Annual Report • Feb 8, 2012
Annual Report
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Stockholm 8 February 2012
| 1 Jan 2011- | 1 Oct 2011- | 1 Jan 2010- | 1 Oct 2010- | |
|---|---|---|---|---|
| 31 Dec 2011 | 31 Dec 2011 | 31 Dec 2010 | 31 Dec 2010 | |
| 12 months | 3 months | 12 months | 3 months | |
| Production in Mboepd Operating income in MUSD Net result in MUSD Net result attributable to shareholders of the Parent Company in MUSD Earnings/share in USD1 Diluted earnings/share in USD1 EBITDA in MUSD Operating cash flow in MUSD |
33.3 1,269.5 155.2 160.1 0.51 0.51 1,012.1 676.2 |
34.7 323.0 -14.0 -12.5 -0.05 -0.05 244.8 89.4 |
30.5 798.6 129.5 142.9 0.46 0.46 603.5 573.4 |
32.6 240.1 86.6 90.4 0.29 0.29 177.7 156.9 |
The numbers included in the table above are based on continuing operations. 1 Based on net result attributable to shareholders of the Parent Company
Lundin Petroleum is a Swedish independent oil and gas exploration and production company with a well balanced portfolio of world-class assets primarily located in Europe and South East Asia. The Company is listed at the NASDAQ OMX, Stockholm (ticker "LUPE") and at the Toronto Stock Exchange (TSX) (Ticker "LUP"). Lundin Petroleum has proven and probable reserves of 211 million barrels of oil equivalent (MMboe).
It is a great pleasure to update you on developments at Lundin Petroleum following our exceptional performance in 2011. 2011 was transformational for the Company when it became clear that Avaldsnes/Aldous (now renamed Johan Sverdrup) is one of the largest discoveries ever made in the North Sea. Our strategy, which is predicated on organic exploration growth, has delivered excellent success which resulted in a 100 percent increase in the share price of Lundin Petroleum during 2011, equating to increased shareholder value of SEK 27 billion.
The major news in 2011 was clearly the announcement of increased contingent resources in the Avaldsnes discovery, offshore Norway. As we had previously indicated, the Avaldsnes structure extends to the west into the Statoil operated PL265 and this was confirmed with the Aldous Major South discovery. Avaldsnes and Aldous Major South are essentially one connected giant oil field. Our Avaldsnes appraisal drilling programme in PL501, where we are operator, coupled with Statoil's discovery well and subsequent appraisal well in PL265 has confirmed that the thickness and quality of the Jurassic reservoir is better than previously assumed. Consequently, Lundin Petroleum has increased the contingent resource range for the Avaldsnes discovery in PL501 to between 800 million and 1.8 billion barrels of gross recoverable oil. Statoil has announced a contingent resource range of 900 million to 1.5 billion barrels of gross recoverable oil for the Aldous Major South discovery in PL265. As a result, the Johan Sverdrup discovery is estimated to contain gross contingent resources of between 1.7 and 3.3 billion barrels of recoverable oil. This makes the discovery one of the five largest discoveries ever made on the Norwegian Continental Shelf and the largest discovery since the mid 1980s. Furthermore, the discovery is located in 115 metres of water depth, in a reservoir of less than 2,000 metres, close to existing infrastructure with spare capacity and with oil that is of excellent quality. It is truly remarkable that a discovery of this size and quality could be made by Lundin Petroleum, in the heart of the Norwegian North Sea, 45 years after the first exploration activity began in the area.
The priority in 2012 is to fully appraise the discovery to better define the resource range and to provide information for development planning. The results of the first 2012 appraisal well targeting the southern extension of the discovery were disappointing with the top reservoir coming in low to prognosis and below the oil water contact. Appraisal drilling will, however, continue with a further five to seven new wells likely to be drilled in PL501 and PL265 in 2012. In tandem with the appraisal programme we are working closely with Statoil and our partners to move the conceptual project development planning forward. The discovery will be a major contributor to North Sea production for years to come and due to its size, location and quality of reservoir, will be one of the most valuable discoveries ever made in the North Sea.
Lundin Petroleum produced excellent financial results in 2011 with a net result for the year of MUSD 155.2. The strong production performance has continued and resulted in operating cash flow of MUSD 676.2 and EBITDA of MUSD 1,012.1 for the year. Our balance sheet remains very much under leveraged, with net debt of only MUSD 133, and an asset base which will support much higher leverage if required. We expect to continue to generate strong operating cash flow from our producing assets which will be the primary source of funding for our future development and exploration expenditures. As a result of the Luno field development project moving forward, we are likely to refinance our existing reserve based lending facility in 2012 to provide additional financial flexibility.
Lundin Petroleum has raised no cash equity since the initial USD 50 million equity raise when the Company was formed 10 years ago. Our growth has been funded from internally generated cash flow and the conservative utilisation of bank credit. This financial strategy will continue with the requirement for additional equity unlikely for the foreseeable future.
We have been very successful in increasing our resource base from exploration drilling and this continued in 2011. Our proven and probable reserves which are independently audited by Gaffney Cline & Associates increased by over 20 percent to 211 MMboe and again we have achieved an exceptional reserve replacement ratio of 264 percent. The producing Alvheim and Volund fields continued to yield increased reserves as well as the Tellus discovery which is now incorporated into the Luno development.
In addition to our reserves, our contingent resources increased by over 200 percent to 851 MMboe primarily as a result of the Johan Sverdrup field. Lundin Petroleum, as a result, has increased its net reserves and contingent resources to over 1 billion barrels.
During 2011, production averaged 33,300 barrels of oil equivalent per day (boepd) which was at the high end of our guidance range. The fourth quarter production of 34,700 boepd was particularly strong as a result of the continued outperformance of the Volund field, offshore Norway. Our forecast for 2012 is for production of between 32,000 and 38,000 boepd which represents an increase of 5 percent from 2011 if we assume the mid point of our guidance range. The increase of production in 2012 will be driven by production start up from the Gaupe field, offshore Norway at the end of the first quarter as well as new development wells on both the Alvheim and Volund fields.
We have made excellent progress with respect to our development projects and are on schedule to achieve our forecast of doubling production by the end of 2015. The 70,000 boepd production target will be driven principally by our various Norwegian development projects. Whilst it is premature to discuss production forecasts from the Johan Sverdrup field it is, I believe, conservative to assume that our net production will more than double again after production start up from this field.
If we briefly look at the progress on our various development projects:
Our view has always been that, despite being seen as a mature area, the Norwegian Continental Shelf represents an area with excellent exploration potential. The higher historical tax environment compared to the UK coupled with the fact that the independent sector was not active in Norway until 10 years ago meant that exploration drilling activity was much lower in Norway than in the UK. The geological setting is essentially the same and therefore the lower drilling activity in Norway creates an opportunity for aggressive exploration driven companies such as Lundin Petroleum. Our exploration success with the discovery of Volund, Luno, Apollo and now Johan Sverdrup clearly shows that this strategy has worked.
Nevertheless we believe there is more to be found. Despite the priority in respect of rig capacity to the appraisal of Johan Sverdrup, we will have an aggressive exploration programme in Norway in 2012 with eight new exploration wells. We will be drilling three new exploration wells in the Southern Utsira High where we feel we have a very good understanding of the subsurface. The exploration drilling will continue in 2013. We will be drilling the Albert well in the Møre Basin in the Northern North Sea close to where there have been interesting recent discoveries in the UK and Norway. In the Barents Sea, where we are one of the largest acreage owners, we have acreage close to Statoil's Skrugard and Havis discoveries where there will be an exploration well in 2012.
We continue to successfully acquire new acreage in the Norwegian licensing rounds with the award of 10 new licences in the APA 2011 round announced in January 2012.
Our exploration drilling campaign in Malaysia is proceeding well. The Tarap gas discovery announced in the second quarter od 2011 has been followed up with a further gas discovery at Cempulut. The two discoveries coupled with a third existing discovery in our licence means we have contingent resources of over 250 billion cubic feet (bcf) of gas in block SB303 offshore Sabah, east Malaysia. This is most likely a sufficient resource to consider a cluster development in an area which is facing an increasing gas deficit. We have had two oil discoveries offshore peninsular Malaysia and are now looking at development options for the Bertam field. Our Malaysian drilling campaign will continue in 2012 with a further five wells.
We have created significant shareholder value over the last 10 years since Lundin Petroleum was formed. We are today one of the largest independent exploration and production companies in Europe. Our exploration team has proven that our organic growth strategy in Norway has been successful and I think we are on the right track to replicate this in Malaysia. We are confident that there is more success to come. We have the people, the licences, access to technology and the financial capacity to further increase our resources which will deliver more increases to shareholder value.
At the same time we have expanded our organization to develop our discoveries and have the financial capacity to bring these projects to production. In a world where it is becoming increasingly difficult to find conventional oil resources in proven petroleum basins located in stable political environments, I am convinced that the value of these resources will increase over time. The 2011 story has been an amazing experience but more importantly the future is very exciting, and I and the Lundin Petroleum team are focused upon the continued success of our company.
Best Regards
C. Ashley Heppenstall President and CEO
The net production in Norway to Lundin Petroleum for the twelve month period ended 31 December 2011 (reporting period) was 23,200 barrels of oil equivalent per day (boepd).
The net production for the reporting period from the Alvheim field (Lundin Petroleum working interest (WI) 15%), offshore Norway, was 11,200 boepd. The Alvheim field has been on production since June 2008 and continues to perform above expectations. The excellent reservoir performance has resulted in increased gross ultimate recovery during 2011 to 282 million barrels of oil equivalent (MMboe) representing a 69 percent increase in ultimate recovery from when the Alvheim plan of development was completed in 2005. Phase 2 of Alvheim development drilling commenced in 2010 and has been completed. Two development wells began production in October 2011. A third well started production in January 2012. A phase 3 development well will be drilled in 2012. The cost of operations for the Alvheim field in 2011 was approximately USD 5.00 per barrel.
The net production from the Volund field (WI 35%) amounted to 12,000 boepd for the reporting period and significantly exceeded forecast. First production from the Volund field commenced in April 2010 and production increased during the year to the plateau production as development drilling was successfully completed. Volund field production during the reporting period was above the 8,700 boepd net Volund field firm capacity on the Alvheim FPSO as it took advantage of additional spare capacity. An additional Volund development well will be drilled in 2012.
In October 2009, a new oil discovery on the Bøyla prospect in PL340 (WI 15%) was announced. The Bøyla field contains gross recoverable contingent resources of 21 MMboe and will be developed as a subsea tieback to the Alvheim FPSO. A plan of development will be submitted for the Bøyla field in the first half of 2012 with first oil expected in 2014. During the first quarter of 2011, the Caterpillar exploration well in PL340BS was completed as an additional new oil discovery. Caterpillar, located close to the Bøyla field, will now most likely be developed through the Bøyla subsea development facilities.
The Luno field located in PL338 (WI 50%) was discovered in 2007 and has subsequently been appraised by two further wells.
In April 2011, the Tellus exploration well in PL338 was completed as an oil discovery. The Tellus discovery is a northern extension of the Luno field. Two reservoir tests were completed in the Tellus well, the first of which, in the fractured basement, was the first successful full scale basement test on the Norwegian Continental shelf. The potential commercial production from the fractured basement has positive implications to add resources from this interval in the Luno South discovery and in the surrounding area.
The Luno and Tellus discoveries will be developed as one field. In January 2012, a plan of development was submitted for the Luno field to the Norwegian Ministry of Petroleum and Energy. The development plan incorporates the provision for a coordinated development solution of the Luno field with the nearby Draupne field located in licence PL001B and operated by Det norske oljeselskap ASA. Discussions with Det norske oljeselskap ASA with respect to a coordinated development solution are ongoing and it is expected that an agreement will be concluded shortly. First production from the Luno field is expected in late 2015 with forecast gross peak production of approximately 90,000 boepd. The Luno platform design capacity will accommodate in excess of 120,000 boepd when Draupne production is combined with that from the Luno field. The gross capital cost of the Luno field development is estimated at USD 4 billion to include platform, pipelines and 15 wells. The Luno field is estimated to contain 186 (MMboe) of gross proved and probable reserves. A contract has been awarded to Kvaerner covering engineering, procurement and construction of the jacket for the Luno platform. A contract has been awarded to Rowan Companies Inc. for a jack up rig to drill the Luno development wells.
An exploration well in PL501 (WI 40%) targeting the Avaldsnes prospect was successfully completed in the third quarter of 2010 as an oil discovery. After the discovery well, it was estimated that the Avaldsnes discovery contained gross recoverable contingent resources of 100 to 400 MMboe within PL501 and that the fault controlled structure extended to the west into PL265 (WI 10%).
During 2011, two Avaldsnes appraisal wells 16/3-4 and 16/2-7, both of which were sidetracked, have been successfully completed. The appraisal wells confirmed the extension of the Avaldsnes discovery to the south-east and south. Both wells confirmed excellent quality Jurassic reservoir characteristics following comprehensive coring and logging programmes. The wells encountered oil bearing reservoir of thickness and quality better than the discovery well and the first appraisal well tested at an average production rate in excess of 5,500 boepd through a restricted choke. In August 2011, Statoil, the operator of PL265, announced the discovery of Aldous Major South with the well 16/2-8 encountering a gross oil column of 65 metres of excellent quality Jurassic sandstone reservoir. An appraisal of Aldous Major South was successfully completed in October 2011 with well 16/2-10. As a result of the appraisal drilling on Avaldsnes and Aldous Major South it is now confirmed that the two discoveries are one connected giant oil field which in January 2012 has been named the Johan Sverdrup field. Following the 2011 appraisal drilling programme, Lundin Petroleum announced a range of gross recoverable contingent resources for the Avaldsnes discovery in PL501 of between 800 million and 1.8 billion barrels which have been audited by Gaffney Cline & Associates. Similarly, Statoil has announced a range of gross recoverable contingent resources in PL265 of between 900 million and 1.5 billion barrels of oil. The Johan Sverdrup discovery is therefore estimated to contain contingent resources of between 1.7 and 3.3 billion barrels of recoverable oil which is one of the largest ever discoveries on the Norwegian continental shelf and the largest since the mid 1980s. The discovery is located in 115 metres water depth, the reservoir is at a depth of less than 2,000 metres and the field is located 35 kms from the Grane field pipeline infrastructure with significant spare capacity. The discovered oil is approximately 28 degree API and is of excellent quality.
In January 2012, the third appraisal well 16/5-2S located in PL 501 was completed. The objective of the well was to delineate the southern flank of the Avaldsnes discovery. The well despite encountering good Jurassic sandstone reservoir was deep to prognosis and as a result the reservoir was below the oil water contact. The impact of the well will most likely reduce current resource estimates in the southern area of the Avaldsnes discovery.
During the third quarter of 2011, Statoil, as operator, also completed the drilling of the Aldous Major North prospect in PL265. The well encountered an oil column in the Upper Jurassic reservoir which was thinner and of lesser quality than anticipated. Further appraisal drilling will be required to determine the commerciality of Aldous Major North.
At least a further three appraisal wells will be drilled in PL501 in 2012 and Statoil will likely drill two further appraisal wells in PL265 in 2012. The appraisal programme will define the recoverable resource and assist with the development planning strategy. The Avaldsnes and Aldous Major South discoveries will be unitised and Lundin Petroleum as operator of PL501 and Statoil as operator of PL265 are jointly committed to moving forward the development as a top priority.
There will be further exploration drilling in 2012 in the Southern Utsira High area with the drilling of the Luno II prospect in PL359 (WI 40%), Jorvik prospect in PL338 (WI 50%) and Biotitt prospect in PL544 (WI 70%). Additional prospectivity has been identified in the area where further exploration drilling will continue in 2013.
The plan of development for the Gaupe field in PL292 (WI 40%) was approved in June 2010, and first production is expected at the end of the first quarter of 2012. The Gaupe field operated by BG Group has estimated gross proven plus probable reserves of approximately 31 MMboe and is estimated to produce at a plateau production rate net to Lundin Petroleum of 5,000 boepd.
A plan of development of the Brynhild field (formerly called Nemo) in PL148 (WI 70%) was approved by the Norwegian Ministry of Petroleum and Energy in November 2011. The Brynhild field contains gross proven plus probable reserves of 20 MMboe and is expected to produce at an estimated plateau production rate net to Lundin Petroleum of 8,400 boepd with first oil forecast in late 2013. The development involves the drilling of four wells tied back to the existing Shell operated Pierce field infrastructure in the UK sector of the North Sea. In November 2011, Lundin Petroleum increased its working interest in PL 148 containing the Brynhild field from 50 percent to 70 percent.
In January 2011, Lundin Petroleum was awarded ten exploration licenses in the 2010 APA Licensing Round of which six licenses are operated by Lundin Petroleum. In April 2011, Lundin Petroleum was awarded license PL609 as operator in the 21st Norwegian Licensing Round. PL609 (WI 40%) is located in the Barents Sea to the east of Statoil's large new Skrugard oil discovery which is estimated by Statoil to contain between 150 and 250 MMboe. In January 2012, Lundin Petroleum was awarded a further ten exploration licenses in the 2011 APA Licensing Round of which four will be operated by Lundin Petroleum.
In July 2011, the Skalle exploration well in PL438 (WI 25%) was completed as a gas discovery with estimated gross contingent resources of between 88 and 283 billion cubic feet (bcf). The Skalle discovery is located approximately 25 kms from the producing Snøvhit gas field. Additional prospectivity for further hydrocarbons exists in the Skalle substructure and in additional prospects in PL438.
In July 2011, Lundin Petroleum completed the drilling of well 25/10-11 on the Earb South prospect in PL505 (WI 30%). The well encountered three separate hydrocarbon bearing Jurassic sandstones sequences with poor reservoir quality. The well was tested and flowed oil and gas to surface but the reservoir was tight. It is unlikely that the discovery can currently be commercialised despite the large in place hydrocarbon volumes.
In May 2011, Lundin Petroleum acquired a 30 percent interest in PL330 located in the northern Norwegian Sea.
The net production in the Paris Basin (WI 100%) averaged 2,400 boepd and in the Aquitaine Basin (WI 50%) averaged 700 boepd for the reporting period. The redevelopment of the Grandville field in the Paris Basin involving the drilling of eight new development wells and the installation of new production facilities has commenced. Grandville development drilling is continuing in 2012. The year end 2011 independent reserves audit resulted in confirmed, estimated net proven plus probable reserves of 25 MMboe, an increase of 16 percent, mainly related to the redevelopment of the Vert La Gravelle field.
The net gas production to Lundin Petroleum from the Netherlands averaged 2,000 boepd for the reporting period.
Interpretation of the 3D seismic acquired in 2010 on the Slyne Basin licence 04/06 (WI 50%) has been completed.
The net production to Lundin Petroleum from the Singa gas field (WI 25.9%) during the reporting period amounted to 1,200 boepd. Production from the Singa field commenced in 2010. Current gross production from the two Singa production wells is in excess of 30 million standard cubic feet per day (MMscfd) of sales gas.
A 474 km 2D seismic acquisition programme has been completed on the Rangkas block (WI 51%).
A 975 km² 3D seismic acquisition programme on the Baronang and Cakalang blocks (WI 100%) was completed in 2010. Exploration drilling will now commence in 2013. In addition a 1,500 km 2D seismic acquisition programme was completed on Cakalang in 2011.
A new Production Sharing Contract for the South Sokang block was signed in December 2010 (WI 60%). A 2,400 km 2D seismic acquisition programme was completed in 2011.
A new Production Sharing Contract for the Gurita block was signed in March 2011 (WI 100%). A 3D seismic acquisition programme in excess of 400 km² will be completed in 2012.
The 2009 3D seismic data programme identified numerous drilling targets for the 2011/2012 drilling campaign. Five exploration and appraisal wells were drilled in 2011.
The Tarap exploration well drilled in SB303 (WI 75%), offshore Sabah, east Malaysia was completed in July 2011 as a gas discovery. The well encountered gas in each of the five independently sealed Miocene sands targeted finding gross vertical pay of approximately 150 metres. The gross contingent resources of the Tarap discovery are 171 bcf. The Cempulut exploration well also in SB303 was also completed as a gas discovery. The well encountered a Miocene reef with 50 metres of gross vertical pay. There is a third discovery named Titik Terang in the SB303 contract area. The three discoveries are in close proximity to one another and have an estimated gross contingent resource (best estimate) of more than 250 bcf. We are now evaluating the potential for a cluster development. There are various options for the commercialisation of gas in the Sabah area.
The first exploration well Batu Hitam-1 drilled in PM308A (WI 35%), offshore peninsular Malaysia was plugged and abandoned as a dry hole after encountering good reservoir but with high concentrations of carbon dioxide. The second exploration well in PM 308A Janglau-1 completed in November 2011 was an oil discovery proving up a new play concept in Oligocene intra-rift sands. The discovery will require further appraisal drilling to determine commerciality.
In June 2011, Lundin Petroleum acquired a 75 percent working interest in block PM307 offshore Peninsula Malaysia. A 2,100 km² 3D seismic acquisition programme was completed in 2011. In January 2012, the Bertam-2 appraisal well was successfully completed proving the continuity and quality of the K10 oil reservoir sandstone. Bertam is likely a commercial oil field and studies are now progressing to review potential development concepts.
A further five exploration and/or appraisal wells will be drilled in Malaysia in 2012 offshore Sabah and offshore peninsular Malaysia. Drilling is expected to commence mid-year.
The net production to Lundin Petroleum from Russia for the period was 3,100 boepd.
In the Lagansky block (WI 70%) in the northern Caspian a major oil discovery was made on the Morskaya field in 2008. The discovery is deemed to be strategic, due to its offshore location, by the Russian Government under the Foreign Strategic Investment Law. As a result a 50 percent ownership by a state owned Company is required prior to appraisal and development. During 2010, 103 km² of new 3D seismic was acquired on the Lagansky block which has identified further exploration prospects in the Lagansky block.
The net production to Lundin Petroleum from the Oudna field (WI 40%) was 700 boepd for the reporting period.
The drilling of the exploration wells Mindou Marine-1 on block Marine XI (WI 18.75%) and the Makoula Marine-1 on block Marine XIV (WI 21.55%) was completed in the fourth quarter of 2011. Both wells were plugged and abandoned as dry holes. All exploration drilling commitments have been fulfilled on the two blocks and no further exploration drilling is forecast in 2012.
The net result from continuing operations for the twelve month period ended 31 December 2011 (reporting period) amounted to MUSD 155.2 (MUSD 129.5). The net result attributable to shareholders of the Parent Company from continuing operations for the reporting period amounted to MUSD 160.1 (MUSD 142.9) representing earnings per share on a fully diluted basis of USD 0.51 (USD 0.46).
Earnings before interest, tax, depletion and amortisation (EBITDA) for the reporting period amounted to MUSD 1,012.1 (MUSD 603.5) representing EBITDA per share on a fully diluted basis of USD 3.25 (USD 1.93). Operating cash flow for the reporting period amounted to MUSD 676.2 (MUSD 573.4) representing operating cash flow per share on a fully diluted basis of USD 2.17 (USD 1.84).
There are no significant changes to the Group for the reporting period.
The prior year includes the results of Etrion Corporation up to 12 November 2010, the date of distribution of the shares held in Etrion Corporation to Lundin Petroleum's shareholders, and the Salawati Basin and Salawati Island assets which were sold on 29 December 2010. The results of the United Kingdom operations are included under discontinued operations up to 6 April 2010, the date of the spin-off of the UK business.
Production for the reporting period amounted to 33.3 Mboe per day (Mboepd) (30.5 Mboepd) and was comprised as follows:
| 1 Jan 2011- 31 Dec 2011 |
1 Oct 2011- 31 Dec 2011 |
1 Jan 2010- 31 Dec 2010 |
1 Oct 2010- 31 Dec 2010 |
|
|---|---|---|---|---|
| Production | 12 months | 3 months | 12 months | 3 months |
| Norway | ||||
| - Quantity in Mboe | 8,477.1 | 2,262.0 | 6,629.8 | 1,874.1 |
| - Quantity in Mboepd | 23.2 | 24.7 | 18.2 | 20.4 |
| France | ||||
| - Quantity in Mboe | 1,119.2 | 276.0 | 1,160.8 | 296.6 |
| - Quantity in Mboepd | 3.1 | 3.0 | 3.2 | 3.2 |
| Netherlands | ||||
| - Quantity in Mboe | 725.0 | 184.7 | 756.7 | 191.4 |
| - Quantity in Mboepd | 2.0 | 2.0 | 2.1 | 2.1 |
| Indonesia | ||||
| - Quantity in Mboe | 423.6 | 131.0 | 887.1 | 250.2 |
| - Quantity in Mboepd | 1.2 | 1.4 | 2.4 | 2.7 |
| Russia | ||||
| - Quantity in Mboe | 1,139.4 | 277.5 | 1,321.2 | 302.0 |
| - Quantity in Mboepd | 3.1 | 3.0 | 3.6 | 3.3 |
| Tunisia | ||||
| - Quantity in Mboe | 267.2 | 57.0 | 372.2 | 83.3 |
| - Quantity in Mboepd | 0.7 | 0.6 | 1.0 | 0.9 |
| Total from continuing | ||||
| operations | ||||
| - Quantity in Mboe | 12,151.5 | 3,188.2 | 11,127.8 | 2,997.6 |
| - Quantity in Mboepd | 33.3 | 34.7 | 30.5 | 32.6 |
| Discontinued operations - United Kingdom |
||||
| - Quantity in Mboe | - | - | 812.2 | - |
| - Quantity in Mboepd | - | - | 2.2 | - |
| Total excluding non controlling interest |
||||
| - Quantity in Mboe | 12,151.5 | 3,188.2 | 11,940.0 | 2,997.6 |
| - Quantity in Mboepd | 33.3 | 34.7 | 32.7 | 32.6 |
The increase in Norway production volumes over the comparative reporting period is attributable to the Volund field which came onstream in April 2010. The Volund field has a contracted minimum capacity of 25.0 Mboepd gross through the Alvheim FPSO but has produced at an average 34.0 Mboepd gross in 2011 taking advantage of spare capacity. On a net Lundin Petroleum basis, Volund has contributed 12.0 Mboepd (5.3 Mboepd) for the reporting period and 12.5 Mboepd (9.7 Mboepd) for the fourth quarter of 2011.
The production figures for Indonesia include the contributions of the Salawati assets of 2.0 Mboepd for the full year 2010. The Salawati assets were sold in December 2010.
Net sales of oil and gas for the reporting period amounted to MUSD 1,257.7 (MUSD 785.2) and are detailed in Note 1. Sales volumes for the reporting period were 14 percent higher and the achieved oil price was 40 percent higher than the comparative period and this has resulted in oil and gas revenues being 60 percent higher than the comparative period. The average price achieved by Lundin Petroleum for a barrel of oil equivalent amounted to USD 101.04 (USD 71.92) and is detailed in the following table. The premium over dated Brent on Norwegian crude oil sold during the reporting period averaged USD 3.87 per barrel. The average Dated Brent price for the reporting period amounted to USD 111.26 (USD 79.50) per barrel.
Sales of oil and gas for the reporting period were comprised as follows:
| Sales Average price per boe expressed |
1 Jan 2011- 31 Dec 2011 |
1 Oct 2011- 31 Dec 2011 |
1 Jan 2010- 31 Dec 2010 |
1 Oct 2010- 31 Dec 2010 |
|---|---|---|---|---|
| in USD | 12 months | 3 months | 12 months | 3 months |
| Norway | ||||
| - Quantity in Mboe | 8,843.2 | 2,353.7 | 6,712.5 | 1,970.4 |
| - Average price per boe | 109.57 | 107.39 | 77.93 | 84.17 |
| France | ||||
| - Quantity in Mboe | 1,155.5 | 283.3 | 1,168.0 | 289.5 |
| - Average price per boe | 110.59 | 110.68 | 79.35 | 88.52 |
| Netherlands | ||||
| - Quantity in Mboe | 725.0 | 184.7 | 756.7 | 191.4 |
| - Average price per boe | 60.74 | 64.14 | 44.37 | 50.52 |
| Indonesia | ||||
| - Quantity in Mboe | 387.7 | 117.0 | 607.7 | 277.5 |
| - Average price per boe | 32.43 | 32.19 | 65.31 | 67.06 |
| Russia | ||||
| - Quantity in Mboe | 1,138.4 | 271.2 | 1,290.0 | 290.5 |
| - Average price per boe | 69.85 | 70.36 | 51.65 | 56.61 |
| Tunisia | ||||
| - Quantity in Mboe | 198.2 | - | 382.6 | - |
| - Average price per boe | 125.12 | - | 77.15 | - |
| Total from continuing operations |
||||
| - Quantity in Mboe | 12,448.0 | 3,209.9 | 10,917.5 | 3,019.3 |
| - Average price per boe | 101.04 | 99.33 | 71.92 | 78.23 |
| Discontinued operations - United Kingdom |
||||
| - Quantity in Mboe | - | - | 814.4 | - |
| - Average price per boe | - | - | 76.82 | - |
| Total | ||||
| - Quantity in Mboe | 12,448.0 | 3,209.9 | 11,731.9 | 3,019.3 |
| - Average price per boe | 101.04 | 99.33 | 72.26 | 78.23 |
The sales figures for Indonesia include the contributions of the Salawati assets for the full year 2010.
Sales quantities in a period can differ from production quantities as a result of permanent and timing differences. Timing differences can arise due to inventory, storage and pipeline balances effects. Permanent differences arise as a result of paying royalties in kind as well as the effects from production sharing agreements.
Oil produced in Tunisia is only lifted when the Ikdam FPSO is near to full. An Oudna cargo was lifted in April 2011 and was the only Tunisian lifting during 2011.
The oil produced in Russia is sold on either the Russian domestic market or exported into the international market. 37 percent (40 percent) of Russian sales for the reporting period were on the international market at an average price of USD 109.92 per barrel (USD 76.17 per barrel) with the remaining 63 percent (60 percent) of Russian sales being sold on the domestic market at an average price of USD 46.45 per barrel (USD 34.98 per barrel).
Other operating income amounted to MUSD 11.8 (MUSD 13.4) for the reporting period and includes MUSD 5.8 (MUSD -) of income relating to a quality differential compensation adjustment payable from the Vilje field owners to the Alvheim and Volund field owners. All three fields produce to the Alvheim FPSO vessel and the oil is commingled to produce an Alvheim crude blend which is then sold. This adjustment for the comparative period amounted to MUSD 3.2 and was netted off against production costs. Also included in other operating income is tariff income from France and the Netherlands and income for maintaining strategic inventory levels in France. Other operating income for the comparative period includes MUSD 9.3 relating to Etrion's solar business.
Production costs for the reporting period amounted to MUSD 193.1 (MUSD 157.1) and are detailed in Note 2. The production and depletion costs per barrel of oil equivalent produced from continuing oil and gas operations are detailed in the table below.
| Production cost and depletion in USD per boe |
1 Jan 2011- 31 Dec 2011 12 months |
1 Oct 2011- 31 Dec 2011 3 months |
1 Jan 2010- 31 Dec 2010 12 months |
1 Oct 2010- 31 Dec 2010 3 months |
|---|---|---|---|---|
| Cost of operations | 8.43 | 8.89 | 8.63 | 9.87 |
| Tariff and transportation | ||||
| expenses | 1.88 | 1.64 | 1.57 | 1.88 |
| Royalty and direct taxes | 4.31 | 4.03 | 3.74 | 3.38 |
| Changes in inventory/lifting | ||||
| position | 1.08 | -0.01 | -0.31 | 0.09 |
| Other | 0.18 | 0.17 | 0.38 | 0.84 |
| Total production costs | 15.88 | 14.72 | 14.01 | 16.06 |
| Depletion | 13.59 | 13.72 | 12.85 | 12.79 |
| Total cost per boe | 29.47 | 28.44 | 26.86 | 28.85 |
The total cost of operations for the reporting period was MUSD 102.5 compared to MUSD 97.2 for the comparative period. The current reporting period includes costs of the Volund field, Norway and Singa field, Indonesia, for a full twelve month period whereas the Volund and Singa fields contributed costs partially in the comparative period having commenced production in the second quarter of 2010. In addition, in the reporting period there have been certain oneoff costs associated with the unplanned shutdown of the Alvheim FPSO during the second quarter of 2011 and expenditures related to the FPSO used on the Oudna field. The increases are partly offset following the disposal of the Salawati assets, Indonesia in December 2010.
The cost of operations for the fourth quarter of 2011 was MUSD 28.3, corresponding to USD 8.89 per barrel compared to MUSD 30.2 corresponding to USD 9.87 per barrel for the comparative period. The total cost of operations per barrel for the full year was USD 8.43 per barrel which was below the original 2011 forecast of USD 8.60 per barrel.
The tariff and transportation expenses for the reporting period amounted to MUSD 22.9 compared to MUSD 17.4 for the comparative period. The increase is mainly due to the increased production contribution from the Volund field, Norway, which pays a tariff to the Alvheim field owners and commenced production in April 2010. Lundin Petroleum has a 15 percent working interest in the Alvheim field and a 35 percent interest in the Volund field and the self-to-self element of the tariff is eliminated for accounting purposes leaving a net 20 percent cost for Volund in tariff and transportation expenses.
Royalty and direct taxes includes Russian Mineral Resource Extraction Tax (MRET) and Russian Export Duties. The rate of MRET is levied on the volume of Russian production and varies in relation to the international market price of Urals blend and the Rouble exchange rate. MRET averaged USD 21.21 (USD 13.83) per barrel of Russian production for the reporting period. The rate of export duty on Russian oil is revised by the Russian Federation monthly and is dependent on the average price obtained for Urals Blend for the preceding one month period. The export duty is levied on the volume of oil exported from Russia and averaged USD 57.52 (USD 37.59) per barrel for the reporting period. The royalty and direct taxes have increased compared to prior year following the rise in crude prices impacting the cost of Russian MRET and export duty.
There are both permanent and timing differences that result in sales volumes not being equal to production volumes during a period. Changes to the hydrocarbon inventory and under or overlift positions result from these timing differences and an amount of MUSD 13.1 (MUSD -3.4) was charged to the income statement for the reporting period. The Norway fields, Alvheim and Volund, went from a net underlift position at the start of 2011 to a net overlift position as at 31 December 2011 resulting in a charge of MUSD 18.5 to production costs for the reporting period. This charge was partly offset by a build-up of hydrocarbon inventory from the Oudna field on the Ikdam FPSO, Tunisia, resulting in a MUSD 5.3 credit to production costs for the reporting period.
Depletion costs amounted to MUSD 165.1 (MUSD 145.3) and are detailed in Note 3. The main increase from the comparative period is in Norway where the depletion cost expensed has increased by 28 percent in line with the increase in production. Norway contributed approximately 80 percent of the total depletion charge for the period at a rate of USD 15.34 per barrel and this increases the overall rate from the comparative period.
Exploration costs for the reporting period amounted to MUSD 140.0 (MUSD 127.5) and are detailed in Note 4. The amount expensed during the fourth quarter of 2011 was MUSD 59.8 of which MUSD 51.3 relates to the two unsuccessful Congo (Brazzaville) wells drilled during the quarter along with the associated capitalised licence costs. In addition, MUSD 7.0 was expensed relating to Licence PL301, Norway.
Exploration and appraisal costs are capitalised as they are incurred. When exploration drilling is unsuccessful the costs are immediately charged to the income statement as exploration costs. All capitalised exploration costs are reviewed on a regular basis and are expensed where there is uncertainty regarding their recoverability.
The general, administrative and depreciation expenses for the reporting period amounted to MUSD 67.0 (MUSD 41.0) of which MUSD 44.9 (MUSD 10.3) related to non-cash charges in relation to the Group's Long-term Incentive Plan (LTIP) scheme. The comparative reporting period includes an amount of MUSD 11.7 relating to Etrion.
The cost for the fourth quarter of 2011 increased due to the increase in the LTIP provision as a result of a higher Lundin Petroleum share price at the balance sheet date. The value of the LTIP awards, based on Lundin Petroleum's share price at the balance sheet date, is applied to the vested portion of all outstanding LTIP awards. The charge to the income statement for the reporting period includes the revaluation of the provision relating to prior reporting periods. Lundin Petroleum has mitigated the exposure to the cost of the LTIP by purchasing 6,882,638 of its own shares. For more detail refer to the Remuneration section.
Financial income for the reporting period amounted to MUSD 46.5 (MUSD 21.0) and is detailed in Note 6.
Interest income for the reporting period amounted to MUSD 4.1 (MUSD 3.4). The interest income in the reporting period includes an amount of MUSD 1.5 relating to a loan to Etrion Corporation which is no longer eliminated on consolidation, following the distribution of the shares held in Etrion in November 2010. The Etrion loan was repaid during the second quarter of 2011. In the comparative reporting period, there is MUSD 0.6 of interest income on a tax refund.
Foreign exchange gains for the reporting period amounted to MUSD 8.9 (MUSD 13.4). The US Dollar continued to strengthen against the Euro and the Norwegian Kroner during the fourth quarter of 2011 giving rise to exchange gain movements on the intercompany loans and working capital balances.
In March 2011, Lundin Petroleum converted MUSD 13.0 of the MUSD 23.8 convertible loan receivable from Africa Oil Corporation (AOC) loan into 14 million shares in AOC at a conversion price of Canadian Dollars (CAD) 0.90 per share. The shares were subsequently sold on the open market for CAD 2.00 per share realising a gain of MUSD 15.6. In April 2011, the remainder of the loan was converted into 11.85 million shares at a conversion price of CAD 0.90 per share and the shares were sold on the open market for CAD 2.10 per share realising a further gain of MUSD 14.3.
Financial expenses for the reporting period amounted to MUSD 21.0 (MUSD 33.5) and are detailed in Note 7.
Interest expenses for the reporting period amounted to MUSD 5.4 (MUSD 10.0). Included in the comparative period is MUSD 3.6 of interest expenses relating to Etrion's loan facilities.
In January 2008, the Group entered into an interest rate hedging contract to fix the LIBOR rate of interest at 3.75 percent per year on MUSD 200 of the Group's USD borrowings for the period from January 2008 until January 2012. An amount of MUSD 7.0 (MUSD 7.0) was charged to the income statement for the reporting period for settlements under the hedging contracts.
A provision for the costs of site restoration is recorded in the balance sheet at the discounted value of the estimated future cost. The effect of the discount is unwound each year and charged to the income statement. An amount of MUSD 4.5 (MUSD 4.0) has been charged to the income statement for the reporting period.
The tax charge for the reporting period amounted to MUSD 574.4 (MUSD 251.9) and is detailed in Note 8.
The current tax charge for the reporting period amounted to MUSD 400.2 (MUSD 68.2) of which MUSD 365.6 (MUSD 36.1) relates to Norway. The increase in the Norway current tax charge from the comparative period is mainly due to the utilisation of the tax losses in 2010, as well as higher production and higher oil prices in 2011. The current tax charge in the fourth quarter of 2011 is MUSD 186.7 of which MUSD 179.9 relates to Norway. The Norwegian current tax is accrued throughout the year based on the forecast taxable income for the full year and due to the stronger production, higher oil prices and deferred development and exploration expenditure, the current tax charge in the fourth quarter is higher than the previous quarters.
The deferred tax charge for the reporting period amounted to MUSD 174.2 (MUSD 183.7) and arises primarily where there is a difference in depreciation for tax and accounting purposes and tax losses have offset the current tax charge. MUSD 166.2 (MUSD 183.3) of the deferred tax charge is attributable to Norway.
The Group operates in various countries and fiscal regimes where corporate income tax rates are different from the regulations in Sweden. Corporate income tax rates for the Group vary between 20 percent and 78 percent. The effective tax rate for the Group for the reporting period amounted to 79 percent. This effective rate is calculated from the face of the income statement and does not reflect the effective rate of tax paid within each country of operation. The effective rate of tax is driven by Norway where the tax rate is 78 percent reduced by the effect of uplift for tax purposes on development expenditure. The effective rate is increased due to a number of non-tax adjusted items in the reporting period including the exploration costs of Congo (Brazzaville) and Malaysia, certain general and administrative costs and certain financial items. The operational tax rate adjusted for the Congo (Brazzaville) and Malaysia exploration costs is 69 percent for the reporting period.
The net result attributable to non-controlling interest for the reporting period amounted to MUSD -4.9 (MUSD -13.4) and mainly relates to the non-controlling interest's share in a Russian subsidiary which is fully consolidated.
The net result from discontinued operations for the reporting period amounted to MUSD - (MUSD 369.0). The amount in the comparative period is attributable to the net result for the United Kingdom up to 6 April 2010, the date of the UK spin-off. For more detail refer to Note 9.
Oil and gas properties amounted to MUSD 2,329.3 (MUSD 1,999.0) and are detailed in Note 10.
Development and exploration expenditure incurred for the reporting period was as follows:
| Development expenditure | 1 Jan 2011- 31 Dec 2011 |
1 Oct 2011- 31 Dec 2011 |
1 Jan 2010- 31 Dec 2010 |
1 Oct 2010- 31 Dec 2010 |
|---|---|---|---|---|
| in MUSD | 12 months | 3 months | 12 months | 3 months |
| Norway | 186.8 | 30.8 | 106.3 | 20.4 |
| France | 30.9 | 10.2 | 13.2 | 4.1 |
| Netherlands | 4.1 | 1.7 | 4.5 | 0.9 |
| Indonesia | 6.4 | 2.3 | 10.2 | 1.8 |
| Russia | 4.2 | 0.7 | 6.6 | 1.1 |
| Development expenditures | ||||
| from continuing operations | 232.4 | 45.7 | 140.8 | 28.3 |
| Discontinued operations - | ||||
| United Kingdom | - | - | 17.1 | - |
| Development expenditures | 232.4 | 45.7 | 157.9 | 28.3 |
During the reporting period, an amount of MUSD 186.8 of development expenditure was incurred in Norway, primarily on the Gaupe field development and the Phase 2 drilling on the Alvheim field. MUSD 106.3 was spent on development projects in Norway in the comparative period, predominantly on the Volund field development and Alvheim field drilling.
| Exploration expenditure | 1 Jan 2011- | 1 Oct 2011- | 1 Jan 2010- | 1 Oct 2010- |
|---|---|---|---|---|
| 31 Dec 2011 | 31 Dec 2011 | 31 Dec 2010 | 31 Dec 2010 | |
| in MUSD | 12 months | 3 months | 12 months | 3 months |
| Norway | 288.6 | 51.6 | 160.8 | 90.8 |
| France | 1.7 | 0.7 | 1.0 | 0.4 |
| Indonesia | 16.4 | 4.4 | 13.5 | 3.0 |
| Russia | 10.0 | 3.1 | 18.3 | 4.3 |
| Malaysia | 98.7 | 38.4 | 10.6 | 3.8 |
| Congo (Brazzaville) | 19.0 | 11.4 | 2.5 | 0.8 |
| Vietnam | 0.4 | - | 15.3 | -0.3 |
| Other | 2.7 | 0.9 | 4.4 | 0.5 |
| Exploration expenditures | ||||
| from continuing operations | 437.5 | 110.5 | 226.4 | 103.3 |
| Discontinued operations - | ||||
| United Kingdom | - | - | 0.2 | - |
| Exploration expenditures | 437.5 | 110.5 | 226.6 | 103.3 |
During the reporting period, exploration expenditure of MUSD 288.6 was incurred in Norway mainly on the Tellus discovery well on licence PL338, the Caterpillar discovery well on licence PL340, the Earb South well on licence PL505, the Skalle well on licence PL438 and the Johan Sverdrup appraisal wells (combined Avaldsnes/Aldous Major South) on licences PL501 and PL265. MUSD 98.7 was incurred in Malaysia primarily for the drilling and testing of the Tarap and Cempulut wells on block SB303, drilling the Batu Hitam and Janglau wells on block PM308A and drilling the Bertam appraisal well on block PM307. Two wells were drilled in Congo (Brazzaville) in the fourth quarter of 2011.
Other tangible assets amounted to MUSD 16.1 (MUSD 15.3) and represent office fixed assets and real estate.
Financial assets amounted to MUSD 31.2 (MUSD 114.9) and are detailed in Note 11. Other shares and participations amounted to MUSD 17.8 (MUSD 68.6) and predominantly relate to the shares held in ShaMaran Petroleum which are reported at market price. Long-term receivables amounted to MUSD - (MUSD 23.8) following the conversion to shares of the MUSD 23.8 convertible loan to Africa Oil Corporation and their subsequent sale. Other financial assets amounted to MUSD 11.0 (MUSD 17.8) and include Etrion Corporation bonds of MUSD 9.6 (MUSD -) held by Lundin Petroleum. The comparative period for other financial assets included MUSD 16.5 of recoverable VAT in Russia of which MUSD 14.2 of Russian VAT was received during the reporting period and the outstanding receivable was reclassified to current assets at 31 December 2011.
The deferred tax asset amounted to MUSD 15.3 (MUSD 15.1) and mainly relates to unutilised tax losses in the Netherlands.
Receivables and inventories amounted to MUSD 224.4 (MUSD 236.2) and are detailed in Note 12.
Trade receivables amounted to MUSD 145.0 (MUSD 94.2). A higher number of cargoes lifted in December 2011 and higher oil prices have resulted in the value of the trade receivables being higher at 31 December 2011.
Short-term loan receivables amounted to MUSD - (MUSD 74.5) following repayment of the Etrion loan during the second quarter of 2011.
Other assets amounted to MUSD 21.2 (MUSD 6.3) and included an amount of MUSD 11.2 (MUSD -) for a carried interest in licence PL148 Brynhild, Norway, under the terms of an option agreement. In the first quarter of 2012, the seller exercised the option to sell its 30 percent working interest in the licence to Lundin Petroleum and the amount will be transferred to oil and gas properties in the first quarter of 2012 subject to completion of the deal.
Cash and cash equivalents amounted to MUSD 73.6 (MUSD 48.7). Cash balances are held to meet operational and investment requirements.
The non-current part of provisions amounted to MUSD 988.0 (MUSD 763.7) and is detailed in Note 13.
The provision for site restoration amounted to MUSD 119.3 (MUSD 93.8) and relates to future decommissioning obligation liabilities. The increase compared to the comparative period results from the change in estimate of the decommissioning costs at 31 December 2011 and the inclusion of the decommissioning liability associated with the Gaupe development.
The provision for deferred taxes amounted to MUSD 803.5 (MUSD 650.7) and is arising on the excess of book value over the tax value of oil and gas properties. Deferred tax assets are netted off against deferred tax liabilities where they relate to the same jurisdiction in accordance with International Financial Reporting Standards (IFRS).
The non-current portion of the provision for Lundin Petroleum's LTIP scheme amounted to MUSD 58.1 (MUSD 12.8).
Other non-current provisions amounted to MUSD 5.6 (MUSD 5.0) and include a termination indemnity provision in Tunisia.
Long-term interest bearing debt amounted to MUSD 207.0 (MUSD 458.8) and relates to the outstanding loan under the Group's MUSD 850 revolving borrowing base facility.
Other non-current liabilities amounted to MUSD 21.8 (MUSD 17.8) and mainly represent funding advances made by a non-controlling interest entity in relation to LLC PetroResurs, Russia.
Other current liabilities amounted to MUSD 390.6 (MUSD 185.0) and are detailed in Note 14.
Tax payables amounted to MUSD 240.1 (MUSD 39.7) of which MUSD 223.0 (MUSD 20.9) relates to Norway.
Joint venture creditors amounted to MUSD 88.4 (MUSD 100.9) and relate to ongoing operational costs.
The short term portion of the fair value of the interest rate swap entered into in January 2008 is included in current liabilities and amounted to MUSD 0.2 (MUSD 6.9).
Other liabilities amounted to MUSD 21.5 (MUSD 5.9) and included an amount of MUSD 10.9 (MUSD -) payable to Noreco in relation to Lundin Petroleum's acquisition of Noreco's 20 percent working interest in licence PL148 Brynhild, Norway.
The current portion of the provision for Lundin Petroleum's LTIP scheme amounted to MUSD 12.2 (MUSD 6.0).
The business of the Parent Company is investment in and management of oil and gas assets. The net result for the Parent Company amounted to MSEK -182.4 (MSEK 3,936.1) for the reporting period.
The result includes general and administrative expenses of MSEK 206.1 (MSEK 72.2), financial income of MSEK 5.9 (MSEK 15.3) for supporting certain financial obligations for ShaMaran Petroleum and interest expense of MSEK 25.3 (MSEK 28.1). The comparative result for 2010 includes a dividend received from a subsidiary of MSEK 3,995.2.
During the reporting period, the Group has entered into transactions with related parties on a commercial basis as described below:
The Group received MUSD 0.4 (MUSD 0.3) from ShaMaran Petroleum for the provision of office and other services and MUSD 0.9 (MUSD 2.0) for supporting certain financial obligations.
The Group received MUSD 0.2 (MUSD 0.9) from AOC being interest on a loan that was converted into shares in the reporting period.
The Group paid MUSD 0.7 (MUSD 0.4) to other related parties in respect of aviation services received.
Etrion has reimbursed a Euro loan provided by the Group which amounted to MUSD 83.0 at the time of the reimbursement in May 2011. Interest of MUSD 1.5 (MUSD 0.5) was charged on the loan in the reporting period.
Lundin Petroleum has a secured revolving borrowing base facility of MUSD 850 with a seven year term expiring in 2014, of which MUSD 207.0 was drawn in cash as at 31 December 2011. The MUSD 850 facility is a revolving borrowing base facility secured against certain cash flows generated by the Group. The amount available under the facility is recalculated every six months based upon the calculated cash flow generated by certain producing fields at an oil price and economic assumptions agreed with the banking syndicate providing the facility and is currently in excess of the facility size. The facility has reached a stage where availability reduces every six months. The maximum amount that can be drawn under the facility has been reduced to MUSD 630 and will continue to reduce until maturity of the facility. Lundin Petroleum is in the process of arranging a new financing facility to meet the funding requirements of its future development projects.
Lundin Petroleum has, through its subsidiary Lundin Malaysia BV, entered into five Production Sharing Contracts (PSC) with Petroliam Nasional Berhad, the oil and gas company of the Government of Malaysia (Petronas), in respect of the six operated blocks in Malaysia. BNP Paribas, on behalf of Lundin Malaysia BV has issued bank guarantees in support of the work commitments in relation to these PSCs amounting to MUSD 91.2. In addition, BNP Paribas has issued additional bank guarantees to cover work commitments in Indonesia amounting to MUSD 2.4.
Lundin Petroleum owns 50 million shares in ShaMaran Petroleum which it acquired in 2009 in a non-cash transaction. The investment was booked at the fair value of the shares at the date of acquisition and under accounting rules, any subsequent movement in the fair value of the shares is being recorded in the consolidated statement of comprehensive income. In January 2012, ShaMaran Petroleum announced that it had relinquished its working interests in its operated Production Sharing Contract licences and, as such, there has been a permanent diminution in the fair value of the shares of ShaMaran Petroleum. The cumulative loss recognised in other comprehensive income will be reclassified from equity and recognised in the income statement in the first quarter of 2012. The accounting loss in value is estimated to amount to MUSD 19.
In the first quarter of 2012, Talisman exercised their option to sell Lundin Petroleum a 30 percent working interest in licence PL148 Brynhild, Norway, subject to applicable government approvals.
Lundin Petroleum AB's issued share capital amounted to SEK 3,179,106 represented by 317,910,580 shares with a quota value of SEK 0.01 each.
As at 31 December 2011, Lundin Petroleum held 6,882,638 of its own shares.
The board of directors will propose to the AGM that no dividend will be paid to the shareholders for the financial year 2011.
In 2008, Lundin Petroleum implemented a Long-term Incentive Plan (LTIP) scheme consisting of a Unit Bonus Plan which provides for an annual grant of units that will lead to a cash payment at vesting. The LTIP is payable over a period of three years from award. The cash payment will be determined at the end of each vesting period by multiplying the number of units then vested by the share price. The share price for determining the cash payment at the end of each vesting period will be the five trading day average closing Lundin Petroleum share price prior to and following the actual vesting date.
The AGM held on 13 May 2009 approved the 2009 LTIP and divided it into one plan for Executive Management (being the President and Chief Executive Officer, the Chief Operating Officer, the Chief Financial Officer and the Senior Vice President Operations) (Phantom Options Scheme) and one plan for certain other employees.
The LTIP for Executive Management includes 5,500,928 phantom options with an exercise price of SEK 52.91 (rebased from 4,000,000 phantom options and SEK 72.76 respectively following the distribution of the EnQuest and Etrion shares). The Phantom Options Scheme will vest in May 2014 being the fifth anniversary of the date of grant. The recipients will be entitled to receive a cash payment equal to the average closing price of the Company's shares during the fifth year following grant, less the exercise price, multiplied by the number of phantom options. The participants of the Phantom Option Scheme are not entitled to receive new awards under the Unit Bonus Plan whilst the phantom options are still outstanding.
Lundin Petroleum holds 6,882,638 of its own shares acquired at an average cost of SEK 46.51 per share which mitigates the exposure of costs of the LTIP. The Lundin Petroleum share price at 31 December 2011 was SEK 169.20. The provision for LTIP amounted to MUSD 70.3 as at 31 December 2011 and the market value of the shares held at 31 December 2011 was MUSD 169.1. The gain in the value of the own shares held can not be offset against the cost for the LTIP in accordance with accounting rules.
The number of units relating to the 2009, 2010 and 2011 Unit Bonus Plans outstanding as at 31 December 2011 were 219,985, 470,169, and 418,400.
The year end report of the Group has been prepared in accordance with International Accounting Standard (IAS) 34, Interim Reporting, and the Swedish Annual Accounts Act (1995:1554). The accounting policies adopted are consistent with those followed in the preparation of the Group's annual financial statements for the year ended 31 December 2010.
The year end report of the Parent Company is prepared in accordance with accounting principles generally accepted in Sweden, applying RFR 2 issued by the Swedish Financial Reporting Board and the Annual accounts Act (1995:1554).
Under Swedish company regulations it is not allowed to report the Parent Company results in any other currency than SEK and consequently the Parent Company's financial information is reported in SEK and not in USD.
The major risk the Group faces is the nature of oil and gas exploration and production itself. Oil and gas exploration, development and production involve high operational and financial risks, which even a combination of experience, knowledge and careful evaluation may not be able to fully eliminate or which are beyond the Company's control. Lundin Petroleum's long-term commercial success depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. A future increase in Lundin Petroleum's reserves will depend not only on its ability to explore and develop any properties that Lundin Petroleum may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. In addition, there is no assurance that commercial quantities of oil and gas will be discovered or acquired by Lundin Petroleum.
The Group faces a number of risks and uncertainties in the areas of operation which may have an adverse impact on its ability to successfully pursue its exploration, appraisal and development plans as well as on its production of oil and gas. A more detailed analysis of the operational risks faced by Lundin Petroleum is given in the Company's annual report for 2010.
Lundin Petroleum is, and will be, actively engaged in oil and gas operations in various countries. Lundin Petroleum's exploration, development and production activities may be subject to political and economic uncertainties, expropriation of property and cancellation or modification of contract rights, taxation, royalties, duties, foreign exchange restrictions and other risks arising out of foreign governmental sovereignty over the areas in which Lundin Petroleum's operations are conducted, as well as risks of loss in some countries due to civil strife, acts of war, guerrilla activities and insurrection. Further, certain aspects of Lundin Petroleum's exploration and production programmes require the consent or favourable decisions of governmental bodies.
As an international oil and gas exploration and production company operating globally, Lundin Petroleum is exposed to financial risks such as fluctuations in oil price, currency rates, interest rates as well as liquidity and credit risks. The Company shall seek to control these risks through sound management practice and the use of internationally accepted financial instruments, such as oil price, currency and interest rate hedges. Lundin Petroleum uses financial instruments solely for the purpose of minimising risks in the Company's business. A more detailed analysis of the financial risks faced by Lundin Petroleum and how it addresses these risks is given in the Company's annual report for 2010.
The Group entered into an interest hedging contract on 8 January 2008, fixing the LIBOR rate of interest at 3.75 percent p.a. on MUSD 200 of the Group's USD borrowings for the period January 2008 to January 2012. The interest rate contract relates to the current credit facility. Under IAS 39, the interest rate contract is effective and qualifies for hedge accounting. Changes in fair value of this contract are charged directly to other comprehensive income. As at 31 December 2011, there is a current liability in the balance sheet amounting to MUSD 0.2 (MUSD 6.9) representing the fair value of the outstanding part of the interest rate contract.
For the preparation of the financial statements for the reporting period, the following currency exchange rates have been used.
| 31 Dec 2011 | 31 Dec 2010 | ||||
|---|---|---|---|---|---|
| Average | Period end | Average | Period end | ||
| 1 USD equals NOK | 5.5998 | 5.9927 | 6.0345 | 5.8564 | |
| 1 USD equals Euro | 0.7185 | 0.7729 | 0.7537 | 0.7484 | |
| 1 USD equals Rouble | 29.3738 | 32.2784 | 30.3570 | 30.5493 | |
| 1 USD equals SEK | 6.4867 | 6.8877 | 7.1954 | 6.7097 |
| 31 Dec 2011 31 Dec 2011 31 Dec 2010 31 Dec 2010 12 months 3 months 12 months 3 months Expressed in TUSD Note Continuing operations Operating income Net sales of oil and gas 1 1,257,691 318,810 785,162 236,197 Other operating income 11,824 4,193 13,437 |
3,896 240,093 -60,687 92,319 |
|---|---|
| 1,269,515 323,003 798,599 |
|
| Cost of sales | |
| Production costs 2 -193,104 -46,935 -157,065 -48,735 |
|
| Depletion costs 3 -165,138 -43,757 -145,316 -38,352 |
|
| Exploration costs 4 -140,027 -59,800 -127,534 |
|
| Gross profit 771,246 172,511 368,684 |
|
| Gain on sale of assets - - 66,126 |
66,126 |
| General, administration and | |
| depreciation expenses -67,022 -31,903 -40,960 -14,270 |
|
| Operating profit 5 704,224 140,608 393,850 144,175 |
|
| Result from financial investments | |
| Financial income 6 46,455 7,305 20,956 |
7,117 |
| Financial expenses 7 -21,022 -4,790 -33,463 |
-8,390 |
| 25,433 2,515 -12,507 |
-1,273 |
| Profit before tax 729,657 143,123 381,343 142,902 |
|
| Tax 8 -574,413 -157,158 -251,865 -56,271 |
|
| Net result from continuing | |
| operations 155,244 -14,035 129,478 |
86,631 |
| Discontinued operations | |
| Net result from discontinued operations 9 - - 368,992 |
-283 |
| Net result 155,244 -14,035 498,470 |
86,348 |
| Net result attributable to the | |
| shareholders of the Parent | |
| Company: | |
| From continuing operations 160,137 -12,500 142,883 |
90,396 |
| From discontinued operations - - 368,992 |
-283 |
| 160,137 -12,500 511,875 |
90,113 |
| Net result attributable to Non | |
| controlling interest: | |
| From continuing operations -13,405 -4,893 -1,535 |
-3,765 |
| From discontinued operations - - - |
- |
| -4,893 -1,535 -13,405 |
-3,765 |
| Net result 155,244 -14,035 498,470 |
86,348 |
| Earnings per share – USD 1 | |
| From continuing operations 0.51 -0.05 0.46 |
0.29 |
| From discontinued operations - - 1.18 |
0.00 |
| 0.51 -0.05 1.64 |
0.29 |
| Diluted earnings per share – USD 1 From continuing operations 0.51 -0.05 0.46 |
0.29 |
| From discontinued operations - - 1.18 |
0.00 |
| 0.51 -0.05 1.64 |
0.29 |
1 Based on net result attributable to shareholders of the Parent Company.
| Expressed in TUSD | 1 Jan 2011- 31 Dec 2011 12 months |
1 Oct 2011- 31 Dec 2011 3 months |
1 Jan 2010- 31 Dec 2010 12 months |
1 Oct 2010- 31 Dec 2010 3 months |
|---|---|---|---|---|
| Net result | 155,244 | -14,035 | 498,470 | 86,348 |
| Other comprehensive income | ||||
| Exchange differences foreign operations | -37,525 | -25,193 | -43,972 | -1,201 |
| Cash flow hedges | 6,971 | 1,708 | -378 | 1,217 |
| Available-for-sale financial assets Income tax relating to other |
-50,210 | -1,583 | 53,128 | 39,691 |
| comprehensive income | -1,743 | -427 | -1,771 | 171 |
| Other comprehensive income, net of tax |
-82,507 | -25,495 | 7,007 | 39,878 |
| Total comprehensive income | 72,737 | -39,530 | 505,477 | 126,226 |
| Total comprehensive income attributable to: Shareholders of the Parent Company |
80,466 | -37,732 | 510,165 | 120,511 |
| Non-controlling interest | -7,729 | -1,798 | -4,688 | 5,715 |
| 72,737 | -39,530 | 505,477 | 126,226 |
| Expressed in TUSD | Note | 31 December 2011 | 31 December 2010 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 10 | 2,329,270 | 1,998,971 |
| Other tangible assets | 16,084 | 15,271 | |
| Financial assets | 11 | 31,241 | 114,878 |
| Deferred tax | 15,345 | 15,066 | |
| Total non-current assets | 2,391,940 | 2,144,186 | |
| Current assets | |||
| Receivables and inventories | 12 | 224,407 | 236,247 |
| Cash and cash equivalents | 73,597 | 48,703 | |
| Total current assets | 298,004 | 284,950 | |
| TOTAL ASSETS | 2,689,944 | 2,429,136 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Shareholders´ equity | 1,000,882 | 920,416 | |
| Non-controlling interest | 69,424 | 77,365 | |
| Total equity | 1,070,306 | 997,781 | |
| Non-current liabilities | |||
| Provisions | 13 | 987,993 | 763,672 |
| Bank loans | 207,000 | 458,835 | |
| Other non-current liabilities | 21,830 | 17,836 | |
| Total non-current liabilities | 1,216,823 | 1,240,343 | |
| Current liabilities | |||
| Other current liabilities | 14 | 390,600 | 184,997 |
| Provisions | 13 | 12,215 | 6,015 |
| Total current liabilities | 402,815 | 191,012 | |
| TOTAL EQUITY AND LIABILITIES | 2,689,944 | 2,429,136 | |
| Pledged assets | 519,624 | 459,220 | |
| Contingent liabilities | - | - |
| Expressed in TUSD | 1 Jan 2011- 31 Dec 2011 |
1 Oct 2011- 31 Dec 2011 |
1 Jan 2010- 31 Dec 2010 |
1 Oct 2010- 31 Dec 2010 |
|---|---|---|---|---|
| 12 months | 3 months | 12 months | 3 months | |
| Cash flow from operations | ||||
| Net result | 155,244 | -14,035 | 498,470 | 86,348 |
| Gain on sale of assets | - | - | -424,196 | -65,843 |
| Adjustments for non-cash related items | 915,174 | 291,974 | 575,955 | 167,616 |
| Interest received | 1,457 | 41 | 589 | 227 |
| Interest paid | -1,597 | 2,335 | -2,937 | 358 |
| Income taxes paid | -183,870 | -119,547 | -25,029 | -4,241 |
| Changes in working capital | 10,528 | -26,957 | -65,734 | -13,383 |
| Total cash flow from operations | 896,936 | 133,811 | 557,118 | 171,082 |
| Cash flow from investments | ||||
| Investment in subsidiary assets | - | - | -22,553 | -14,370 |
| Investment in associated company | - | - | 235 | 10 |
| Proceeds from sale of other shares and participations | 53,938 | - | 446 | - |
| Change in other financial fixed assets | 1,908 | 12,168 | 39 | 43 |
| Other payments | -1,168 | -293 | -3,085 | -1,564 |
| Divestment | - | - | -65,808 | -40,805 |
| Investment in intangible assets | - | - | -200 | 5 |
| Investment in oil and gas properties | -670,032 | -156,305 | -348,819 | -95,211 |
| Investment in solar power properties | - | - | -21,210 | -1,813 |
| Investment in office equipment and other assets | -3,786 | -673 | -4,853 | -1,721 |
| Total cash flow from investments | -619,140 | -145,103 | -465,808 | -155,426 |
| Cash flow from financing | ||||
| Changes in long-term receivables | - | - | -75,324 | -8,687 |
| Changes in long-term liabilities | -252,238 | -13,616 | -49,609 | -63,595 |
| Paid financing fees | - | - | -51 | - |
| Purchase of own shares | - | - | -10,712 | - |
| Proceeds from share issuance subsidiary company | - | - | 15,191 | - |
| Dividend paid to non-controlling interests | -212 | - | - | - |
| Total cash flow from financing | -252,450 | -13,616 | -120,505 | -72,282 |
| Change in cash and cash equivalents | 25,346 | -24,908 | -29,195 | -56,626 |
| Cash and cash equivalents at the beginning of the period |
48,703 | 98,075 | 77,338 | 53,545 |
| Cash held for sale / distribution | - | - | - | 50,074 |
| Currency exchange difference in cash and cash | ||||
| equivalents | -452 | 430 | 560 | 1,710 |
| Cash and cash equivalents at the end of the | ||||
| period | 73,597 | 73,597 | 48,703 | 48,703 |
| Cash flow from operations | ||||
| From continuing operations | 896,936 | 133,811 | 880,394 | 171,365 |
| From discontinued operations | - | - | -323,276 | -283 |
| 896,936 | 133,811 | 557,118 | 171,082 | |
| Cash flow from investments | ||||
| From continuing operations | -619,140 | -145,103 | -423,422 | -155,426 |
| From discontinued operations | - | - | -42,386 | - |
| -619,140 | -145,103 | -465,808 | -155,426 | |
| Cash flow from financing | ||||
| From continuing operations | -252,450 | -13,616 | -120,505 | -72,282 |
| From discontinued operations | - | - | - | - |
| -252,450 | -13,616 | -120,505 | -72,282 |
| Additional | |||||
|---|---|---|---|---|---|
| Share | capital/Other | Retained | controlling | ||
| capital | reserves | earnings | Net result | interest | Total equity |
| 463 | 840,378 | 712,085 | -411,268 | 95,555 | 1,237,213 |
| - | - | -411,268 | 411,268 | - | - |
| - | -1,959 | 249 | 511,875 | -4,688 | 505,477 |
| - | - | - | - | 94 | 94 |
| - | 4,660 | -10,520 | - | -13,596 | -19,456 |
| - | -419,316 | -298,288 | - | - | -717,604 |
| - | -10,712 | - | - | - | -10,712 |
| - | 4,379 | -4,379 | - | - | - |
| - | - | 2,769 | - | - | 2,769 |
| - | -420,989 | -310,418 | - | -13,502 | -744,909 |
| 463 | 417,430 | -9,352 | 511,875 | 77,365 | 997,781 |
| - | - | 511,875 | -511,875 | - | - |
| - | -79,671 | - | 160,137 | -7,729 | 72,737 |
| - | - | - | - | -212 | -212 |
| -212 | |||||
| 463 | 337,759 | 502,523 | 160,137 | 69,424 | 1,070,306 |
| - | paid-in - |
- | - | Non -212 |
| NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS |
|---|
| ------------------------------------------------ |
| Note 1. Net sales of oil and gas, | 1 Jan 2011- | 1 Oct 2011- | 1 Jan 2010- | 1 Oct 2010- |
|---|---|---|---|---|
| 31 Dec 2011 | 31 Dec 2011 | 31 Dec 2010 | 31 Dec 2010 | |
| TUSD | 12 months | 3 months | 12 months | 3 months |
| Net sales of: | ||||
| Crude oil | ||||
| - Norway | 911,072 | 236,431 | 490,390 | 154,413 |
| - France | 127,789 | 31,359 | 92,681 | 25,628 |
| - Netherlands | 228 | 57 | 128 | 52 |
| - Indonesia | 3 | - | 34,994 | 16,295 |
| - Russia | 79,515 | 19,078 | 66,624 | 16,445 |
| - Tunisia | 24,795 | - | 29,517 | - |
| 1,143,402 | 286,925 | 714,334 | 212,833 | |
| Condensate | ||||
| - Netherlands | 1,314 | 343 | 1,088 | 353 |
| - Indonesia | - | - | 200 | 136 |
| 1,314 | 343 | 1,288 | 489 | |
| Gas | ||||
| - Norway | 57,909 | 16,329 | 32,687 | 11,427 |
| - Netherlands | 42,496 | 11,448 | 32,357 | 9,266 |
| - Indonesia | 12,570 | 3,765 | 4,496 | 2,182 |
| 112,975 | 31,542 | 69,540 | 22,875 | |
| Net sales of oil and gas from | ||||
| continuing operations | 1,257,691 | 318,810 | 785,162 | 236,197 |
| Net sales of oil and gas from discontinued | ||||
| operations – United Kingdom | - | - | 62,567 | - |
| Total net sales of oil and gas | 1,257,691 | 318,810 | 847,729 | 236,197 |
| Note 2. Production costs, | 1 Jan 2011- 31 Dec 2011 |
1 Oct 2011- 31 Dec 2011 |
1 Jan 2010- 31 Dec 2010 |
1 Oct 2010- 31 Dec 2010 |
| 12 months | 3 months | 12 months | 3 months | |
| TUSD | ||||
| Cost of operations Tariff and transportation expenses |
102,476 22,863 |
28,338 5,228 |
97,179 17,438 |
30,171 5,638 |
| Direct production taxes | 52,390 | 12,843 | 41,624 | 10,136 |
| Change in inventory/lifting position | 13,129 | -17 | -3,409 | 275 |
| Other | 2,246 | 543 | 4,233 | 2,515 |
| Production costs from continuing | ||||
| operations | 193,104 | 46,935 | 157,065 | 48,735 |
| Production costs from discontinued | ||||
| operations – United Kingdom | - | - | 32,030 | - |
| Total production costs | 193,104 | 46,935 | 189,095 | 48,735 |
| Note 3. Depletion costs, | 1 Jan 2011- | 1 Oct 2011- | 1 Jan 2010- | 1 Oct 2010- |
| 31 Dec 2011 | 31 Dec 2011 | 31 Dec 2010 | 31 Dec 2010 | |
| TUSD | 12 months | 3 months | 12 months | 3 months |
| Norway | 130,011 | 34,622 | 101,643 | 28,262 |
| France | 12,174 | 3,056 | 14,623 | 3,969 |
| Netherlands | 11,939 | 2,985 | 16,490 | 3,715 |
| Indonesia | 6,250 | 1,932 | 4,218 | 1,017 |
| Russia | 4,764 | 1,162 | 6,002 | 1,370 |
| Tunisia | - | - | 6 | - |
| Depletion of oil and gas properties | 165,138 | 43,757 | 142,982 | 38,333 |
| Italy | - | - | 2,334 | 19 |
| Depletion of solar properties | - | - | 2,334 | 19 |
| Depletion from continuing operations | 165,138 | 43,757 | 145,316 | 38,352 |
| Depletion from discontinued operations – | ||||
| United Kingdom | - | - | 11,362 | - |
| Total depletion costs | 165,138 | 43,757 | 156,678 | 38,352 |
| Note 4. Exploration costs, | 1 Jan 2011- 31 Dec 2011 |
1 Oct 2011- 31 Dec 2011 |
1 Jan 2010- 31 Dec 2010 |
1 Oct 2010- 31 Dec 2010 |
|---|---|---|---|---|
| TUSD | 12 months | 3 months | 12 months | 3 months |
| Norway | 74,060 | 7,333 | 94,526 | 61,053 |
| Malaysia | 11,015 | - | - | - |
| Vietnam | - | - | 31,906 | -258 |
| Congo (Brazzaville) | 51,263 | 51,263 | - | - |
| Other | 3,689 | 1,204 | 1,102 | -108 |
| Exploration costs from continuing operations |
140,027 | 59,800 | 127,534 | 60,687 |
| Exploration costs from discontinued operations - United Kingdom |
- | - | 61 | - |
| Total exploration costs | 140,027 | 59,800 | 127,595 | 60,687 |
| Note 5. Operating profit, | 1 Jan 2011- 31 Dec 2011 |
1 Oct 2011- 31 Dec 2011 |
1 Jan 2010- 31 Dec 2010 |
1 Oct 2010- 31 Dec 2010 |
|---|---|---|---|---|
| TUSD | 12 months | 3 months | 12 months | 3 months |
| Operating profit | ||||
| - Norway | 703,711 | 196,175 | 303,892 | 62,417 |
| - France | 85,334 | 19,888 | 52,309 | 14,382 |
| - Netherlands | 18,868 | 4,786 | 7,273 | 2,586 |
| - Indonesia | 168 | -267 | 18,203 | 13,867 |
| - Russia | 7,715 | 1,191 | 4,734 | 955 |
| - Tunisia | 13,476 | -197 | 11,500 | -205 |
| - Malaysia | -11,010 | - | - | - |
| - Congo (Brazzaville) | -51,273 | -51,273 | - | - |
| - Vietnam | -459 | -6 | -31,906 | 258 |
| - Other | -62,306 | -29,689 | 27,845 | 49,915 |
| Operating profit from continuing | ||||
| operations | 704,224 | 140,608 | 393,850 | 144,175 |
| Operating profit from discontinued | ||||
| operations – United Kingdom | - | - | 20,774 | - |
| Total operating profit | 704,224 | 140,608 | 414,624 | 144,175 |
| Note 6. Financial income, | 1 Jan 2011- | 1 Oct 2011- | 1 Jan 2010- | 1 Oct 2010- |
|---|---|---|---|---|
| 31 Dec 2011 | 31 Dec 2011 | 31 Dec 2010 | 31 Dec 2010 | |
| TUSD | 12 months | 3 months | 12 months | 3 months |
| Interest income | 4,138 | 815 | 3,409 | 1,522 |
| Foreign exchange gain, net | 8,945 | 6,291 | 13,360 | 4,923 |
| Insurance proceeds | 1,734 | - | 377 | - |
| Guarantee fees | 998 | 294 | 2,348 | 43 |
| Gain on sale of loan conversion shares | 29,974 | - | - | - |
| Other financial income | 666 | -95 | 1,462 | 629 |
| Financial income from continuing | ||||
| operations | 46,455 | 7,305 | 20,956 | 7,117 |
| Financial income from discontinued | ||||
| operations – United Kingdom | - | - | 360 | - |
| Total financial income | 46,455 | 7,305 | 21,316 | 7,117 |
| 31 Dec 2010 3 months |
|---|
| 3,777 |
| 1,801 |
| 32 |
| 1,015 |
| 603 |
| -5 |
| 1,167 |
| 8,390 |
| - |
| 8,390 |
| Note 8. Tax, | 1 Jan 2011- 31 Dec 2011 |
1 Oct 2011- 31 Dec 2011 |
1 Jan 2010- 31 Dec 2010 |
1 Oct 2010- 31 Dec 2010 |
|---|---|---|---|---|
| TUSD | 12 months | 3 months | 12 months | 3 months |
| Continuing operations | ||||
| Current tax | 400,210 | 186,701 | 68,152 | 34,428 |
| Deferred tax | 174,203 | -29,543 | 183,713 | 21,843 |
| Tax from continuing operations | 574,413 | 157,158 | 251,865 | 56,271 |
| Current tax | - | - | 7,315 | - |
| Deferred tax | - | - | 1,673 | - |
| Tax from discontinued operations – United Kingdom |
- | - | 8,988 | - |
| Total tax | 574,413 | 157,158 | 260,853 | 56,271 |
| Note 9. Discontinued operations, | 1 Jan 2011- | 1 Oct 2011- | 1 Jan 2010- | 1 Oct 2010- |
|---|---|---|---|---|
| 31 Dec 2011 | 31 Dec 2011 | 31 Dec 2010 | 31 Dec 2010 | |
| TUSD | 12 months | 3 months | 12 months | 3 months |
| Net sales | - | - | 62,567 | - |
| Other operating income | - | - | 1,983 | - |
| Operating income | - | - | 64,550 | - |
| Production costs | - | - | -32,030 | - |
| Depletion costs | - | - | -11,362 | - |
| Exploration costs | - | - | -61 | - |
| General, administration and depreciation | ||||
| expenses | - | - | -323 | - |
| Operating profit | - | - | 20,774 | - |
| Financial income | - | - | 360 | - |
| Financial expenses | - | - | -1,224 | - |
| Profit before tax | - | - | 19,910 | - |
| Tax | - | - | -8,988 | - |
| Net result from discontinued | ||||
| operations | - | - | 10,922 | - |
| Gain on sale of assets | - | - | 358,070 | -283 |
| Net result from discontinued | ||||
| operations | - | - | 368,992 | -283 |
| Note 10. Oil and gas properties, TUSD |
31 Dec 2011 | 31 Dec 2010 |
|---|---|---|
| Norway | 1,269,746 | 1,018,533 |
| France | 172,467 | 159,168 |
| Netherlands | 43,739 | 49,721 |
| Indonesia | 93,610 | 78,011 |
| Russia | 615,015 | 614,731 |
| Malaysia | 129,830 | 42,058 |
| Congo (Brazzaville) | - | 32,256 |
| Ireland | 4,339 | 4,099 |
| Others | 524 | 394 |
| 2,329,270 | 1,998,971 |
| Note 11. Financial assets, TUSD |
31 Dec 2011 | 31 Dec 2010 |
|---|---|---|
| Other shares and participations | 17,775 | 68,613 |
| Capitalised financing fees | 2,506 | 4,650 |
| Long-term receivables | - | 23,791 |
| Other financial assets | 10,960 | 17,824 |
| 31,241 | 114,878 |
| Note 12. Receivables and inventories, TUSD |
31 Dec 2011 | 31 Dec 2010 |
|---|---|---|
| Inventories | 31,589 | 20,039 |
| Trade receivables | 144,954 | 94,190 |
| Underlift | 1,851 | 13,452 |
| Short-term loan receivables | - | 74,527 |
| Joint venture debtors | 20,252 | 21,389 |
| Prepaid expenses and accrued income | 4,522 | 6,351 |
| Other assets | 21,239 | 6,299 |
| 224,407 | 236,247 |
| Note 13. Provisions, TUSD |
31 Dec 2011 | 31 Dec 2010 |
|---|---|---|
| Non-current: | ||
| Site restoration | 119,341 | 93,766 |
| Deferred taxes | 803,493 | 650,695 |
| Long-term incentive plan | 58,079 | 12,806 |
| Pension | 1,460 | 1,421 |
| Other provisions | 5,620 | 4,984 |
| 987,993 | 763,672 | |
| Current: | ||
| Long-term incentive plan | 12,215 | 6,015 |
| 12,215 | 6,015 | |
| 1,000,208 | 769,687 |
| Note 14. Other current liabilities, TUSD |
31 Dec 2011 | 31 Dec 2010 |
|---|---|---|
| Trade payables | 16,546 | 16,031 |
| Overlift | 7,670 | 1,761 |
| Tax payables | 240,052 | 39,679 |
| Accrued expenses and deferred income | 16,227 | 7,667 |
| Acquisition liabilities | - | 5,680 |
| Joint venture creditors | 88,417 | 100,931 |
| Short-term loans | - | 450 |
| Derivative instruments | 168 | 6,866 |
| Other liabilities | 21,520 | 5,932 |
| 390,600 | 184,997 |
| 1 Jan 2011- | 1 Oct 2011- | 1 Jan 2010- | 1 Oct 2010- | |
|---|---|---|---|---|
| 31 Dec 2011 | 31 Dec 2011 | 31 Dec 2010 | 31 Dec 2010 | |
| Expressed in TSEK | 12 months | 3 months | 12 months | 3 months |
| Operating income | ||||
| Other operating income | 42,644 | 13,599 | 25,822 | 10,595 |
| Gross profit | 42,644 | 13,599 | 25,822 | 10,595 |
| General and administration expenses | -206,108 | -94,157 | -72,222 | -33,908 |
| Operating loss | -163,464 | -80,558 | -46,400 | -23,313 |
| Result from financial investments | ||||
| Financial income | 6,560 | 1,877 | 4,012,086 | 952 |
| Financial expenses | -25,495 | -7,181 | -36,928 | -8,546 |
| -18,935 | -5,304 | 3,975,158 | -7,594 | |
| Profit before tax | -182,399 | -85,862 | 3,928,758 | -30,907 |
| Corporation tax | - | - | 7,328 | - |
| Net result | -182,399 | -85,862 | 3,936,086 | -30,907 |
| Expressed in TSEK | 1 Jan 2011- 31 Dec 2011 12 months |
1 Oct 2011- 31 Dec 2011 3 months |
1 Jan 2010- 31 Dec 2010 12 months |
1 Oct 2010- 31 Dec 2010 3 months |
|---|---|---|---|---|
| Net result | -182,399 | -85,862 | 3,936,086 | -30,907 |
| Other comprehensive income | - | - | - | - |
| Total comprehensive income | -182,399 | -85,862 | 3,936,086 | -30,907 |
| Total comprehensive income attributable to: |
||||
| Shareholders of the Parent Company | -182,399 | -85,862 | 3,936,086 | -30,907 |
| -182,399 | -85,862 | 3,936,086 | -30,907 |
| Expressed in TSEK | 31 December 2011 | 31 December 2010 |
|---|---|---|
| ASSETS | ||
| Non-current assets | ||
| Financial assets | 7,871,947 | 7,871,947 |
| Total non-current assets | 7,871,947 | 7,871,947 |
| Current assets | ||
| Receivables | 8,954 | 7,175 |
| Cash and cash equivalents | 3,849 | 6,735 |
| Total current assets | 12,803 | 13,910 |
| TOTAL ASSETS | 7,884,750 | 7,885,857 |
| SHAREHOLDERS´EQUITY AND LIABILITIES Shareholders´ equity including net result for the |
||
| period | 7,169,977 | 7,352,376 |
| Non-current liabilities | ||
| Provisions | 36,403 | 36,403 |
| Payables to Group companies | 673,988 | 482,281 |
| Total non-current liabilities | 710,391 | 518,684 |
| Current liabilities | ||
| Current liabilities | 4,382 | 14,797 |
| Total current liabilities | 4,382 | 14,797 |
| TOTAL EQUITY AND LIABILITIES | 7,884,750 | 7,885,857 |
| Pledged assets | 3,579,013 | 3,081,228 |
| Contingent liabilities | - | - |
| 1 Jan 2011- | 1 Oct 2011- | 1 Jan 2010- | 1 Oct 2010- | |
|---|---|---|---|---|
| 31 Dec 2011 | 31 Dec 2011 | 31 Dec 2010 | 31 Dec 2010 | |
| Expressed in TSEK | 12 months | 3 months | 12 months | 3 months |
| Cash flow from operations | ||||
| Net result | -182,399 | -85,862 | 3,936,086 | -30,907 |
| Non-cash items | 207,811 | 94,494 | -3,918,807 | 29,189 |
| Changes in working capital | -12,492 | -12,661 | -798 | 1,941 |
| Total cash flow from operations | 12,920 | -4,029 | 16,481 | 223 |
| Cash flow from investments | ||||
| Change in other financial fixed assets | - | - | 1,590 | 5,142 |
| Total cash flow from investments | - | - | 1,590 | 5,142 |
| Cash flow from financing | ||||
| Change in long-term liabilities | -15,702 | 7,131 | 71,870 | - |
| Purchase of own shares | - | - | -83,157 | - |
| Total cash flow from financing | -15,702 | 7,131 | -11,287 | - |
| Change in cash and cash equivalents | -2,782 | 3,102 | 6,784 | 5,365 |
| Cash and cash equivalents at the | ||||
| beginning of the period | 6,735 | 894 | 532 | 1,656 |
| Currency exchange difference in cash and | ||||
| cash equivalents | -104 | -147 | -581 | -286 |
| Cash and cash equivalents at the end | ||||
| of the period | 3,849 | 3,849 | 6,735 | 6,735 |
| Restricted equity | Unrestricted equity | |||||
|---|---|---|---|---|---|---|
| Share | Statutory | Other | Retained | |||
| Expressed in TSEK | capital | reserve | reserves | earnings | Net result | Total equity |
| Balance at 1 January 2010 | 3,179 | 861,306 | 5,120,750 | 1,887,788 | -32,271 | 7,840,752 |
| Transfer of prior year net result | - | - | - | -32,271 | 32,271 | - |
| Total comprehensive income | - | - | - | - | 3,936,086 | 3,936,086 |
| Transactions with owners | ||||||
| Dividend | - | - | -2,515,168 | -1,826,272 | - | -4,341,440 |
| Purchase of own shares | - | - | -83,157 | - | - | -83,157 |
| Transfer of share based payments | - | - | 29,380 | -29,380 | - | - |
| Share based payments | - | - | - | 135 | - | 135 |
| Total transactions with | ||||||
| owners | - | - | -2,568,945 | -1,855,517 | - | -4,424,462 |
| Balance at 31 December 2010 | 3,179 | 861,306 | 2,551,805 | - | 3,936,086 | 7,352,376 |
| Transfer of prior year net result | - | - | - | 3,936,086 | -3,936,086 | - |
| Total comprehensive income | - | - | - | - | -182,399 | -182,399 |
| Balance at 31 December 2011 | 3,179 | 861,306 | 2,551,805 | 3,936,086 | -182,399 | 7,169,977 |
Key financial data is based on continuing operations.
| 1 Jan 2011- | 1 Oct 2011- | 1 Jan 2010- | 1 Oct 2010- | |
|---|---|---|---|---|
| 31 Dec 2011 | 31 Dec 2011 | 31 Dec 2010 | 31 Dec 2010 | |
| Financial data (TUSD) | 12 months | 3 months | 12 months | 3 months |
| Operating income | 1,269,515 | 323,003 | 798,599 | 240,093 |
| EBITDA | 1,012,063 | 244,752 | 603,450 | 177,681 |
| Net result | 155,244 | -14,035 | 129,478 | 86,631 |
| Operating cash flow | 676,201 | 89,367 | 573,380 | 156,929 |
| Data per share (USD) | ||||
| Shareholders' equity per share | 3.22 | 3.22 | 2.96 | 2.96 |
| Operating cash flow per share | 2.17 | 0.28 | 1.84 | 0.51 |
| Cash flow from operations per share | 2.88 | 0.43 | 1.79 | 0.55 |
| Earnings per share | 0.51 | -0.05 | 0.46 | 0.29 |
| Earnings per share fully diluted | 0.51 | -0.05 | 0.46 | 0.29 |
| EBITDA per share fully diluted | 3.25 | 0.78 | 1.93 | 0.57 |
| Dividend per share | - | - | 2.30 | 0.20 |
| Quoted price at the end of the financial | ||||
| period | 24.57 | 24.57 | 12.47 | 12.47 |
| Number of shares issued at period end | 317,910,580 | 317,910,580 | 317,910,580 | 317,910,580 |
| Number of shares in circulation at period | ||||
| end | 311,027,942 | 311,027,942 | 311,027,942 | 311,027,942 |
| Weighted average number of shares for | ||||
| the period | 311,027,942 | 311,027,942 | 312,096,990 | 311,027,942 |
| Weighted average number of shares for | ||||
| the period (fully diluted) | 311,027,942 | 311,027,942 | 312,096,990 | 311,027,942 |
| Key ratios (%) | ||||
| Return on equity | 15 | -1 | 12 | 9 |
| Return on capital employed | 53 | 12 | 24 | 9 |
| Return on capital employed | 53 | 12 | 24 | 9 |
|---|---|---|---|---|
| Net debt/equity ratio | 15 | 15 | 36 | 36 |
| Equity ratio | 40 | 40 | 41 | 41 |
| Share of risk capital | 69 | 69 | 67 | 67 |
| Interest coverage ratio | 5,919 | 4,893 | 1,860 | 2,555 |
| Operating cash flow/interest ratio | 5,460 | 3,131 | 2,742 | 2,798 |
| Yield | - | - | 18 | 2 |
Shareholders' equity per share: Shareholders' equity divided by the number of shares in circulation at period end.
Operating cash flow per share: Operating income less production costs and less current taxes divided by the weighted average number of shares for the period.
Cash flow from operations per share: Cash flow from operations in accordance with the consolidated statement of cash flow divided by the weighted average number of shares for the period.
Earnings per share: Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period.
Earnings per share fully diluted: Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period after considering the dilution effect of outstanding warrants.
EBITDA per share fully diluted: EBITDA divided by the weighted average number of shares for the period after considering the dilution effect of outstanding warrants. EBITDA is defined as operating profit before depletion of oil and gas properties, exploration costs, impairment costs, depreciation of other assets and gain on sale of assets.
Quoted price at the end of the financial period: The quoted price in USD is based on the quoted price in SEK converted in USD against the closing rate of the period.
Weighted average number of shares for the period: The number of shares at the beginning of the period with changes in the number of shares weighted for the proportion of the period they are in issue.
Return on equity: Net result divided by average total equity.
Return on capital employed: Income before tax plus interest expenses plus/less exchange differences on financial loans divided by the average capital employed (the average balance sheet total less non-interest bearing liabilities).
Net debt/equity ratio: Net interest bearing liabilities divided by shareholders' equity.
Equity ratio: Total equity divided by the balance sheet total.
Share of risk capital: The sum of the total equity and the deferred tax provision divided by the balance sheet total.
Interest coverage ratio: Result after financial items plus interest expenses plus/less exchange differences on financial loans divided by interest expenses.
Operating cash flow/interest ratio: Operating income less production costs and less current taxes divided by the interest charge for the period.
Yield: dividend per share in relation to quoted share price at the end of the financial period.
Ian H. Lundin Chairman
C. Ashley Heppenstall President & CEO
William A. Rand
Asbjørn Larsen Lukas H. Lundin Magnus Unger
Dambisa F. Moyo Kristin Færøvik
The AGM will be held on 10 May 2012 in Stockholm, Sweden.
In compliance with applicable Canadian regulations, Lundin Petroleum has prepared the "Statement of Reserves Data and Other Oil and Gas Information" as at 31 December 2011 in the prescribed form, and will make this Statement available on the Canadian securities regulators' website: www.sedar.com. The Statement will also be available on the Company's website: www.lundin-petroleum.com.
| For further information, please contact: | ||
|---|---|---|
| C. Ashley Heppenstall, | Maria Hamilton, | |
| President and CEO | or | Head of Corporate Communications |
| Tel: +41 22 595 10 00 | Tel: +46 8 440 54 50 | |
| Tel: +41 79 63 53 641 |
The above information has been made public in accordance with the Securities Market Act and/or the Financial Instruments Trading Act.
Certain statements made and information contained herein constitute "forward-looking information" (within the meaning of applicable Canadian securities legislation). Such statements and information (together, "forward-looking statements") relate to future events, including the Company's future performance, business prospects or opportunities. Forward-looking statements include, but are not limited to, statements with respect to estimates of reserves and or resources, future production levels, future capital expenditures and their allocation to exploration and development activities, future drilling and other exploration and development activities, ultimate recovery of reserves or resources are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.
All statements other than statements of historical fact may be forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute forwardlooking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations and assumptions will prove to be correct and such forward-looking statements should not be unduly relied upon. These statements speak only as on the date of this news release and the Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, operational risks (including exploration and development risks), productions costs, availability of drilling equipment and access, reliance on key personnel, reserve estimates, health, safety and environmental issues, legal risks and regulatory changes, competition, geopolitical risk, financial risks. These risks and uncertainties are described in more detail under the heading "Risk Factors" and elsewhere in the Company's 2010 annual report. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. Actual results may differ materially from those expressed or implied by such forward-looking statements. Forward-looking statements included in this new release are expressly qualified by this cautionary statement.
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.
The contingent resource range for the Johan Sverdrup discovery has been estimated including uncertainties in reservoir extent, reservoir properties and recovery factors. The main contingency preventing the classification of the resources as reserves is the definition of a conceptual development plan.
The recovery and production estimates of the Company's resources provided herein are only estimates and there is no guarantee that the estimated resources will be recovered or produced. Actual resources may be greater than or less than the estimates provided here. There is no certainty that it will be commercially viable for the Company to produce any portion of these resources.
The effective date of the resource estimate is the date of this press release.
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