Annual Report • Mar 24, 2014
Annual Report
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Page 16
Our exploration activity in 2013 resulted in exciting discoveries in both the Barents Sea and in the North Sea.
Page 10
Next year, the Storting will decide on the development of the Johan Sverdrup field, one of the biggest on the Norwegian shelf.
Page 22
It took Det norske eight years to become a fully fledged oil company, engaging in exploration, development and production.
Page 30
Det norske oljeselskap ASA is engaged in exploration, development and production of the petroleum resources on the Norwegian shelf. We have exploration activities in the North Sea, the Norwegian Sea and the Barents Sea. We are the operator of the development of the Ivar Aasen field in the Utsira High area in the North Sea and operator of the production on the Jette field. In addition, we have ownership inte-
rests in two of the three licences that constitute the Johan Sverdrup development.
Det norske is headquartered in Trondheim, with offices in Oslo and Harstad. Today, we have more than 250 employees. Det norske is listed on Oslo Børs under the ticker "DETNOR".
For additional information about Det norske, please visit www.detnor.no.
Always moving forward to create value on the Norwegian shelf
Annual reports can be rather dull, yet the information published in them is important to any company. Det norske wants to make its annual report exciting reading. We have good stories to tell both shareholders and others. This is why we have chosen to publish this annual report in a magazine format.
For Det norske, 2013 was a year of many good stories. We have made exciting discoveries, and the Norwegian Parliament has approved the development of the Ivar Aasen field. Furthermore, we have confirmed that Johan Sverdrup is an oil field showing enormous potential.
Jette is perhaps the smallest field on the Norwegian shelf, but when production started in May, it was a significant milestone for Det norske. Now we are an integrated exploration, development and production company. Our employees are happy and proud to be working for our company. They know that we emphasize what is most important; health, safety and the environment.
You can read more about these great stories here. These are the same stories that we have told through advertisements, on our website and in our audiovisual productions during the year. The storytelling is important for us as a company, as well as for the understanding of our industry.
Enjoy our story!
The annual report is made by Det norske's Communication and Accounting departments, in cooperation with Vanntett design and Headspin.
Print: Communicatio Forlag.
Trondheim Headquarters
Visiting and postal address: Føniks, Munkegata 26 NO-7011 Trondheim, Norway
Tel. +47 90 70 60 00 E-mail [email protected] Oslo Visiting address: Bryggetorget 1 Aker Brygge NO-0250 Oslo, Norway Postal address: Postboks 2070, Vika NO-0125 Oslo, Norway Tel. +47 95 44 60 00
Harstad Visiting address: Havnebygget Rikard Kaarbøsgate 2, 2nd floor NO-9405 Harstad, Norway Postal address: P.O. Box 854 NO-9488 Harstad, Norway
We are always committed to each other, the company and society.
We are always curious and aiming for new and better solutions.
We always build trust and reputation through reliability and consistent behaviour.
We always put safety first and strive to create the highest possible value for our owners and for society.
| About Det norske | ||
|---|---|---|
| Organisation and values | 3 | |
| Summary Five years with Det norske |
4 | |
| Most important events of the year Quarterly key figures |
6 7 |
Organisation |
| Executive Chairman A milestone year |
8 | |
| Exploration and licences | ||
| Treasure hunt Licence to drill |
10 14 |
|
| Field development | ||
| Ivar Aasen The giant Sverdrup |
16 22 |
|
| Gina Krog | 27 | |
| Production Jette Production record |
30 32 |
|
| Health, safety and the environment What matters most |
34 | |
| Finance | ||
| Fresh capital | 38 | |
| Ethical guidelines | 40 |
| Corporate responsibility | |
|---|---|
| Petroleum activities | 41 |
| Research | 42 |
| Social responsibility | 44 |
| Organisation | |
| Thriving together | 46 |
| Always moving forward | 48 |
| Board of Directors | 50 |
| Executive management | 51 |
| Words and phrases | 52 |
| Petroleum quiz | |
| Board of Directors' Report | 55 58 |
| Board of Directors' Report on Corporate Governance |
70 |
| Financial Statements | |
| with Notes | |
| Board of Directors' and | |
| Chief Executive Officer's | 79 |
| statement | 126 |
It took Det norske eight years to become a fully fledged oil company, engaging in exploration, development and production.
Page 30
Johan Sverdrup
Next year, the Storting will decide on the development of the Johan Sverdrup field, one of the biggest on the Norwegian shelf.
Page 22
Exploration
Our exploration activity in 2013 resulted in exciting discoveries in both the Barents Sea and in the North Sea.
Page 10
4 ANNUAL REPORT 2013 ANNUAL REPORT 2013
Licences and operatorships
Number of employees 2009 2010 2011 2012 2013 0 50 100 150 200 250
Producing fields
Merger with Aker Explo ration. Det norske merges with Aker Exploration and strengthens its position as the second largest compa ny on the Norwegian shelf.
Plan for the Ivar Aasen field. Det norske submits Plan for development and operation of the Ivar Aasen field to the Ministry of Petroleum and Energy. This is the company's first major development as operator.
Fully fledged oil company. With start-up of production on the Jette field, Det norske has become a fully fledged oil company with activities in the enti re chain of value creation; exploration, development and production.
Giant discovery. Det norske participates in the Johan Sverdrup discovery. The company is one of the most successful companies listed on Oslo Børs with a growth rate of more than 200 percent.
High level of explorati on activities. Det norske participates in 15 wells, of which nine as operator. The company conducts its first production test on the Ivar Aasen field – with very positive results.
| 2013 | 2012 | 2011 | 2010 | 2009 | |
|---|---|---|---|---|---|
| No. of licence interests as of 31 December | 80 | 67 | 65 | 66 | 67 |
| No. of operatorships | 33 | 26 | 28 | 30 | 34 |
| Production | 1 629 115 bbl | 544 734 bbl | 548 268 bbl | 763 494 bbl | 673 603 bbl |
| Average production per day | 4 463 bbl | 1 488 bbl | 1 502 bbl | 2 092 bbl | 1 845 bbl |
| Reserves (P50) as of 31 December | 66 mill. bbl | 65 mill. bbl | 68 mill. bbl | 1 mill. bbl | 29 mill. bbl |
| Reserves (P50) and contingent resources (P50) as of 31 December |
* | 525 mill.bbl | 492 mill. bbl | 177 mill. bbl | 165 mill. bbl |
| Total operating revenues | 944 MNOK | 332 MNOK | 438 MNOK | 366 MNOK | 265 MNOK |
| Operating profit/loss before depreciation and amortisation |
-1 091 MNOK | -1 582 MNOK | -849 MNOK | -1 292 MNOK | -1 168 MNOK |
| Operating profit/loss | -2 227 MNOK | -3 843 MNOK | -1 078 MNOK | -1 591 MNOK | -1 435 MNOK |
| Income/loss before taxes | -2 545 MNOK | -3 949 MNOK | -1 311 MNOK | -1 736 MNOK | -1 389 MNOK |
| Net income/loss | -549 MNOK | -957 MNOK | -370 MNOK | -564 MNOK | -513 MNOK |
| Exploration costs | 1 637 MNOK | 1 609 MNOK | 1 012 MNOK | 1 412 MNOK | 1 186 MNOK |
| Total exploration costs (expensed and capitalised) |
1 659 MNOK | 1 656 MNOK | 1 810 MNOK | 2 449 MNOK | 1 804 MNOK |
| Cash flow before financing activities | -1 889 MNOK | -2 156 MNOK | -266 MNOK | -1 105 MNOK | -865 MNOK |
| Book value of equity | 3 188 MNOK | 3 736 MNOK | 3 677 MNOK | 3 058 MNOK | 3 858 MNOK |
| Market capitalisation | 9 385 MNOK | 11 608 MNOK | 11 257 MNOK | 3 000 MNOK | 3 756 MNOK |
| No. of shares as of 31 December | 140 707 363 | 140 707 363 | 127 915 786 | 111 111 111 | 111 111 111 |
| Nominal value per share as of 31 December | 1.00 NOK | 1.00 NOK | 1.00 NOK | 1.00 NOK | 1.00 NOK |
| Share price as of 31 December | 66.7 NOK | 82.5 NOK | 88.0 NOK | 27.0 NOK | 33.8 NOK |
| Number of employees as of 31 December | 230 | 214 | 173 | 193 | 176 |
* Resource figures for 2013 are not reported due to unitisation negotiations for Johan Sverdrup.
| Q1 | Q2 | Q3 | Q4 | |
|---|---|---|---|---|
| Total production (boepd) | 1 929 | 5 613 | 5 940 | 4 328 |
| Oil and gas production (Kboe) | 174 | 511 | 547 | 398 |
| Oil price realised (USD/barrel) | 112 | 103 | 112 | 109 |
| Operating revenues (MNOK) | 80 | 286 | 324 | 254 |
| Cash flow from production (MNOK) | 37 | 227 | 269 | 151 |
| Exploration expenses (MNOK) | 234 | 271 | 588 | 544 |
| Total exploration expenditures (expensed and capitalised) (MNOK) |
306 | 373 | 581 | 400 |
| Operating loss (MNOK) | -251 | -277 | -518 | -1 182 |
| Net loss for the period (MNOK) | -20 | -41 | -158 | -329 |
| No. of licences (operatorships) | 69 (28) | 72 (30) | 74 (30) | 80 (33) |
Total exploration expenditures (expensed and capitalised) (MNOK)
| 3 January | Discovery in appraisal well in the Kvitsøy basin, part of the Johan Sverdrup field in licence 265. |
|---|---|
| 24 February | Production from Glitne ends. Over a 12-year period of production, the field has produced 56 million barrels of oil equivalents, double the original estimate. |
| 8 March | The Ivar Aasen project signs a pre-unit agreement with the partners in the adjacent licence 457. The Asha discovery in licence 457 is connected to Ivar Aasen and enables a more profitable development. |
| 14 May | Discovery in the Fault Margin well in licence 265, confirming excellent reservoir qualities in the central western part of Johan Sverdrup. |
| 19 May | Det norske starts production on Jette, the company's first self-produced oil as operator. |
| 21 May | The Storting approves the plan for development and operation of the Ivar Aasen and Gina Krog fields. |
| 12 June | Det norske is awarded four new licences in the Barents Sea, including two operatorships, in the 22nd licensing round. |
| 20 June | Det norske completed a successful NOK 1.9 billion bond offering with a term of seven years. |
| 4 September | Det norske enters into a USD 1 billion revolving credit facility. The facility contains an uncommitted accordion option that could increase the facility to USD 2 billion. |
| 10 September | Oil and gas discovery on the Gohta prospect in the Barents Sea. Preliminary estimates indicate volumes between 113 and 239 million barrels of oil equiva lents. The production test showed good production rates. |
| 8 October | Karl Johnny Hersvik appointed new Chief Executive Officer of Det norske. |
| 4 November | Discovery in the Askja prospect in licence 272 in the North Sea. |
authorities, licence partners and suppliers.
In just a few years, Det norske has earned the authorities' trust. The company was awarded ten new licences in 2013, including four as operator. These awards demonstrate that the authorities believe in the company.
Exploration has been the company's core activity since its inception. The year 2013 was a year full of good results, a year where determined work led to major discoveries in both the Askja and Gohta prospects. We have spent considerable resources in the High North and are excited about the possibilities of commercial oil discoveries in the Barents Sea.
A big part of Det norske's development is related to the values on the Johan Sverdrup
field, one of the biggest oil discoveries in Norwegian history. The field represents enormous future value creation for Det norske, our owners, and, not least, for society. Managing great assets has never been easy, nor should it be. Det norske will be a responsible partner and will contribute strongly to ensure that the choice of concept, unitisation and development are successful. We have worked to ensure predictability in the funding of our major development projects up until 2020. In 2013, we succeeded in securing the necessary funding with the flexibility we need.
Erik Haugane's retirement as CEO and the board's appointment of Karl Johnny Hersvik as his successor was another important milestone for the company in 2013. Together with capable and committed colleagues, Haugane has established a solid foundation for growth. Hersvik, with his sound background from the industry, will build on this foundation and bring the company into the future.
Det norske operates on the basis of its vision of always moving forward to create value on the Norwegian shelf.
Sverre Skogen Executive Chairman of the Board
The year 2013 was a very eventful year. The Plan for development and operation (PDO) for the Ivar Aasen field was unanimously approved by the Norwegian parliament, the Storting. The approval illustrates the important role the Norwegian petroleum industry plays in Norwegian society and the broad political agreement on important development projects such as the Ivar Aasen field.
The Ivar Aasen field is a big and important project for Det norske. NOK 27 billion will be invested in the course of a few years, and during the development period, the project organisation will account for the bulk of the company. Most contracts are now in place, and the work is well under way in Trondheim, Oslo and London, in Sardinia and in Singapore.
In connection with the awarding of the development contracts, an important discussion emerged about Norwegian competitiveness. Several major contracts were
won by foreign parties, but, in reality, more than half of the investments went to Norwegian suppliers. Many of the foreign yards use Norwegian sub-suppliers.
It is puzzling that Norwegian suppliers cannot offer engineering work carried out in Norway. For me personally, as an experienced industrial leader, it is worrying that Norway cannot increase its competitiveness in relation to the jobs that require the most expertise. The engineering work for the Ivar Aasen field is carried out in the UK. I have travelled around to monitor the project's progress, and I am confident that we have a good basis for succeeding.
Another important milestone for Det norske was reached on 19 May, when we started production on the Jette field, the first oil produced by Det norske as operator. This marked Det norske's becoming a fully fledged oil company. At the same time, this has been a demanding project for us. Nevertheless, it has given us valuable experience and expertise, which are crucial factors when dealing with the
Det norske has made its place in the history of Norwegian oil production. From being a small fish in a big pond, we are now well on our way to establishing ourselves as one of the major companies on the Norwegian Continental Shelf. We are always moving forward with one objective in mind: To create value on the Norwegian shelf.
The Norwegian Continental Shelf is full of treasures, both big and small.
Det norske is always on a treasure hunt, and in 2013, the hunt bore fruit. Oil and gas discoveries in both the Barents Sea and in the North Sea increased the company's resources by more than the target for the year. The majority of the increase in resources was due to the Gohta and Askja discoveries.
Ambitious exploration strategy. Det norske remains one of the most ambitious oil companies on the Norwegian Continental Shelf. Det norske participated in a total of 14 wells in 2013, in one of them as operator. Total investments in exploration activities amounted to approximately NOK 1.7 billion. About two thirds of the company's exploration funds are invested in mature areas of the North Sea, where the infrastructure is good and the discovery rate is still high. The remaining resources are invested in less explored areas of the Norwegian Continental Shelf, primarily the Barents Sea.
Promising appraisal. An extensive appraisal programme has in 2013 been carried out on the gigantic Johan Sverdrup discovery. The programme focused on the western and southern parts of the field, with the goal of mapping the extent and quality of the discovery.
In January, the drilling of an appraisal well was completed in licence 265 in the southwestern part of the field, in the Kvitsøy basin (16/2-15). The well encountered a 30-metre oil column in Middle and Upper Jurassic sandstone layers, 20 metres of which had excellent reservoir properties. Some months later, the drilling of two appraisal wells was completed in the western
Transocean Barents. Photo: Det norske
Exploration and licences
these licences, and so far, no more exploration wells have been decided.
Det norske also started drilling in the Trell prospect in licence 102F, with Total as operator. The operation was delayed due to poor weather and technical problems. On 21 February 2014, Det norske confirmed an oil discovery of between 3 and 12 million barrels of recoverable oil. The licensees will assess the discovery in conjunction with nearby prospects with a view to further follow-up.
The only exploration well operated by Det norske was drilled in July in the Augunshaug prospect in licence 542/542B, in the southern part of the North Sea. No trace of hydrocarbons was encountered in the well. The well was drilled using the jack-up drilling rig Maersk Giant, an operation that took 55 days.
in Permian limestone on the Norwegian shelf and opens up new possibilities for exploration in the area. The operator's preliminary volume estimate is between 113 and 239 million barrels of oil equivalents.
In the Norvarg prospect a little further north in the Barents Sea, where Det norske is partner, the company drilled an appraisal well to map the properties of a gas discovery made in 2011. The well proved more sand and better porosity than the discovery well, and thus lower productivity than expected.
part of the Johan Sverdrup field. The Fault Margin well (16/2-17S) encountered an 82-metre oil column in Jurassic rock. This is the biggest oil column found so far. In addition, a sidetrack (16/2-17B) was drilled to examine the potential for possible reservoir-type Jurassic rock in the Cliffhanger South prospect in the west. No sandstone was encountered in this well, and it was classified as dry.
A small oil discovery was also made in the west, in the Cliffhanger North prospect, in exploration well 16/2-18S. The well encountered a 15-metre oil column in fractured granitic bedrock, but the production test carried out indicated poor production qualities.
In the neighbouring licence 502, where Det norske has a 22.22 percent interest, an appraisal well was drilled in a previously untested part of the discovery. The well (16/5-3) encountered a 13.5-metre oil column in Jurassic rock in a high-quality reservoir, and confirmed contact with the rest of the Johan Sverdrup field. It is very good news for Det norske that Johan Sverdrup also extends into licence 502.
Odd Ragnar Heum, SVP Asset Johan Sverdrup, is very pleased with the results of the appraisal programme:
'The appraisal programme removes uncertainty about how far the field extends along the western fault. The fact that the reservoir shows the same exceptional qualities that we have seen in the central part of the field is very good news.'
More information about the Johan Sverdrup field on page 22.
Discoveries still being made. In licence 272, in the North Sea, Det norske participated in two discoveries in the Askja West and Askja East prospects. In Askja West, a 90-metre gas column was encountered, while a 40-metre net oil column was found in Askja East. A preliminary estimate of the Askja discoveries indicates the presence of between 19 and 44 million barrels of oil equivalents. The wells were drilled to assess the potential of a possible development of the Krafla and Krafla West oil discoveries that were made in the same licence in 2011. The Krafla and Askja discoveries combined have a production potential of between 69 and 124 million barrels of oil equivalents. Several undrilled prospects remain in The Askja prospect is located in licence 272 in the northern part of the North Sea. The same licence includes the previous Krafla and Krafla West discoveries, which also extend into licence 035. The Krafla and Askja discoveries combined have potential recoverable resources of between 69 and 124 million barrels of oil equivalents.
Statoil 50% (O) Det norske 25% Svenska Petroleum 25% The Gohta prospect is located 35 kilometres northwest of the Snøhvit field in the Barents Sea. Preliminary estimates indicate a volume of between 113 and 239 million barrels of oil equivalents.
The discovery confirms a new exploration model that will have positive ripple effects for oil and gas exploration in the Barents Sea. The well was drilled by the semi-submersible drilling rig Transocean Arctic at a depth of 342 metres. This is the first exploration well in licence 492. The licence was awarded in the APA 2007 licensing round.
Lundin Petroleum 40% (O) Det norske 40% Norwegian Energy Company 20%
Film: Det norske's exploration activity in 2013
Well data and seismic: Exploration activities done by Ingeborg Waldal Verstad at Det norske's headquarters in Trondheim.
Det norske remains one of the most active oil companies on the Norwegian shelf. The company has good access to licences and operatorships.
As of 31 December 2013, Det norske had 80 licences on the Norwegian shelf. The company is operator for 33 of them. During the year, Det norske was awarded ten new licences and bought into nine. The company relinquished or sold a total of seven licences. In three licences, Det norske went from being a partner to taking over as operator.
Six new licences in APA. In connection with the awarding of licences in predefined areas (APA), Det norske was awarded ownership interests in six new licences, as operator in two of them. All the licences are in the North Sea and help to strengthen Det norske in the company's established core area.
"Det norske is very pleased with the licence
awards," says Project Manager Evy Glørstad-Clark. "To be awarded ownership interests in six licences is a firm vote of confidence from the Ministry of Petro leum and Energy. We are especially pleased to have been awarded the operatorship in our first priority".
Strengthens the High North. In the licensing rounds that are carried out every other year, Det norske was awarded four new licences, as operator in two of them. All the licences are in the Barents Sea. Det norske has thereby strengthened its exploration activities in a very promising area. The company sees the awarding of the licences in the Barents Sea as a recognition of the company's expertise, which strengthens the company's long-term work in the High North.
A licence, also called a pro duction licence, is a permit/ right to engage in exploration for petroleum resources and subsequent production on the Norwegian Continental Shelf. The licence is limited to a spe cified geographical area on the Norwegian Continental Shelf and to a specified time period. The licences are awarded by the authorities, represented by the Ministry of Petroleum and Energy, to one or more qualified oil companies.
The collaboration between the oil companies in a licence is regulated by agreements adopted by the authorities. The authorities also stipula te certain obligations when awarding licences, among other things relating to the acquisition of new seismic data or the drilling of wells. In practice, this means that the licensees must decide within a specific time period, often between one and three years, whether they wish to drill an exploration well. If they do not wish to drill, the production licence lapses.
Lundin Eni Total Statoil
Two types of licensing rounds are held for the Norwegian Continental Shelf:
Awards in Predefined Areas (APA) is an annual licensing round that comprises the mature parts of the continen tal shelf with known geology and good infrastructure. The awards give many new compa nies an opportunity to explore areas that have been available for several years, but that have been relinquished for various reasons. This concerns areas on the whole continental shelf: the North Sea, the Norwegian Sea and the Barents Sea.
The ordinary licensing rounds comprise the less explored parts of the conti nental shelf. These rounds are normally held every second year. In 2013, the 22nd licen sing round was held. When the very first licensing round was announced in 1965, nine companies, or groups of companies, were awarded 22 production licences.
PARTNER
Exploration and licences
Licences and operatorships: Det norske has good access to licences and operatorships. At year-end 2013, the company had ownership interests in 80 licences. Det norske is the operator for 33 of these.
I n the first week of November, the first steel was cut at SMOE's yard in Batam in Indonesia. At the same time, the work on the platform deck started at the yard in Singapore. Sverre Skogen, Executive Chairman, could strike the gong to mark the construction start.
The next day, he visited Saipem's yard in Arbatax in Sardinia. Here, he pressed the button to cut the first steel at the yard. For everyone involved, this marked that the work had started.
The work is based on extensive detailed engineering to determine what should be constructed. Most of the work is carried out by personnel from Mustang in Woking and Saipem in Kingston upon Thames, both located in the London area. In both places, several employees and consultants from Det norske participate in the work. Construction of the living quarters will soon commence at Apply Leirvik in Stord, the world's biggest New Norwegian-speaking municipality. Ivar Aasen would have liked that.
The whole world. The Norwegian people are behind the development of the Ivar Aasen field. On 21 May 2013, the Norwegian Storting unanimously approved the Plan for development and operation of the field, which is the first major development with Det norske as operator. Det norske has a 35 percent interest in the field.
When Det norske constructs the Ivar Aasen platform, it is a global project. It is not merely the locations where the different parts are being assembled that are important. Various products and units arrive in Singapore, Sardinia and Stord from all over the world.
The main contractors have many sub-contractors. The map of contractors shows that deliveries for the Ivar Aasen platform are made from around 150 locations. Although the major contracts were won abroad, large parts of the Ivar Aasen field will come from Norway.
Several hundred employees and consultants from Det norske are working on the Ivar Aasen project. At most, the project will involve several thousand contracted and subcontracted employees. This is the modern style of nation-building, which involves the whole world.
Bård Atle Hovd, SVP Ivar Aasen Project, says: "We in Det norske are proud of Ivar Aasen. A project of this size is a puzzle with a lot of players. It is very important for us that they all pull together to achieve the goal of starting production in the fourth quarter of 2016."
The construction of the Ivar Aasen platform is on schedule. The first steel has been cut and the welding is under way, in both Singapore and in Sardinia. Many big and small parts of what will eventually become the Ivar Aasen field have been completed.
He adds: "We have set many goals for the Ivar Aasen project. The most important one, however, is to ensure zero injuries. Health, safety and the environment are top priorities and the goal is zero serious incidents."
The goal is zero. Together with its part ners, employees and contractors, Det norske is committed to goals relating to health, safety and the environment: zero incidents; unconditional involvement and dedicated leadership; learning and pro-acti -
ve knowledge sharing; a listening, open and honest corporate culture.
Lifetime of twenty years. The Ivar Aasen field is located to the west of the Johan Sverdrup field in the North Sea and contains around 158 million barrels of oil equivalents. Det norske's share of production will amount to around 16 000 barrels of oil equivalents per day from the fourth quarter of 2016, and 23 000 barrels of oil equivalents per day at plateau production in 2019. Total investments in the project are estimated at NOK 27.4 billion. It is anticipated that the Ivar Aasen field will have an economic life of approximately 20 years, depending on oil prices and production trends. Based on the current oil price, the field is expected to generate gross revenues of approximately NOK 100 billion in its lifetime.
The field will be a phased development, with development of the Ivar Aasen and West Cable discoveries in the first phase, and the Hanz discoveries in the second phase. The production platform will be located above the Ivar Aasen reservoir, and the resources from West Cable will be drained through a well drilled from the platform. A subsea installation on Hanz will be tied to the Ivar Aasen platform to recover the resources there.
The Ivar Aasen development is co ordinated with the adjacent Edvard Grieg field, which will receive partially processed oil and gas from the Aasen field for further processing and export. The Edvard Grieg platform will also supply the Ivar Aasen platform with lift gas and electricity.
Growing field development. The Ivar Aasen development is growing after the Asha discovery made in the adjacent licence 457. This reservoir is connected to the reservoir on Ivar Aasen. The partners in the Ivar Aasen developement has signed an agreement with the licensees in licence 457 concerning joint resource utilisation. The main elements of the agreement concern the joint development of the discoveries and the distribution of ownership interests in the joint development. This work will be completed by June 2014. The Asha oil
Italy: Sverre Skogen, Executive Chairman of Det norske, pushes the button that starts the first cutting of steel in Sardinia.
Photo: Det norske
Art for Ivar Aasen: Det norske has ordered a custom-made graphic print for the Ivar Aasen development.
Artist: Marit Bjartnes.
Film: steel cutting in Sardinia
The poet and language scholar Ivar Aasen (1813-1896) was on the move for 2,735 days between 1842 and 1883. This corresponds to seven years and six months. If we divide 2,735 by 23 years, we find that Ivar Aasen travelled 119 days a year. In other words, he was on the move every third day.
Ivar Aasen never crossed any national borders. The idea of travelling abroad never really occurred to him until 1875: "I have also long had a desire to travel to Stockholm or Copenhagen and further afield, as travelling abroad is so easy these days, but I haven't really had the time."
Ivar Aasen travelled about 24,438 kilometres. This language scholar travelled a distance equivalent to half the earth's circumference to find out everything he needed to know to create a new written language on the basis of the old dialects. As much as 61 percent of his linguistic travels were by boat.
A collector short in stature but well-versed in languages. Ivar Aasen was just 161.5 cm tall and was probably dissatisfied with his short stature. He dodged his military service, not wishing to don the uniform of the Swedish king. He was fined for failing to turn up for his military service, which was the only fine he ever received.
He was very interested in plants and had a systematic collection of 509 plants. He wrote a book about Norwegian plants entitled Norske Plantenavne ('Norwegian plant names').
Ivar Aasen was well versed in langua ges – a true internationalist. He could read English, Icelandic, Old Norse, French and German, in addition to the Scandinavian languages.
Ivar Aasen was a nation-builder, but never exercised the right to vote. Up until 1884, men had to own property to be eligible to vote, which he did not. After that, he never registered on the electoral roll, which was a prerequisite for voting. When Ivar Aasen died, he had assets worth NOK 2.1 million.
Source: Historia om Ivar Aasen by Ottar Grepstad
The Ivar Aasen development comprises production of the resources in three discoveries: the Ivar Aasen discovery in PL 001B, West Cable in PL 242 and Hanz in PL 028B. Parts of the Ivar Aasen discovery extend into the neighbouring licence 457.
The Ivar Aasen field will be developed with a fixed steel platform with a plant for partial processing. The platform will also have living quarters.
The plan is to develop the Ivar Aasen field with a total of 15 wells: eight production wells and seven water injection wells. The production wells on Ivar Aasen and West Cable will be drilled from the platform, while the two wells on Hanz
will be connected to the platform by a 14-kilometre-long pipeline.
The wells will be drilled using a dedicated jack-up rig.
The Ivar Aasen field is a coordinated development with the Edvard Grieg field, located ten kilometres further south-east. Oil and gas will be sent via two pipelines to the Grieg platform for final processing and then exported through two new pipelines to the Grane oil pipeline and the SAGE gas pipeline on the UK continental shelf. The Ivar Aasen platform will be supplied with electricity from the Grieg platform.
discovery from December 2012 is located east of the Ivar Aasen field.
The discoveries. The Ivar Aasen development comprises production of the resources in three discoveries: Ivar Aasen, Hanz and West Cable in blocks 16/1 and 25/10 between the southern part of Viking Graben and the Utsira High, in the northern part of the North Sea, approximately 175 km west of Karmøy. The Ivar Aasen field was discovered in 2008, when Det norske drilled well 16/1-9 in what was then the Draupne prospect. The drilling proved hydrocarbons in sandstone of the Middle Jurassic and Upper Triassic age. Hanz was discovered by Esso in 1997, through well 25/10-8, drilled in prospects of the Middle Jurassic and Paleocene ages. Esso also drilled the West Cable prospect in 2004, encountering oil in Middle Jurassic sands through well 16/1-7.
Nation building. Ivar Aasen helped build the nation through his work to establish Nynorsk (New Norwegian) as a national language. Through its development of the Ivar Aasen field, Det norske is one of the present-day nation builders. Ivar Aasen travelled all over Norway to create a national language, while we are using resources from all over the world to develop the Ivar Aasen field. He developed cultural values for Norway as a nation – we are developing the Norwegian Continental Shelf to generate values as a basis for Norwegian wealth and welfare.
The Ivar Aasen platform deck will be built by SMOE in Singapore and Batam in Indonesia. The work is scheduled for completion in the first six months of 2016. The total weight of the deck is around 15,000 tonnes (dry weight).
The living quarters module for the Ivar Aasen platform will be built by Apply Leirvik in Stord. The module will have seven decks and a total deck space of 3,300 square metres. It will have 70 single cabins, a helideck and control room. The living quarters will be constructed of aluminium.
The steel jacket will be constructed by Saipem at the yard in Arbatax in Sardinia. The jacket will have a height of 138 metres and be installed at a depth of 112 metres. Its total weight will be around 9,000 tonnes.
Saipem has also been contracted to carry out transport and installation. The contract ensures that the platform deck can be lifted onto the jacket at the right time. The steel jacket will be installed during the first six months of 2015 and the platform deck will be lifted into place in the course of the first six months of 2016.
Aibel won the contract for the hook-up of the Ivar Aasen platform. The company is responsible for operational support, maintenance and modification assignments for the field. The offshore hook-up work will be started in summer 2016.
EMAS AMC will deliver and install pipelines for the Ivar Aasen field. The offshore installation activities will be completed by 2016. The company will lay the subsea power cable which will be connected to the platform on the adjacent Edvard Grieg field.
Siemens will deliver a complete integrated electrical, control and communications system in connection with the construction of the platform for the Ivar Aasen field in the North Sea.
Prosafe will ensure that people have a place to stay during the work on Ivar Aasen. Safe Scandinavia will be used as flotel. A flotel is mobile floating living quarters.
Maersk Drilling is to drill the wells on Ivar Aasen with the XL Enhanced 2 jack-up rig. This is one of the most advanced drilling rigs in the world. The rig is currently under construction in Singapore. Pre-drilling is scheduled to start following the installation of the platform jacket.
The Ivar Aasen field is located in the northern part of the North Sea, approximatly 175 west of Karmøy. Production is estimated to start in Q4 2016.
Statoil 50% Det norske 35% (O) Bayerngas Norge 15%
Licences: 001B, 028B and 242
All set: From Saipem's yard in Arbatax, located on the east coast of Sardinia, where the platform jacket is being constructed.
The map of contractors: The Ivar Aasen development is constructed in more than 150 locations.
Under construction in Singapore: The jack-up drilling rig XLE Enhanced is commissioned to drill the wells on the Ivar Aasen field. Here, the rig is under construction in Singapore.
Steel cutting in Singapore
Joint development: Ivar Aasen is a joint development with the adjacent field Edvard Grieg (right).
Johan Sverdrup fought to ensure that all power would be concentrated in the Storting. The breakthrough of the parliamentary system in 1884 gave life to Sverdrup's political dream of control by elected representatives of the people.
Next year, the Storting will decide on the development of the Johan Sverdrup field, one of the biggest ever fields on the Norwegian Continental Shelf. "This is an outstanding field that will generate great value for society as a whole. We are proud to be a part of this development," says Øyvind Bratsberg, Det norske's Chief Operating Officer.
The Johan Sverdrup field contains between 1.8 and 2.9 billion barrels of oil equivalents. The field will start producing in 2019 and production will continue for 50 years. In full production, the field will be responsible for a quarter of all Norwegian oil production. Sverdrup is a fantastic field of great importance to society. Most of the value creation will benefit society at large.
For Det norske, the Johan Sverdrup field is a dream come true and without doubt the company's greatest asset. It spans an area of more than 200 square kilometres and extends into three licences, and Det norske has owning interests in two of them.
Confirms the quality. In 2013, an extensive appraisal programme was carried out on the Johan Sverdrup field. The programme removed all doubt about how far the field extends along the Western fault and has confirmed that the reservoir has the same exceptional qualities as the central parts of the field. This is very encouraging.
Development solution. The Johan Sverdrup field will be developed in several phases. The partners have chosen a robust and flexible solution that facilitates continued development in the future. In the first phase, the field will be developed with a processing platform, drilling platform, riser platform and living quarters. The platforms will be installed on steel jackets linked by bridges.
Oil and gas from the Johan Sverdrup field will be exported to shore through dedicated pipelines. The oil will be transported to the Mongstad terminal in Hordaland county, while the gas will be transported through Statpipe to Kårstø in Rogaland county for processing and onward transportation. In the first phase, the Johan Sverdrup field will be supplied with power from shore.
More than 70 percent of the field's total resources Development concept: The field centre will, in the first phase, consist of a processing platform, drilling platform, riser platform and living quarters, and has been designed so as to facilitate capacity for future development. Illustration: Statoil
can be recovered using the first-phase installations. The field's expected production capacity in the first phase is between 315,000 to 380,000 barrels of oil equivalents per day. When fully developed, the anticipated plateau production for the field as a whole is between 550,000 to 650,000 barrels of oil equivalents per day.
Investments in the first phase are estimated at between NOK 100 and NOK 120 billion. The amount includes a field centre, wells, export of oil and gas, power supply, provisions for unforeseen changes and for any price developments in the market.
The partnership. The Johan Sverdrup field consists of three licences. Det norske has a 20 percent interest in licence 265 and a 22.22 percent interest in licence 502. The distribution of ownership interests in the field is decided through negotiations which must be completed by the time the Plan for development and operation (PDO) is submitted. Statoil will act as operator for the Johan Sverdrup project in the field development phase.
Forceful. Johan Sverdrup was a forceful leader. "When it is his turn to speak...he leaps to his feet and opens his mouth and, from that moment, no-one sees or hears anything except what Johan Sverdrup has to say. The words fly from his tongue like lightning, often sharp and biting," wrote the newspaper Hamar Stiftstidende in 1869. In that year, it was decided that the Storting should convene every year. Up until then, the elected assembly only met every third year.
Johan Sverdrup was a great agitator, living by and for his politics. This was his first big victory. Once the parliamentary system was implemented against the King's will in 1884, Sverdrup became Prime Minister. He paved the way for parliamentary control of all important decisions.
The Storting will also make the final decision on the development of the Johan Sverdrup field. This is scheduled to take place in the course of the first six months of 2015. Once the decision has been made, development can most likely begin, 200 years after Sverdrup was born in Larvik on 30 July 1816.
The Johan Sverdrup development. The discovery of Johan Sverdrup was made in 2010 on the Avaldsnes prospect in licence 501. A year later a major discovery was made in the Aldous Major prospect in the neighbouring licence 265, where Det norske holds a 20 percent interest. Later it was confirmed that the discovery also included licence 502.
The discovery of Johan Sverdrup was made in 2010 on the Avaldsnes prospect in licence 501. A year later a major discovery was made in the Aldous Major prospect in the neighbouring licence 265, where Det norske holds a 20 percent interest. Later it was confirmed that the discovery also included licence 502.
Partners in licence 265: Statoil 40% (O) Petoro 30% Det norske 20% Lundin Petroleum 10%
Partners in licence 501: Lundin 40% (O) Statoil 40% Maersk Oil 20%
Partners in licence 502: Statoil 44.44% (O) Petoro 33.33% Det norske 22.22%
doubt that the sand from Johan Sverdrup contains oil.
Photo: Anette Westgaard, Statoil.
Larger than Oslo: The Johan Sverdrup field extends across an area measuring more than 200 square kilometres. Here, a map of the field has been placed above the city of Oslo.
Gina Krog is a small, but important addition to Det norske's portfolio of development projects.
On 21 May 2013, the Norwegian parliament, the Storting, approved the plan for development and operation of this oil field, situated in the middle part of the North Sea. The total recoverable reserves are estimated
at 225 million barrels of oil equivalents, corresponding to approximately 7.5 million barrels for Det norske. Total investments are estimated at NOK 31 billion. Production from Gina Krog is scheduled to start in the first quarter 2017 and is expected to last until 2037. Gina Krog will be developed with a fixed platform that will be tied in to the Sleipner field for gas export. The oil will be transported by ship.
Gina Krog's resources extend into licence 029B, in which Det norske is a partner. Following the unitisation process that took place in 2012, Det norske negotiated an ownership interest of 3.3 percent. Despite this moderate interest, Det norske is still part of something big.
Gina Krog (1847–1916) was an uncompromising advocate of women's rights who played a decisive role in the struggle that led to universal suffrage for women in 1913. It is no coincidence, therefore, that Dagny was renamed Gina Krog on International Women's Day 8 March 2013, the year Norway celebrated the centenary of women's suffrage.
Statoil 58,7% (O) Total E&P Norge 38% Det norske 3.3%
Licences: 029B, 029C, 048, 303
Names are important symbols. In 2011, the Minister of Petroleum and Energy, Ola Borten Moe, proposed a new practice for naming oil fields on the Norwegian Continental Shelf. Report No 28 to the Storting, 'An industry for the future', contained a proposal that the names of fields should reflect the field's national importance. In the current system, the names proposed for new independent developments should mainly have a link to Norway's system of constitutional democracy, which emerged in the period after 1814. The names are supposed to celebrate people who played a part in the development of democracy in Norway.
In the past, the names of petroleum fields on the Norwegian Continental Shelf have mostly been inspired by Norse history and mythology and Norwegian folktales.
After Johan Sverdrup became Prime Minister, several democratising reforms were introduced. The right to vote was extended, first to include men with a certain income, and then to universal suffrage for men in 1898. The Storting introduced a jury system whereby juries in criminal cases consisted of laymen. To the delight of Ivar Aasen, who has lent his name to a field development for which Det norske is the operator, Landsmål (New Norwegian) was afforded the same status as Riksmål (Dano-Norwegian). In Sverdrup's period as Prime Minister, married women attained full legal capacity. Seven years of compulsory schooling for everyone was also introduced.
The 'general'. Johan Sverdrup was a fierce advocate for democracy, but in the last few years of his life, most people turned their back on him. Some people called him 'the little general'. The defence forces were one of his great concerns and he established the Ministry of Defence in 1885. While he was Prime Minister, he also served as Minister of the Navy, Minister of the Army and Minister of Defence. He said about his work that he 'wanted to do things that will be remembered for as long as the country is inhabited'.
Beneficial indulgence. Johan Sverdrup opposed higher taxes on beer and spirits in the 1840s. He said: 'Spirits are not an absolute evil; the indulgence is often beneficial, particularly in cold and tough climates.'
The top of the mountain. In 1840, Johan Sverdrup became famous for what was, at the time, a real feat. He was the first to climb Mount Surtningssui in Jotunheimen, Norway's seventh highest mountain at 2,368 metres above sea level. Up until then, no Norwegian was known to have reached greater heights in the Norwegian mountains.
The King's coup. Johan Sverdrup's words 'All power to this assembly' meant that both the Government and the Storting should gather in the Storting for open debates. Sverdrup submitted a draft constitutional amendment to this effect, but King Oscar II refused to approve the decision. His first refusal was in 1872. The draft amendment was submitted again on several occasions, but the King continued to say no. When Sverdrup's liberal supporters won the majority in both the Lagting and the Odelsting in 1883, impeachment proceedings were brought against the Selmer Government and most ministers were deprived of their offices. The conflict ended when King Oscar II finally asked Sverdrup to form a government on 26 June 1884. In practice, the parliamentary system had been introduced.
Source: Karsten Alnæs, Norges historie.
Johan Sverdrup (1816–1892) was a fierce advocate for democracy, but in the last years of his life, most people turned their back on him.
Illustration: Vanntett Design.
It was to take eight years for Det norske to become a fully fledged oil company engaging in exploration, development and own production.
On 19 May 2013, Det norske started production on the Jette field, thereby reaching an important milestone for the company. The company recovered its very first oil as operator for one of the smallest oil fields in the North Sea.
The Jette field is a sound addition and increased the company's production by more than 250 percent from April to May. Throughout the year, the field has produced oil from two subsea wells connected to the Jotun platform. Since the startup, the average daily production has been 6 000 barrels of oil. Good preparations and cooperation with the operator on the Jotun platform has secured a good first production year for the field.
As a measure to optimise production planning and follow-up, Det norske is continuously working to update the reservoir and well models. In the most recently updated certification of the reserves, it is assumed that the Jette field contains about five million barrels of oil.
The field is small, and there have been several challenges related to the the development. The drilling of the production wells was technically challenging. Nevertheless, Jette is the fastest developed field on the Norwegian shelf. It took Det norske less than 21 months to start production after submitting the Plan for development and operation (PDO).
Production record. The total producti on in 2013 was 1 629 115 barrels of oil equivalents, an increase of 300 percent compared with 2012 (545 734 barrels of oil equivalents). The average daily production was 4,463 barrels. Production peaked in June with an average production of 9,655 barrels per day.
In 2013, Det norske was a licensee in five producing fields. In addition to Jette (70 percent), Det norske participated as a partner in the Atla (10 percent), Jotun (7 percent), Glitne (10 percent) and Varg fields (5 percent). Due to technical problems, Enoch has not been producing in 2013. The oil was sold at an average price of USD 109 per barrel, a decrease of five percent in relation to USD 115 per barrels in 2012.
The important Varg field. After 15 years of producing oil, preparations for gas pro duction started on the Varg field in 2013. Since the start-up in December 1998, Varg has produced around 95 million barrels of oil, while more than 1 000 million Sm3 of gas has been injected into the reservoir. This is the gas that will be produced now.
The original Plan for development and operation (PDO) estimated the recoverable resources to be just over 63 million barrels. With a production of 95 million barrels so far, the Varg field has already exceeded the optimistic production forecasts by more than 50 percent.
The Glitne field . In February 2013, Det norske concluded its production on the Glitne field, nine years after production was scheduled to close down. The story of the recovery of the resources on the Glitne field illustrates the importance of measures that promote increased oil recovery and extend the useful life of mature fields. When the production on the Glitne field ended on 24 February, the field had produced 56 million barrels of oil, twice the original estimate.
The Varg field has a special place in the history of Det norske, as it was maybe the most important reason why the company was founded. After three years as operator, Hydro planned to shut down the Varg field in 2002. The licence partner Statoil supported this proposal. A shutdown would imply that the FPSO Petrojarl Varg, owned by PGS Production, would have no field assignment. At the same time, the authorities had opened up the Norwegian shelf for new companies after 2001, and Erik Haugane and Kaare Gisvold in PGS Production saw the opportunity for starting an oil company, take over the Varg field, and continue operations. PGS Petroleum (later Pertra) paid NOK 6 for a 70 percent ownership interest in the Varg field. Production continued, marking the beginning of a success story. In 2005, Pertra was sold to Talisman Energy at a price in excess of NOK 1 billion. Pertra (later Det norske) retained a five percent ownership interest in the field.
Like Pertra, Talisman was willing to invest in the field. New wells were drilled, and the use of new technology resulted in very good production from the Varg field and good profitability. Few fields have succeeded in surpassing Varg with regard to production prognoses and expected design life.
Since the original planned shutdown date, the field has produced close to 70 million barrels.
Good cooperation with Exxon: Jette produces from two subsea wells that are tied to the Jotun platform. Det norske is very pleased with the cooperation with the operator of Jotun, Exxon.
Photo: Det norske
The Jette field is in the south ern part of the North Sea, six kilometres south of the Jotun field. It was discovered in 2009 and is one of the smallest oil fields in the North Sea.
Det norske 70% (O) Petoro 30%
Operated from Trondheim: From Trondheim, the Operations Support unit has direct access to real-time data for monitoring of wells and production on the Jette field. Håvard Borthne, Field Manager (left) and VP Operations Erling Ronglan.
Photo: Thor Nielsen
Film: production start at the Jette field
Zero injuries to people or harm to the environment, zero orders from the Norwegian authorities and sound planning of health, safety and environment aspects in connection with the Ivar Aasen development had a central place in Det norske's HSE work in 2013.
The company's operational activity has been highly varied during the year. As regards drilling, the company drilled one exploration well in licence 542 on the Augunshaug prospect in the North Sea.
Seismic surveys were carried out in the Barents Sea and of the seabed on the Ivar Aasen field. In connection with the development and preparations for production on Jette, there has also been substantial maritime activity in the form of the installation of protective structures over production equipment on the seabed. All operations were carried out with good HSE results.
Safe with Aasen. In connection with the development of the Ivar Aasen field, health, safety and environmental considerations play a pivotal role in all parts of the project. Technical safety, barrier management and the prevention of major accidents all have a central place, as does ensuring good operational solutions. Det norske wishes to build a platform that will provide a good working environment, where the natural environment is also safeguarded.
HSE considerations have been systematically included in contract awards and in the follow-up of suppliers. During the year, the company has held two HSE sessions for senior executives and HSE managers from suppliers in the project. Topics addressed during the sessions were inter alia health, safety and environment in design, compliance with the project's goals and requirements relating to safety as well as the importance of interaction across disciplines and suppliers.
All the suppliers have committed themselves to the project's HSE goals and signed the project's HSE commitment declaration.
The Petroleum Safety Authority Norway carried out an inspection of the working
No non-conformances in Singapore: In November, Det norske carried out an HSE inspection at SMOE's yard in Singapore. From left: Gaute Solberg, HSE Lead, and Tonje Foss, Contract and Procurement Manager Ivar Aasen Topside. Photo: Headspin
relevant in connection with major incidents that require prolonged effort and a lot of personnel. Together with the authorities, Det norske has taken part in the industry's efforts to develop this system, and it developed plans for such an emergency response system in connection with its own operations in 2013.
Emergency preparedness. In the past year, Det norske has placed great emphasis on further developing the quality of the company's emergency response system and on facilitating present and future activities. Upon start-up of operations on Jette, the company strengthened its emergency preparedness by introducing a continuous operational standby system. Det norske has established office locations and activities abroad in connection with the development of Ivar Aasen. Emergency response plans and an emergency response organisation to deal with any incidents that might occur in these work locations are adopted.
Det norske's overall emergency preparedness organisation comprises well-trained personnel who regularly practise handling
accidents through planned emergency response drills. A considerable number of people are on standby duty at all times in order to deal with any incidents.
Det norske is a member of the Norwegian Operators' Association for Emergency Preparedness (OFFB), which has a key role in the company's emergency preparedness work. Together with OFFB, Det norske has carried out several emergency response drills in 2013, including two all-day drills. One of them concerned the development of Ivar Aasen and an incident in Singapore, while the other was related to exploration drilling on Augunshaug.
Det norske has sound oil-spill response expertise and it participates actively in NOFO (the Norwegian Clean Seas Association for Operating Companies). NOFO is specially trained in handling oil-spill response situations. Det norske has been a member of NOFO since it was founded, and contributes standby personnel to NOFO's operations team. If Det norske were to be responsible for an oil spill, NOFO would play a key role in damage limitation and oil spill recovery.
environment and material management in June, and of process integrity and barrier management in October. Both the inspections were carried out in connection with the Ivar Aasen development and the engineering studies that are being carried out at the project office in Woking, London. The findings from the inspections are being systematically followed up.
Det norske is a member of the business sector's NOx fund. By paying contributions, the company also helps to make funds available for measures aimed at reducing emissions in other industries, and in shipping and fisheries. Det norske had no reportable unforeseen discharges to sea in 2013.
The Ivar Aasen platform is being built without gas turbines for power supply and it is prepared for connection to a possible future power plant supplying the fields on the Utsira High with electricity from shore.
Barrier management plays a key role in the prevention of major accidents on Ivar Aasen. Good management of technical, operational and organisational barriers, and ensuring that the importance of this is understood at all management levels, is a crucial part of this work. Barrier management has a key role in all parts of the project and it is integrated in engineering studies, construction, preparations for operations, production drilling and in the interface between the different activities.
Another lesson learned was the need to have a coherent management system that ensures uniform organisation of different parties' emergency preparedness. By having identical incident response management and organisation of emergency preparedness, the various authorities and operating companies can cooperate better in an emergency situation. This is particularly
Det norske played an important part in establishing a joint emergency response centre through the establishment of the Norwegian Operators' Association for Emergency Preparedness (OFFB) in 2009. OFFB is Det norske's and the other member companies' second-line emergency preparedness system. Four years after the organisation was established, the number of member companies has increased from three full members in 2009 to 11 in 2013.
In addition to handling second-line emergency response for the companies, the centre plays an active role in raising the companies' expertise, as well as in emergency response training and emergency response planning. OFFB has established a centre for the development of emergency response expertise, including dealing with next-of-kin.
Det norske's goals for health, safety and the environment are to avoid harm to personnel, the environment and material assets, execute its operations in such a way that we avoid work-related illnesses, secure the technical integrity of facilities and avoid orders being issued by the Norwegian authorities.
Det norske shall achieve these objectives through integrating HSE considerations in all activities managed and carried out by the company. These considerations shall be prioritised at all levels within the company.
Det norske shall be a good employer. HSE-related issues pertaining to all activities offshore and onshore are to be taken seriously and duly followed up.
Det norske's premise is that all undesired events can be avoided.
To develop a good HSE culture and promote a healthy attitude is important in order to achieve our goals.
Film: health, safety and environment in the development of the Ivar Aasen field.
development of the Ivar Aasen field as operator and is about to embark on the major development of the Johan Sverdrup field. The banks' willingness to invest in the credit facility underlines the quality of the company's assets," says Alexander Krane, Det norske's CFO.
The share. Det norske oljeselskap ASA is listed on Oslo Børs with ticker code DETNOR. At the turn of the year, the share value was NOK 66.70 per share, corresponding to a market value of NOK 9.4 billion. That was lower than the market value at the beginning of the year. The reduction was the result of a 16 percent fall in the share price on one of the last days of December.
Since 22 June 2012, the share has been listed on the OBX Index, making it one of the most liquid shares on Oslo Børs. The shares in Det norske are divided between 5,763 share accounts. Ownership is nonetheless fairly concentrated. At year-end 2013, the 30 biggest accounts controlled 77 percent of the share capital. Det norske has a strong industrial owner, Aker Capital AS, which owns 49.9 percent of the shares in the company. The geographical breakdown of the shareholders has been relatively stable throughout 2013. At year-end, 87.5 percent of the share capital was controlled by Norwegian citizens and companies registered in Norway.
Det norske aims to ensure that the share is attractive and easily
In 2013, good work to secure financing has laid the foundation for the development of Ivar Aasen and Johan Sverdrup.
Det norske has sound finances. At year-end 2013, the company's equity ratio was 31 percent, it had good liquidity – with NOK 1.7 billion in the bank – and a substantial unused borrowing limit. Good work to secure financing has laid the foundation for the development of Ivar Aasen and Johan Sverdrup.
Det norske completed a bond offering in June, raising NOK 1 900 million in fresh capital. It is one of the biggest high-yield bond issues ever in the Norwegian market. It was the second time that Det norske has issued high-yield bonds. The bond issue will contribute to financing the development of both Johan Sverdrup and Ivar Aasen. The bonds mature in summer 2020 and have a coupon rate based on three-month NIBOR plus 5 percent.
In September, the company completed the refinancing of its revolving credit facility. The new credit facility increased drawing rights from USD 500 million to USD 1 billion. The agreement also included an option to increase the loan by a further USD 1 billion. The facility has a term to maturity of five years and falls due in 2018.
"We are very satisfied with the support Det norske has received from leading banks. It strengthens Det norske's liquidity now that the company has started
| No. of shares Percentage | ||
|---|---|---|
| Aker Capital AS | 70 339 610 49.99% | |
| Folketrygdfondet | 8 339 094 | 5.93% |
| Odin Norge | 2 645 420 | 1.88% |
| Verdipapirfondet DNB Norge Selekti 2 279 125 | 1.62% | |
| Odin Norden | 1 933 769 | 1.37% |
| Clearstream Banking S.A. | 1 555 695 | 1.11% |
| Varma Mutual Pension Insurance | 1 445 000 | 1.03% |
| KLP Aksje Norge VPF | 1 325 144 | 0.94% |
| JP Morgan Chase Bank. NA | 1 166 346 | 0.83% |
| Danske Invest Norske Instit. LI. | 1 156 849 | 0.82% |
| Tvenge | 1 100 000 | 0.78% |
| Verdipapirfondet DNB Norge (IV) | 1 081 909 | 0.77% |
| VPF Nordea Kapital | 1 080 784 | 0.77% |
| Fondsfinans Spar | 1 075 000 | 0.76% |
| VPF Nordea Norge Verdi | 1 025 804 | 0.73% |
| JP Morgan Clearing Corp. | 910 648 | 0.65% |
| Kommunal Landspensjonskasse | 880 000 | 0.63% |
| Skandinaviska Enskilda Banken AB | 800 916 | 0.57% |
| Statoil Pensjon | 800 647 | 0.57% |
| Danske Bank | 765 230 | 0.54% |
Share performance 2013
negotiable. Each share carries one vote at the general meeting and equal rights to dividend. The company is currently not in a position to pay dividend.
Det norske wishes to promote transparency in society. Nominee accounts conceal who the real owners of the shares are, and the company believes this to be unfortunate. As of 31 December 2013, 8 percent of the share capital was registered to nominee accounts.
Corporate governance. Det norske oljeselskap ASA 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. However, the company's ethics go further than mere compliance.
More detailed comments on corporate governance can be found in the Board of Directors' Report and the annual accounts.
Det norske practises a policy of zero tolerance of corruption in all its activities. 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 will place further emphasis on ethics and anti-corruption by carrying out risk assessments and introducing an anti-corruption programme for employees. Det norske will also assess how the principles of the UN Global Compact are relevant to the company's activities.
Investments
Twenty new discoveries were made in 2013, seven more than in 2012. Seven of these discoveries were made in the North Sea, eight in the Norwegian Sea and five in the Barents Sea. The discoveries contain resources of between 504 and 1,032 million barrels of oil equivalents. The level of exploration activity was highest around the Utsira High in the North Sea. Drilling started on 59 wells in 2013, consisting of 45 exploration wells and 14 appraisal wells.
A total of 1,345 million barrels of oil equivalents were produced in 2013. This is 313 million less than in the record year 2004, and 69 million less than in 2012. Four new fields started producing in 2013, including the Jette field.
Four developments were approved by the authorities in 2013. Det norske participates in two of them: the Ivar Aasen and Gina Krog fields.
Thirteen fields are currently under development on the Norwegian Continental Shelf.
It is expected that investments in 2013 will amount to NOK 173 billion. The Norwegian Petroleum Directorate expects the high level of activity in the petroleum sector to continue, but that growth will stagnate. Up until now, growth has been the result of increased activity and increased costs in the various supplier markets.
The petroleum industry currently employs about 43,000 people, but more than 250,000 jobs can be linked, directly or indirectly, to the activity on the Norwegian Continental Shelf.
In recent years, the petroleum industry has accounted for nearly 50 percent of all Norwegian export and about 26 percent of government revenues.
Sources: The Norwegian Petroleum Directorate, The Norwegian Oil and Gas Association
1000 sm3 gas = 1 sm3 oil equivalent
Technological improvements and the development of new work methods are crucial to Det norske's development as a company, and to the petroleum industry as a whole.
Det norske wishes to increase the in dustry's expertise and the company is especially concerned with developing the geology and geophysics disciplines. In 2013, the company supported R&D projects worth NOK 59 million.
Best at geological interpretation. Explo ration has been Det norske's core activity since its inception, and, naturally, it is the company's top research priority. Det norske wishes to lead the field as regards geological interpretation. This discipline dominate both in terms of the number of projects and the amounts invested, and just under NOK 33 million was spent in 2013.
One of the projects looks at how infor mation from drilling operations can be utilised more efficiently. Through this project, Det norske has contributed to the development of new analysis methods. These methods have made it possible to study the geology and the geological processes in drilling operations in even greater detail.
Looking to the north. The High North is another important area for research, with particular emphasis on the Barents Sea. Det norske is involved in several research projects that are looking at how the company and the region can develop the expertise that is required for oil recovery. This is in order to ensure that the region is capable of meeting the needs of the coming oil activities. Det norske cooperates with the University of Nordland (UiN) and the trade association Verftsringen in Northern Norway, among others. The company has contributed to ISO certification of four companies and to the training of four apprentices (see separate article).
One of the projects Det norske has supported is Coldtech, which deals with a number of challenges relating to operations in Arctic waters. The project is part-funded by Det norske and examines, inter alia, how much ice a ship's hull and other installations can withstand. The project, which started in 2009, is part of the Forskningsløft i Nord research initiative. The project will be concluded in 2014.
Det norske was highly praised in a report issued by the UiN in 2013 for its local presence, high profile and community engagement in Northern Norway. The report emphasises wide-ranging cooperation with everything from schools and the authorities to the supplier industry as one of the factors behind Det norske's success in achieving good results.
Det norske continues to fund two adjunct professorships in Norway and plays an active part in the Force collaboration (organised by the Norwegian Petroleum Directorate) in order to contribute to raising competence within and outside the oil industry.
Det norske is mainly involved in external research projects, with internal follow-up as a guarantee for the work. Of a total of 59 projects, 33 concerned issues relating to the subsurface, while eight were related to development. Eleven projects concerned operations, drilling and well operations, and seven HSE and R&D administration.
Det norske has taken steps to ensure that the supplier industry in Northern Norway has an opportunity to become qualified suppliers to the oil industry.
In 2013, three new compa nies were certified by Det Norske Veritas. They are Teknor (ISO 14001), Blokken Skipsverft (ISO 9001) and Maritim Sveis (ISO 9001).
Through its commitment to the region, Det norske has contributed funding that has resulted in suppliers in the region currently leading the field as regards certification in quality assurance and health, safety and the environment. Sixteen companies have be come qualified as suppliers over a three-year period.
Funding from Det norske has made it possible for companies to become qualified as sup pliers in the petroleum indus try's joint qualification system, Achilles JQS. Through such qualification, the companies are offered ISO 9001 and ISO 14001 certification, which is essential if they are to be considered as suppliers. The establishment of big engine ering companies in Harstad and Tromsø has also impro ved proximity to customers.
Lofoten: Under the joint agreement with Det norske, Ballstad Slip AS was the first company to receive ISO certification. Here they are being presented with the certificate.
foundation Det norske is built on. Since its in ception, the company's goal has been to make a positive contribution to society. Det norske supports activities that are directly related to our operations as an oil company, activities that contribute to the public good and activities that can benefit our employees.
One of the company's most important projects is building schools in Rwanda in collaboration with UNICEF. Together with the rock band Kaizers Orchestra, Det norske has supported the Schools for Africa-project since 2008 and contributed to building schools in the Kamonyi district in Rwanda. Ten schools have been built or improved since the start-up of the project. As a result of this project, more than 10 000 students now have better schools, better learning environments and teachers who have taken continuing education.
Det norske is also one of the main sponsors of Det Norske Teatret in Oslo, Trondheim Jazzfestival, the Nidaros Cathedral Boys' Choir and the food festival Trøndersk Matfestival. The company also sponsors local amateur sporting activities, and cultural and community projects upon recommendations submitted by employees. In 2013, the company sponsored more than 60 such projects, mostly related to sports and culture for children and young people.
Det norske cooperates with schools, universities, organisations and the business community. In 2013, this included the teaching of geosciences in upper secondary schools, and more active information aimed at students in higher education, primarily at the Norwegian University of Science and Technology (NTNU).
Det norske has a long-term collaboration with Det Norske Teatret.
In 2013, the theatre celebrated the centenary of its first performance. The opening was held in Kristiansand on 2 January 1913 and featured, among other things, Ervingen (The Heir) by Ivar Aasen and Rasjonelt fjøsstell (Rational Dairying) by Hulda Garborg.
Det Norske Teatret is part of a grass roots movement which aims to carry on the work of Ivar Aasen, who created the Nynorsk (New Norwegian) langua ge based on Norwegian dialects. The theatre's mission statement from 1913 therefore states that it aims to "show plays in the New Norwegian language in towns and villages". Hulda and Arne Garborg found the inspiration for a 'New Norwegian theatre' on their travels to Berlin in the 1890s and their contact with artists at the Freie Volksbühne, an organisation promoting literature and theatre of the people.
Before the theatre was established, there was a group of amateurs called Det Norske Spellaget (the Norwegian theatre company). Their repertoire also included Ervingen. They went on tour and were met with catcalls and booing in both Ha mar and Trondhjem. That illustrates how heated Norway's language conflict was. In 2014, Det Norske Teatret will present a play about Ivar Aasen sponsored by Det norske.
In collaboration with the famous Nor wegian skier Oddvar Brå and the city of Trondheim, Det norske has established and funded the waymarking of Bråløypa, a test track for cross-country skiers in the Bymarka outdoor recreation area in Trondheim. On 11 September 2013, the Bråtesten uphill race was organi sed as an open race for the first time.
When Oddvar Brå developed Bråtesten in 2006, the goal was to set a test that gives a good indication of participants' physical capacity. Over the years, co untless cross-country skiers have te sted their physical fitness by taking this test. Today, it is regularly used by Team Trøndelag and by cross-country skiers who are part of the sports and physical education programme at Heimdal up per secondary school, among others. Bråtesten is five kilometres long and has a height difference of 207 metres.
With commitment, we always achieve a bit more, both as human beings and as a company.
Culture: In 2013, Det norske entered into a sponsorship agreement with the Nidaros Cathedral Boys' Choir in Trondheim.
Sports: Det norske was the main sponsor of the roller ski race "Midtbysprinten" in Trondheim. Petter Northug jr. could celebrate his victory, albeit in pouring rain.
Education: Det norske has contributed to UNICEF's Schools for Africa-project in Rwanda since 2008.
The record low sickness absence rate in 2013 confirms that people enjoy working for Det norske and appreciate each other's company.
Exciting jobs in Norway's most important industry, an environment with highly capable and friendly colleagues, where employees are given responsibility and can see visible results of the work they do. The above sums up the working environment in Det norske. The record low sickness absence rate in 2013 confirms that people like working for Det norske and enjoy each other's company.
The total sickness absence was 1.8 percent in 2013, down from 2.4 percent in 2012 and 3.4 percent in 2011. At the end of the year, the company had a total of 230 employees in its five office locations in Trondheim, Oslo, Harstad, London and Singapore. A high level of activity, mainly due to the development of the Ivar Aasen field, led to an increase in the number of employees. 38 people were taken on and 17 left the company in 2013. Six of the latter were attached to the Stavanger office, which the company decided to close down in 2011. Including the closing of the Stavanger office, Det norske had an employee turnover of five percent in 2013. Det norske carries out a working environment survey every other year, the last one in 2012. The psychological and physical working environment is perceived as good, and employees are motivated and look forward to going to work. The areas with a potential for improvement uncovered by the survey were followed up in 2013. A new working environment and organisation survey will be carried out in 2014.
The employees of the Det norske are organised in the trade unions Tekna and IndustriEnergi.
In 2013, Det norske signed an Inclusive Workplace agreement with the Norwegian Labour and Welfare Administration (NAV), and the company was approved as an Inclusive Workplace (IW) enterprise. The company facilitated work training for external jobseekers in the process of re-entering employment.
We have had a health and safety service in all our offices, including the project offices.
Health and safety rounds and evacuation drills were held in the office locations in 2013. The company's occupational health service also held courses in CPR and first-aid. During the year, the company has installed defibrillators in all four office locations, and in the company's conference venue in Sandvika in Verdal.
Equal opportunities.The company endeavours to achieve a balanced working environment in which everyone has equal opportunities based on qualifications and irrespective of gender, ethnicity or disability. In December 2013, the proportion of female employees was 30,4 percent, up from 28.5 percent in 2012. The proportion of women on the board of directors is 33.33 percent. Men and women in the same jobs and with the same experience, and who perform equally well, will receive the same pay in Det norske. The type of job, discipline area and number of years of work experience affect pay levels. The company endeavours to recruit more women to male-dominated jobs and discipline areas.
Det norske focuses on developing employees' competence and encourages all employees to update their competence regularly through courses, seminars and
Det norske: 1.8% Norsk Industri: 4.4 % Norway in general: 6.48 %
the possibilities offered internally through a rotation system. Among other things, Det norske cooperates with the Norwegian Centre for Project Management at the Norwegian University of Science and Technology (NTNU) and Metier, which have offered employees courses in project planning and project management.
The company holds regular gatherings for the different discipline areas and an annual gathering for the whole company. The company has a mandatory two-day gathering for new employees. This initiative reflects the company's increased focus on creating a shared understanding, culture and identity. The introductory course is part of the Det norske school, which is under development.
Det norske has an active company sports team with local clubs in all office locations. The company supports a wide range of activities. In 2013, there were 20 different active groups. Det norske owns Sandvika Fjellstue AS. This conference centre is used by the whole company for courses, gatherings, management meetings, board meetings and conferences. In addition, employees can use the mountain lodge in Sandvika in their spare time.
Cooperation: Highly capable and friendly colleagues creates a good working environment. From left: Vidar Otnes, Monica Almvik, Kjersti B. Pedersen, Terje A. Pedersen og Hans Arvid Olsen.
Photo: Thor Nielsen.
A vision is an idea of something that lies ahead, a dream to strive for.
Since its inception, Det norske has been driven by visions. When Det Norske Oljeselskap was founded in 1971, its vision was to be a 'limited liability company for the people'. When Erik Haugane and his co-founders started Pertra in 2001, their vision was to establish a fully fledged and independent oil company in Trondheim.
A small oil company saw the light of day and put down roots by the Nidelva river. In 2007, Pertra merged with the Norwegian part of DNO and became the Det norske oljeselskap ASA. But visionary leaders never settle down – they want to keep moving forward. Therefore, the vision quickly came to be the second biggest oil company on the Norwegian Continental Shelf. An ambitious plan, many would claim.
In a time when many people had doubts about the future of the Norwegian oil industry, Det norske saw the possibilities. In 2009, Det norske merged with Aker Exploration. With Aker as one of its owners, Det norske was further strengthened. Stable, Norwegian industrial ownership made it possible for the company to take part in and develop projects such as Jette, Ivar Aasen and Johan Sverdrup.
When the Johan Sverdrup field was discovered in 2011, optimism returned to the industry. All it took was an amazing oil discovery on the Utsira High. And Det norske was part of it all. The vision was the Norwegian oil adventure continues.
Since the company was established, Det norske has made some bold choices on the Norwegian Continental Shelf. The company has seen possibilities, not limitations. Det norske has moved forward when others have given up.
The year 2013 marks the beginning of a new era for Det norske. The vision to become a fully fledged oil company with exploration, development and production has become a reality. The development of the Ivar Aasen field is well under way, the development concept for the Johan Sverdrup field has been chosen and unitisation is
imminent. On 1 May 2014, Det norske will get a new CEO. Together with 250 committed colleagues, Karl Johnny Hersvik will bring the company into the future.
With our history, expertise and ambitions, we will continue to challenge conventional truths. We will explore and develop the possibilities on the Norwegian Continental Shelf in the best interest of our employees, investors and society as a whole. In close dialogue with the employees and the management, the board has defined the vision and the values that will lead the company safely through the start-up on the Ivar Aasen and Johan Sverdrup fields, licencing rounds, exploration and production. We will always be moving forward to create value on the Norwegian shelf.
Executive Chairman Sverre Skogen presented Det norske's new vision and values at Røros. The topic of the employees' group discussions was the new values and their significance in everyday life. From left: Ellen Trolid, Tom Bugge, Asbjørn Brenna, Øyvind Husby, Stephen Town, Håkon Brækken and Terje Børresen.
Photo: Thor Nielsen.
Teamwork: Great enthusiasm over Det norske's company values. From left Ida Sørli Frellsen, Pål Ove Sukka.
Photo: Thor Nielsen.
CHIEF FINANCIAL OFFICER (04)
Alexander Krane (born 1976) holds an M.Sc. in business and economics from Bodø Graduate School of Business and an MBA from the Norwegian School of Economics (NHH). He is also a state authorised public accountant. Before joining Det norske in September 2012, Mr Krane served as Corporate Controller of Aker ASA. He has previously worked with Norse Energy Corp. ASA and with KPMG, both in Norway and in the US.
SVP IVAR AASEN PROJECT (01)
Bård Atle Hovd (born 1959) holds an M.Sc. in engineering from the Norwegian University of Science and Technology (NTNU) and an MBA from the Norwegian School of Economics (NHH). He joined Det norske in 2011 and has 25 years of experience in operations, project development and project execution from ConocoPhillips, where he worked from 1987 to 2011. Prior to joining Det norske, he was responsible for project development and the PDO for Eldfisk II in ConocoPhillips.
ODD RAGNAR HEUM
SVP ASSET JOHAN SVERDRUP (05)
Odd Ragnar Heum (born 1955) holds an M.Sc. in petroleum geosciences from the Norwegian University of Science and Technology (NTNU). He joined Det norske in 2008. Mr Heum has more than 30 years experience from the Norwegian and international oil industry (Statoil, Saga, Hydro and StatoilHydro), primarily within exploration and business development.
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EXECUTIVE CHAIRMAN (03)
Sverre Skogen (born 1956) has served as the Executive Chairman of the board of directors since 1 May 2013. He holds an M.Sc. 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 has served as Executive Chairman of the board of directors since 1 May 2013, when Erik Haugane resigned as Chief Executive Officer. Karl Johnny Hersvik will take up the position as CEO of the company effective 1 May 2014.
CHIEF OPERATING OFFICER AND ACTING
GENERAL MANAGER (02) Øyvind Bratsberg (born 1959) holds an M.Sc. in engineering from NTH (now NTNU). He joined Det norske in 2008 and has 25 years of experience from several companies, mainly Statoil, within marketing, business development and operations. His core competencies are in the areas of commercial negotiations and management, and he also has experience from operating offshore installations and project development. Before joining Det norske, Mr Bratsberg was responsible for early-phase field development on the Norwegian Continental Shelf in StatoilHydro
SVP BUSINESS SUPPORT AND ACTING SVP EXPLORATION (06)
Anita Utseth (born 1966) holds an M.Sc. in mechanical engineering from the Norwegian University of Science and Technology (NTNU) and a master's degree in energy economics and environmental management from Scuola Superiore di Enrico Mattei in Milan. Ms Utseth's areas of responsibility include follow-up of health, safety and the environment, personnel and administration, ICT, quality and the company's R&D activities. Ms Utseth has previously served as State Secretary in the Ministry of Petroleum and Energy and has held several positions in Pertra, the Norwegian Directorate for Nature Management and the Norwegian Petroleum Directorate. Ms Utseth has served as the company's acting SVP Exploration since Bjørn Martinsen resigned from his position in September 2013.
CORPORATE ASSEMBY. The annual general meeting of Det norske held 17 April 2013 decided to establish a corporate assembly. In 2013, 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, Kjell Martin Edin.
as of 31.12.2013
Sverre Skogen (born 1956) has served as the Executive Chairman of the board of directors since 1 May 2013. He holds an M.Sc. 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).
Anne Marie Cannon (born 1957) has more than 30 years experience from the oil and gas sector in both industry and investment banking. From 2000 to 2014 she was a Senior Advisor to the Natural Resources Group at 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 and 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. Ms Cannon holds a B.Sc. Honours Degree from Glasgow University. Ms Cannon is a British citizen.
BOARD MEMBER (01)
Kitty Hall (born 1956) has headed various technology companies within the geophysics sector for 25 years. She serves on the board of Seabird Exploration. 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 a master's degree in stratigraphy from Bircbeck College, University of London. She is a British citizen.
BOARD MEMBER (05)
Inge Sundet (born 1963) is Drilling Manager Ivar Aasen. He has been with Det norske since 2008 and has held several positions in the drilling department. Mr Sundet holds a Master of Science in mechanical engineering from NTNU (1988). He was in Statoil from 2001 to 2008, primarily working with well completions (Heidrun and Kristin). He has also worked offshore as Drilling Supervisor. From 1989 to 2001 he was employed at SINTEF as Senior Researcher within Safety and Reliability.
JØRGEN C.
ARENTZ ROSTRUP BOARD MEMBER (03)
Jørgen C. Arentz Rostrup (born 1966) is Managing Director of Yara Ghana Ltd. at Yara International. He has held management positions in 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 as CFO and served as member of the corporate management in Hydro 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 cutive Vice President Projects in Norsk Hydro. Mr Røtjer has held a large variety of management positions in Hydro since 1980 and been responsible for several large development projects. From 1995 to 1998 he was Project Director for the Njord field development on the Norwegian Continental Shelf and was appointed Head of Hydro Technology & Projects. In 2004, Mr Røtjer was appointed Project Director for the Ormen Lange and Langeled subsea gas development projects in the Norwegian Sea. He holds a master's degree in mechanical engineering
Tom Røtjer (born 1953) is Exe-
Tonje Foss (born 1971) is Contract and Procurement Manager Ivar Aasen Topside. She holds a Master of Science from the University of Stavanger and has more than 15 years of experience from the oil industry, both in Stavanger and Trondheim. Ms Foss' experience from the oil industry includes employment in Kværner Rosenberg, Schlumberger and Corrocean
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, board member of Aker Solutions ASA, Kværner 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.
Bjørn Thore Ribesen (born 1970) is Offshore Installation Manager for Ivar Aasen. He joined Det norske in 2007. Mr Ribesen has held several positions in the drilling department, including Drilling and Well Manager Ivar Aasen until 31 December 2013. Mr Ribesen graduated with a BEng Honours Degree from University of Newcastle upon Tyne (1996). Before he joined Det norske he was in Schlumberger (1996–2007), where he held a variety of positions within logging, directional drilling and offshore management.
as of 31.12.2013
THE NOMINATION COMMITTEE. Det norske's nomination committee in 2013 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.
– 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 organisational 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 interest 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 Latin 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.
Exogene geology – This is the geology relating to the external processes which alter the earth's surface at sea or land, i.e., climate and climate-related processes. The opposite is endogene geology, which relates to internal processes originating within the earth, e.g., volcanoes, earth quakes and magmatic rocks.
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).
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 characterised 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.
IW enterprise – IW is an abbreviation for Inclusive Workplace. An IW enterprise has entered into a cooperative agreement with NAV (the Norwegian Labour and Welfare Administration). The main objectives of the IW agreement are to prevent and reduce sickness absence, strengthen presence in the workplace and improve the working
environment, and to prevent people from being excluded from or dropping out of the labour market.
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.
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 utilisation 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.
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 characterised 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 which 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.
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 recognised 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-today 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 owmership interests.
Palaeogene period – This is a geologic period which extends from 66 to 56 million years ago.
Permian period – Permian is a geologic period which 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 also other substances recovered in connection with such hydrocarbons.
Petroleum activity – All activity linked to subsea petroleum deposits, including investigation, exploratory drilling, recovery, transport, utilisation and termination, and also the planning of such activities, but not the transportation of petroleum in bulk by ship.
Plan for development and operation (PDO) – If a licencee 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 time period.
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 characterised 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.
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.
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.
Subsurface subjects – These teaching subjects include inter alia geology, geophysics and reservoir techniques.
Ticker/ticker code – An arrangement of characters (usually letters) representing a particular security listed on an exchange or otherwise traded publicly.
Triassic period – Geological period which 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 Nations initiative to encourage businesses worldwide to adopt sustainable and socially responsible 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, the environment and anti-corruption.
Unitisation – 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, utilisation and cessation of petroleum activities shall be submitted to the Ministry of Petroleum and Energy for approval.
Water injection – Refers to the met-
hod 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
(WEC) – Pursuant to the Working Environment Act, undertakings which regularly employ at least 50 employees shall have a working environment committee. The working environment committee shall make efforts to establish a fully satisfactory working environment in the undertaking.
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.
| 20 points | 15 points | 10 points | 5 points | 1 point | |
|---|---|---|---|---|---|
| PERSON | He was born in Oslo on 5 November 1917 and was a Norwegian politician, diplomat and legal practitioner. He has been referred to as one of the great Norwegians of the last century. |
He served as a Cabinet Minis ter in the governments of Prime Ministers Trygve Bratteli and Odvar Nordli. First he served as Minister of Trade and Shipping, then as Norway's first, and thus far only, Minister for the Law of the Sea from 1974 to 1978. |
He was a judge at the Interna tional Court of Justice in The Hague from 1985 to 1994. He negotiated Norway's tra de agreement with the EEC in 1972. Together with Arne Treholt he also negotiated the disputed "Grey Zone" agreement. |
As Undersecretary in the Nor wegian Ministry of Foreign Affairs he played a key role in the Norwegian petroleum industry. He shares his first name and party affiliation with the former Prime Minister of Norway, Jens Stoltenberg. |
Together with Carl August Fleischer and Leif Terje Lød desøl he played a pivotal role in securing the Norwegian State's interests in petroleum operations. Their proposal for establishing a first framework for the petroleum industry be came the Royal Decree of 9 April 1965. |
| TECHNO | The development of this techn ology has saved the petroleum industry millions of Norwegian kroner. Development started in 1979 and was based on an idea conceived by two rese archers from the Institute for Energy Technology. |
In 2012, this technology was awarded Aftenposten's Norway's best invention after 1980 prize. |
The technology has been adopted by oil companies from all over the world. The technology makes it possible to transport oil, gas and water through the same pipeline from one platform to the next. Pre viously, the same components had to be transported through three different pipelines. |
The technology was developed at Tiller in Trondheim, Nor way. SINTEF, Statoil, Saga and Norsk Hydro have all made significant contributions to this development. |
The technology consists of the modelling tool OLGA, which simulates transport of oil, gas and water through the same pipeline. |
| OIL FIELDS | This field is one of the world's ten largest oil fields. When it was discovered, it was the world's largest offshore oil field. |
The field is located in an area where the ocean depth varies between 70 and 75 metres. Production of oil from the field has caused the seabed in this area to sink ten metres. |
Drilling of the first exploration well started on 21 August 1969, but the well was soon plugged due to the risk of a blowout. . |
Philips Petroleum used the rig Ocean Viking to drill the field, starting on 21 August 1969. Due to the risk of a blowout, the well was plugged and the rig moved 1 km. After a period of bad weather, drilling re commenced in December. On 23 December, the discovery that marked the beginning of Norway's oil adventure was confirmed. |
The field is located in block 2/4 in the southern part of the North Sea. The field was the first Norwegian field that started producing. |
| YEAR | DNO was awarded its first licence on the Norwegian shelf this year. |
In the Norwegian Sea, the Draugen field was discovered this year. The Draugen field was the first field to be developed in the Norwegian Sea. |
An important oil policy compro mise was made this year. The reason behind this compromise was Statoil's too dominant po sition on the Norwegian shelf. |
This year, the first major commercial gas discovery, the Snøhvit field, was made in the Barents Sea. |
The compromise was referred to as the big "oil compromise" and resulted in the establis hment of the State's Direct Financial Interest (SDFI); the predecessor of Petoro. The Winter Olympic Games were held in Sarajevo. |
| METHOD | This much utilised method in the petroleum industry emerged from the classic earthquake research of the early 1900s. |
After the introduction of the magnetic tape recording in the 1950s, the quality of this met hod improved considerably. Now, it was possible to perform simple data processing such as filtering and NMO. |
During the First World War, the method was used to localise artillery. Today, the method is also used for mapping of wa ter bodies in connection with construction of tunnels and for environmental studies of soil. |
In 1962, this method was put to use for the purpose of mapping the Norwegian Continental Shelf. The method is based on measuring the time sound waves use for travelling through rocks. |
The method depicts the un derground and maps potential petroleum resources, resulting in a profile showing geological structures. |
| GEOLOGY | Rocks from this geologic pe riod date from 206 to 146 million years ago. In this period, the climate was warm and humid, and dinosaurs and pterodactyls lived in the coastal regions of Norway. |
In this geologic period the supercontinent of Pangea was further divided into smaller continents. |
Enormous amounts of sand were deposited during this period. The sand deposits have formed reservoir rocks of this age, the dominant rock in discoveries being made in the North Sea today. |
Some of the best sandstone reservoirs can be dated to this period, including parts of the Johan Sverdrup reservoir. |
The 1993 Steven Spielberg movie made this geologic period famous. |
How many squares can you locate?
you see?
4 3 6 7
?
6
Petroleum quiz:, Jens Evensen, Multiphase Flow Technology, Ekofisk, 1984, seismology, Jurassic
and Financial Statements 2013
| Board of Directors' Report | 58 |
|---|---|
| Board of Directors' Report on Corporate Governance |
70 |
| Financial Statements with Notes |
79 |
| Board of Directors' and Chief Executive Officer's |
|
| Statement | 126 |
| Auditor's Report | 127 |
Dear fellow shareholders
In 2013, Det norske made good progress in our development portfolio. The Plan for Development and Operation for the Ivar Aasen and Gina Krog fields were approved by the Norwegian Parliament; both important milestones on the path towards an increase of production from 2016/2017. During 2013, the partners in the giant Johan Sverdrup oil field navigated steadily towards a development concept decision. Production tripled to 1.6 million barrels of oil equivalents as Jette came into production. On the exploration front, Det norske participated in the Gohta discovery in the Barents Sea, a new exploration play in this region.
We currently estimate P50 net reserves for the company at 65.8 million barrels of oil equivalents. The "Development Pending" resource estimate ranges from 54 to 100 million barrels of recoverable oil equivalents, excluding Johan Sverdrup. The operator Statoil has reported gross field recoverable resources in the range of 1,800 - 2,900 million barrels of oil equivalents. An unitisation process is ongoing. Det norske has a 20 percent interest in production licence (PL) 265 and 22.22 percent in PL 502, which encompasses the western part of the field.
Det norske has a major investment program ongoing and Ivar Aasen and Johan Sverdrup are the two largest investments. Financial robustness is important for safeguarding the value in these projects. In 2013, Det norske doubled its bank field development facility to USD 1 billion and increased the accordion option from USD 100 million to USD 1 billion. Additionally, in July, the company placed a NOK 1.9 billion bond at Nibor + 500 basis points. These actions strengthened the company's investment capacity. In order to complete all current development projects, additional funding is required and the company is continuously considering various sources of funding to facilitate the expected growth of the company.
Since the discovery of the Johan Sverdrup field in 2010, 31 exploration and appraisal wells have been drilled to further map the field. Production in the first phase of the development could be as high as 380 000 barrels per day. Production at plateau is estimated at between 550,000 and 650,000 barrels per day. Det norske's ownership interest in this field will be determined through an unitisation process and a conclusion is expected in early 2015.
The formal partner decision to pass Decision Gate 2 (DG2) was made in February 2014. The selected concept is further described in the section "Events after year-end".
Det norske carries out significant offshore operations on the Norwegian Continental Shelf (NCS). These activities involve thousands of workers in different countries on different continents. As a result, Corporate Social Responsibility is important to the Board of Det norske. Accordingly, it recognises 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.
Production from Jette commenced in May 2013. Jette is a subsea development, and the oil is transported to Jotun for processing and export. Jette has produced 0.97 million barrels of oil equivalents net to Det norske during 2013. This is below previous estimates. Estimated reserves have been reduced, and the value of the field was impaired in the fourth quarter accounts.
Det norske is well positioned to participate in future growth on the NCS. In our portfolio of field development projects, Ivar Aasen and Johan Sverdrup stand out as the two main pillars. These two assets give Det norske a strong position in the new oil province on the Utsira High. The two significant discoveries made in 2013, Askja (near Oseberg) and Gohta (in the Barents Sea) strengthen our portfolio of discoveries for the future, and we also have a strong portfolio of exploration licences. We are, however, conscious of the risk associated with project execution and increasing investment costs being experienced by the industry. The Board has a clear focus on capital discipline and risk mitigation, wherever possible. The Board recognises the demands of successfully navigating a transition from an exploration company to a mid-sized E&P company and believes the company has the resources to succeed.
The Det norske share ended at NOK 66.70 in 2013, compared with NOK 82 at year-end in 2012. The average number of shares in issue during 2013 was 140.7 million. No equity issues were made in 2013. Aker Capital AS remains the largest owner with 49.99 percent of the shares.
Det norske oljeselskap ASA (Det norske) is active in exploration, development and production of petroleum resources on the Norwegian shelf. In addition, we have a separate Johan Sverdrup business unit to manage our interest due to the importance of this asset in our portfolio. Det norske carries out all its activities through a single company which holds no oil or gas assets outside of Norway. All our activities are, consequently, within the Norwegian offshore tax regime, and to the extent the company has overseas activities, these are related to construction and engineering of field development projects.
Det norske is active in all three main petroleum provinces on the NCS: the North Sea, the Norwegian Sea and the Barents Sea. 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 head office function is divided between Oslo and Trondheim. The company also has an office in Harstad in order to assist with Barents Sea operations.
Erik Haugane retired from his position as Chief Executive Officer (CEO) of the company in May 2013 under the terms of an agreement entered into by the Board of Directors with Mr. Haugane in 2005. Sverre Skogen has been working as Executive Chair since May 2013 and he will be replaced by Karl Johnny Hersvik. Mr. Hersvik comes from the position as Senior Vice President of Statoil's Research and Development division and will take up the position as CEO of Det norske effective from 1 May 2014.
At the end of 2013, the company had 230 (214) employees. It is a major licence holder on the NCS and operates 33 licences and is partner in an additional 47 licences.
Det norske's exploration strategy is twofold. Approximately two-thirds of its exploration resources are in mature areas in the North Sea, where the discovery rates continues to be high and the finding costs are still attractive. There is extensive infrastructure in the North Sea, which makes it possible to bring discoveries rapidly into production, compared with less mature areas. The remaining resources are invested in exploration in frontier areas, mainly the Barents Sea where the company is exploring for discoveries that can be commercialised and ensure long-term growth.
In 2013, Det norske participated in 14 exploration and appraisal wells. In addition to the discoveries in the Johan Sverdrup appraisal wells, Det norske encountered hydrocarbons at Gohta (oil) in the Barents Sea and the Askja (oil and gas) prospect adjacent to the Krafla discovery in the North Sea. Det norske is partner with a 40 percent interest in PL 492, where the Gohta discovery was made. Gohta is situated approximately 35 kilometres northwest of the Snøhvit field in the Barents Sea. The production test was successful and was the first successful testing of Permian carbonates in the Barents Sea. Preliminary estimates provided by the operator indicate volumes between 113 and 239 million barrels of oil equivalents. The second discovery of 2013 was made in PL 272 on the Askja prospect in the North Sea, where Det norske holds a 25 percent interest. The Askja discovery has preliminary estimated recoverable resources of between 19 and 44 million barrels of oil equivalents. Together with the neighbouring discovery at Krafla, with between 50 and 80 million barrels of oil equivalents, a joint development may provide between 69 and 124 million barrels of recoverable resources.
In 2013, total investments in exploration activities amounted to NOK 1.7 billion, the same level as in 2012. The company will still be an active explorer on the NCS. The exploration activity will be somewhat reduced in the years ahead, when the company has large investments in its development projects.
Det norske participates in three field development projects: Ivar Aasen (35 percent), Gina Krog (3.3 percent) and Johan Sverdrup (20 percent in PL 265 and 22.22 percent in PL 502).
The Ivar Aasen field is Det norske's first major development project as operator. A major milestone was passed on 21 May 2013, when the Plan for Development and Operation (PDO) was approved by the Norwegian Parliament. First oil is expected in the fourth quarter of 2016. Det norske holds a 35 percent interest in the field. 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 158 million barrels of oil equivalents, of which 120 million barrels are oil. 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).
Full field development costs are estimated at NOK 27.4 billion (nominal), of which approximately NOK 19 billion will be invested prior to production start-up. Det norske's 35 percent ownership interest represents an investment of about NOK 8.6 billion.
Ivar Aasen is a two-stage development, with Ivar Aasen and West Cable developed in Phase one, 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 two 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.
Det norske has, together with the partners in Ivar Aasen, signed a pre-unitisation agreement with the partners in the neighbouring PL 457. The agreement allows for a joint development of the discoveries and sets out principles for working towards an initial unitisation. The agreement is signed by all involved partners and the unitisation agreement is to be entered into by June 2014. Det norske's interest in the unitised field will be less than the present 35 percent.
During 2013, Det norske has awarded several of the Ivar Aasen development contracts. 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 will be build by Apply Leirvik at Stord. The steel jacket is being constructed by Saipem in Sardinia. Siemens will deliver the control and communication systems for the platform.
Gina Krog
The PDO for the Gina Krog field 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 percent interest in PL 029B. Based on its interest in PL 029B the company reached an unitisation agreement with the other partners, leaving Det norske with a 3.3 percent interest in the total field.
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 equivalents.
The Johan Sverdrup field is located in the mature part of the North Sea, 140 kilometres west of Stavanger and consists of discoveries in three licences. The Aldous Major South discovery in PL 265, where Det norske holds a 20 percent interest, confirmed that the Johan Sverdrup field was a giant field stretching into the adjacent PL 501 licence discovery. Communication between the two discoveries - in addition to a part of PL 502, where Det norske holds a 22.22 percent ownership interest - was confirmed.
The discovery is located in 110 metres of water, the reservoir being situated at a depth of 1,900 metres. Since the discovery in 2010, 31 exploration and appraisal wells have been drilled on and around Johan Sverdrup to further map the field in all licences. The reservoir quality has proved to be exceptional.
In 2013, the Johan Sverdrup appraisal programme continued and early in the year the Kvitsøy Basin (PL 265) drilling was completed. The result confirmed good reservoir qualities in the southern part of PL 265. During 2013, the western part of the Johan Sverdrup field was also tested and marked the completion of the appraisal programme in central parts of the field. The results from the "Fault Margin" appraisal well in PL 265 removed any uncertainty related to the reservoir quality in the part of the Johan Sverdrup discovery bordering the field's main western boundary fault. The well encountered an 82-metre gross oil column.
In addition, further exploration activity on the basement high located immediately west of the Johan Sverdrup discovery, called Cliffhanger, was also tested. The results from the two wells testing this area were disappointing.
The pre-unit operator Statoil has recommended a concept for the first phase. Statoil communicated gross field recoverable contingent resources between 1,800 and 2,900 million barrels oil equivalents. In February 2014, the formal partner decision to pass Decision Gate 2 (DG2) was made and the selected concept was communicated to the public. The selected concept is further described in the section "Events after year-end".
In addition to the above-mentioned fields, Det norske is engaged in early phase projects, such as Frigg GD, Krafla and Frøy. The company is operator and has a 50 percent ownership interest in Frøy.
As of 31 December 2013, Det norske had ownership interests in four producing fields: Jette (70 percent), Atla (10 percent), Jotun (7 percent) and Varg (5 percent). Det norske's share of production from these fields amounted to 1.63 million barrels of oil equivalents, compared to 0.55 in 2012. This corresponds to 4,463 barrels of oil equivalents per day in 2013 and 1,458 in 2012.
Det norske is the operator of the Jette field where production commenced 19 May 2013. Based on a recovery rate of 30 percent, the field was estimated to contain between six and seven million barrels of oil equivalents before production commenced. The field has been developed with a subsea installation tied back to the Jotun B platform. Jette produced 1.4 million barrels of oil equivalents in 2013 (gross). The production level is declining. Jette reserves have been downward revised and estimated remaining gross P50/2P reserves are 3.24 million barrels of oil equivalents.
Atla is producing from a subsea installation piped to Heimdal via the subsea installations on the Skirne field. The gas-condensate field started production in 2012, and is operated by Total. The current physical gross production is approximately 11,000 boepd. Total remaining gross P50/2P reserves are estimated to be 6.8 million barrels of oil equivalents.
Jotun is producing from an integrated wellhead platform (Jotun B) and an FPSO (Jotun A). The field is operated by ExxonMobil and has currently nine wells in production, including the two tie-back wells from Jette. The field is producing according to prognosis and the current gross production is approximately 2,700 boepd. Estimated remaining gross P50/2P reserves are estimated at 3.6 million barrels.
The Varg field is operated by Talisman and developed using the FPSO 'Petrojarl Varg', with integrated oil storage connected to a wellhead platform. Current total production at Varg is approximately 8,600 boepd. The producing wells are performing in line with prognosis. A gas blow-down project has been executed and started production in early 2014. One gas producer with a new gas export line has been installed between the Petrojarl Varg FPSO and the subsea facilities on the nearby Rev gas field which is further piped to the Armada platform on the UK shelf. The remaining gross P50/2P reserves from Varg gas are estimated at 3.9 million barrels of oil equivalents. In addition, 2.4 million barrels of oil are estimated remaining from the oil producers. Economical cut-off is expected within 2016.
The Glitne field in PL 048B is located in the North Sea, 40 kilometres north of Sleipner, and is operated by Statoil. Det norske holds a 10 percent interest in Glitne. The field was shut in February 2013 and decommissioning is ongoing. Permanent plugging and abandonment of the remaining wells are planned for in 2014. The final gross production on Glitne was 56 million barrels of oil, compared to the expected estimate of 25 million barrels of oil when the PDO was submitted (+124 percent).
The Enoch field straddles the border between the Norwegian and the British sector. The field is operated by Talisman, and Det norske holds a 2 percent interest. The field is developed using a single horizontal subsea well and is connected to the Brae A platform in the UK sector.
Production started in May 2007, and the field is expected to continue production until 2017. Total remaining gross P50/2P reserves are estimated to be 2.6 million barrels of oil equivalents. The field has been shut down since February 2012 due to mechanical problems with the X-mas tree. Work is ongoing to bring the field back on production during the first half of 2014.
Det norske collaborates both with leading research establishments and other companies to support the development of technology. A total of 60 projects were active in 2013. The gross research and development expenditures, prior to recharging to licence partners, were NOK 59 (58) million. A majority of the projects are related to understanding geology and the use of different exploration models. Projects are also being carried out in areas of HSE, drilling and wells, and also development and operation of fields.
(All figures in brackets apply to 2012.)
The applied accounting principles are the same as for the previous financial year, except when it comes to pension liabilities. The effect of the change is described in Note 1.36.
The company's total operating revenues amounted to NOK 944 (332) million. Petroleum from the producing fields amounted to 1,629,000 (545,000) barrels of oil equivalents. The production in 2013 is from the fields Jette, Atla, Jotun, Varg and Glitne, while the production in 2012 is from Jotun, Varg, Enoch and Glitne. The average realised oil price was USD 107 per barrel, which is down seven percent compared with an average price of USD 115 per barrel in 2012.
general exploration activities.
Gross payroll expenses before recharges amounted to NOK 444 (372) million. Net payroll expenses were NOK 38 (11) million. The net reported payroll expense is low because expenses related to exploration, development and production activities are invoiced to operated licences or allocated directly to their respective categories of activities. A breakdown of payroll expenses is included in Note 8.
Depreciation amounted to NOK 471 (111) million. The increase is mainly due to depreciations of Jette which came on stream in May 2013 and Atla, which came on stream in October 2012.
Net impairments of tangible fixed assets and intangible assets amounted to NOK 666 (2,150) million. The main reason for the high impairment charge in 2012 was challenges experienced while drilling production wells on the Jette field, which resulted in an impairment of NOK 1,881 million in the third quarter of 2012. An additional impairment related to Jette was recorded in 2013 with NOK 349 million. Both in 2013 and 2012, impairments were also recognised for some licences due to increased plugging and abandonment liabilities and relinquishment of licences.
Other operating expenses amounted to NOK 110 (83) million for the company, of which area fees accounted for NOK 58 (52) million and preparation for operation of development licences accounted for NOK 30 (19) million. The net reported operating expense is low because expenses related to activities within exploration, development and production are invoiced to operated licences or allocated directly to their respective categories of activities. A breakdown of other operating expenses is included in Note 9.
The company reported an operating loss of NOK 2,227 (3,843) million.
The pre-tax loss amounted to NOK 2,545 (3,949) million, and the tax income on the ordinary loss amounted to NOK 1,997 (2,992) million. The tax rules and tax calculations are described in Notes 1 and 11 to the financial statements.
The after-tax loss was NOK 549 (957) million.
ANNUAL REPORT 2013
Total assets at year-end amounted to NOK 10,541 (8,364) million and the increase was mainly caused by capital expenditures in development projects.
Equity decreased by NOK 548 (62) million to NOK 3,188 million, caused by the net loss. At year-end, equity amounted to approximately 31 (45) percent of total assets.
At 31 December, total interest-bearing liabilities amounted to NOK 4,989 (2,456) million. A new USD 1 billion credit facility was established, including an additional USD 1 billion uncommitted accordion option. The facility replaced the prior USD 500 million revolving credit facility. The company also successfully completed a NOK 1.9 billion bond offering. For information about terms and unused amounts of credit facilities, see Note 19.
Exploration expenses amounted to NOK 1,637 (1,609) million and are mainly related to dry and non-commercial wells, seismic data and
Cash and cash equivalents totalled NOK 1,709 (1,154) million at the end of the year.
Net cash flow from operating activities amounted to NOK 916 (1,419) million. This included tax refunds excluding interest of NOK 1.318 (1.443) million.
Net cash flow from investment activities amounted to NOK -2,805 (-3,575) million. This mainly relates to investments in fixed assets of NOK 1,496 (2,875) million and investments in intangible assets of NOK 1,359 (1,114) 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 NOK 2,444 (2,469) million, mainly caused by establishment of the new NOK 1.9 billion bond and several withdrawals and repayments on existing and new credit facilities.
In total, the company had a cash position and tax refund claim of NOK 3,120 (2,428) million at the end of the year.
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 2014.
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 2013, or the loss for 2013, other than those presented in the Board of Directors' Report or that otherwise follow from the financial statements.
The company prepares its financial statements in accordance with the International Financial Reporting Standards (IFRS) adopted by EU and the Norwegian Accounting Act.
Det norske complies with guidelines from Oslo Børs and the Society of Petroleum Engineer's (SPE) classification system for quantification of petroleum reserves and contingent resources. Total net P90/1P reserves are estimated at 48.5 (42.5) million barrels of oil equivalents at yearend, while net P50/2P reserves amounted to 65.8 (65.3) million barrels of oil equivalents at year-end. See Note 31 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 NOK 547 million from other equity.
The Board recognises the significant risks associated with the operations and, in particular, those associated with the growth and transition period the company is in. Consequently the Board has dedicated significant resources and time to understand and discuss not only project specific risks and general risks facing an E&P company, but also inherent risks connected to organisation, culture and leadership.
Experience has shown that E&P companies face significant risks. The regulation of activities on the NCS provides good and sound frameworks for handling these. 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, to be among the greatest. Accordingly, this is where the mitigating efforts are concentrated. We highlight below the general risks faced by E&P companies, such as exposure to oil price, interest rates, currency risks, and valuation of resource base. This is followed by a discussion of the particular risks for Det norske including project execution risk, access to capital and organisational issues.
The company's operated oil and gas reserves and resources are assessed by internal experienced professionals with input from licence partners. The non-operated reserves and resources are largely based on input from the operators. Additionally, the independent consultancy AGR Petroleum Services AS has certified the company's reserve estimates and its most significant contingent resources.
The assessment of reserves and contingent resources is coordinated and quality-assured by a small group of experts led by a reservoir engineer with more than 20 years' experience of this type of assessment. The reserves report is reviewed by the Audit Committee and approved by the Board of Directors before it is published.
Estimating recoverable volumes is always associated with significant uncertainty, and the reported P50/2P estimate is Det norske's best estimate for reserves and includes volumes that are expected to be recoverable based on assumptions of future economic, financial and taxrelated conditions. The P90/1P estimate reflects assumed recoverable volumes with a high degree of certainty.
Available methods for mapping subsurface oil and gas deposits do not eliminate all uncertainty in calculating volumes of hydrocarbons in place or their recoverability. There is therefore a risk that the final result may be even lower than the P90/1P estimate. Regarding our contingent resources the dominant resource is the giant Johan Sverdrup field. In connection with the recent concept selection the pre-unit operator Statoil has published full field resources between 1,800 and 2,900 million barrels oil equivalents, illustrating the typical uncertainty at this early stage of development, despite that the field has been extensively mapped based on 31 exploration and appraisal wells since the discovery in 2010. This program, planned to be concluded in 2014, will further reduce the uncertainty. However, also ownership interest in the future unit is uncertain, as this will be decided through a negotiation process between the equity holders of the underlying production licences. This negotiation process will take place in 2014 and early 2015, in parallel with the work towards a Plan for Development and Operation (PDO) for the field. Due to the upcoming unitisation process, Det norske has chosen not to report any information regarding recoverable volumes from the PL 265/PL502 part of the Johan Sverdrup discovery in the Annual Statement of Reserves.
Det norske continuously reviews its development projects. In some cases, the company may decide not to proceed with a project or to postpone a development decision pending more detailed assessment at a later date. In other cases, the company will decide to progress the development to production.
Det norske is currently involved in several capital-intensive and complex development projects. All of these projects have different time frames and investment levels. The risk exists that the company and its partners will not be able to stay within these limits, especially in light of the observed cost inflation on the NCS. Budget overruns and exceeding time limits in projects may in turn have a negative impact on the project finances.
The company is undergoing a significant transformation due to its role as the operator of development projects. Jette has started up and is the company's first operated field in production, and the PDO has been approved for Ivar Aasen. This involves adding substantial human resources to the organisation within appropriate control structures in order to execute substantial capital expenditure programmes. The Board works closely with management at this critical stage in the company's transformation to ensure that risks associated with this process are mitigated to the maximum possible extent.
Det norske's revenues come from the sale of petroleum and the revenue flow is, therefore, exposed to changes in oil and gas prices.
Det norske's oil production is currently limited, and the company has decided not to hedge against changes in the oil or gas price. In the Board's view, shares in Det norske give the investors an un-hedged exposure to the oil price.
The Board will nonetheless consider hedging against oil price fluctuations in step with the company's growing involvement in development projects and the considerable increase in production that is expected in the years ahead.
Exchange rate fluctuations involve both direct and indirect financial risk exposure. The company's petroleum revenues are in USD, whereas the expenses are mainly in NOK, USD and SGD, with smaller proportions in EUR, GBP, CHF and DKK. The exposure to USD on the revenue side is partly mitigated by the company's borrowings in USD, and on the debt side with foreign exchanges from USD to other currencies than NOK.
Det norske is exposed to interest-rate risk related to bonds and bank debt in connection with taking up loans and placements of liquid assets. Floating-interest loans involve an interest rate risk for the company's future cash flow. Det norske is exposed to risk (discount/premium) through fixed-interest loans due to changes in the market interest rate.
As of year-end, Det norske had interest-bearing debt of NOK 4,989 million, of which NOK 478 million was short-term debt. All loans have floating interest rates, but the company has entered into swap agreements for about 50 percent of the amount in order to reduce interest risk exposure.
Pursuant to the company's guidelines, liquid assets shall be placed so that the interest rate risk is of less than one year's duration. All bank deposits have floating interest rates. The company's sensitivity to potential changes in interest rates is shown in Note 29.
Det norske is exposed to credit risk through receivables and the fair value of financial commitments. Historically, the company has not experienced losses on receivables as its customers are large, creditworthy oil companies, and it has therefore not been necessary to make provision for bad debt.
Low credit risk is given priority in the management of the company's liquid assets. Liquid assets are placed in bank deposits, bonds and funds that represent a low credit risk.
The maximum credit risk exposure equals the balance sheet value of trade debtors, plus other short-term receivables and investments as described in Note 29.
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 maintains sufficient liquidity in its 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 Board of Directors.
Excess liquidity is defined as a portfolio consisting of liquid assets other than the funds deposited in regular current 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 realisation at short notice) is generally more important than maximising the return.
Some reporting requirements are associated with the agreement with the bank syndicate that furnished the credit facility, including quarterly updates of a revolving liquidity budget for the next 12 months. The company met these requirements in 2013.
The company's objective for the placement and management of excess capital is to maintain a low risk profile and good liquidity.
As of 31 December, the company's excess liquidity is mainly deposited in bank accounts.
As of 31 December, the company had cash reserves of NOK 1,709 (1,154) million. However, the combination of limited production revenues and active exploration and development programmes require active management of liquidity risk.
The company has various means available to it to handle increased future capital requirements such as raising additional funds through debt, portfolio adjustments or equity issues.
In October 2013, the company refinanced its USD 500 million revolving credit facility with a new USD 1,000 milion revolving credit facility at improved terms. The USD 100 million uncommitted accordion under the old facility was also replaced with a USD 1,000 million uncommitted accordion. The facility has maturity of five years from the signing date. The company also raised NOK 1,900 million in an unsecured bond in June. The bond has maturity of seven years from 2 July 2013.
Det norske is building an organisation around employees with competence in the disciplines of exploration, subsurface technology drilling, field development and operations, and business development. The aim is to develop an organisation that will create value for shareholders and society, safely and efficiently, without causing any harm to people or the environment.
It is of paramount importance to Det norske that all activities should be conducted with zero harm to people or the environment. The safety of people, the environment and assets is therefore an integrated part of Det norske's activities. Det norske shall contribute to the promotion of healthy attitudes and an HSE culture that helps us to reach our goals.
During 2013, Det norske was the operator of one exploration well on the Norwegian shelf. The drilling operations were conducted on the Augunshaug prospect in PL 542 in the North Sea. In addition, Det norske planned drilling operations on Langlitinden in PL 659 in 2013, where the drilling operation itself took place in 2014. In addition to exploration drilling, Det norske carried out several operations in 2013, such as seismic surveys in the Barents Sea and seafloor seismic acquired at Ivar Aasen. Final installation work on the Jette field took place in the first half of 2013. These operations were carried out with good operational and HSE results.
Jette came on stream in May, and produced without any HSE incidents throughout 2013.
Det norske did not receive any mandatory orders or notification of such related to our operations from the Norwegian authorities in 2013. The Petroleum Safety Authority (PSA) Norway carried out an audit of the Ivar Aasen working environment and material handling and an audit of process integrity and barrier management in 2013. Findings from these audits are systematically followed up.
The company's HSE&Q programme and specific activities in sub-projects have reflected the four mains priorities of the PSA (barriers, management and major accident risk, the natural environment and groups exposed to risk) also in 2013.
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 an 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.
Det norske is an active member of a network consisting of several operating companies with the aim of developing a joint emergency response centre, the Norwegian Operators' Association for Emergency Preparedness (OFFB). OFFB's task is to manage and maintain a second-line emergency preparedness system on behalf of the member companies. In 2013, Det norske has inter alia conducted a full-day exercise relating to the Ivar Aasen development project and an exercise in connection with exploration drilling on PL 542 Augunshaug.
For a period, Det norske maintains a high level of activity due to the Ivar Aasen project. This entails that the company has employed and hired several resources to ensure the right competence and capacity for the tasks pertaining to the development project. In the time ahead, it will be challenging for the industry to recruit sufficient qualified personnel in the most important technological disciplines. During 2013, two highly qualified senior executives were recruited, confirming Det norske's position as an attractive employer in the industry.
Det norske has a long-standing collaboration with graduate schools, university colleges, universities and business and industry in order to recruit and retain both talents and experienced personnel for senior and executive positions. Det norske recruited its new Chief Executive Officer, Karl Johnny Hersvik. He came from the position as Senior Vice President of Statoil's Research and Development division.
During the course of 2013, the number of employees at Det norske increased, mainly as a result of new tasks related to the company's development, which has required more personnel and new competence. At year-end, the company had 230 (214) employees.
gender, ethnicity, sexual orientation or disability.
In December 2013 women held 30.4 percent of the positions (28.5 percent in 2012). The percentage of women on the Board of Directors is 33.3 percent (50.0 percent in 2012). The percentage of women in the executive management is 16.7 (14.3 percent in 2012), and in middle management with personnel responsibility 26.3 percent (43.8 percent in 2012).
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 impact the pay level of individual employees.
As of 31.12.2013, 5.7 percent of the employees were of foreign origin (5.6 percent in 2012).
Det norske has a Working Environment Committee as described in the Norwegian Working Environment Act. The committee plays an important role in monitoring and improving the work environment and to ensure 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. In 2013, the company conducted a survey on behalf of the Ivar Aasen project, encompassing both employees as well as hired consultants.
Det norske is an IA (Inkluderende Arbeidsliv) company and has in 2013 organised work training for external job applicants who are in the process of returning to work.
The company endeavours to achieve a working environment with equal opportunities for all on the basis of qualifications and irrespective of
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. Two local trade unions are registered as being represented in the company, which are Tekna and IndustriEnergi.
In the Board's view, the working environment in Det norske at the end of 2013 was good.
In 2013, sickness absence in Det norske was 1.8 (2.4) percent, 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 Det norske's behalf.
Corporate Social Responsibility is important to the board of Det norske. The company is committed to carry out operations in a transparent and responsible manner, and is following most of the elements of the framework in ISO 26000:2010 standard "Guidance on social responsibility".
One of the values in Det norske is to be responsible, which means that we always put safety first when working to maximise value for shareholders and society. As Det norske is in the execution phase of the Ivar Aasen project, it is important to perform the procurement processes for large Engineering Procurement and Construction (EPC) contracts in a professional way. Det norske bases the procurement processes on competitive bidding and the principles of non-discrimination, equal treatment and transparency of the bidders. The company is committed to use suppliers who operate consistently in accordance with Det norske's values, comply with national laws and meet Det norske's requirements within HSE, CSR, ethics and anti-corruption, and quality management systems, including human rights and labour standards. By the end of the year 2013 all major contracts for the Ivar Aasen field development had been awarded.
Another value in Det norske is to be enquiring, which means that we are aiming for new and improved solutions. Det norske has a comprehensive program to support research, education and economic development in Northern Norway. Overall, this is a program of around NOK 15 million. Det norske supports the Mathematics and Natural Science faculty at the University of Tromsø. The grant has a limit of NOK 8.7 million and will be used for an advanced XRF scanner. In order to ensure that it has qualified personnel to operate the equipment, Det norske pays a researcher at the Institute of Geology. With our office in Harstad as a base, Det norske has entered into several agreements with industry, with special attention on research and education. In cooperation with the Verftsringen (the yard circle) in North Norway, we have e.g. entered into agreements where Det norske will pay 75 percent of the cost of the apprentice period for students. Det norske has initiated several research and development projects which include the University of Tromsø and other schools in North Norway. The Cold Climate Technology program at the Northern Research Institute at Narvik is an example.
Det norske would like all employees to be involved, entailing that we are committed to each other, to the company and to our community. Most people in Det norske are involved in some kind of voluntary work within culture or athletics organisations in their free time, and all employees have the opportunity to apply for sponsorships for their local community organisation. In 2013, a total of NOK 0.65 million was distributed to voluntary organisations through this mechanism.
In addition, Det norske sponsors a variety of cultural arrangements and institutions, among them Det Norske Teatret in Oslo, The Aasen Centre in Ørsta/Volda, Kosmorama Film Festival in Trondheim and Trøndersk Matfestival. In 2013, this support amounted to approximately NOK 3 million.
The fourth value in Det norske is to be reliable, which means that we strive to build trust and a good reputation by means of being predictable. In our operations, Det norske has zero tolerance for corruption. During 2013, the Ethics Code of Conduct was updated. Being an international customer even more than before through the Ivar Aasen project, one of the improvements in the Code of Ethics is that Det norske shall comply with the four conventions of the International Labour Organization (ILO) concerning the right to organise, the prohibition of child labour, the prohibition of forced or compulsory labour, and of not allowing discrimination in respect of employment and occupation.
The Ivar Aasen project has established regular HSE summits, involving top management from both the Det norske and the contractors, focusing on how project work shall be performed in a safe and sustainable manner. As Det norske is a relatively new customer in the international EPC market, this initiative has been well received.
A whistleblower helpline has been implemented making it easily accessible for all people in Det norske to submit issues of concern.
In 2014, Det norske will increase the focus on ethics and anti-corruption by performing a risk assessment on fraud-related issues and introduce an anti-corruption program to the employees. As Det norske has expanded with several site offices for the Ivar Aasen project in several countries in Europe and Asia in 2013, special attention will be given to these offices. In addition, Det norske will assess how the UN Global Compact Principles will influence the operations performed.
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 23 October 2012, 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.
In January 2014, Det norske was awarded interests in a total of six licences in the Awards in Pre-defined Areas (APA) 2013, two of which as operator. All six licences are located in the North Sea.
In February 2014, Det norske announced a discovery in PL 102F in exploration well 25/5-9 on the Trell prospect. The well encountered a gross oil column of 21 metres in the Heimdal formation, of which 19 metres had good reservoir quality. Basic data acquisition and sampling were carried out. The acquired information and pressure data indicate, as expected, very good production properties. Preliminary estimates place the size of the discovery between 3-12 million boe of recoverable oil. The licensees will evaluate the discovery together with other nearby prospects and consider further follow-up.
The drilling operations on well 7222/11-2 on the Langlitinden prospect in PL 659 were completed. Det norske is operator with a 20 percent ownership interest. The well encountered an oil-bearing channel sand of Triassic age. The primary objective of the well was to prove hydrocarbons in the Kobbe Formation reservoir (Triassic) and notably to prove good flow properties in the same reservoir. The well encountered oil in channel sands, which also was the main target for the well. Extensive data sampling, including cores, wireline logs and fluid samples have been performed. Movable hydrocarbons were proved in the main target for the well, but mini-DST proved poor reservoir properties. The partnership in PL 659 will evaluate the results carefully with respect to the remaining prospectivity of the licence. Based on preliminary analysis, Det norske is of the opinion that the volumes proven in this well, as of today, are insufficient to justify a field development.
Statoil, as the pre-unit operator of the Johan Sverdrup field, made the key parts of the concept selection disclosed to the public in February 2014, as Decision Gate 2 (DG2) was passed in the Johan Sverdrup pre-unit partnership. The Johan Sverdrup field will be developed in multiple phases. For the first phase, the Plan for development and operation (PDO) will comprise the establishment of a field centre, composed of four platforms: a processing platform, a well head and drilling platform, a riser, utilities and export platform and a living quarter platform, all steel jackets. In addition, three subsea templates for water injection will be installed. The production capacity in the first phase will be between 315,000 and 380,000 barrels of oil equivalents per day.
Statoil communicated gross field recoverable contingent resources between 1,800 and 2,900 million barrels of oil equivalents. The preliminary estimated recovery factor is about 60 percent. However, the ambition is to increase this towards 70 percent. Total investments for the first phase are estimated to be between NOK 100 and 120 billion. Phase 1 has capacity to produce more than 70 percent of the resources. The estimate includes all investments in platforms, subsea installations, wells, export pipelines and power from shore, including contingencies and market adjustment allowances.
The first phase development is robust and has flexibility to secure an optimal development of the total field resources, including methods for increased and enhanced oil recovery, as well as potential 3rd party production. The concept for future phases will be decided in a separate process after the phase 1 PDO. Full field production capacity is expected to be in the range 550,000 to 650,000 barrels of oil equivalents per day. From both a technical and commercial perspective, the expected life of the Johan Sverdrup field is approximately 50 years. The oil and gas from the Johan Sverdrup field will be exported to shore via dedicated pipelines. The oil will be transported to the Mongstad terminal in the county of Hordaland, whereas the gas will be transported via the Statpipe line to Kårstø in the county of Rogaland for processing and onward transportation. The plan is to submit a Johan Sverdrup PDO to the authorities by the first quarter of 2015. The Johan Sverdrup field spans across three licences, and a unitisation negotiation process will take place between the Johan Sverdrup licensees. The unit agreement needs to be concluded before the PDO can be handled by the authorities.
In January, Gro Haatvedt accepted an offer to become Senior Vice President Exploration in Det norske olieselskap ASA. Haatvedt was previously Senior Vice President for Exploration on the Norwegian Continental Shelf in Statoil. Time of taking office is yet to be decided, but will be no later than August 2014.
The Board believes that Det norske is well positioned for further growth. Jette and Atla will continue to contribute positively to production and cash flow in the near term, whilst Ivar Aasen and Johan Sverdrup have the potential to significantly increase production and transform the company in the longer term. Project execution at Ivar Aasen is important to the company, and the Board is following the project closely. After passing DG2 on Johan Sverdrup, focus will be on the unitisation process. The two discoveries made in 2013 on Askja and Gohta are very encouraging. The company will continue to actively explore on the NCS, although the exploration activity will be somewhat reduced in the years ahead, since capital allocation will be key over the next years.
The Board believes the financing obtained in 2013 provides a solid foundation when embarking on the investments related to the Johan Sverdrup and Ivar Aasen projects. Given the funding requirements of Det norske arising in the medium term, the board is committed to evaluating various financial alternatives.
ogen, Executive Chairal the Board
mman Mme
Anne Marie Cannon, Deputy Chair
Kitty Hall (Katherine Jessie Martin), Board men
Bjørn Thore Ribesen, Board member
Jacqe
Tonje Eskeland Foss, Board member
Ståle Gjersvold, Deputy Board Member
The Board of Directors of Det norske oljeselskap ASA
Trondheim, 11 March 2014
| $\overline{G}$ Tom Røtjer, Board member |
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|---|---|
| $\frac{1}{2}$ Kjell Inge Røkke, Board member |
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| nber | Gen Camp N& U- Gen CArentz Rostrup, Coard member |
| hy fan at | |
| Øyvind Bratsberg, General Manager | |
Det norske oljeselskap ASA ('Det norske') aims to ensure the greatest possible value creation to the shareholders and society over time. 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.
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 at 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 21 December 2012, 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 program 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 evaluates and defines 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.
Det norske is in the process of transforming from a pure exploration company into a full cycle exploration, development and production (E&P) company. The approval of the Plan for Development and Operation of the Ivar Aasen field, where Det norske is operator, in May 2013 was a major milestone and represented a significant step towards the goal of becoming a full cycle E&P company.
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.
association
Further information about licences and activities is available at http://www.detnor.no/en/our-assets/portfolio.
ANNUAL REPORT 2013
The Board seeks to optimise 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, and underlines that a solid equity ratio is important if Det norske is to achieve its strategic goals in the future. Ensuring an optimal 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. In addition, Det norske plans to carry out an active exploration programme during the next few years. 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, and by maturing existing discoveries and development projects towards production.
At year-end 2013, the company's book equity was NOK 3,188 million, which represents 30 percent of the balance sheet total of NOK 10,541 million.
The financial liquidity is considered to be good. At 31 December 2013, the company's cash and cash equivalents were NOK 1,709 million. In addition, available utilisation on credit facilities amounted to NOK 4,806 million.
In April 2013, the Annual General Meeting (AGM) authorised the Board to increase the share capital by a maximum of NOK 14,070,730, representing up to 10 percent 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 2013 the mandate had not been used.
The general meeting in April 2013 provided the Board a mandate to re-purchase company shares equivalent to up to 10 percent of the total share capital. The mandate is valid until the ordinary general meeting in 2014. As of 31 December 2013, the mandate has not been used.
Further information about the Articles of Association is available at:http://www.detnor.no/en/investors/corporate-governance/articles-of-
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 2013, Aker Capital AS owned 49.99 percent 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.
Applicable accounting standards and regulations require Aker ASA to prepare its consolidated financial statements to include accounting information of Det norske oljeselskap. Det norske oljeselskap 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 oljeselskap. Such distribution of unpublished accounting information from Det norske oljeselskap to Aker ASA is executed under strict confidentiality and in accordance with applicable regulations on handling of inside information.
The Board recognises Aker Capital'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 counter a shareholder structure with many long-term investors.
Det norske has established procedures to ensure that agreements with Aker controlled companies are entered into on an arm's-length basis.
In the event that the Board decides to use its current authorisation 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 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 percent 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 7 April 2014. 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).
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 2014, the Board will nominate an independent person who can vote on behalf of the shareholders as their authorised representative. The Board of Directors 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.
Det norske's general meetings are normally chaired by the Chair of the Board, or a person appointed by the Chair of the Board. Representatives from the Board of Directors, the nomination committee, the auditor and the executive management are encouraged to 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.
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.
shareholder of the company.
The nomination committee should be composed in a manner that takes into account the interests of shareholders in general. The nominating 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.
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 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 2013. 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 directors, one (Kjell Inge Røkke) is affiliated with the company's largest shareholder Aker Capital. All other directors are considered independent of the company's main shareholder, as well as of the company's material business contacts. All directors are considered independent of the company's executive personnel.
The Board composition ensures alignment of interests with all shareholders and the Board collectively meets the need for expertise, capacity and diversity. Directors 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 members is available on the website: http://www.detnor.no/om-oss/stvret/?lang=en
Shareholders who are unable to attend the AGM are encouraged to vote by proxy. The deadline for registration is set as close as possible to
Committee member Kjetil Kristiansen is currently the Head of HR Aker ASA, who is the 100 percent owner of Aker Capital, the major
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:
A. Drawing up strategic plans and supervising these through regular reporting and reviewing.
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
D. Ensuring the establishment and securing the integrity of the company's internal control and management systems.
In 2013, the Board has conducted a total of 13 board meetings, including a strategy meeting.
The Board recognises 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 organisation, 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, to be among the greatest. 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.
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.
Erik Haugane retired from his position as Chief Executive Officer (CEO) of the company in May 2013 under the terms of an agreement entered into by the Board of Directors with Mr. Haugane in 2005. Sverre Skogen has been working as Executive Chair since May 2013. Karl Johnny Hersvik will take the position as CEO from May 2014.
The Board carried out a formal evaluation of its own performance in 2013, as recommended by the Code, and took note of the findings.
The Board has established an audit committee consisting of the following two board members:
Both members are independent of the biggest owner.
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 2013 the committee held six 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 with implementing a new whistle-blowing practice, considered the process and reporting of the Annual Statement of Reserves and financial reporting improvements. In evaluating the performance for the vear 2013, 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.
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 license are subject to audits from authorities, such as the Petroleum Safety Authority, the Norwegian Environment Agency, as well as license partners. During 2013, Det norske participated in financial audit in seven license partnerships, while the company received audits on eight of its operated licenses, in addition to two licenses where we performed the drilling on behalf of other parties. Furthermore, several reports were purchased from financial audits in partner-operated licenses. In addition to these financial audits, there were audits from authorities and license 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, and in this way assist the company in its continuous work to improve the management system.
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 2014. These processes are stated in the company's HSEQ plan for 2014.
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 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.
During an annual strategy meeting in 2013 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 organisation 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 of risks, opportunities and threats, and outlines how these shall be monitored and governed.
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. In 2013, the Aasen project enganged an independent third party to evaluate improvement areas of the risk management process in the project environment, focusing on transparent risk management from discipline to executive level.
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 operationalised as follows:
The established framework is an integrated part of the company's management system. The company's internal control environment is characterised 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 approves the overall risk assessment related to financial reporting on an annual basis. In 2013, the following 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 2013, has identified strengths, weaknesses, opportunities and threats. Compared to 2012, the efficiency and design of internal controls have improved. Some of the improvements are:
In 2014, 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
The Board stipulates the Chief Executive Officer's remuneration and other terms and conditions of employment. Note 8 to the annual accounts contain details about the remuneration of the Board and executive management, including payroll, bonus payments and pension expenses.
The company has a bonus scheme based on company-wide performance and is capped at 20 percent of the annual salary. The annual bonus is at the Board's discretion and applies to all company employees except executive management. All employees receive the same percentage in bonus relative to his or her salary. For 2013, the Board decided on a 15 percent bonus based on an overall assessment of the company's performance, including exploration results and progress of development projects.
The company has no pension scheme for salaries exceeding NOK 1,022,940 (12 times the average Norwegian basic amount G), but a share investment scheme has been introduced as part of the pay system to compensate for this. The company buys shares on the behalf of its employees and the employees subsequently receive shares valued at 10 percent of the previous year's gross salary from the company. The cash.
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 recognises 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). 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. The complete annual report, including approved and final annual accounts and the Board of Directors' report, is available no later than three weeks before the AGM.
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 organised for major investors, investment managers and analysts. The company also attends investor conferences.
the underlying values in the company.
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.
Ernst & Young, Norway, is the auditor of Det norske.
The AGM elects the auditor and approves the auditor's fee. At least once a year, the Board of Directors will meet with the auditor 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 most meetings with the Audit Committee (AC) and meets the AC without the company's management being present. 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 interests as auditor.
company will pay a corresponding amount as tax compensation. For those who do not want to buy shares, half the amount will be paid in
The long-term purpose of the Investor Relation function is to secure access to capital on competitive terms, and for the share price to reflect
| OVERVIEW OF THE FINANCIAL STATEMENTS AND NOTES | PAGE |
|---|---|
| Income statement | 79 |
| Statement of comprehensive income | 79 |
| Statement of financial position | 80 |
| Statement of changes in equity | 82 |
| Statement of cash flow | 83 |
| Note 1: Summary of IFRS accounting principles | 84 |
| Note 2: Important events in 2013 | 96 |
| Note 3: Overview of subsidiaries | 96 |
| Note 4: Segment information | 96 |
| Note 5: Exploration expenses | 97 |
| Note 6: Inventories | 97 |
| Note 7: Production costs and cash flow from production | 97 |
| Note 8: Remuneration and guidelines for remuneration of executives and the board of directors, and total payroll ex | 98 |
| Note 9: Other operating expenses | 101 |
| Note 10: Financial items | 101 |
| Note 11: Tax | 102 |
| Note 12: Earnings per share | 104 |
| Note 13: Tangible fixed assets and intangible assets | 104 |
| Note 14: Impairments | 106 |
| Note 15: Accounts receivable | 107 |
| Note 16: Other short-term receivables | 107 |
| Note 17: Long-term receivables | 108 |
| Note 18: Other non-current assets | 108 |
| Note 19: Cash and cash equivalents | 108 |
| Note 20: Share capital and shareholders | 109 |
| Note 21: Pensions and other long-term employee benefits | 110 |
| Note 22: Provision for abandonment liabilities | 113 |
| Note 23: Derivatives | 113 |
| Note 24: Bonds | 113 |
| Note 25: Interest-bearing loans and assets pledged as security | 114 |
| Note 26: Other current liabilities | 114 |
| Note 27: Liabilities, lease agreements and guarantees | 115 |
| Note 28: Transactions with related parties | 116 |
| Note 29: Financial instruments | 117 |
| Note 30: Investments in jointly controlled assets | 123 |
| Note 31: Classification of Reserves and Contigent Resources (unaudited) | 124 |
| Note 32: Events after the year-end closing of the accounts | 126 |
| Statement from Board of Directors and Chief Executive Officer | 126 |
| 1 January - 31 December (NOK 1,000) | Note | 2013 | 2012 |
|---|---|---|---|
| Petroleum revenues | 7 | 933 162 | 325 093 |
| Other operating revenues | 10 719 | 7 351 | |
| Total operating revenues | 943 881 | 332 444 | |
| Exploration expenses | 5 | 1 637 063 | 1 609 314 |
| Production costs | 7 | 249 619 | 210 962 |
| Payroll and payroll-related expenses | 8 | 38 025 | 11 000 |
| Depreciations | 13 | 470 529 | 111 687 |
| Impairments | 14 | 666 135 | 2 149 653 |
| Other operating expenses | 9 | 109 886 | 82 799 |
| Total operating expenses | 3 171 256 | 4 175 414 | |
| Operating profit/loss | -2 227 375 | -3 842 970 | |
| Interest income | 40 750 | 54 997 | |
| Other financial income | 80 567 | 68 399 | |
| Interest expenses | 301 834 | 128 250 | |
| Other financial expenses | 137 435 | 101 050 | |
| Net financial items | 10 | -317 952 | -105 906 |
| Loss before taxes | -2 545 327 | -3 948 876 | |
| Taxes (+)/tax income (-) | 11 | -1 996 727 | -2 991 624 |
| Net loss | -548 600 | -957 251 | |
| Weighted average no. of shares outstanding | 140 707 363 128 649 729 | ||
| Weighted average no. of shares fully diluted | 140 707 363 128 649 729 | ||
| Loss after taxes per share (adjusted for split) | 12 | (3,90) | (7,44) |
| Loss after taxes per share (adjusted for split) fully diluted | 12 | (3,90) | (7,44) |
| 1 January - 31 December (NOK 1,000) | 2013 | 20121) |
|---|---|---|
| Loss for the period | -548 600 | -957 251 |
| Items which will not be reclassified over profit and loss: | ||
| Actuarial gain/loss pension plan | 4 064 | -6 834 |
| Tax related to items which will not be reclassified | -3 170 | 5 331 |
| Total loss | -547 706 | -958 756 |
| Attributable to: | ||
| Majority interests | -547 706 | -958 756 |
| Total | -547 706 | -958 756 |
1) See Note 21 for information about comparative figures.
| (All figures in NOK 1,000) | Note | 31.12.2013 | 31.12.2012 |
|---|---|---|---|
| ASSETS | |||
| Intangible assets | |||
| Goodwill | 13 | 321 120 | 387 551 |
| Capitalised exploration expenditures | 13 | 2 056 100 | 2 175 492 |
| Other intangible assets | 13 | 646 299 | 665 542 |
| Deferred tax asset | 11 | 630 423 | |
| Tangible fixed assets | |||
| Property, plant and equipment | 13 | 2 657 566 | 1 993 269 |
| Financial assets | |||
| Long-term receivables | 17 | 125 432 | 31 995 |
| Other non-current assets | 18, 29 | 285 399 | 193 934 |
| Total non-current assets | 6 722 340 | 5 447 783 | |
| Inventories | |||
| Inventories | 6 | 40 880 | 21 209 |
| Receivables | |||
| Accounts receivable | 15, 29 | 134 221 | 101 839 |
| Other short-term receivables | 16, 29 | 499 419 | 342 566 |
| Short-term deposits | 29 | 24 075 | 23 138 |
| Calculated tax receivables | 11, 29 | 1 411 251 | 1 273 737 |
| Cash and cash equivalents | |||
| Cash and cash equivalents | 19, 29 | 1 709 166 | 1 154 182 |
| Total current assets | 3 819 011 | 2 916 670 | |
| TOTAL ASSETS | 10 541 352 | 8 364 453 |
Paid-in capital
| (All figures in NOK 1,000) Note |
31.12.2013 | 31.12.20121) |
|---|---|---|
| EQUITY AND LIABILITIES | ||
| Paid-in capital | ||
| Share capital 20 |
140 707 | 140 707 |
| Share premium | 3 089 542 | 3 089 542 |
| Total paid-in equity | 3 230 249 | 3 230 249 |
| Other equity | -41 780 | 505 926 |
| Total equity | 3 188 470 | 3 736 175 |
| Provision for liabilities Pension obligations 21 |
66 512 | 65 258 |
| Deferred taxes 11 |
126 604 | |
| Abandonment provision 22 |
828 529 | 798 057 |
| Provisions for other liabilities | 780 | 647 |
| Non-current liabilities | ||
| Bonds 24, 29 |
2 473 582 | 589 078 |
| Other interest-bearing debt 25, 29 |
2 036 907 | 1 299 733 |
| Derivatives 23, 29 |
49 453 | 45 971 |
| Current liabilities | ||
| Short-term loan Short term 25, 29 29 |
478 050 478 050 |
567 567 075 |
| Trade creditors 29 |
452 435 | 258 596 |
| Accrued public charges and indirect taxes | 23 579 | 24 536 |
| Abandonment provision 22 |
147 375 | |
| Other current liabilities 26 |
795 680 | 852 722 |
| Total liabilities and provision for liabilities | 7 352 882 | 4 628 277 |
| TOTAL EQUITY AND LIABILITIES | 10 541 352 | 8 364 453 |
1) See note 21 for information about comparative figures.
Sverre Skogen, Chair of the Board Tom Røtjer, Board Member Anne Marie Cannon, Deputy Chair Kjell Inge Røkke, Board Member Kitty Hall (Katherine Jessie Martin), Board Member Jørgen C Arentz Rostrup, Board Member Bjørn Thore Ribesen, Board Member Inge Sundet, Board Member Tonje Eskeland Foss, Board Member Øyvind Bratsberg, General Manager The Board of Directors of Det norske oljeselskap ASA
Trondheim, 11 March 2014
| Other equity | |||||||
|---|---|---|---|---|---|---|---|
| Share | Share | Other com | Total other | Total equity | |||
| capital | premium | Other paid | prehensive | Retained | equity | ||
| (All figures in NOK 1,000) | in capital | income | earnings | ||||
| Equity as of 31.12.2011 | 127 916 | 2 083 271 | 3 600 107 | -2 134 743 | 1 465 364 | 3 676 551 | |
| Pension adjustment, see Note 21 | -684 | -684 | -684 | ||||
| Equity as of 31.12.2011 (adjusted) | 127 916 | 2 083 271 | 3 600 107 | -684 | -2 134 743 | 1 464 680 | 3 675 867 |
| Private placement | 12 792 | 1 006 271 | 1 019 063 | ||||
| Pension adjustment, see Note 21 | -1 504 | -1 504 | -1 504 | ||||
| Profit/loss for 2012 | -957 251 | -957 251 | -957 251 | ||||
| Equity as of 31.12.2012 | 140 707 | 3 089 542 | 3 600 107 | -2 188 | -3 091 994 | 505 926 | 3 736 175 |
| Total loss for 2013 | 894 | -548 600 | -547 706 | -547 706 | |||
| Equity as of 31.12.2013 | 140 707 | 3 089 542 | 3 600 107 | -1 294 | -3 640 593 | -41 780 | 3 188 470 |
| 1 January - 31 December (NOK 1,000) | Note | 2013 | 2012 |
|---|---|---|---|
| Cash flow from operating activities | |||
| Profit/loss before taxes | -2 545 327 | -3 948 876 | |
| Taxes paid during the period | -26 585 | ||
| Tax refund during the period | 1 318 430 | 1 443 140 | |
| Depreciation | 13 | 470 529 | 111 687 |
| Net impairment losses | 14 | 666 135 | 2 149 653 |
| Accretion expenses | 42 765 | 17 519 | |
| Reversal of tax item related to shortfall value of purchase price allocation (PPA) | 5 | -57 000 | |
| Losses on sale of licences | 734 | 13 461 | |
| Changes in derivatives | 23 | 3 174 | 44 847 |
| Amortisation of interest expenses and arrangement fee | 10 | 88 458 | 39 576 |
| Expensed capitalised dry wells | 5 | 1 150 541 | 1 116 403 |
| Changes in inventories, accounts payable and receivables | 141 786 | 44 467 | |
| Changes in net current capital and in other current balance sheet items | -394 934 | 444 144 | |
| NET CASH FLOW FROM OPERATING ACTIVITIES | 915 707 | 1 419 019 | |
| Cash flow from investment activities | |||
| Payment for removal and decommissioning of oil fields | 22 | -36 739 | -678 |
| Disbursements on investments in fixed assets | 13 | -1 495 709 | -2 874 627 |
| Disbursements on investments in capitalised exploration and other intangible assets | 13 | -1 358 941 | -1 114 277 |
| Sale/farmout of tangible fixed assets and licences | 86 472 | 414 336 | |
| NET CASH FLOW FROM INVESTMENT ACTIVITIES | -2 804 917 | -3 575 247 | |
| Cash flow from financing activities | |||
| Private placement | 1 019 063 | ||
| Repayment of short-term debt | -1 500 000 | -2 000 000 | |
| Repayment of long-term debt | -2 185 102 | -600 000 | |
| Proceeds from issuance of long-term debt | 4 729 297 | 1 849 749 | |
| Proceeds from issuance of short-term debt | 1 400 000 | 2 200 000 | |
| NET CASH FLOW FROM FINANCING ACTIVITIES | 2 444 195 | 2 468 812 | |
| Net change in cash and cash equivalents | 554 985 | 312 583 | |
| Cash and cash equivalents at start of period | 1 154 182 | 841 599 | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 1 709 166 | 1 154 182 | |
| Breakdown of cash equivalents at end of period: | |||
| Bank deposits, etc. | 1 693 319 | 1 140 750 | |
| Restricted bank deposits | 15 847 | 13 432 | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | 19 | 1 709 166 | 1 154 182 |
Det norske oljeselskap ASA ('Det norske') 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 company registered and domiciled in Norway. Det norske's shares are listed on Oslo Børs. The company's registered business address is in Trondheim, Norway.
As per 31 December 2013, Aker Capital AS owned 49.99 percent 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's financial statement consists of only a single legal entity. Consequently, there are no consolidated figures to report.
The financial statements were approved by the Board of Directors on 11 March 2014 and will be presented for approval at this year's Annual General Meeting on 7 April 2014.
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.
The company's functional currency and presentation currency is Norwegian kroner (NOK), and all amounts have been rounded off to the nearest thousand unless otherwise stated.
The preparation of financial statements in accordance with IFRS requires the management to make assessments, estimates and assumptions that have an effect on the application of accounting principles and on recognised 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.
Accounting estimates are used to determine reported amounts, including the possibility of realising 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 judgement 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 recognised when new estimates can be determined with sufficient certainty. Changes to accounting estimates are recognised 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 are used to estimate production volumes used as the basis for depreciation. 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. 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.
Fixed tangible assets and intangible assets: At 31 December 2013, the book value of operating assets (both fixed tangible assets and intangible assets) was NOK 5,681 million, see Notes 13 and 14.
Successful Effort Method - exploration: Det norske's accounting policy is to temporarily recognise expenses relating to the drilling of exploration wells in the Statement of financial position as capitalised 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 capitalised 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 capitalised and assessed for impairment on each reporting date. See items 1.8 and 1.9 for further details.
At 31 December 2013, the book value of capitalised exploration expenditures was NOK 2,658 million, see Note 13.
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, in order to estimate future cash flows. 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 13 'Property, plant and equipment and intangible assets' and Note 14 'Impairment of goodwill and other assets'.
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 recognised at fair value on the date they are incurred. At the initial recognition of an obligation, the expense is capitalised as production plant and depreciated over the useful life of the asset (typically by unit of production). It is difficult to estimate the expenses of decommissioning and removal at initial recognition as these estimates are based on 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 expenses are constantly changing. The estimates include costs based on expected removal concepts and estimated expenses 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 expenses capitalised 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.
At 31 December 2013, the book value of decommissioning and removal obligations amounted to NOK 976 million, see Note 22.
Pension obligations: When estimating the net present value of the defined contribution pension benefit obligations that represent a gross longterm liability in the Statement of financial position and indirectly the period's net pension expense in the Statement of income, the management makes a number of critical assumptions affecting these estimates. These assumptions relate to discount rate to be applied to future benefit payments, expected returns on pension plan assets, annual wage growth and average employee turnover. Considerable changes in relation to these assumptions between periods may have material impact on the accounts.
At 31 December 2013, the pension commitment amounted to NOK 66.5 million, see Note 21.
Income tax: The company may annually incur significant amounts of income tax payable and/or earn a considerable tax receivable. The company also recognises considerable changes in deferred tax or deferred tax benefits. These figures are based on management's interpretation of applicable laws and regulations, and on relevant court decisions. The quality of these estimates is largely dependent on management's ability to apply a complex set of rules and identify changes to the existing legal framework.
As of 31 December 2013, the book value of deferred tax asset amounted to NOK 630 million, while estimated tax receivables amounted to
NOK 1,411 million, see Note 11.
Rig contracts: The company has considerable obligations relating to rig contracts. Rig contracts are subject to impairment tests based on changes in future rig rates and utilisation.
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 recognised on an ongoing basis in the accounting period.
Revenues from petroleum products are recognised on the basis of the company's ideal share of production during the period, regardless of actual sales (entitlement method).
Other revenues are recognised when the goods or services are delivered and material risk and control are transferred.
Dividends are recognised when the shareholders' dividend rights are approved by the Annual General Meeting.
A joint venture is a contractual arrangement whereby two or more parties undertake an economic activity that is subject to joint control. Det norske has interests in licences that do not constitute separate companies. All these interests are in licences on the Norwegian Continental Shelf that are defined as jointly controlled assets pursuant to IAS 31. The company recognises investments in jointly controlled assets (oil and gas licences) by proportionate consolidation, by reporting its share of related expenses, assets, liabilities and cash flows under the respective items in the company's financial statements.
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. Current 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 fixed 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 input factors, processes to which these input factors are subjected, and a production output that is or has the ability to generate operating revenues.
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. Sold businesses are included in the accounts until the time of the sale.
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 flow generating units or groups of cash flow generating units that are expected to benefit from synergy effects of the merger. For internal management purposes, goodwill is assessed for each individual field/licence, and these are deemed to be individual cash flow generating entities.
In step acquisitions of companies, the acquisition cost is calculated as the sum of the fair value of previously acquired assets on the date of acquisition and the consideration for the most recent purchase. Changes in the value of previous assets are recognised in the Income statement. Calculation of goodwill and non-controlling interests can be made based on two equally valid alternative methods:
1) Goodwill is only recognised for the majority's share, with further identification of goodwill in connection with subsequent purchasing of minority interest.
2) Goodwill is recognised for both the majority and the minority interest, i.e., on a 100 percent basis. Any subsequent acquisition of remaining minority interests does not entail any adjustment of goodwill, but is treated as an equity transaction.
When using the second alternative, non-controlling interest must be valued at fair value. The choice between alternative 1 and 2 is not a choice between principles and is made in connection with each individual acquisition.
The allocation of excess 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 costs over and above capital issue and borrowing costs must be expensed as they are incurred.
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 do a 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.
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 will be regarded as asset purchases. Oil and gas production licences For oil and gas-producing assets and licences in a development phase, the acquisition cost is allocated between capitalised exploration expenses, licence rights, production plant, deferred tax and goodwill.
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 purchased 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 assets acquisitions, no provision is made for deferred tax.
Farm-in agreements
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
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 recognises swaps based on historical cost, as the fair value often is difficult to measure.
According to Norwegian law a unitisation 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 unitisation agreement shall be approved by the Ministry of Petroleum and Energy.
The company recognises unitisations in the exploration phase based on historical cost, as the fair value often is difficult to measure. For unitisations involving licences outside the exploration phase, it has to be considered whether the transaction has commercial substance. If so, the unitisation is recognised at fair value.
General
Tangible fixed assets are recognised on a historical cost basis. Depreciation of assets other than oil and gas fields is calculated using the straight-line method over 3-5 years and adjusted for any fall in value or 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 capitalised and depreciated over the remaining lease period.
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 recognised 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 sale 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 minus the sales costs.
Exploration and development costs relating to oil and gas fields Capitalised 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 recognised as tangible assets. Pre-operational costs are expensed as they incur.
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 capitalised exploration cost as of the reporting date is expensed if the drilling is completed before the date when the financial statement are authorised for issue.
Drilling cost for exploration wells are temporarily capitalised pending the evaluation of potential discoveries of oil and gas resources. Such costs can remain capitalised 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 recognised 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.
Capitalised 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 capitalised 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 materially 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 flows that are independent of cash flows from other groups of fixed assets. For oil and gas assets, this is carried out at the field or licence level. The loss in value for capitalised exploration costs is assessed for each well. Impairment is recognised when the book value of an asset or a cash flow generating unit exceeds the recoverable amount. The recoverable amount is the higher of the asset's net sales value 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 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 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 reserve. The reserves are cut at the time they no longer make a positive contribution to the cash flow, or the rental contract for the installation expires.
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 recognised 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 recognised. Such reversals are recognised 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 useful life.
Goodwill is tested for impairment annually or more frequently if events or changes in circumstances indicate that the value may be impaired.
Impairment of goodwill is valued by assessing the recoverable value of the cashgenerating unit to which the goodwill is related. Det norske has chosen to assess goodwill for each licence. Impairment is recognised if the recoverable amount is less than the book value of the field/licence, including associated goodwill and deferred tax as described in sections 1.8 and 1.9. 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 recognised deferred tax and goodwill in a business combination, both goodwill and deferred taxes from the acquisition is included when calculating gain/loss. When recording impairment of such licences as a result of impairment testing, the same assumptions are applied, in that goodwill and deferred tax are assessed together with the related licence.
Fixed assets and groups of fixed assets and liabilities are classified as held for sale if their capitalised value will be recovered in a sales transaction rather than through continued use. This is regarded as valid when a sale is highly likely and the fixed asset (or groups of fixed assets and liabilities) is available for immediate sale in its current condition. The management must have committed the company to a sale and the sale must be expected to be completed within one year of the classification date.
Fixed assets and groups of fixed assets and liabilities classified as held for sale are estimated at the lower of the previous book value and the fair value minus sales costs.
The company has the following categories of financial assets and liabilities:
Financial assets at fair value through profit and loss
Financial assets at fair value trough profit or loss: Financial instruments that are either classified as held for trading, or are designed as
Held–to-maturity investments: Financial assets with fixed or determinable payments and fixed maturity, other than loans and receivables, for which there is a positive intention and ability to hold to maturity and which have not been designated 'at fair value
Loans and receivables: Financial assets with fixed or determinable payments that are not quoted in an active market, do not qualify as 'trading' assets and have not been designated 'at fair value through profit or loss' or as 'available for sale'.
Available for sale financial assets: Financial assets that are designed as 'available-for-sale' or are not classified as 'loan and
Financial liabilities at fair value through profit and loss: Financial instruments that are either classified as 'held for trading', or are
Other financial liabilities are not explicitly defined but are those that are not 'held for trading' or designated 'at fair value through profit
A financial asset or liability is measured initially at fair value. Subsequent measurement depends on the category of financial instrument. Some categories are measured at amortised cost, and some at fair value. In limited circumstances other measurement bases apply, for example certain financial guarantee contracts.
Measurement at amortised cost is financial assets/liabilities:
Held to maturity: Non-derivative financial assets that the entity has the positive intention and ability to hold to maturity.
Loans and receivables: Non-derivative financial assets with fixed or determinable payments that are not quoted in an active market.
Financial liabilities that are not carried at fair value through profit or loss or otherwise required to be measured in accordance with
Measurement at fair value is financial assets/liabilities:
At fair value through profit or loss: This category includes financial assets and financial liabilities held for trading, including derivatives not designated as hedging instruments and financial assets and financial liabilities that the entity has designated for measurement at
Available for sale: All financial assets that do not fall within one of the other categories. These are measured at fair value. Unrealised changes in fair value are reported in other comprehensive income. Realised changes in fair value (from sale or impairment) are
Financial assets that are assessed at amortised 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 value is recognised 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 amortised cost would have been if the impairment had not been recognised at the time when the impairment was reversed. Reversals of previous impairments are presented as income.
Loans that can be converted into share capital pursuant to an option granted to the lender, and where the number of shares issued does not change in the event that the fair value change, are treated as hybrid financial instruments. Transaction costs relating to the issuing of a hybrid financial instrument are allocated between liabilities and equity in the same proportion as the proceeds. The equity component of convertible bonds is calculated as that part of the proceeds of the issue that exceeds the net present value of future interest and instalment payments, discounted by the market interest rate for similar commitments without conversion rights. The interest expenses to be included in the Income statement are calculated using the effective interest rate method.
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 capitalisation. Development costs that are expected to generate future financial benefits are capitalised when the following criteria are met:
All other research and development costs are expensed as incurred.
Costs that are capitalised include material costs, direct payroll expenses and a share of directly related joint expenses. Capitalised development costs are recognised in the Statement of financial position at acquisition cost minus accumulated depreciation.
Capitalised development costs are amortised over the asset's estimated useful life.
The company carries out ongoing reclassification of payroll and operating costs for 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, with a deduction for accumulated depreciation. 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 operational lease agreements. Rental payments are classified as operational expenses and are recognised on a straight-line basis over the contract period.
Trade debtors are recognised 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 capitalised as part of the asset's acquisition cost. Capitalised interest is only capitalised during the development phase. Other borrowing costs are expensed in the period in which they are incurred.
A qualifying asset is an asset for which an extensive period is required before it is ready for its intended use or sale.
Spare parts are valued at the lower of cost price and net sales 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 sales value is equal to the estimated sales price minus the
Spare parts estimated sales cost.
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 (the entitlement method).
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. Interest is taken to income based on the effective interest method as it is earned.
All loans are initially recognised at acquisition cost, which equals the fair value of the amount received minus issuing costs relating to the loan.
Subsequently, interest-bearing loans are valued at amortised cost using the effective interest method; the difference between the acquisition cost (after transaction costs) and the face value is recognised in the Income statement during the period until the loan falls due. Amortised costs are calculated by considering all issue costs and any discount or premium on the settlement date.
General
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 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 likely that future earnings or current tax regulations will make it possible to utilise the benefit. Deferred tax benefits that are not capitalised will be re-evaluated on each date of Statement of financial position and capitalised insofar as it is likely 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 in effect or that are expected to be in effect on the balance sheet date..
Tax payable and deferred tax is recognised 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 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 percent until 1 January 2014, when it was changed to 27 percent. The rate for special tax was 50 percent until the same date, when it was changed to 51 percent.
Tax depreciation
Pipelines and production facilities can be depreciated by up to 16 2/3 percent 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 percent per year over a period of four years, totalling 30 percent of the investment. From 5 May, the rate is 5.5 percent per year over a period of four years, totalling 22 percent of the investment. Uplift is recognised 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 deduction is calculated as the net financial costs of interest-bearing debt multiplied by 50 percent of the ratio between tax-related impaired value as of 31 December in the income year of the capital asset allocated to the offshore tax jurisdictions 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 district.
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 percent 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 taxrelated 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 has a pension scheme that is administered and managed by a Norwegian life insurance company. The calculation of the estimated pension liability for defined-benefit pensions is based on external actuary methods, and is compared to the value of the pension assets.
When pension costs and pension liabilities are entered into the accounts, the pension scheme's performance formula is applied – 'accrued benefits 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 recognised at fair value. Pension commitments and pension assets are presented net in the Statement of financial position and classified mainly as payroll and payroll-related expenses, and a smaller part as other financial expenses. The pension plans are charged to income at the time of the decision being taken. 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 recognised return is recorded continuously against 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. A curtailment occurs when the company makes a considerable reduction in the number of employees encompassed by the scheme or changes the terms and conditions for a defined-benefit pension plan such that a considerable part of the current employees' future earning periods will no longer qualify for benefits or only qualify for reduced benefits.
The introduction of a new benefit scheme or improvements to a current benefit scheme will lead to changes in the company's pension liability. This is expensed on a straight-line basis until the effect of the change is earned. The introduction of new schemes or changes in existing schemes that are implemented with retroactive effect, so that the employees immediately earn a free policy (or a change in their free policy) are recognised in the Income statement immediately regardless of any conditions to future employment. Gains or losses associated with restrictions or termination of pension schemes are recognised as they are incurred.
An early retirement scheme (AFP) has been introduced for all employees. The scheme is treated as a defined contribution pension, and therefore expensed as incurred.
A provision is recognised 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 expenses related to decommissioning and removal. A corresponding asset is capitalised 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 recognised 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.
All transactions, agreements, and business activities with related parties are conducted on ordinary market terms (arm`s length principles).
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.
Earnings per share are calculated by dividing the ordinary profit/loss 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 annual result divided by the weighted average number of outstanding shares during the period, adjusted for the dilution effect of any share options. Profits due to shareholders and the weighted average of outstanding shares are adjusted for the dilution effect of any share options. All shares that can be redeemed in connection with share options and that are 'in the money' are included in the calculation. Any share options are expected to be converted on the date of transfer.
Contingent liabilities are accounted for in the annual accounts, if it is more than 50 percent likely that they will occur. Major 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 recognised if it is virtually certain that the condition will occur. However, information about such contingent assets is provided if there is a certain probability that they will benefit the company.
Events subsequent to the reporting period, both positive and negative, are defined as events taking place between the balance-sheet date and the date of approving the financial statements for publication.
Incidents that provide knowledge about matters that existed on the date of the Statement of financial position will be adjusted in the financial
statements.
Any material events related to circumstances occurring after the date of the Statement of financial position will be disclosed in the notes to the
financial statements.
The Statement of cash flow has been prepared using the indirect method.
When necessary, the comparative figures have been corrected in order to correspond to the changes in this year's presentation of the
accounts.
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 2013.
The following new and amended standards and interpretations have been implemented for the first time in 2013:
Effective as of 1 January 2013, the company has utilised IAS 19 Benefits to employees (June 2011) ("IAS 19R") and altered the basis for calculation of pension liabilities and pension costs. The company has previously employed the "corridor" method for accounting of unamortised estimate deviations. The corridor method is no longer allowed and, in accordance with IAS 19R, all estimate deviations are to be recognised under other comprehensive income (OCI). The corridor as of 1 January 2012, in the amount of NOK 3.1 million, has been reset to zero. Pension liabilities increased correspondingly as of 1 January 2012, whereas the equity was reduced by NOK 0.7 million (after tax), and NOK 1.5 million as of 31 December 2012.
Return on pension plan assets was previously calculated on the basis of a long-term expected return on the pension plan assets. Due to the application of IAS 19R, the net interest cost of the period is now calculated by applying the discount rate applicable to the liability at the start of the period on the net liability. Thus, the net interest cost comprises interest on the liability and return on the pension plan assets, both calculated with the discount rate. Changes in net pension liabilities due to premium payments and pension benefits are taken into consideration. The difference between actual return on the pension plan assets and the recognised return is recognised against the OCI on an ongoing basis. The pension cost in 2012, recognised in accordance with the prior principles, amounted to NOK 29.7 million.
As a consequence of the altered principle for handling of unamortised estimate deviations and calculation of net interest cost, the recognised pension cost increased to NOK 36.5 (29.7+6.8) million, of which an estimate deviation in the amount of NOK 6.8 million was charged to other comprehensive income - OCI. The pension liability as of 31 January 2012 increased to NOK 65.3 million. IAS 19 R has been applied retrospectively, and the corresponding figures have changed.
The amendments in IAS 1 require all items in other comprehensive income to be grouped into two categories. Items that can be reclassified to profit or loss in subsequent periods (e.g. net gains on hedges on net investments, exchange differences related to translation of a foreign operation to presentation currency, net change in cash flow hedges and net gains or losses on financial assets classified as available for sale) shall be presented separately from items that will never be reclassified (e.g. actuarial gains or losses on defined benefit plans). The amendments will only affect the presentation and has no effect on the company's financial position or profit or loss.
The standard provides principles and guidance for measuring fair value of assets and liabilities where another IFRS requires or permits fair value measurements. The standard does not state when fair value should be employed as this is regulated in other standards. The standard has not had a major impact on Det norskes accounting, as the company only has financial instruments measured at fair value.
The amendments in IAS 1 clarify the difference between voluntary comparative amounts and the minimum requirements. Normally the presentation of the prior period's comparative amounts fulfills the minimum requirements. The amendments have not affected the company's financial position or profit or loss.
The amendment clarifies that significant spare parts and servicing equipment which meet the definition of propery, plant and equipment, are not inventory.
The amendment clarifies that income taxes arising from distributions to owners of equity instruments shall be accounted for in accordance with IAS 12.
The standards and interpretations that are issued, but not yet effective, up to the date of issuance of the company's financial statements, 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. The company has only described standards which are adopted by EU at the time of publication of the financial statements.
IFRS 10 replaces the portion of IAS 27 Consolidated and Separate Financial Statements that addresses the accounting for consolidated financial statements. It also includes the issues raised in SIC-12 Consolidation — Special Purpose Entities. IFRS 10 establishes a single control model that applies to all entities. The changes introduced by IFRS 10 will 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.
IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 Jointly-controlled Entities — Non-monetary Contributions by Venturers. IFRS 11 uses some of the terms that were used IAS 31, but with different meanings. Thus, there may be some confusion as to whether IFRS 11 is a significant change from IAS 31. For example, whereas IAS 31 identified three forms of joint ventures (i.e., jointly controlled operations, jointly controlled assets and jointly controlled entities), IFRS 11 addresses only two forms of joint arrangements (joint operations and joint ventures) where there is joint control. IFRS 11 removes the option to account for jointly controlled entities (JCEs) using proportionate consolidation. Instead, JCEs that meet the definition of a joint venture must be accounted for using the equity method. For joint operations (which includes former jointly controlled operations, jointly controlled assets, and potentially some former JCEs), an entity recognises its assets, liabilities, revenues and expenses, and/or its relative share of those items, if any.
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 recognises investments in joint operations (oil and gas licences) by reporting its share of related 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 under the definition in IFRS 11 as there is no joint control, the company recognises 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.
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 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 were management were to reach a different conclusion regarding consolidation — by providing more information about unconsolidated entities.
These new standards are effective as of 1 January 2014. There are separate transitional provisions for both IFRS 10, 11 and 12. In the summer of 2012 the IASB adopted certain amendments to IFRS 10, 11 and 12, and it has given some relief from the requirement for full retrospective application. Those amendments have no effect on the company's financial position or profit or loss.
The amendment provides an exception to the consolidation requirement for entities that meet the definition of an investment entity.
An investment entity accounts for subsidiaries at fair value through profit or loss, in accordance with IFRS 9 Financial Instruments (IAS 39, if changes are implemented before the implementation of IFRS 9). An investment entity does not consolidate its subsidiaries (unless the subsidiary provides services that relate only to the entity's own investment activities). An entity must meet all three elements of the definition and consider whether it has four typical characteristics, in order to qualify as an investment entity. An entity must consider all facts and circumstances, including its purpose and design, in making its assessment.
IAS 27: An investment entity that is required to account for all of its subsidiaries at fair value through profit or loss in accordance with IFRS 10, presents separate financial statements as its only financial statements.
IFRS 12: Additional disclosures are required for investment entities. Investment entities must disclose:
The significant judgments and assumptions it has made in determining how an entity meets the definition of an investment
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. These amendments are issued to align the disclosure requirements in IAS 36 with the IASB's original intention when consequential amendments to IAS 36 were made as a result of the issuance of IFRS 13 Fair Value Measurement. The amendments are effective for annual periods beginning on or after 1 January 2014. The change is not considered to have any major impact for Det norske, as the company does not value anything at fair value less costs to sell.
The narrow-scope amendments will allow hedge accounting to continue in a situation where a derivative, which has been designated as a hedging instrument, is novated to effect clearing with a central counterparty as a result of laws or regulation, if specific conditions are met (in this context, a novation indicates that parties to a contract agree to replace their original counterparty with a new one).These amendments are effective for annual periods beginning on or after 1 January 2014. The amendment will not have a major impact for Det norske, as the company currently does not have any kind of hedge accounting and derivatives is used in small scale.
The company made good progress in the portfolio of development licenses. The Plan for Development and Operations of the Ivar Aasen and Gina Krog fields were approved by the Norwegian Parliament, both important milestones on the path towards a step up in production from 2016/2017. During 2013, the partners in the giant Johan Sverdrup oil field navigated steadily towards a development concept decision. Production tripled to 1.6 million barrels of oil equivalents as Jette came into production. On the exploration front, Det norske participated in the Gohta discovery in the Barents Sea, a new exploration play in this region.
The company doubled its bank field development facility to USD 1 billion and increased the accordion option from USD 100 million to USD 1 billion. Additionally, in July, the company placed a NOK 1.9 billion bond at Nibor + 500 basis points. These actions strengthened the company's investment capacity.
The company owns 100 percent of Sandvika Fjellstue AS, which is a conference centre used by Det norske, located in Sandvika in Verdal. Sandvika Fjellstue AS is from a materiality consideration not consolidated, but is recognised at a cost of NOK 12 million in the Statement of financial position, see Note 18.
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 decisionmaker, defined as the company's top management. All revenues derive from sales to large external customers.
| Breakdown of exploration expenses: | 2013 | 2012 |
|---|---|---|
| Seismic, well data, field studies and other exploration expenses | 312 695 | 335 265 |
| Recharged rig costs | -118 958 | -31 491 |
| Share of exploration expenses from licence participation, incl. seismic | 151 340 | 149 267 |
| Expensing of exploration wells capitalised in previous years | 553 288 | 252 719 |
| Expensing of exploration wells capitalised this year | 597 253 | 863 684 |
| Share of payroll and other operating expenses classified as exploration | 122 000 | 76 333 |
| Research and development costs related to exploration activities | 19 445 | 20 536 |
| Reversal of tax item related to shortfall value of purchase price allocation (PPA) | -57 000 | |
| Total exploration expenses | 1 637 063 | 1 609 314 |
Inventories consist of oil that has been produced but not lifted, plus inventories of spare parts.
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Inventory of oil - produced, but not delivered | 2 151 | |
| Share of spare parts inventory | 40 880 | 19 058 |
| Inventories | 40 880 | 21 209 |
| Change in inventory of oil (exclusive of spare parts inventories) | -2 151 | -747 |
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, production and exploration expenses, respectively.
| Breakdown of revenues: | 2013 | 2012 |
|---|---|---|
| Recognised income oil | 791 155 | 255 844 |
| Recognised income gas | 117 752 | 47 917 |
| Tariff income | 24 255 | 21 332 |
| Total petroleum revenues | 933 162 | 325 093 |
| Breakdown of produced volumes (barrel of oil equivalents): | ||
| Oil | 1 263 889 | 388 223 |
| Gas | 365 226 | 141 462 |
| Total produced volumes | 1 629 115 | 529 685 |
| Petroleum revenues | 933 162 | 325 093 |
| Production costs | 249 619 | 210 962 |
| Net revenues from production | 683 543 | 114 131 |
The spare parts inventory mainly consists of equipment for the drilling of exploration wells or spare parts for development and production licences. 'Change in inventory' is included in 'Production costs' in the Income statement.
Production costs include costs associated with leasing, operation and maintenance of subsea installations, production vessels, platforms and well intervention and workover activities, CO2 tax, etc. Production cost also includes provision for future losses. The share of payroll and administration expenses that can be ascribed to operations is reclassified and shown as a production cost, see Note 8. The costs relate to the production licences Jette, Atla, Varg, Jotun, Enoch and Glitne. The production cost also includes insurance of production wells.
| Breakdown of payroll expenses: | 2013 | 2012 |
|---|---|---|
| Payroll expenses | 274 974 | 237 379 |
| Bonus | 64 934 | 53 366 |
| Severances (see footnote 1 in the first table below) | 1 135 | |
| Benefit pension plan | 36 239 | 29 244 |
| Contribution pension plans | 2 299 | 1 445 |
| National Insurance contributions | 48 240 | 38 453 |
| Other personnel costs | 16 203 | 11 239 |
| Payroll expenses charged to licences or reclassified as exploration, | ||
| development or production costs | -406 000 | -360 616 |
| Total personnel expenses | 38 025 | 11 000 |
At the start of the year the number of employees was 214. As of 31.12.2013, the number of employees was 230.
| Number of man-years equivalents employed during the year | 2013 | 2012 |
|---|---|---|
| Europe | 220,6 | 202,6 |
| Southeast Asia | 1,5 | |
| Total | 222,1 | 202,6 |
| Remuneration of senior executives in 2013: | Salary | Share invest ment and bonus ³) |
Other benefit |
Accrued pension costs Other |
Total remuneration |
Total number of shares (in 1000) |
Owning interest |
|
|---|---|---|---|---|---|---|---|---|
| Erik Haugane (Chief Executive Officer) 1) | 3 242 | 1 345 | 79 | 942 | 347 | 5 955 | 360 | 0,26 % |
| Øyvind Bratsberg (Chief Op. Officer and act. General Mng.) | 3 369 | 1 311 | 21 | 234 | 4 934 | 44 | 0,03 % | |
| Alexander Krane (Chief Financial Officer) | 2 083 | 235 | 30 | 229 | 2 576 | 2 | 0,00 % | |
| Bjørn Martinsen (SVP Exploration) 2) | 1 741 | 565 | 25 | 239 | 232 | 2 801 | 15 | 0,01 % |
| Odd Ragnar Heum (SVP Asset Johan Sverdrup) | 2 070 | 577 | 27 | 219 | 2 893 | 59 | 0,04 % | |
| Bård Atle Hovd (SVP Ivar Aasen Project) | 2 754 | 782 | 28 | 257 | 3 821 | 7 | 0,01 % | |
| Anita Utseth (SVP Business Support and act. SVP Expl.) | 1 840 | 477 | 18 | 297 | 2 631 | 46 | 0,03 % | |
| Total remuneration of senior executives in 2013 | 17 099 | 5 293 | 227 | 1 716 | 578 | 25 612 | 534 | 0,38 % |
2) Resigned 15.10.2013. The amount in the column 'Other' relates to holiday pay earned and paid in 2013.
3) Share savings investment scheme earned in 2012, disbursed in 2013.
| Share invest ment and |
Other | Accrued pension |
Total | Total number of shares |
Owning | |||
|---|---|---|---|---|---|---|---|---|
| Remuneration of senior executives in 2012: | Salary | bonus 4) | benefit | costs Other | remuneration | (in 1000) | interest | |
| 1) Erik Haugane (Chief Executive Officer) |
3 129 | 1 168 | 28 | 191 | 4 516 | 725 | 0,52 % | |
| Øyvind Bratsberg (Deputy Chief Executive) | 3 077 | 1 144 | 27 | 206 | 4 454 | 42 | 0,03 % | |
| 2) Alexander Krane (Chief Financial Officer) |
692 | 8 | 700 | 0,00 % | ||||
| 3) Teitur Poulsen (Chief Financial Officer) |
1 927 | 1 093 | 19 | 218 | 322 | 3 579 | 0,00 % | |
| Bjørn Martinsen (SVP Exploration) | 2 570 | 706 | 34 | 218 | 3 528 | 13 | 0,01 % | |
| Odd Ragnar Heum (SVP Asset Johan Sverdrup) | 1 938 | 747 | 29 | 188 | 2 902 | 57 | 0,04 % | |
| Bård Atle Hovd (VP Development Projects) | 2 435 | 488 | 33 | 257 | 3 213 | 19 | 0,01 % | |
| Anita Utseth (VP Business Support) | 1 602 | 617 | 25 | 276 | 2 520 | 46 | 0,03 % | |
| Total remuneration of senior executives in 2012 | 17 370 | 5 963 | 203 | 1 554 | 322 | 25 412 | 903 | 0,64 % |
1) Resigned 31.07.2013. As compensation the company pays 70 percent of wages from the age of 60 to 67. The liability is calculated using the same actuarial assumptions as the company's other pension obligations. At the time he resigned he owned 565 032 shares in the company.
1) Resigned 31.07.2013.
2) Started 1.9.2012.
3) Resigned 31.8.2012. The amount in the column 'Other' relates to holiday pay earned and paid in 2012.
4) Share savings investment scheme earned in 2011, disbursed in 2012.
The table below includes regular fees to the board and fees for participation in the board's subcommittees. The fees to the nomination committee are also included. Some board members have shares in the company. The table also includes the number of shares and owning interest in Det norske oljeselskap ASA held directly or indirectly throught related parties. Indirect ownership through other companies is included as a whole where the owning interest is 50 percent or more.
| Total number |
Owning interest |
|||
|---|---|---|---|---|
| of shares | as of | |||
| Name | Comments | Fee | (in 1000) | 31.12.2013 |
| Sverre Skogen | Chair of the Board from 17.4.2013. Executive Chair from 12.6.2013. | 387 | 0,00 % | |
| Anne Marie Cannon | Board memb. Deputy Chair from 17.04.2013. | 333 | 0,00 % | |
| Member of the audit commitee. | ||||
| Maria Moræus Hanssen | Board member. Deputy Chair from 9.5.2011. Member of the audit comm. Resigned 17.10.2013. |
516 | 0,00 % | |
| Jørgen C Arentz Rostrup | Board member from 17.4.2013. Chair of the audit commitee | 293 | 0,00 % | |
| Kitty Hall (Kathr. Martin) | Board member from 17.4.2013. | 205 | 0,00 % | |
| Tom Røtjer | Board member from 19.4.2012. | 351 | 0,00 % | |
| Tonje Foss | Employee representative from 8.8.2012. | 151 | 9 | 0,01 % |
| Inge Sundet | Employee representative from 8.8.2012. | 160 | 8 | 0,01 % |
| Kjell Inge Røkke 1) | Deputy Board memb. until 5.5.2013. Board member from 17.4.2013. |
279 | 0,00 % | |
| Ståle Gjersvold | Deputy Board member from 19.4.2012. | 110 | 0,00 % | |
| Kristin Gjertsen | Employee rep. Deputy Board member from 8.8.2012. | 48 | 4 | 0,00 % |
| Bjørn Thore Ribesen | Employee rep. Deputy Board member from 8.8.2012. Board member from 3.9.2013. |
99 | 13 | 0,01 % |
| Peder Garten | Employee rep. Deputy board member from 17.4.2013. | 15 | 2 | 0,00 % |
| Kjell Martin E Edin | Employee rep. Deputy board member from 17.4.2013. | 15 | 1 | 0,00 % |
| Kjetil Kristiansen j |
Chair of the nomination committee from 17.4.2013. | 0,00 % , |
||
| Øyvind Eriksen | Member of the nomination committee from 17.4.2013. | 33 | 0,00 % | |
| Finn Haugan | Member of the nomination committee. | 31 | 0,00 % | |
| Hilde Myrberg | Member of the nomination committee. | 31 | 0,00 % | |
| Members before Annual General Meeting in April 2013: | ||||
| Svein Aaser | Chair of the Board from 12.4.2011. Chair of the compens. comm. Resigned 17.4.2013. |
407 | 5 | 0,00 % |
| Berge Gerdt Larsen | Board member. Resigned 17.04.2013. | 47 | 0,00 % | |
| Hege Sjo | Board member. Chair of the audit commitee. Resigned 17.4.2013. | 267 | 0,00 % | |
| Carol Bell | Board member from 12.4.2011. Member of the audit commitee. | 247 | 0,00 % | |
| Resigned 17.4.2013. | ||||
| Liv Malvik | Deputy Board memb. from 12.4.2011. Resigned 17.4.2013. | 34 | 0,00 % | |
| Lone Fønss Schrøder | Deputy Board memb. from 12.4.2011. Resigned 17.4.2013. | 19 | 0,00 % | |
| Total fees | 4 077 | 42 | 0,03 % |
| Total number of shares |
Owning interest as of |
|||
|---|---|---|---|---|
| Name | Comments | Fee | (in 1000) | 31.12.2013 |
| Sverre Skogen | Chair of the Board from 17.4.2013. Executive Chair from 12.6.2013. | 387 | 0,00 % | |
| Anne Marie Cannon | Board memb. Deputy Chair from 17.04.2013. Member of the audit commitee. |
333 | 0,00 % | |
| Maria Moræus Hanssen | Board member. Deputy Chair from 9.5.2011. Member of the audit comm. Resigned 17.10.2013. |
516 | 0,00 % | |
| Jørgen C Arentz Rostrup | Board member from 17.4.2013. Chair of the audit commitee | 293 | 0,00 % | |
| Kitty Hall (Kathr. Martin) | Board member from 17.4.2013. | 205 | 0,00 % | |
| Tom Røtjer | Board member from 19.4.2012. | 351 | 0,00 % | |
| Tonje Foss | Employee representative from 8.8.2012. | 151 | 9 | 0,01 % |
| Inge Sundet | Employee representative from 8.8.2012. | 160 | 8 | 0,01 % |
| Kjell Inge Røkke 1) | Deputy Board memb. until 5.5.2013. Board member from 17.4.2013. |
279 | 0,00 % | |
| Ståle Gjersvold | Deputy Board member from 19.4.2012. | 110 | 0,00 % | |
| Kristin Gjertsen | Employee rep. Deputy Board member from 8.8.2012. | 48 | 4 | 0,00 % |
| Bjørn Thore Ribesen | Employee rep. Deputy Board member from 8.8.2012. Board member from 3.9.2013. |
99 | 13 | 0,01 % |
| Peder Garten | Employee rep. Deputy board member from 17.4.2013. | 15 | 2 | 0,00 % |
| Kjell Martin E Edin | Employee rep. Deputy board member from 17.4.2013. | 15 | 1 | 0,00 % |
| Kjetil Kristiansen | Chair of the nomination committee from 17.4.2013. | 0,00 % , |
||
| Øyvind Eriksen | Member of the nomination committee from 17.4.2013. | 33 | 0,00 % | |
| Finn Haugan | Member of the nomination committee. | 31 | 0,00 % | |
| Hilde Myrberg | Member of the nomination committee. | 31 | 0,00 % | |
| Members before Annual General Meeting in April 2013: | ||||
| Svein Aaser | Chair of the Board from 12.4.2011. Chair of the compens. comm. Resigned 17.4.2013. |
407 | 5 | 0,00 % |
| Berge Gerdt Larsen | Board member. Resigned 17.04.2013. | 47 | 0,00 % | |
| Hege Sjo | Board member. Chair of the audit commitee. Resigned 17.4.2013. | 267 | 0,00 % | |
| Carol Bell | Board member from 12.4.2011. Member of the audit commitee. Resigned 17.4.2013. |
247 | 0,00 % | |
| Liv Malvik | Deputy Board memb. from 12.4.2011. Resigned 17.4.2013. | 34 | 0,00 % | |
| Lone Fønss Schrøder | Deputy Board memb. from 12.4.2011. Resigned 17.4.2013. | 19 | 0,00 % | |
| Total fees | 4 077 | 42 | 0,03 % |
In 2013, a corporate assembly was established. No remuneration was paid to the corporate assembly in 2013.
1) The largest shareholder of Det norske, Aker Capital AS, is controlled by Aker ASA (100 percent) which in turn is controlled by Kjell Inge Røkke and his family through TRG Holding AS and The Resource Group AS.
The board will submit a policy statement concerning salaries and other remuneration to senior executives to the Annual General Meeting.
In 2013, the company's remuneration policy has been in accordance with the guidelines described in the Directors' Report for 2012 and submitted to the Annual General Meeting for an advisory vote in April 2013.
The board has established guidelines for 2013 and until the Annual General Meeting in 2014, for salaries and other remuneration to the Chief Executive Officer (CEO) and other senior executives. The guidelines will be reviewed at the company's Annual General Meeting in 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 share bonus program, defined benefit pension plans and other payments in kind such as free newspaper, free internet connection at home and subsidised fitness centre fees. The company has established bonus programs for both senior executives and other employees. In special cases, the company may offer other benefits in order to recruit personnel, including compensation for bonus rights earned in previous employment. The company does not offer share option schemes to employees.
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. The CEO has retired from his position in 2013. See comments in the section 'Remuneration of senior executives in 2013'.
It is up to the board to decide whether to pay bonuses, based on the previous year's performance. For 2013, the bonus was set to 15 percent. The bonuses were disbursed in February 2014.
The company has no pension scheme for salaries exceeding 12 times the National Insurance basic amount (G), but a share savings investment scheme has been introduced as part of the pay system, equivalent to 20 percent of gross annual salary. The employees receive an annual payment of 10 percent of the previous year's gross salary. If employees wish to buy shares in the company, the company will pay a corresponding amount as tax compensation provided that the employee agrees to hold those shares for at least 12 months. For those who do not buy shares, a tax withholding will be deducted from the payment. The first payments under the share investment scheme were made in January 2011 the the company will pay a corresponding amount as tax compensation provided that the employee agrees to hold the investment were in 2011.
In order to recruit new employees to the company 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 percent of their gross annual salary at an interest rate corresponding to the taxable norm interest rate. The lender is a selected bank, and the company guarantees for the employees' loans. Guarantees furnished by the company for employee loans in 2013 amounted to NOK 32 886. The corresponding figure for 2012 was NOK 18 978. 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.
The effect for the company of implementing the above mentioned guidelines, is that the company's result is affected by the related costs.
| 2013 | 2012 | |
|---|---|---|
| Office costs, including rental of premises | 59 999 | 61 744 |
| IT costs | 89 319 | 72 205 |
| Advertising and profiling | 9 390 | 9 311 |
| Travel expenses | 16 931 | 12 253 |
| Consultants' and auditor's fees | 33 564 | 32 702 |
| Operating expenses charged to licences/ classified as fixed assets, | ||
| exploration and production costs | -197 403 | -199 165 |
| Preparation for operation on development licences | 30 259 | 18 653 |
| Area fee | 57 723 | 51 551 |
| Other operating expenses | 10 103 | 23 545 |
| Other operating expenses | 109 886 | 82 799 |
| The company's auditor's fees are included under Other operating expenses and are allocated as follows: | ||||
|---|---|---|---|---|
| Auditor's fees (all figures are exclusive of VAT) | 2013 | 2012 | ||
| Fees for statutory audit services | 973 | 1 000 | ||
| Other attestation services | 30 | 62 | ||
| Tax advice | 218 | 263 | ||
| Audit-related fees | 62 | 264 | ||
| Services other than audit services | 139 | 446 | ||
| Total auditor's fees | 1 421 | 2 035 |
| 2013 | 2012 | |
|---|---|---|
| Interest income | 40 750 | 54 997 |
| Total interest income | 40 750 | 54 997 |
| Return on financial investments | 988 | 1 628 |
| Fair value of derivates | 9 077 | |
| Currency gains | 70 502 | 66 771 |
| Total other financial income | 80 567 | 68 399 |
| Interest expenses | 340 112 | 217 142 |
| Capitalised interest costs development projects | -126 737 | -128 468 |
| Amortisation of loan costs and accreation expence | 88 458 | 39 576 |
| Total interest expenses | 301 834 | 128 250 |
| Currency losses | 113 222 | 54 022 |
| Realised loss on derivatives | 11 912 | 1 941 |
| Fair value of derivates | 12 250 | 44 847 |
| Decline in value of financial investments | 50 | 240 |
| Total other financial expenses | 137 435 | 101 050 |
| Net financial items | -317 952 | -105 906 |
The currency gains and losses can mainly be ascribed to realised and unrealised exchange rate fluctuations relating to the company's credit facilities, bank accounts, trade receivables and trade creditors in foreign currencies.
The capitalised rate (weighted average interest rate) used to determine the amount of borrowing cost eligible for capitalisation is 9.1 percent.
The corresponding rate for 2012 was 9.7 percent.
| Tax base | 2013 | 2012 |
|---|---|---|
| Profit/(loss) before tax | -2 545 327 | -3 948 875 |
| Reversal of tax element related to business combination - booked as exploration | -57 000 | |
| Permanent differences | -140 933 | -19 473 |
| Change in temporary differences | 305 850 | 1 678 808 |
| Basis for ordinary income tax (28 %) | -2 380 410 | -2 346 540 |
| Current year uplift | -323 150 | -220 332 |
| Financial items subject to only 28 % ordinary tax | 264 346 | 141 353 |
| Basis for special tax (50 %) | -2 439 214 | -2 425 520 |
| Breakdown of the current year's tax income: | Tax rate | 2013 | 2012 |
|---|---|---|---|
| Calculated current year's exploration tax refund | 78 % | 1 413 159 | 1 299 985 |
| Prior periods adjustments to tax refund | 16 753 | 19 472 | |
| Current tax income (refund) | 1 429 912 | 1 319 457 | |
| Prior periods adjustments to deferred tax | -151 | 24 186 | |
| Change in deferred tax | 566 966 | 1 704 981 | |
| Reversal of tax item related to shortfall value of purchase price allocation (PPA), | |||
| accounted as exploration expenses | -57 000 | ||
| Deferred tax income (expense) | 566 815 | 1 672 167 | |
| Net tax income (+) / tax expense (-) | 1 996 727 | 2 991 624 | |
| Effective tax rate in % | -78 % | -76 % |
| Reconciliation of tax income/tax expense (-) | Tax rate | 2013 | 2012 |
|---|---|---|---|
| 28 % company tax on result before tax | 28 % | 712 692 | 1 105 685 |
| 50 % special tax on result before tax | 50 % | 1 272 664 | 1 974 438 |
| Interest on tax losses carryforward | 20 965 | 10 257 | |
| Previous period adjustment | -150 | 43 239 | |
| Tax effect of uplift | 50 % | 161 575 | 110 166 |
| Tax effect of financial items - 28 % only | 50 % | -117 159 | -76 284 |
| Deferred tax on current year's impairment booked directly to Statement | |||
| of financial position | -89 653 | -178 525 | |
| Permanent differences | 78 % | 35 795 | 59 649 |
| Reversal of tax element on shortfall value related to business | |||
| combination - booked as exploration expense | 100 % | -57 000 | |
| Total tax income (+)/ tax expense (-) for the year | 1 996 727 | 2 991 624 |
The tax rate for general corporate tax is changed from 28 to 27 percent from 01.01.2014. The rate for special tax is from the same date changed from 50 to 51 percent. The deferred tax / deferred tax asset is calculated with the new rates as of 31.12.2013. Also the uplift, a special income deduction in the basis for calculation of special tax, is from 05.05.2013 changed to 5.5 percent per year for a periode of four years, totaling 22 percent of the investment. Before this date the uplift was 7.5 percent per year in four years, with a total of 30 percent of the investment.
| Breakdown of tax effect of temporary differences and tax losses Applied tax |
|||
|---|---|---|---|
| carryforward: | rate | 31.12.2013 | 31.12.2012 |
| Capitalised exploration costs | 78 % | -1 603 758 | -1 696 884 |
| Other intangible assets | 78 % | -352 430 | -458 920 |
| Other intangible assets | 27 % | -647 | -806 |
| Tangible fixed assets | 78 % | 332 578 | 299 914 |
| Inventories | 78 % | -925 | |
| Overlift/underlift of oil | 78 % | -13 714 | -10 314 |
| Pension liabilities | 78 % | 51 879 | 43 147 |
| Other provisions in accordance with GAAP | 78 % | 849 752 | 833 864 |
| Other provisions in accordance with GAAP | 27 % | 233 | 504 |
| Net gain on revaluation account (agio/disagio) | 78 % | -11 702 | |
| Net gain on revaluation account (agio/disagio) | 27 % | -1 832 | |
| Arrangement fee, short-term loans | 78 % | -5 992 | -16 998 |
| Arrangement fee, short-term loans | 27 % | -3 853 | |
| Arrangement fee, bond issue | 78 % | -2 101 | -5 639 |
| Arrangement fee, bond issue | 27 % | -6 406 | |
| Arrangement fee, multicurrency loan | 78 % | -29 003 | -35 228 |
| Arrangement fee, multicurrency loan | 27 % | -18 812 | |
| Financial instruments | 27 % | 12 966 | 12 557 |
| Tax losses carryforward | 27 % | 479 558 | 325 590 |
| Tax losses carryforward | 51 % | 939 713 | 588 853 |
| Change in accounting principle relating to pension liabilities | 7 754 | ||
| Other | 461 | 461 | |
| Total deferred tax (-) / deferred tax asset (+) | 630 424 | -126 604 |
| Reconciliation of change in deferred tax/deferred tax asset: | 31.12.2013 | 31.12.2012 |
|---|---|---|
| Deferred tax as of 1.1 | -126 604 | -2 039 627 |
| Change in deferred tax through Statement of income | 567 368 | 1 672 167 |
| Prior periods adjustments | ||
| Deferred tax on current year's impairment booked directly to Statement of financial position | 89 653 | 178 525 |
| Deferred tax on historical drilling cost regarding swaps of licence interests | 103 177 | |
| Deferred tax entered against OCI | -3 170 | 5 331 |
| Reversal of tax item related to shortfall value of purchase price allocation, accounted as a tax expense | 57 000 | |
| Total deferred tax (-) / deferred tax asset (+) | 630 424 | -126 604 |
| Tax receivable (+) | 1 411 251 | 1 273 737 |
|---|---|---|
| Prior periods adjustments | -1 908 | -26 249 |
| Calculated current year's exploration tax refund | 1 413 159 | 1 299 985 |
| 2013 | 2012 | |
|---|---|---|
| Profit/loss for the year due to holders of ordinary shares | -548 600 | -957 251 |
| The year's average number of ordinary shares (in thousands) | 140 707 | 128 650 |
| Earnings per share | -3,90 | -7,44 |
Earnings per share is calculated by dividing the year's profit/loss due to shareholders, which was NOK -548.6 million (NOK -957.3 million in 2012) by the year's weighted average number of outstanding ordinary shares, which was 140.7 million (128.65 million i 2012). There are no option schemes or convertible bonds in the company. This means that there is no difference between the earnings per share and the diluted result per share.
| Fields under develoment |
Production facilities, |
Fixtures and fittings, office |
Total | |
|---|---|---|---|---|
| 2012 | including wells | machinery, etc. | ||
| Acquisition cost 31.12.2011 | 803 352 | 457 089 | 106 744 | 1 367 185 |
| Additions | 2 575 739 | 775 587 | 19 318 | 3 370 644 |
| Disposals | -417 904 | -417 904 | ||
| Reclassification from exploration expenditures | 202 560 | 202 560 | ||
| Acquisition cost 31.12.2012 | 3 163 747 | 1 232 675 | 126 062 | 4 522 485 |
| Acc. depreciations & impairment losses 31.12.2012 | -1 799 650 | -655 386 | -74 180 | -2 529 216 |
| Book value 31.12.2012 | 1 364 097 | 577 290 | 51 882 | 1 993 269 |
| Depreciation for the year | 82 435 | 18 316 | 100 751 | |
| Impairment losses for the year | 1 799 650 | 163 701 | 1 963 351 |
Capitalised exploration expenditures are reclassified to 'Fields under development' when the field enters into the development phase. Fields under development are reclassified to 'Production facilities' from start-up of production. Production facilities, including wells, are depreciated in accordance with the Unit of Production Method. Office machinery, fixtures and fittings, etc. are depreciated using the straight-line method over their useful life, i.e., 3-5 years. Removal and decommisioning cost for production facilities is included as 'Production facilities', and has increased with NOK 171.8 million in 2013 and NOK 496 million i 2012, see Note 22.
Disposal in 2012 is related to farm-out of Jette Unit with 18 percent. This transaction had no material impact on the Income statement.
| Total depreciations for the year | |
|---|---|
| Depreciations of intangible assets | |
| Depreciations of tangible fixed assets |
| Other intangible assets | Exploration | ||||
|---|---|---|---|---|---|
| 2013 | Licences | Software | Total | Goodwill | expenses |
| Acquisition cost 31.12.2012 | 1 104 424 | 45 180 | 1 149 604 | 644 569 | 2 175 492 |
| Additions | 121 975 | 2 918 | 124 893 | 1 263 617 | |
| Disposals/expensed dry wells | 467 | 467 | 1 370 026 | ||
| Relinquished licences | 323 229 | 323 229 | 178 917 | ||
| Reclassification to tangible fixed assets | -12 984 | ||||
| Acquisition cost 31.12.2013 | 902 705 | 48 099 | 950 804 | 465 653 | 2 056 100 |
| Acc. depreciations & impairment losses 31.12.2013 | 261 089 | 43 414 | 304 503 | 144 532 | |
| Book value 31.12.2013 | 641 616 | 4 684 | 646 299 | 321 120 | 2 056 100 |
| Depreciation for the year | 16 714 | 2 133 | 18 847 | ||
| Impairment losses for the year | 124 694 | 124 694 | 66 430 | ||
| Other intangible assets | Exploration | ||||
|---|---|---|---|---|---|
| 2012 | Licences | Software | Total | Goodwill | expenses |
| Acquisition cost 31.12.2011 | 1 110 324 | 43 989 | 1 154 313 | 648 337 | 2 387 360 |
| Additions | 366 | 1 191 | 1 557 | 1 112 719 | |
| Disposals/expensed dry wells | -6 266 | -6 266 | -3 768 | -1 122 028 | |
| Reclassification to tangible fixed assets | -202 560 | ||||
| Acquisition cost 31.12.2012 | 1 104 424 | 45 180 | 1 149 604 | 644 569 | 2 175 492 |
| Acc. depreciations & impairment losses 31.12.2012 | 442 782 | 41 281 | 484 062 | 257 019 | |
| Book value 31.12.2012 | 661 642 | 3 899 | 665 542 | 387 550 | 2 175 492 |
| Depreciation for the year | 7 990 | 2 946 | 10 936 | ||
| Impairment losses for the year | 226 194 | 226 194 | 135 062 |
| Breakdown of depreciations in the Statement of income: | 2013 | 2012 |
|---|---|---|
| Depreciations of tangible fixed assets | 451 683 | 100 751 |
| Depreciations of intangible assets | 18 847 | 10 936 |
| Total depreciations for the year | 470 529 | 111 687 |
See Note 14 for a breakdown of total impairments in 2013.
Goodwill is mainly allocated to the Johan Sverdrup (PL 265) and Ivar Aasen (001B and 028B) discoveries.
Software is depreciated over its useful life (3 years) using the straight-line method. Licences related to fields in production are depreciated
using the Unit of Production method.
Book value of licences as of 31 December 2013 relates to fields in the exploration and evaluation phase, development phase and production phase with NOK 399.3 million, NOK 216.7 million, and NOK 25.6 million, respectively. Corresponding figures for 2012 was NOK 499.2 million, NOK 121.5 million and NOK 40.9 million.
Some of the licences have been pledged as security for the company's credit facilities; see Note 30. The calculated book value of licences furnished as security as of 31.12.2013 is NOK 4,400.3 million and as of 31.12.2012 NOK 4,143.6.
Jette came on stream in May 2013. All investments on the Jette field were previously included as fields under development, but reclassified to production facilities when Jette came on stream. Impairment of fields under development in 2012 amounted to NOK 1,799.7 million and was entirely related to Jette. This impairment was reclassified correspondingly from development to production.
The company has entered into several commitments regarding the development project on the Ivar Aasen field. For more information about
the topic see Note 27.
* Discount rate of 10.7 percent nominal after tax (Weighted average cost of capital - WACC)
The following nominal oil price assumptions are applied:
| Year | Average USD |
|---|---|
| 2014 | 109 |
| 2015 | 103 |
| 2016 | 97 |
| 2017 | 93 |
| 2013 | 2012 | |
|---|---|---|
| Impairment of other intangible assets/licence rights | 124 694 | 226 194 |
| Impairment of tangible fixed assets | 564 663 | 1 963 351 |
| Impairment of technical goodwill | 66 430 | 135 062 |
| Deferred tax | -89 653 | -174 955 |
| Total impairments | 666 135 | 2 149 653 |
Impairment of tangible fixed assets was related to Jette, Varg, Jotun and Glitne with respectively NOK 349, 135, 64 and 17 million. 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 NOK 125 and 66 million were 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.
For producing licences and licences in the development phase, recoverable amount is estimated based on discounted future after tax cash flows. Future cash flows are calculated on the basis of expected production profiles and estimated proven and probable remaining reserves. The following assumptions have been applied:
* Oil prices are based on forward prices, and it is expected that 2017 will be the final year of production for fields that are currently under production. Fields in exploration or development phase are based on the company's long-term oil price assumptions.
The company experienced technical challenges in connection with the completion of the first production well on the Jette field. As a result, the company revised the development drilling plan. The revised plan resulted in higher drilling costs and reduced estimated recoverable reserves compared to the original plan. This caused reduced profitability of the field. Consequently, Det norske performed an impairment assessment and recorded an impairment charge of NOK 1 881 million before tax. The impairment included amounts from tangible fixed assets, intangible assets, goodwill and deferred tax. The net aftertax effect of this charge was NOK 477 million.
During the year the company's fixed assets related to the producing fields Glitne and Jotun were impaired with NOK 164 million before tax. The impairment was mainly due to the increase in the estimate of the abandonment provision. The remaining impairments for 2012 are related to exploration licences that have been or are in the process of being relinquished.
The valuation unit used for assessment of impairment will depend on the lowest level at which it is possible to identify cash flows that are independent of cash flows from other groups of fixed assets. For oil and gas assets, this is carried out at the field or licence level. The loss in value for capitalised exploration costs is assessed for each well. Impairment is recognised when the book value of an asset or a cash flowgenerating unit exceeds the recoverable amount. The recoverable amount is the higher of the asset's fair value less cost to sell and 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 and the specific risk related to the asset. The discount rate is derived from weighted average cost of capital (WACC).
An impairment test of goodwill and pertaining licences was carried out in the fourth quarter in accordance with the company's accounting principles. The test was carried out as of 31 December 2013. Goodwill is capitalised as a consequence of the requirement in IFRS 3 to make provision for deferred tax in connection with a business combination, even if the transactions are made on an "after-tax" basis as a result of a section 10 decision in line with applicable petroleum taxation. The offsetting entry to deferred tax is goodwill. Note 15: Accounts receivable
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Receivables related to the sale of petroleum | 71 103 | 23 211 |
| Receivables related to licence transaction | 1 284 | |
| Invoicing related to expense refunds, including rigs | 62 052 | 78 603 |
| Unrealised exchange rate gain/losses | -218 | 25 |
| Total accounts receivable | 134 221 | 101 839 |
Credit risk and currency risk related to trade debtors are discussed in more detail in Note 29 Financial instruments. No provisions for bad debt were made for 2012 or 2013.
Ageing of accounts receivable as of 31.12. was as follows:
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Receivables related to deferred volume at Atla | 3 103 | |
| Pre-payments, including rigs | 146 977 | 33 648 |
| VAT receivable | 11 444 | 21 289 |
| Underlift | 18 611 | 24 288 |
| Other receivables, including operator licences | 319 283 | 263 341 |
| Total other short-term receivables | 499 419 | 342 566 |
For information about receivables related to deferred volume at Atla, see Note 17.
| Year | Total 1) | Not due | <30 d | 30-60d | 60-90d | >90d |
|---|---|---|---|---|---|---|
| 2012 | 101 813 | 65 449 | 37 876 | -1 209 | 175 | -303 |
| 2013 | 134 439 | 47 389 | 83 754 | -104 | 3 225 |
A sensitivity analysis has been carried out in relation to impairment of producing fields and development projects, with a charge in the net cash flow or discount rate of +/- 10 percent. For one of the producing fields this would have resulted in an impairment charge of
NOK 50 million.
1) The deviation between the age-distributed current ledger and total trade receivables was due to unrealised exchange rate gains/losses.
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.
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Receivables related to deferred volume at Atla | 125 432 | 31 995 |
| Total long-term receivables | 125 432 | 31 995 |
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Shares in Sandvika Fjellstue AS (see Note 3) | 12 000 | 12 000 |
| Debt service reserve | 260 446 | 169 241 |
| Tenancy deposit | 12 954 | 12 694 |
| Total other non-current assets | 285 399 | 193 934 |
For information regarding debt service reserve and tenancy deposit, see Note 29.
The item 'Cash and cash equivalents' consists of bank accounts and cash.
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Cash | 5 | 5 |
| Bank deposits | 1 693 314 | 1 140 745 |
| Restricted funds (tax withholdings) | 15 847 | 13 432 |
| Total cash and cash equivalents | 1 709 166 | 1 154 182 |
The physical production volumes from Atla were higher than the commercial production volumes. This was caused by the high pressure from the Atla field which temporarily has stalled the production from the neighbouring field Skirne. This is expected to continue through 2014 and into 2015. Income is recognised based on physical production volumes measured at market value. This deferred compensation is recorded as a long-term or short-term receivable depending on when the income will occur, see Note 16.
The company has unused amounts available for withdrawal on the exploration facility and the revolving credit facility, described in more detail in Note 25.
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Share capital | 140 707 | 140 707 |
| No. of shares (in 1,000) | 140 707 | 140 707 |
| The nominal value per share is NOK | 1.00 | 1.00 |
All shares in the company carry the same voting rights.
Earnings per share are shown in Note 12.
| No. of | ||
|---|---|---|
| shares (in | Owning | |
| Overview of the 20 largest shareholders registered as of 31.12.2013: | 1,000) | interest |
| AKER CAPITAL AS | 70 340 | 49,99 % |
| FOLKETRYGDFONDET | 8 339 | 5,93 % |
| ODIN NORGE | 2 645 | 1,88 % |
| VERDIPAPIRFONDET DNB NORGE SELEKTIV | 2 279 | 1,62 % |
| ODIN NORDEN | 1 934 | 1,37 % |
| CLEARSTREAM BANKING S.A. | 1 556 | 1,11 % |
| VARMA MUTUAL PENSION INSURANCE | 1 445 | 1,03 % |
| KLP AKSJE NORGE VPF | 1 325 | 0,94 % |
| JP MORGAN CHASE BANK, NA | 1 166 | 0,83 % |
| DANSKE INVEST NORSKE INSTIT. II. | 1 157 | 0,82 % |
| TVENGE | 1 100 | 0,78 % |
| VERDIPAPIRFONDET DNB NORGE (IV) | 1 082 | 0,77 % |
| VPF NORDEA KAPITAL | 1 081 | 0,77 % |
| FONDSFINANS SPAR | 1 075 | 0,76 % |
| VPF NORDEA NORGE VERDI | 1 026 | 0,73 % |
| JP MORGAN CLEARING CORP. | 911 | 0,65 % |
| KOMMUNAL LANDSPENSJONSKASSE | 880 | 0,63 % |
| SKANDINAVISKA ENSKILDA BANKEN AB | 801 | 0,57 % |
| STATOIL PENSJON | 801 | 0,57 % |
| DANSKE BANK | 765 | 0,54 % |
| OTHER | 39 000 | 27,72 % |
| Total | 140 707 | 100 % |
For accounting purposes, it is assumed that pension rights are earned on based on accrued benefits method, see Note 1.27.
The pension liability was calculated, based on assumptions as of year-end, by an independent actuary.
| Unsecured scheme Secured scheme Components of net periodic pension cost |
Total | |||||
|---|---|---|---|---|---|---|
| recognised | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 |
| Service cost and benefit changes cost | 172 | 1 916 | 36 067 | 27 328 | 36 239 | 29 244 |
| Financial cost | 528 | 412 | 1 335 | 40 | 1 863 | 452 |
| Net periodic pension costs | 700 | 2 328 | 37 403 | 27 368 | 38 103 | 29 697 |
| Cost of defined contribution pension | 118 | 118 | ||||
| Pension costs collective early-retirement pension scheme (AFP) | 2 181 | 1 327 | ||||
| Total pension costs | 40 402 | 31 142 | ||||
| Presented as payroll expenses in the statement of income | 38 539 | |||||
| Presented as financial expenses in the statement of income | 1 863 | |||||
| Total pension costs in the Statement of income | 40 402 |
As a consequence of the altered principle for handling of unamortised estimate deviations and calculation of net interest cost, the recognised pension cost increased to NOK 36.5 (29.7+6.8) million, of which an estimate deviation in the amount of NOK 6.8 million was charged to other comprehensive income - OCI. The pension liability as of 31 January 2012 increased to NOK 65.3 million. IAS 19 R has been applied retrospectively, and the corresponding figures have changed.
As from 1 September 2011, the company has introduced a collective early-retirement pension scheme (AFP). In accordance with the current regulations, the premium is expensed as it is incurred. Total premiums expensed in 2013 amounted to NOK 2.2 million, and the corresponding figure for 2012 was NOK 1.3 million. In 2013, the premium has been 2.0 percent of total salary payments between 1.0 and 7.1 times the base amount.
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.
The company has a defined benefit plan which covers 224 persons. The plan applies to salaries of up to 12 times the basic National Insurance amount (G) and entitles to defined future benefits of maximum 66 percent of a person's pay on retirement. The benefit depends mainly on the number of earning years, pay level on reaching the pensionable age and National Insurance amounts. The pension liabilities are covered by an insurance company. Expected premium payments in 2014 amount to NOK 28.6 million.
In addition to the secured pension plan, the previous Chief Executive Officer has an unsecured early retirement plan. The liability is calculated using the same actuarial assumptions as for the company's other pension liabilities. Both the liability and the costs related to this plan are included in the figures below.
Effective as of 1 January 2013, the company has utilised IAS 19 Benefits to employees (June 2011) ("IAS 19R") and altered the basis for calculation of pension liabilities and pension costs. The company has previously employed the "corridor" method for accounting of unamortised estimate deviations. The corridor method is no longer allowed and, in accordance with IAS 19R, all estimate deviations are to be recognised under other comprehensive income (OCI). The corridor as of 1 January 2012, in the amount of NOK 3.1 million, has been reset to zero. Pension liabilities increased correspondingly as of 1 January 2012, whereas the equity was reduced by NOK 0.7 million (after tax), and NOK 1.5 million as of 31 December 2012.
Return on pension plan assets was previously calculated on the basis of a long-term expected return on the pension plan assets. Due to the application of IAS 19R, the net interest cost of the period is now calculated by applying the discount rate applicable to the liability at the start of the period on the net liability. Thus, the net interest cost comprises interest on the liability and return on the pension plan assets, both calculated with the discount rate. Changes in net pension liabilities due to premium payments and pension benefits are taken into consideration. The difference between actual return on the pension plan assets and the recognised return is recognised against the OCI on an ongoing basis. The pension cost in 2012, recognised in accordance with the prior principles, amounted to NOK 29.7 million.
| Other comprehensive income - OCI during period | Unsecured scheme | Secured scheme | Total | |||
|---|---|---|---|---|---|---|
| (R=Remeasurements loss (+) gain (-) | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 |
| R - change in discount rate | -176 | -5 928 | -6 104 | |||
| R - change in other financial assumptions | -17 463 | -17 463 | ||||
| R - change in mortality table | 172 | 6 825 | 6 998 | |||
| R - change in other demographic assumptions | ||||||
| R - experience DBO | 3 458 | 16 861 | 20 318 | |||
| R - experience Assets | -8 866 | -8 866 | ||||
| Investment management cost | 1 052 | 1 052 | ||||
| OCI losses (+) gains (-) during period | 3 454 | -290 | -7 519 | 7 124 | -4 064 | 6 834 |
| Unsecured scheme | Secured scheme | Total | ||||
|---|---|---|---|---|---|---|
| The year's change in gross pension liability: | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 |
| Gross pension liability (PBO) as of 01.01. | 14 536 | 10 953 | 107 024 | 73 911 | 121 560 | 84 864 |
| Payroll tax as of 01.01 | 1 544 | 4 654 | 6 198 | |||
| Service cost | 172 | 1 916 | 36 067 | 27 328 | 36 239 | 29 244 |
| Interest cost | 528 | 412 | 3 702 | 40 | 4 230 | 452 |
| Pension payments | -1 295 | -43 | -31 | -1 338 | -31 | |
| Payroll tax on premium payments | -3 891 | -3 891 | ||||
| The year's actuarial loss/(gain) | 3 454 | -290 | 477 | 1 122 | 3 931 | 832 |
| Gross pension liability (PBO) as of 31.12. | 17 396 | 14 536 | 143 335 | 107 024 | 160 731 | 121 560 |
| Unsecured scheme | Secured scheme | Total | ||||
|---|---|---|---|---|---|---|
| The year's change in gross pension funds: | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 |
| Gross pension funds as of 1.1. | 56 302 | 40 998 | 56 302 | 40 998 | ||
| Expected returns on pension funds/interest income | 2 367 | 1 906 | 2 367 | 1 906 | ||
| Actuarial loss/gain | 7 995 | -5 260 | 7 995 | -5 260 | ||
| Pension payments | -43 | -31 | -43 | -31 | ||
| Reclassification of funds in unsecured scheme | ||||||
| Premium payments | 31 490 | 18 689 | 31 490 | 18 689 | ||
| Payroll tax on premium payments | -3 891 | -3 891 | ||||
| Fair value of pension funds as of 31.12. | 94 219 | 56 302 | 94 219 | 56 302 |
| Unsecured scheme | Secured scheme | Total | ||||
|---|---|---|---|---|---|---|
| Net pension funds/liability (-) as of 31.12. | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 |
| Plan changes not taken/charged to income | -15 246 | -12 740 | -43 046 | -44 454 | -58 292 | -57 194 |
| Social security tax | -2 150 | -1 796 | -6 069 | -6 268 | -8 219 | -8 064 |
| Net capitalised pension funds/liability (-) as of 31.12. -17 396 | -14 536 | -49 116 | -50 722 | -66 512 | -65 258 | |
| Unsecured scheme Secured scheme |
Total | |||||
|---|---|---|---|---|---|---|
| Change during period: | 2013 | 2012 | 2013 | 2012 | 2013 | 2012 |
| Net capitalised pension funds/liability (-) as of 1.1. | -14 536 | -12 498 | -50 722 | -37 554 | -65 258 | -50 051 |
| The year's pension cost | -4 155 | -2 038 | -29 884 | -34 492 | -34 038 | -36 531 |
| Payments charged to operations | ||||||
| Reclassification of funds in unsecured scheme | ||||||
| Payments premium and pension | 1 295 | 31 490 | 21 324 | 32 785 | 21 324 | |
| Net capitalised pension funds/liability (-) as of 31.12. -17 396 | -14 536 | -49 116 | -50 722 | -66 512 | -65 258 |
| Historical information | 2013 | 2012 | 2011 | 2010 | 2009 | 2008 |
|---|---|---|---|---|---|---|
| Gross pension liability (PBO) as of 31.12. | 160 731 | 121 560 | 84 864 | 66 047 | 36 519 | 20 810 |
| Fair value of pension funds | 94 219 | 56 302 | 40 998 | 30 213 | 18 764 | 7 997 |
| Deficit in the scheme | 66 512 | 65 258 | 43 866 | 35 835 | 17 755 | 12 813 |
| Experience-based adjustment of liabilities | -3 931 | 832 | -10 384 | 3 581 | 404 | -1 804 |
| Experience-based adjustment of pension funds | 7 995 | -5 260 | -5 494 | -4 310 | -800 | -1 961 |
| Financial assumptions | 2013 | 2012 |
|---|---|---|
| Discount rate | 4,00 % | 3,80 % |
| Return on pension funds | 4,00 % | 4,00 % |
| Wage and salaries increase | 3,75 % | 3,50 % |
| Base amount adjustment | 3,50 % | 3,25 % |
| Pension adjustment | 1,20 % | 1,90 % |
| Actuarial assumptions | 2013 | 2012 |
|---|---|---|
| Mortality table used | K2013 | K2005+10/15 |
| Disability tariff used | IR-02 | IR-02 |
| Voluntary retirement before 40 years | 4-8% | 4-8% |
| Voluntary retirement after 40 years | 0-2% | 0-2% |
| Percentage distribution of pension funds by investment category | 2013 | 2012 |
|---|---|---|
| Shares | 5,6 % | 6,1 % |
| Bonds | 17,0 % | 15,6 % |
| Money market | 23,3 % | 21,4 % |
| Capital bonds | 35,2 % | 36,8 % |
| Property | 14,3 % | 18,3 % |
| Other | 4,6 % | 1,9 % |
| Total | 100 % | 100 % |
One percent increase in each of the assumptions gives these changes in pension service cost and liability.
The pension scheme is placed in DNB, which has a long-term perspective on the management of the capital. DNB seeks to achieve the highest possible rate of return by composing an investment portfolio that produces the maximum risk-adjusted return. In 2013, the actual value-adjusted return on pension assets was 4.4 percent, equal to the estimated rate (2012: 4.8 percent).
| Discount | Base | ||||
|---|---|---|---|---|---|
| Sensitivity analysis | 1 percent increase of: | rate | Salary | amount | Pension |
| Secured scheme | |||||
| Service cost | -20,8 % | 7,0 % | 1,6 % | 12,6 % | |
| Defined benefit obligation | -20,4 % | 6,3 % | 2,8 % | 12,2 % | |
| Unsecured scheme | |||||
| Service cost | NA | NA | NA | NA | |
| Defined benefit obligation | -2,8 % | NA | NA | -2,9 % |
The calculation of pension costs and net pension liabilities is based on a number of assumptions. The discount rate in 2013 is based on the Norwegian high quality corporate bond rate. The pension liability's average remaining service period is calculated as being 17 years, which corresponds to the difference between the pensionable age and the average age of the company's employees. Wage growth, pension adjustment and regulation of the National Insurance basic amount (G) are based on historical observations for the company and on an expected long-term inflation rate of 2.0 percent. For 2013, the company has applied the Norwegian Accounting Standards Board's (NASB) assumptions as of Desember 2013.
| Provisions as of 1.1 | ||
|---|---|---|
| 31.12.2013 31.12.2012 | ||
|---|---|---|
| Provisions as of 1.1 | 798 057 | 285 201 |
| Incurred cost removal and decommissioning | -36 739 | -677 |
| Accretion expenses - present value calculation | 42 765 | 17 519 |
| Change in estimates | 171 822 | 496 015 |
| Total abandonment provision | 975 904 | 798 057 |
| Break-down of the provision in short- and long-term liabilities |
Break-down of the provision in short- and long-term liabilities
| Total abandonment provision | 975 904 | 798 057 |
|---|---|---|
| Long-term | 828 529 | 798 057 |
| Short-term | 147 375 |
| Nominal discount rates: | Jette | Glitne | Varg | Atla | Enoch | Jotun | |
|---|---|---|---|---|---|---|---|
| 6 month | 5,02 % | ||||||
| 1 year | 5,02 % | ||||||
| 2 year | 5,02 % | 5,07 % | |||||
| 3 year | 5,13 % | 5,13 % | |||||
| 4 year | 5,28 % | 5,28 % | 5,28 % | 5,28 % | |||
| 5 year | 5,43 % | 5,43 % | 5,43 % | ||||
| 6 year | 5,56 % | 5,56 % | |||||
| 7 year | 5,69 % |
Corresponding rate for 2012 was 5,03 percent for Enoch, Jotun, Varg, Atla and Jette and 4.93 percent for Glitne. The main element in "change in estimate" is related to increased estimates on Varg and Jotun.
| Breakdown of non-current other interest-bearing debt: | 31.12.2013 31.12.2012 | |
|---|---|---|
| Principal, bond Norsk Tillitsmann 1) | 592 304 | 589 078 |
| Principal, bond Norsk Tillitsmann 2) | 1 881 278 | |
| 2 473 582 | 589 078 |
| Interest rate swaps: | 31.12.2013 31.12.2012 | |
|---|---|---|
| Unrealised losses interest rate swaps | 49 453 | 45 971 |
| Estimated fair value | 49 453 | 45 971 |
| Loss related to interest rate swaps | 3 174 | 45 971 |
| Loss related to currency forward contracts | 1 283 |
The company's removal and decommissioning liabilities relate to the fields Jette, Glitne, Varg, Atla, Enoch and Jotun. Time of removal is expected to come in 2018 for Jette, 2014-2016 for Glitne, 2016-2018 for Varg, 2018-2020 for Atla, 2017 for Enoch and in 2018-2021 for
Jotun.
The company has entered into three interest rate swaps. The purpose is to swap floating rate loans to fixed rate. These interest rate swaps are market to market and recognised in the Income statement.
1)The loan runs from 28 Januar 2011 to 28 January 2016 and carries an interest rate of 3 month NIBOR + 6.75 percent. The principal falls due on 28 January 2016 and interest is paid on a quarterly basis. The loan is unsecured.
Det norske entered into and settled forward contracts during 2012 to reduce currency exposure in the Jette project. As of 31 December 2012, the company did not have any outstanding currency forward contracts.
The estimate is based on executing a concept for abondonment in accordance with the Petroleum Activities Act and international regulations and guidelines. The calculations assume an inflation rate of 2.5 percent before tax and a nominal discount rate before tax as follow:
Det norske is in compliance with all financial covenants as of 31 December 2013. For futher details on covenants, see Note 29.
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Exploration facility | 478 050 | 567 075 |
| Total short-term loan | 478 050 | 567 075 |
| Available for withdrawal on exploration facility | 31.12.2013 | 31.12.2012 |
|---|---|---|
| 'Calculated tax receivable' in the Statement of financial position | 1 411 251 | 1 273 737 |
| Available for withdrawal | 1 315 991 | 1 187 760 |
| Drawn amount | 500 000 | 600 000 |
| Unused amount available for withdrawal on exploration facility | 815 990 | 587 759 |
The current facility of NOK 3,500 million was establised in December 2012 and the company can draw on the facility until 31 December 2015 with a final date for repayment in December 2016. The maximum utilisation including interest is limited to 95 percent of the tax refund related to exploration expenses.
The interest rate is 3 months' NIBOR plus a margin of 1.75 percent, with a utilisation fee of 0.25 percent on outstanding loan up to NOK 2,750 million and 0.5 percent if the outstanding loan exceeds NOK 2,750 million. In addition, a commitment fee of 0.7 percent is also paid on unused credit.
2)The loan runs from 2 July 2013 to 2 July 2020 and carries an interest rate of 3 month NIBOR + 5 percent. The principal falls due on July 2020 and interest is paid on a quarterly basis. The loan is unsecured.
| Breakdown of other interest-bearing debt | 31.12.2013 | 31.12.2012 |
|---|---|---|
| Revolving credit facility | 1 992 055 | 1 331 467 |
| Unrealised currency gains (-) / losses (+) | 44 852 | -31 734 |
| Total other interest-bearing debt | 2 036 907 | 1 299 733 |
For further details on covenants, see Note 29.
As primary security, the lender has a mortgage in an escrow account into which the tax refund will be deposited. In addition, some licences p y y, g g p , are pledged as security for the lender. For licence overview and corresponding pledges, see Note 30.
| Available for withdrawal on the revolving credit facility | 31.12.2013 | 31.12.2012 |
|---|---|---|
| Available for withdrawal | 6 083 700 | 2 783 200 |
| Drawn amount | 2 093 562 | 1 399 702 |
| Unused amount available for withdrawal on the revolving credit facility | 3 990 138 | 1 383 498 |
The interest rate on the revolving credit facility is from 1 - 6 months NIBOR/LIBOR pluss a margin of 3 percent, with a utilisation fee of 0.5 percent or 0.75 percent based on the amount drawn under the facility. In addition, commitment fee of 1.20 percent is paid on unused credit.
| Breakdown of other current liabilities | 31.12.2012 | |
|---|---|---|
| Current liabilities related to overcall in licences Current liabilities related to overcall in |
202 037 202 037 |
113 113 072 |
| Share of other current liabilities in licences | 310 673 | 519 439 |
| Overlift of petroleum | 9 588 | |
| Other current liabilities including accruals | 273 382 | 220 211 |
| Total other current liabilities | 795 680 | 852 722 |
In September 2013, the company entered into a USD 1 billion revolving credit facility with a group of nordic and international banks. The revolving credit facility can be increased with USD 1 billion on certain future conditions. The company can draw on the facility until September 2018 with a final date for repayment as of September 2018. The facility replaced the company's USD 500 million tranche which originally matured on 31 December 2015.
Other current liabilities includes unpaid wages and vacation pay, provision for future losses and accrued interest.
Future minimum lease obligations in accordance with non-terminable operational lease agreements
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Within 1 year | 165 486 | 46 002 |
| 1 to 5 years | 1 264 685 | 107 919 |
| After 5 years | 262 057 | |
| Total | 1 692 228 | 153 921 |
The company entered into an agreement with Maersk Giant Norge in 2012 for the lease of the rig Maersk Giant in a period of 150 days to drill two wells. One of the wells were drilled in 2013. Det norske has also signed a contract with Dolphin Drilling AS in 2012, for lease of the rig Dolphin Drilling AS in a periode of 60 days.
On behalf of the partners in Ivar Aasen, the company has signed an agreement in 2013 with Maersk XLE2 Norge A/S 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 two additional years.
The company has signed a lease agreement for Transocean Barents which runs to July 2014. The company has signed a lease agreement for Transocean Barents which runs to July
In addition, the company has other operational lease liabilities and other long-term liabilities pertaining to its owning interests in oil and gas
fields.
The company's share of liabilities mentioned above are assumed to fall due as follows:
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 exclusive the rig contract amonts to NOK 2,599.8 million. This amount is not included in any of the tables, since these commitments are not considered as leases.
Total future lease obligations in connection with rig contracts are assumed to fall due as follows:
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Within 1 year | 638 505 | 1 413 171 |
| 1 to 5 years | 888 923 | |
| Total | 638 505 | 2 302 095 |
The company's liabilities in connection with non-terminable agreements for lease of office premises and hire of IT services:
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Within 1 year | 79 810 | 65 431 |
| 1 to 5 years | 343 733 | 324 464 |
| After 5 years | 33 348 | 90 124 |
| Total | 456 890 | 480 019 |
The rig contracts will be used for exploration drilling in the company's licences or subletted to other companies. Before a rig decision is taken, the minimum lease obligation cannot be determined with certainty, since it will depend on the company's owning interest in the respective licences that will actually use the rig. The table below shows the company's total lease obligations in connection with these agreements. The total obligation will be reduced by the contribution paid by the various partners in the respective licences. When the rig decision is taken, the liablility will be included in the table 'Lease obligation pertaining to owning interests in licences'.
The company has two rental agreements for office premises in Oslo, of which the longest 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 expires in 2020. In 2012, the company signed a new contract for IT services. The hire period is five years, both in Harstad and Trondheim expires in In the company signed a new contract for IT The hire period is five years, and the contract cannot be terminated during this period.
The expected minimum rental income from subleasing the rig under non-terminable operational leases as of 31 December 2013 is NOK 700.5 million, the corresponding figure for 2012 was NOK 1,780 million.
| IT services and office Rig contracts premises |
||||
|---|---|---|---|---|
| Breakdown of lease costs: | 2013 | 2012 | 2013 | 2012 |
| Ordinary lease payments | 1 679 215 | 1 819 557 | 69 216 | 56 529 |
| Payments received on subleases | -1 418 911 | -1 598 858 | -5 484 | -5 651 |
| Total | 260 304 | 220 699 | 63 731 | 50 878 |
| Minimum lease obligations during the year: | Note 29: Financial instruments | |||||
|---|---|---|---|---|---|---|
| IT services and office | Capital structure and equity | |||||
| Rig contracts | premises | |||||
| Breakdown of lease costs: | 2013 | 2012 | 2013 | 2012 | ||
| Ordinary lease payments | 1 679 215 | 1 819 557 | 69 216 | 56 529 | ||
| Payments received on subleases | -1 418 911 | -1 598 858 | -5 484 | -5 651 | ||
| Total | 260 304 | 220 699 | 63 731 | 50 878 | ||
| Most of the leases contain an option for extension. The leases do not contain any restrictions on the company's dividend policy or financing. | ||||||
| Liability for damages / insurance | 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 liabilities are covered by an operational liability insurance policy. |
|||||
| Guarantees | ||||||
| The company has established a loan scheme whereby permanent employees can borrow up to 30 percent 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 a savings bank, and the company guarantees for the employees' loans. Guarantees furnished |
||||||
| by the company for employees totalled NOK 32.9 million at 31 December 2013. The corresponding amount for 2012 was NOK 19.0 million. | ||||||
| The company has provided a guarantee in the amount of NOK 12.9 million to cover the rent for the company's premises at Aker Brygge. | ||||||
| For further information about guarantees see Note 29. | ||||||
| Uncertain liabilities | 1) Total committed sources to exceed total uses | |||||
| During the second quarter of 2012, the company announced that it had received a notice of reassessment from the Norwegian Oil Taxation | 2) equity ratio | |||||
| Office (OTO) in respect of 2009 and 2010. Subsequently the notice has been extended to include 2011 and 2012. At the end of the third | 3) debt service reserve ratio, and | |||||
| quarter 2012, the company responded to the notice of reassessment by submitting detailed comments. | 4) asset coverage ratio | |||||
| During the normal course of its business the company will be involved in disputes. The company provides accruals in its financial statements of for probable liabilities related to litigation and claims based on the company's best judgement Det norske does not expect that the financial on position, results of operations or cash flows will be materially affected by the resolution of these disputes. |
company's best judgement. | does not | that the financial | |||
| Note 28: Transactions with related parties | Categories of financial assets and liabilities at fair value. |
|||||
| Owners with controlling interests | Categories of financial assets and financial liabilities: | |||||
| At yearend 2013, Aker (Aker Capital AS) was the largest shareholder in Det norske, with a total owning interest of 49.99 percent. An overview of the 20 largest shareholders is provided in Note 20. |
||||||
| value | ||||||
| Duty of disclosure related to the executive management | ||||||
| For more details about remuneration of key executive personnel, see Note 8. | ||||||
| Transactions with related parties | Assets | |||||
| The whole Aker group is deemed to be a related party due to its ownership connection. | ||||||
| In connection with our development projects on Jette and Ivar Aasen, agreements have been entered into with Aker Solutions and its | ||||||
| subsidiaries, which are associate companies to Aker ASA. Det norske's share of transactions in 2013 and 2012 has been included in the | ||||||
| table below. | ||||||
| Transactions with related parties are carried out on the basis of the "arm's length" principle. | ||||||
| Related party | Receivables (+) / liabilities (-) | 31.12.2013 | 31.12.2012 | Liability | ||
| Aker Solutions | Trade creditors | -7 525 | ||||
| Related party | Revenues (-) / expenses (+) | 2013 | 2012 | |||
| Aker ASA | Software and board remuneration | 1 444 | 6 749 | |||
| Aker Solutions | Delivery to Ivar Aasen and Jette development | 55 041 | 97 806 | |||
| Other Aker companies Other Aker |
1 758 1 |
The company's equity ratio (equity in relation to total capital) as of 31 December is shown in the table below.
| 31.12.2013 | 31.12.2012 | |
|---|---|---|
| Equity as of 31.12 | 3 188 470 | 3 736 175 |
| Total capital | 10 541 352 | 8 364 453 |
| Equity ratio | 30 % | 45 % |
The main objective of the company's management of the capital structure is to maximise return to the owners by ensuring competitive conditions for both the company's own capital and borrowed capital.
The company seeks to optimise 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 and equity markets, including the bond market and the bank market.
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 from 2012 has strengthened the company's financial position.
There are several covenant requirements related to our borrowing facilities. Covenants include: 1) Total committed sources to exceed total uses 2) equity ratio 3) debt service reserve ratio, and 4) asset coverage ratio
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 to refinance its debt, purchase or issue new shares or debt instruments, sell assets or pay back capital to the owners.
| 31.12.2013 | Financial assets at fair value Designated as such upon initial recognition |
Loan and receivables |
Financial liabilities at fair value Designated as such upon initial recognition |
Financial liabilities measured at amortised costs |
Total |
|---|---|---|---|---|---|
| Assets | |||||
| Short-term deposits | 24 075 | 24 075 | |||
| Accounts receivable | 134 221 | 134 221 | |||
| Other short-term receivables1) | 349 338 | 349 338 | |||
| Tax receivables | 1 411 251 | 1 411 251 | |||
| Other non-current assets | 285 399 | 285 399 | |||
| Cash and cash equivalents | 1 709 166 | 1 709 166 | |||
| Total financial assets | 24 075 | 3 889 375 | 3 913 450 | ||
| Liability | |||||
| Derivatives | 49 453 | 49 453 | |||
| Trade creditors | 452 435 | 452 435 | |||
| Bonds | 2 473 582 | 2 473 582 | |||
| Short-term loan | 478 050 | 478 050 | |||
| Other interest-bearing debt | 2 036 907 | 2 036 907 | |||
| Other short-term liabilities | 819 259 | 819 259 | |||
| Total financial liabilities | 49 453 | 6 260 233 | 6 309 686 |
| Liability |
|---|
| ----------- |
| 31.12.2013 | Financial assets at fair value Designated as such upon initial recognition |
Loan and receivables |
Financial liabilities at fair value Designated as such upon initial recognition |
Financial liabilities measured at amortised costs |
Total |
|---|---|---|---|---|---|
| Assets | |||||
| Short-term deposits | 24 075 | 24 075 | |||
| Accounts receivable | 134 221 | 134 221 | |||
| Other short-term receivables1) | 349 338 | 349 338 | |||
| Tax receivables | 1 411 251 | 1 411 251 | |||
| Other non-current assets | 285 399 | 285 399 | |||
| Cash and cash equivalents | 1 709 166 | 1 709 166 | |||
| Total financial assets | 24 075 | 3 889 375 | 3 913 450 | ||
| Liability | |||||
| Derivatives | 49 453 | 49 453 | |||
| Trade creditors | 452 435 | 452 435 | |||
| Bonds | 2 473 582 | 2 473 582 | |||
| Short-term loan | 478 050 | 478 050 | |||
| Other interest-bearing debt | 2 036 907 | 2 036 907 | |||
| Other short-term liabilities | 819 259 | 819 259 | |||
| Total financial liabilities | 49 453 | 6 260 233 | 6 309 686 |
The company has the following financial assets and liabilities: financial assets and liabilities recognised at fair value through profit or loss, loans and receivables, and other liabilities. The last two are recognised in the accounts at amortised cost, while the first item is recognised at fair value.
1)Prepayments are not included in other short-term receivables as prepayments are not deemed to be financial instruments Prepayments are not included in other short-term receivables, as prepayments are not deemed to be financial instruments.
The company met all these requirements both in 2012 and 2013.
Categories of financial assets and financial liabilities:
1)Prepayments are not included in other short-term receivables, as prepayments are not deemed to be financial instruments.
| Financial assets at fair | Financial | ||||
|---|---|---|---|---|---|
| value | Financial liabilities at fair value | liabilities | |||
| Designated as such upon | Loan and | Designated as such upon initial | measured at | ||
| 31.12.2012 | initial recognition | receivables | recognition | amortised costs | Total |
| Assets | |||||
| Short-term deposits | 23 138 | 23 138 | |||
| Trade receivables | 101 839 | 101 839 | |||
| Other short-term receivables1) | 318 862 | 318 862 | |||
| Tax receivables | 1 273 737 | 1 273 737 | |||
| Other non-current assets | 193 934 | 193 934 | |||
| Cash and cash equivalents | 1 154 182 | 1 154 182 | |||
| Total financial assets | 23 138 | 3 042 554 | 3 065 691 | ||
| Liability | |||||
| Derivatives | 45 971 | 45 971 | |||
| Trade creditors | 258 596 | 258 596 | |||
| Bonds | 589 078 | 589 078 | |||
| Short-term loan | 567 075 | 567 075 | |||
| Other interest-bearing debt | 1 299 733 | 1 299 733 | |||
| Other short-term liabilities | 877 258 | 877 258 | |||
| Total financial liabilities | 45 971 | 3 591 740 | 3 637 711 |
The company has financed its activities with an exploration facility, a revolving credit facility and two bonds, all 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.
Revenues from sale of petroleum and gas are in USD, 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 some of the expenses are in USD, some of this risk is reduced. Currency derivatives may be used. Foreign 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 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 capital requirements.
The company's risk management, including financial risk management, is designed to ensure identification, analysis and systematic and cost-efficient handling of risk. Established management procedures provide a good basis for reporting and monitoring of the company's risk exposure.
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. The company's oil and gas production is currently at a limited level, and the company has therefore chosen not to hedge against the related price risk. However, the company will continue to consider hedging against oil and gas prices as production increases.
Oil and gas production from the Atla field started in October 2012. The physical production volumes from Atla were higher than the commercial production volumes due to an agreement to make up for delayed production from Skirne caused by pressure differences, see Notes 16 and 17. Revenue and production costs are accounted for using the physical production from Atla, while the actual sale of the delta between physical production and commercial production occurs in 2014 and 2015, when Skirne production is back at normal rate. This delayed sale results in a greater risk exposure to price fluctuations and exchange rates.
| USD/NOK | Change in exchange rate | 31.12.2013 | 31.12.2012 |
|---|---|---|---|
| Effect on pre-tax profit/loss: | + 10% | -72 900 | -22 652 |
| - 10% | 72 890 | 22 652 |
| The table below shows the company's exposure in USD as of 31 December: | ||
|---|---|---|
| Exposure relating to: | 31.12.2013 | 31.12.2012 |
| Receivables, cash and cash equivalents, other short-term receivables and deposits | 87 213 | 76 991 |
| Trade creditors and other short-term liabilities | -19 858 | -12 567 |
| Revolving credit facility | -187 184 | -105 118 |
| Net exposure in USD | -119 828 | -40 694 |
| EUR/NOK | Change in exchange rate | 31.12.2013 | 31.12.2012 |
|---|---|---|---|
| Effect on pre-tax profit/loss: | + 10% | 2 996 | 3 808 |
| - 10% | -2 996 | -3 808 |
The table below shows the company's exposure in EUR as of 31 December:
| Exposure relating to: | 31.12.2013 | 31.12.2012 |
|---|---|---|
| Receivables, other short-term receivables and cash and cash equivalents | 9 433 | 5 449 |
| Trade creditors and other short-term liabilities | -5 860 | -262 |
| Net exposure in EUR | 3 574 | 5 187 |
The table below shows the company's sensitivity to potential changes in exchange rates according to the company's financial instruments in the Statement of financial position as of 31 December.
The terms of the company's loans are described in Notes 24 and 25.
The company is also exposed for change in other exchange rates as GBP/NOK, CHF/NOK, SGD/NOK and DKK/NOK, but the amount is
| 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: | 31.12.2013 | 31.12.2012 | ||||||
| Effect on pre-tax profit/loss: | + 100 | 60 507 | 70 765 | |||||
| - 100 | -61 469 | -56 568 |
| Change in interest rate level in basis points: | 31.12.2013 | 31.12.2012 | |
|---|---|---|---|
| Effect on pre-tax profit/loss: | + 100 | 60 507 | 70 765 |
| - 100 | -61 469 | -56 568 |
not material as of 31 December 2013.
The table shows the effect on profit or loss in 2013 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. Hence, the market interest rate risk on the interest rate-swaps is unlikely to expose the company to significant future cash flow risk.
The interest-rate risk relating to liquid assets is relatively limited. In accordance with the company's guidelines, the average interest-rate sensitivity, including exposure relating to financial derivatives, shall not exceed one year for the investment portfolio as a whole.
The company is exposed to interest-rate risk to borrowings and placement of liquid assets. Floating-interest loans involve risk exposure for the company's future cash flows. As of 31 December 2013, the company's total loan liabilities amounted to approximately NOK 5.1 billion, distributed between two long-term bond issues, one revolving credit facility and one short-term exploration facility. The purpose with the exploration facility is to finance exploration activities while the credit facility shall mainly finance development projects, see Note 25. The corresponding loan liabilities as of 31 December 2012 amounted to NOK 2.6 billion.
In order to calculate sensitivity of interest rate changes, floating interest rates have been changed by + / - 100 basis points.
The company's liquidity risk is the risk that it will not be able to meet its financial obligations as they fall due.
As of 31 December 2013, the company's excess liquid assets are mainly deposited in bank accounts.
Some reporting requirements are associated with the agreement with the bank syndicate that furnished the exploration facility, including quarterly updates of a revolving liquidity budget for the next 12 months. For the multi-currency facility it is also required that equity must be at least 25 percent and the company shall hold a debt service reserve account. The amount on this account should cover the projected next twelve months financial expenses (excluding the Exploration Financing Facility). The company met this requirement both in 2013 and in
As of 31 December 2013, the company has cash reserves of NOK 1,709,166 (2012: 1,154,182). However, the combination of limited production revenues and active exploration and development programmes sets requirements for managing liquidity risk.
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 day-to-day decision basis for the company's board of directors.
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.
The company will handle any increased future capital requirements through selling assets, raising new capital, taking up loans, entering into p y y p q g g , g p , gp , g carry agreements, strategic alliances or any combination of these, or by adjusting the company's level of activity, if required.
For excess liquidity, the requirement for low liquidity risk (i.e. the risk of realisation at short notice) is generally more important than maximising the return.
The company's objective for the placement and management of excess capital is to maintain a low risk profile and good liquidity.
The table below shows the payment structure for the company's financial commitments, based on undiscounted contractual payments:
| Contractrelated cash flow: | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| 31.12.2013 | Book value |
Less than 1 year |
1-2 years | 2-5 years | Over 5 years | SUM | |||
| Non-derivative financial liabilities: | |||||||||
| Bond issue | 2 473 582 | 177 500 | 177 500 | 984 975 | 2 141 101 | 3 481 076 | |||
| Exploration facility | 478 050 | 538 123 | 538 123 | ||||||
| Revolving credit facility | 2 036 907 | 137 590 | 137 590 | 2 516 785 | 137 590 | ||||
| Trade creditors and other liabilities | 1 271 694 | 1 271 694 | 1 271 694 | ||||||
| Derivative financial liabilities | |||||||||
| Derivatives | 49 453 | 23 743 | 18 896 | 6 745 | 49 384 | ||||
| Total as of 31.12.2013 | 6 309 686 | 2 148 649 | 333 986 | 3 508 505 | 2 141 101 | 5 477 866 |
The company has a total borrowing limit of NOK 3.5 billion for exploration purposes and USD 1 billion mainly for development purpose; see Note 25. In additon the company has two bond issues amounting to NOK 2.5 billion. Together with the company's liquid assets, this is sufficient to finance the company's operations through 2014.
| Book | Contractrelated cash flow: Less than 1 |
|||||
|---|---|---|---|---|---|---|
| 31.12.2012 | value | year | 1-2 years | 2-5 years | Over 5 years | SUM |
| Non-derivative financial liabilities: | ||||||
| Bond issue | 589 078 | 51 780 | 51 780 | 655 807 | 759 367 | |
| Exploration facility | 567 075 | 644 596 | 644 596 | |||
| Revolving credit facility | 1 299 733 | 81 150 | 81 150 | 1 582 301 | 1 744 601 | |
| Trade creditors and other liabilities | 1 135 854 | 1 135 854 | 1 135 854 | |||
| Derivative financial liabilities | ||||||
| Derivatives | 45 971 | 12 661 | 16 788 | 17 687 | 47 136 | |
| Total as of 31.12.2012 | 3 637 711 | 1 926 042 | 149 718 | 2 255 795 | 4 331 555 |
| Contractrelated cash flow: | ||||||||
|---|---|---|---|---|---|---|---|---|
| Book | Less than 1 | SUM | ||||||
| 31.12.2012 | value | year | 2-5 years Over 5 years |
1-2 years | ||||
| Non-derivative financial liabilities: | ||||||||
| Bond issue | 589 078 | 51 780 | 51 780 | 655 807 | 759 367 | |||
| Exploration facility | 567 075 | 644 596 | 644 596 | |||||
| Revolving credit facility | 1 299 733 | 81 150 | 81 150 | 1 582 301 | 1 744 601 | |||
| Trade creditors and other liabilities | 1 135 854 | 1 135 854 | 1 135 854 | |||||
| Derivative financial liabilities | ||||||||
| Derivatives | 45 971 | 12 661 | 16 788 | 17 687 | 47 136 | |||
| Total as of 31.12.2012 | 3 637 711 | 1 926 042 | 149 718 | 2 255 795 | 4 331 555 |
The fair value of derivatives is defined by involved banks based on market considerations; see Note 23.
| Contractrelated cash flow: | ||||||
|---|---|---|---|---|---|---|
| Book | Less than 1 | |||||
| 31.12.2012 | value | year | 1-2 years | 2-5 years | Over 5 years | SUM |
| Non-derivative financial liabilities: | ||||||
| Bond issue | 589 078 | 51 780 | 51 780 | 655 807 | 759 367 | |
| Exploration facility | 567 075 | 644 596 | 644 596 | |||
| Revolving credit facility | 1 299 733 | 81 150 | 81 150 | 1 582 301 | 1 744 601 | |
| Trade creditors and other liabilities | 1 135 854 | 1 135 854 | 1 135 854 | |||
| Derivative financial liabilities | ||||||
| Derivatives | 45 971 | 12 661 | 16 788 | 17 687 | 47 136 | |
| Total as of 31.12.2012 | 3 637 711 | 1 926 042 | 149 718 | 2 255 795 | 4 331 555 |
The risk of counterparties being financially incapable of fulfilling their obligations is regarded as minor as there have not been any losses on accounts receivable, historically. The company's customers are large and creditworthy oil companies and it has therefore not been necessary to make any provision for bad debt.
In the management of the company's liquid assets, low credit-risk is prioritised. 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 and investments; see Notes 15 and 16.
The fair value of the long term loan is virtually the same as book value, as the loan was entered into in September 2013.
The maximum credit risk exposure corresponds to the book value of financial assets in the Statement of financial position.
| 31.12.2013 | 31.12.2012 | |||
|---|---|---|---|---|
| Book | Fair | Book | Fair | |
| Fair value of financial instruments: | value | value | value | value |
| Financial assets valued at fair value through profit or loss: | ||||
| Market-based financial investments | 24 075 | 24 075 | 23 138 | 23 138 |
| Total financial assets | 24 075 | 24 075 | 23 138 | 23 138 |
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.
Items included in market-based financial investments are subordinate loan. The fair value of these 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 increased by NOK 937.5 (2012: 1,387), and the gain is recognised as 'Other financial income' in the Income statement.
The book value of liquid assets and loans is virtually the same as their fair value, as these instruments have a short term to maturity. Correspondingly, the book value 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 financial fixed assets mainly consist of deposits, and hence their value is virtually equal to their fair value.
The bond issue from January 2011 and the one issued in September 2013 are listed on Oslo Børs, and the fair value is determined using
the quoted value as of 31 December.
The following is a comparison between the book value and fair value of the company's financial instruments, without those where the carrying amount is a reasonable approximation of fair value (such as short-term trade receivables and payables).
| 31.12.2013 | 31.12.2012 | ||||
|---|---|---|---|---|---|
| Book | Fair | Book | Fair | ||
| Fair value of financial instruments: | value | value | value | value | |
| Financial liabilities valued at fair value through profit or loss: Derivatives |
49 453 | 49 453 | 45 971 | 45 971 | |
| Financial liabilities measured at amortised cost: | |||||
| Bond issue | 2 473 582 | 2 529 750 | 589 078 | 633 600 | |
| Total financial liabilities | 2 523 035 | 2 579 203 | 635 049 | 679 571 |
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).
The company has no assets in Level 3.
The company classifies fair value measurements by using a value hierarchy that reflects the significance of the input used in preparing the measurements. The fair value hierarchy consists of the following levels:
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).
| 31.12.2013 | |||
|---|---|---|---|
| Assets recognised at fair value | Level 1 | Level 2 | Level 3 |
| Financial assets measured at fair value with changes in value recognised | |||
| through profit or loss | |||
| Derivatives - interest swaps p |
49 453 | ||
| Bond issue | 2 529 750 | ||
| Market-based financial investments | 24 075 | ||
| 31.12.2012 | |||
| Assets recognised at fair value | Level 1 | Level 2 | Level 3 |
| Financial assets measured at fair value with changes in value recognised | |||
| through profit or loss | |||
| Derivatives - interest swaps | 45 971 | ||
| Bond issue | 633 600 | ||
| Market-based financial investments | 23 138 |
In the course of the reporting period, there were no changes in the fair value measurements that involved any transfers between levels.
Det norske has provided the landlord KLP with a guarantee in the amount of NOK 12.9 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. The lenders have security in the company's tax receivable and in licences. For a list of licences in which the lenders have security, see Note 30. The book value of licences furnished as security is NOK 4,400.3 million (2012: 4,143.6 million). In addition lenders have security in account receivables, limited to USD 2.5 milliard, the debt reserve account, derivatives (if those are positive) and payments of insurance settlement.
The company has established a loan scheme whereby permanent employees can borrow up to 30 percent 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 a savings bank, and the company guarantees for the employees' loans. Guarantees furnished by the company for employees totalled NOK 32.9 million at 31 December 2013. The corresponding amount for 2012 was NOK 19.0 million.
Investments in jointly controlled assets is included using the 'gross method' (proportionate consolidation), based on the owning interests.
The company's investments in licences on the Norwegian Continental Shelf as of 31.12.:
| Production licences in which Det norske is operator: | Production licences in which Det norske is partner: | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| Licence | Pledged | 31.12.2013 | 31.12.2012 | Licence | Pledged | 31.12.2013 | 31.12.2012 | ||
| PL 001B | yes | 35,0 % | 35,0 % PL 019C*** | 30,0 % | 0,0 % | ||||
| PL 026B*** | 62,1 % | 0,0 % PL 019D*** | 30,0 % | 0,0 % | |||||
| PL 027D*** | yes | 100,0 % | 60,0 % PL 029B | yes | 20,0 % | 20,0 % | |||
| PL 027ES*** | 40,0 % | 0,0 % PL 035 | yes | 25,0 % | 25,0 % | ||||
| PL 028B | yes | 35,0 % | 35,0 % PL 035B | 15,0 % | 15,0 % | ||||
| PL 103B | yes | 70,0 % | 70,0 % PL 035C | yes | 25,0 % | 25,0 % | |||
| PL 169C | yes | 50,0 % | 50,0 % PL 038 | yes | 5,0 % | 5,0 % | |||
| PL 242 | yes | 35,0 % | 35,0 % PL 038D | yes | 30,0 % | 30,0 % | |||
| PL 337* | 0,0 % | 45,0 % PL 048B | yes | 10,0 % | 10,0 % | ||||
| PL 356* | 0,0 % | 50,0 % PL 048D | yes | 10,0 % | 10,0 % | ||||
| PL 364 | 50,0 % | 50,0 % PL 102C | yes | 10,0 % | 10,0 % | ||||
| PL 414 | yes | 40,0 % | 40,0 % PL 102D | yes | 10,0 % | 10,0 % | |||
| PL 414B | yes | 40,0 % | 40,0 % PL 102F*** | 10,0 % | 0,0 % | ||||
| PL 450*** | yes | 80,0 % | 60,0 % PL 102G*** | 10,0 % | 0,0 % | ||||
| PL 460 | 100,0 % | 100,0 % PL 265 | yes | 20,0 % | 20,0 % | ||||
| PL 482* | 0,0 % | 65,0 % PL 272 | yes | 25,0 % | 25,0 % | ||||
| PL 494**** | yes | 30,0 % | 0,0 % PL 332 | yes | 40,0 % | 40,0 % | |||
| PL 494B**** | yes | 30,0 % | 0,0 % PL 362** | yes | 15,0 % | 15,0 % | |||
| PL 494C**** | yes | 30,0 % | 0,0 % PL 438 | yes | 10,0 % | 10,0 % | |||
| PL 497 | yes | 35,0 % | 35,0 % PL 440S* | 0,0 % | 10,0 % | ||||
| PL 497B | yes | 35,0 % | 35,0 % PL 442 | 20,0 % | 20,0 % | ||||
| PL 504 PL 504*** |
yes | 47,6 % | 29,3 % PL 453S | PL | yes | 25,0 % | 25,0 % | ||
| PL 504BS*** | yes | 83,6 % | 58,5 % PL 492*** | yes | 40,0 % | 50,0 % | |||
| PL 504CS*** | 21,8 % | 0,0 % PL 494**** | 0,0 % | 30,0 % | |||||
| PL 512 | yes | 30,0 % | 30,0 % PL 494B**** | 0,0 % | 30,0 % | ||||
| PL 542 *** | yes | 45,0 % | 60,0 % PL 494C**** | 0,0 % | 30,0 % | ||||
| PL 542B/* | yes | 45,0 % | 0,0 % PL 502 | yes | 22,2 % | 22,2 % | |||
| PL 549S | yes | 35,0 % | 35,0 % PL 522 | yes | 10,0 % | 10,0 % | |||
| PL 553 | yes | 40,0 % | 40,0 % PL 531 | yes | 10,0 % | 10,0 % | |||
| PL 573S | yes | 35,0 % | 35,0 % PL 533 | yes | 20,0 % | 20,0 % | |||
| PL 593* | 0,0 % | 60,0 % PL 535*** | yes | 10,0 % | 20,0 % | ||||
| PL 626 | yes | 50,0 % | 50,0 % PL 535B*/* | yes | 10,0 % | 0,0 % | |||
| PL 659 | yes | 30,0 % | 30,0 % PL 550*** | yes | 10,0 % | 20,0 % | |||
| PL 663** | yes | 30,0 % | 0,0 % PL 551 | yes | 20,0 % | 20,0 % | |||
| PL 677** | yes | 60,0 % | 0,0 % PL 554 | yes | 20,0 % | 20,0 % | |||
| PL 709* | yes | 40,0 % | 0,0 % PL 554B | yes | 20,0 % | 20,0 % | |||
| PL 715* | yes | 40,0 % | 0,0 % PL 558 | yes | 20,0 % | 20,0 % | |||
| Number | 33 | 41 PL 561* | 0,0 % | 20,0 % | |||||
| PL 563 | yes | 30,0 % | 30,0 % | ||||||
| PL 567 | yes | 40,0 % | 40,0 % | ||||||
| * Relinquished licences or Det norske has withdrawn from the licence. | PL 568 | yes | 20,0 % | 20,0 % | |||||
| PL 571 | yes | 40,0 % | 40,0 % | ||||||
| ** Interest awarded in the APA round (Awards in Predefined Areas) in | PL 574*** | 10,0 % | 0,0 % | ||||||
| 2012. Offers were announced in 2013. | PL 613 | yes | 35,0 % | 35,0 % | |||||
| PL 619 | yes | 30,0 % | 30,0 % | ||||||
| *** Acquired/changed through licence transaction or licence is split. | PL 627 | yes | 20,0 % | 20,0 % | |||||
| PL 652* | 0,0 % | 20,0 % | |||||||
| **** Det norske previously partner, now operator. | PL 667** | yes | 30,0 % | 0,0 % | |||||
| PL 672** | yes | 25,0 % | 0,0 % | ||||||
| * Interest awarded in 22nd licencing round. | PL 676S** | yes | 20,0 % | 0,0 % | |||||
| PL 678S** | yes | 25,0 % | 0,0 % | ||||||
| ** Fulla field not pledged Fulla field not |
PL 681** PL 681 |
yes | 16,0 16,0 % |
0,0 % 0,0 |
|||||
| PL 706* | yes | 20,0 % | 0,0 % | ||||||
| On 21 January 2014, Det norske was offered ownership | Number | 47 | 41 |
interests in six licences in APA 2013. For two of these Det norske will be operator.
Figure 1 - SPE's classification system used by Det norske oljeselskap ASA
Det norske oljeselskap ASA's reserve and contingent resource volumes have been classified in accordance with the Society of Petroleum Engineer's (SPE's) 'Petroleum Resources Management System'. This classification system is consistent with Oslo Stock Exchange's requirements for the disclosure of hydrocarbon reserves and contingent resources.
In line with prior year's practise, the company's reserves and contingent resources have been certified by an independent third party AGR Petroleum Services AS.
Det norske oljeselskap ASA has a working interest in eight fields/projects containing reserves, see Table 1. Out of these fields/projects, four are in the sub-class 'On Production' and four are in the sub-class 'Approved for Development'. Note that Varg has reserves in both 'On Production' and in 'Justified for Development'.
Sub-class 'On Production':
Sub-class 'Approved for Development':
Total net proven reserves (P90/1P) as of 31.12.2013 to Det norske are estimated at 48.5 million barrels of oil equivalents (mill. boe). Total net proven plus probable reserves (P50/2P) are estimated at 65.8 million boe. The split between liquid and gas and between the different subcategories can be seen in Table 1.
Changes from 2012 are summarized in Table 2. The main reason for increased net proven total reserve estimate is increased Ivar Aasen C a ges o 0 a e su a ed ab e e a easo o c eased e p o e o a ese e es a e s c eased a ase reserves. Note that the increased "On Production" reserve estimate is because Jette has been upgraded from 'Approved for Development'. Note also that the significantly increased 'Approved for Development' reserve estimate is because all fields reported in 'Justified for Development' last year (Ivar Aasen, Gina Krog and Varg gas) have been upgraded. This is consequently also the reason for the reduced 'Justified for Development' reserve estimates.
| Table 1 - Reserves by field | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| 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. |
||
| (million | (million | (million | (million | (million | (million | ||||||
| 31.12.2013 | % | barrels) | Mton | (bcm) | barrels) | barrels) | barrels) | Mton | (bcm) | barrels) | barrels) |
| Glitne | 10,0 % | 0,00 | 0,00 | 0,00 | 0,00 | ||||||
| Varg | 5,0 % | 1,43 | 1,43 | 0,07 | 2,42 | 2,42 | 0,12 | ||||
| Jotun Unit | 7,0 % | 3,29 | 3,29 | 0,23 | 3,57 | 3,57 | 0,25 | ||||
| Atla | 10,0 % | 0,57 | 0,61 | 4,38 | 0,44 | 0,77 | 0,95 | 6,77 | 0,68 | ||
| Jette (moved from AfD) | 70,0 % | 0,77 | 0,77 | 0,54 | 3,24 | 3,24 | 2,27 | ||||
| Total | 1,28 | 3,32 |
| 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. |
||
| (million | (million | (million | (million | (million | (million | ||||||
| 31.12.2013 | % | barrels) | Mton | (bcm) | barrels) | barrels) | barrels) | Mton | (bcm) | barrels) | barrels) |
| Enoch Unit | 2,0 % | 1,71 | 1,71 | 0,03 | 2,61 | 2,61 | 0,05 | ||||
| Jette (moved to in production) 70,0 % | |||||||||||
| Ivar Aasen (moved from JfD) 35,0 % | 84,46 | 0,87 | 3,87 | 119,25 | 41,74 | 115,49 | 1,06 | 4,67 | 157,56 | 55,15 | |
| Gina Krog (moved from JfD) | 3,3 % | 80,79 | 2,48 | 8,49 | 163,82 | 5,41 | 104,79 | 3,15 11,33 | 213,67 | 7,05 | |
| Varg gas (moved from JfD) | 5,0 % | 0,04 | 0,04 | 0,15 | 1,48 | 0,07 | 0,23 | 0,10 | 0,39 | 3,88 | 0,19 |
| Total | 47,25 | 62,44 |
| 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. |
||
| (million | (million | (million | (million | (million | (million | ||||||
| 31.12.2013 | % | barrels) ) |
Mton | ( (bcm) ) |
barrels) ) |
barrels) ) |
barrels) ) |
Mton | ( (bcm) ) |
barrels) ) |
barrels) ) |
| Ivar Aasen (moved to AfD) | 35,0 % | 0,00 | 0,00 | 0,00 | 0,00 | ||||||
| Gina Krog (moved to AfD) | 3,3 % | 0,00 | 0,00 | 0,00 | 0,00 | ||||||
| Varg gas (moved to AfD) | 5,0 % | 0,00 | 0,00 | 0,00 | 0,00 | ||||||
| Total | 0,00 | 0,00 | |||||||||
| Total Reserves 31.12.2013 | 48,53 | 65,76 |
| Net attributed million barrels of oil equivalents /mboe) |
In production | Approved for Development |
Justified for Development |
Total | ||||
|---|---|---|---|---|---|---|---|---|
| 1P / P90 | 2P / P50 | 1P / P90 2P / P50 1P / P90 | 2P / P50 | 1P / P90 2P / P50 | ||||
| Balance as of 31.12.2012 | 0,92 | 1,60 | 2,72 | 4,53 | 38,81 | 59,17 | 42,45 | 65,31 |
| Production | -1,63 | -1,63 | 0,00 | 0,00 | 0,00 | 0,00 | -1,63 | -1,63 |
| Acquisitions/disposals | 0,00 | 0,00 | 0,00 | 0,00 | 0,00 | 0,00 | 0,00 | 0,00 |
| Estensions 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 | 1,98 | 3,34 | 44,53 | 57,91 | -38,81 | -59,17 | 7,70 | 2,08 |
| Balance as of 31.12.2013 | 1,28 | 3,31 | 47,25 | 62,44 | 0,00 | 0,00 | 48,52 | 65,76 |
| Delta | 0,36 | 1,71 | 44,53 | 57,91 | -38,81 | -59,17 | 6,07 | 0,45 |
Note 32: Events after the year-end closing of the accounts
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 2013 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.
Sverre Skogen, Chair of the Board Tom Røtjer, Board Member Anne Marie Cannon, Deputy Chair Kjell Inge Røkke, Board Member Kitty Hall (Katherine Jessie Martin), Board Member Jørgen C Arentz Rostrup, Board Member Trondheim, 11 March 2014 Bjørn Thore Ribesen, Board Member Inge Sundet, Board Member Tonje Eskeland Foss, Board Member Øyvind Bratsberg, General Manager Ståle Gjersvold, Deputy Board Member
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.
The drilling operations on well 7222/11-2 on the Langlitinden prospect in PL 659 were completed in February 2014. Det norske is of the opinion that the volumes proven in this well are insufficient to justify a field development. Capitalised exploration expenditures as of 31 December 2013 are not expensed as the amount is deemed immaterial. The effect after tax is less than NOK 3 million.
In our opinion, the financial statements of Det norske oljeselskap ASA have been prepared in accordance with laws and regulations and present fairly, in all material respects, the financial position of the Company as at 31 December 2013 and its financial performance and its cash flows for the year then ended in accordance with the International Financial Reporting Standards as adopted by the EU.
Opinion on the Board of Directors' report and on the statements on corporate governance and corporate social responsibility
Based on our audit of the financial statements as described above, it is our opinion that the information presented in the Directors' report [and in the statements on corporate governance and corporate social responsibility] concerning the financial statements and the going concern assumption is consistent with the financial statements and complies with the law and regulations.
Based on our audit of the financial statements as described above, and control procedures we have considered necessary in accordance with the International Standard on Assurance Engagements (ISAE) 3000, «Assurance Engagements Other than Audits or Reviews of Historical Financial Information», it is our opinion that the Board of Directors and Chief Executive Officer have fulfilled their duty to ensure that the Company's accounting information is properly recorded and documented as required by law and generally accepted bookkeeping practice in Norway.
Stavanger, 11 March 2014 ERNST & YOUNG AS
Tor Inge Skjellevik State Authorised Public Accountant (Norway)
(This translation from Norwegian has been made for information purposes only.)
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The nationbuilder Ivar Aasen crisscrossed Norway in his search for words and phrases, developing a language based on rural Norwegian native speech, nynorsk. Now, Det norske has embarked on a worldwide journey developing the Ivar Aasen oil field.
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