this was not reached, which led to Det norske not signing the unitization agreement for Johan Sverdrup. Thus, the other partners have asked the Ministry of Petroleum and Energy to conclude on the final unitization of Johan Sverdrup. Until this conclusion is made, the Ministry has decided that the operator's recommendation be used as a basis. This gives Det norske an 11.8933 per cent interest in the Johan Sverdrup unit.
On 9 February 2015, it was announced that the drilling of the Krafla appraisal well resulted in an updated resource estimate for the Krafla Main discovery, from 50 to 82 million barrels of oil equivalent. Since 2011, five discoveries have been made in the Krafla area in PL 035 and PL 272: Krafla Main, Krafla West, Askja West, Askja East and Krafla North. Based on well results and updated evaluations of the licences, recoverable resources in the two licences are expected to be in the range of 140 to 220 million barrels of oil equivalent. Det norske holds a 25 per cent interest in each of the two licences as partner.
| Offices in: | |||
|---|---|---|---|
| Oslo Alta |
Haugesund Knarvik |
Stavang Stord |
|
| Arendal | Kristiansand | Straume | |
| Bergen | Larvik | Tromse | |
| AS, a Norwegian member firm of the KPMG network of independent | Bode | Mo i Rana | Trondhe |
| ar firms affiliated with KPMG International Cooperative ("KPMG | Elverum | Molde | Tynset |
| tional"), a Swiss entity, | Finnsnes | Narvik | Tønsber |
| Grimstad | Sandefiord | Álesund | |
| and contained to concern and the company of Press and charges Provident developed | Linnand | Consultation of the state |
Telephone: (+47) 90 70 60 00 E-mail: [email protected] www.detnor.no
The headquarters in Trondheim: Det norske oljeselskap ASA Føniks, Munkegata 26 7011 Trondheim, Norway
Oslo: Det norske oljeselskap ASA Bryggetorget 1 Aker Brygge 0250 Oslo, Norway
Det norske oljeselskap ASA Fjordpiren Laberget 22 - Hinna Park 4020 Stavanger, Norway
Det norske oljeselskap ASA Havnebygget Rikard Kaarbøsgate 2, 2nd floor 9405 Harstad, Norway
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