Interim / Quarterly Report • Aug 3, 2011
Interim / Quarterly Report
Open in ViewerOpens in native device viewer
Stockholm 3 August 2011
| 1 Jan 2011- 30 Jun 2011 6 months |
1 Apr 2011- 30 Jun 2011 3 months |
1 Jan 2010- 30 Jun 2010 6 months |
1 Apr 2010- 30 Jun 2010 3 months |
1 Jan 2010- 31 Dec 2010 12 months |
|
|---|---|---|---|---|---|
| Production in Mboepd | 32.3 | 31.1 | 28.6 | 30.2 | 30.5 |
| Operating income in MUSD | 619.0 | 327.2 | 356.2 | 189.7 | 798.6 |
| Net result in MUSD | 130.3 | 76.9 | 20.8 | 7.2 | 129.5 |
| Net result attributable to shareholders | |||||
| of the Parent Company in MUSD | 133.1 | 78.0 | 25.9 | 10.0 | 142.9 |
| Earnings/share in USD1 | 0.43 | 0.25 | 0.08 | 0.02 | 0.46 |
| Diluted earnings/share in USD1 | 0.43 | 0.25 | 0.08 | 0.02 | 0.46 |
| EBITDA in MUSD | 505.3 | 266.9 | 258.4 | 138.8 | 603.5 |
| Operating cash flow in MUSD | 390.3 | 196.7 | 256.3 | 135.8 | 573.4 |
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 187 million barrels of oil equivalent (MMboe).
Lundin Petroleum achieved excellent results in the second quarter of 2011 with increased profitability and cash flow. What is extremely pleasing however, is the continued exploration success. I have always highlighted that the major valuation creation for our company will be achieved through increasing our oil and gas resources, and the best way to do that is through exploration. Norway continues to deliver with a third discovery this year from our first well in the Barents Sea and I'm particularly pleased that our first Malaysian exploration well resulted in a discovery. I hope that in South East Asia we are now on the way to creating a new core development and production area for our Company.
Lundin Petroleum produced a net result for the first six months of MUSD 130.3. The strong production coupled with oil prices achieved of well over USD 100 per barrel resulted in operating cash flow of MUSD 390.3 and EBITDA of MUSD 505.3. Despite our significant exploration and development investment programme net debt during the first half of the year has reduced from MUSD 410 to below MUSD 120.
During the first half of the year production averaged 32,300 barrels of oil equivalent per day (boepd) which was at the high end of our forecasts. This performance was achieved despite a 13 day unplanned shutdown of Alvheim and Volund production during the second quarter to carry out preventative maintenance on the Alvheim FPSO. In particular Volund production has performed significantly above forecast during the period. We expect a further two Alvheim development wells to come on production during the second half of the year as well as first oil from the Gaupe field offshore Norway. As a result of the strong production performance we have revised our production guidance for 2011 upwards from the previous 28 -33,000 boepd to 31 - 34,000 boepd.
We are still forecasting to increase our production over the next 5 years from various Norwegian development projects to over 60,000 boepd.
Our various development projects are positively moving forward. The Gaupe field development is still forecast to commence production this year with a plateau production adding 5,000 boepd net to Lundin Petroleum. On 1 August 2011 we submitted the plan of development of the Brynhild field (formerly called Nemo) to the Norwegian Ministry of Petroleum and Energy for approval. The Brynhild field will be developed as a subsea tieback to Shell's Pierce field in the United Kingdom with first oil forecast for late 2013 at a plateau net production rate of 6,000 boepd. Conceptual development plans have been agreed for the subsea development of the Bøyla field through the Alvheim FPSO and a plan of development will be submitted in 2012.
The Tellus discovery which was made earlier this year and subsequently appraised with a sidetrack will now be developed as part of the Luno field development. The front end engineering and design studies for the development of the Luno field are progressing satisfactorily and it is still planned to submit a plan of development in 2011. We will not be proceeding with the marginal Krabbe development following further technical analysis of this field but we will more than make up the future production from increases to the Luno production plateau and the addition of the Tellus development.
As I have previously indicated the capital cost of these developments will be funded from a combination of internally generated funds and bank borrowings without the requirement for additional equity funding.
The positive exploration news has continued during the second quarter with further discoveries at Skalle in PL438 in the Barents Sea, Earb South in PL505 in the northern Norwegian North Sea and Tarap in Block SB303 offshore East Malaysia. In addition the results of the first Avaldsnes appraisal well were extremely encouraging confirming the extension of the Avaldsnes field to the south east. We have now achieved five discoveries from our first five exploration wells this year following the Tellus and Caterpillar discoveries during the first quarter.
In PL501 the first appraisal well on Avaldsnes encountered excellent quality Jurassic reservoir of multi darcy permeability and 30 percent porosity with net pay thicker than the discovery well. The well tested 5,500 bopd from a restricted choke. The subsequent sidetrack, whilst having a thinner reservoir section, also encountered comparable reservoir quality and provided increased confidence that the part of the Avaldsnes structure previously assumed to be non-hydrocarbon bearing could in fact be covered by Upper Jurassic hydrocarbon bearing reservoir. We are currently drilling the second Avaldsnes appraisal well. The gross resource estimates for the Avaldsnes field located in PL501 were estimated at 100 – 400 MMboe following the discovery well last year and will be updated after the second appraisal well to reflect the results of the appraisal drilling programme. We believe that the Avaldsnes structure extends to the west into the Statoil operated PL265 where Lundin Petroleum is a non-operated partner. Statoil are currently drilling the first of two wells to be drilled this year on PL265 to appraise the extension of Avaldsnes into PL265 where Lundin Petroleum holds 10%. I expect that Avaldsnes appraisal drilling in PL501 will continue in 2012 to fully appraise the field.
We have put together a large acreage position in the Barents Sea over recent years, which has increased further with the award of PL609 in the Norwegian 21st Licensing Round. Our first well in the Barents Sea on the Skalle prospect in PL438 was a gas discovery with estimated gross contingent resources of between 88 and 280 billion cubic feet (bcf). Whilst we were primarily targeting oil potential we will now look to commercialise the discovery which is located close to the producing Snøvhit gas field. The licence contains numerous additional prospects. The Pulk exploration well in PL533 operated by ENI has now slipped into 2012.
Our first exploration well in Malaysia resulted in a large gas discovery on the Tarap prospect offshore Sabah containing 171 bcf of gross contingent resources. The Tarap discovery is in Block SB303 which already contains the nearby Titik Terang gas discovery with additional gross contingent resources of 66 bcf. The gas market in East Malaysia is developing with the construction of additional gas infrastructure to supply the Sabah oil and gas terminal. In the forthcoming months, we will be exploring the commercialisation of our gas resources in East Malaysia. We will be drilling four further exploration and appraisal wells in Malaysia in 2011 and are already planning for a similar drilling campaign in 2012.
Despite the continued uncertainty with regard to world economic growth the oil price has remained strong. As we have predicted there is a growing realisation that current oil prices are no longer a short term aberration but something to be expected as the norm. We maintain our belief that oil prices are and will continue to be driven by the fundamentals of supply and demand and that our low sulphur oil reserves located predominantly in Norway will continue to realise a premium above Brent benchmark prices.
Our business is continuing to grow and I am confident we will continue to increase shareholder value. We are generating strong cash flow and profitability from our existing production which is outperforming, our development projects are proceeding well and our exploration success continues.
Best Regards
C. Ashley Heppenstall President and CEO
The net production in Norway to Lundin Petroleum for the six month period ended 30 June 2011 (reporting period) was 22,300 barrels of oil equivalent per day (boepd). Production was adversely impacted in the second quarter due to a 13 day unplanned shutdown of the Alvheim and Volund fields due to preventative maintenance on the Alvheim FPSO's fire prevention system.
The net production for the reporting period from the Alvheim field (Lundin Petroleum working interest (WI) 15%), offshore Norway, was 11,300 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 reserves during 2010 to 276 million barrels of oil equivalent (MMboe) representing a 65 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 is ongoing with a further two development wells to begin production in the second half of 2011. A third well is being drilled and will begin production early 2012. The forecast cost of operations for the Alvheim field in 2011 is approximately USD 5.00 per barrel.
The net production from the Volund field (WI 35%) amounted to 11,000 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. It is likely that further development drilling will take place on Volund in 2012.
In October 2009, a new oil discovery on the Bøyla prospect in PL340 (WI 15%) was announced. Bøyla contains gross recoverable resources of 20 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 Bøyla will now most likely be developed through the Bøyla development facilities.
The Luno field located in PL338 (WI 50%) was discovered in 2007 and has subsequently been appraised by two further wells. The results of these appraisal wells have been incorporated into the reservoir model being used for development planning and has resulted in an upgrade of gross proven and probable (2P) reserves from 95 MMboe to 148 MMboe for the Luno field. The reserves have been audited by third party reserves auditors Gaffney Cline & Associates. Conceptual development studies for a Luno field standalone development and in relation to a joint development of the Luno field and the nearby Draupne field have been completed. The decision has been made to proceed with a standalone development and FEED studies are now ongoing. A plan of development for the Luno field will be submitted in 2011. It is likely that further exploration drilling in PL338 on additional prospects will take place in 2012.
In April 2011, the Tellus exploration well in PL338 was completed as an oil discovery. The Tellus discovery is most likely a northern extension of the Luno field and is estimated to contain gross contingent resources of between 11 and 55 MMboe. 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. In May 2011 the Tellus exploration well was successfully sidetracked to appraise the discovery and as a result the Tellus development will now be included as part of the Luno development programme.
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 resources of 100 to 400 MMboe within PL501 and that the fault controlled structure extended to the west into PL265 (WI 10%).
The first Avaldsnes appraisal well and sidetrack were successfully completed in July 2011 confirming the extension of the Avaldsnes field to the south east of the discovery well. The appraisal well encountered oil bearing reservoir of thickness and quality better than the discovery well and tested at an average production rate in excess of 5,500 boepd through a restricted choke. A second appraisal well is currently being drilled following which the Avaldsnes resource estimates will be updated to reflect the results of the appraisal programme. Two further wells will be drilled in 2011 by Statoil, operator of PL265, to test the extension of the Avaldsnes structure into PL265, the first of which is currently being drilled as Aldous Major South. The element of the Avaldsnes structure in PL265 has been named Aldous Major South and Aldous Major North.
The Avaldsnes discovery and the Apollo discovery in PL338 made in 2010 have both opened up additional prospectivity in the Greater Luno area and further exploration drilling in PL359 (WI 40%) and PL410 ( WI 70%) will likely take place in 2012.
The plan of development for the Gaupe field in PL292 (WI 40%) was approved in June 2010, where first production is expected in late 2011. The Gaupe field operated by BG Group has estimated gross 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 50%) has been submitted to the Norwegian Ministry of Petroleum and Energy for approval. The Brynhild field contains gross proven plus probable reserves of 22 MMboe and is expected to produce at a plateau production rate net to Lundin Petroleum of 6,000 boepd with first oil forecast in late 2013.
Lundin Petroleum has decided not to proceed with the development of the Krabbe discovery in PL301 (WI 40%) due to uncertainty regarding the recoverable resources from the field.
In January 2011, Lundin Petroleum was awarded ten exploration licences in the 2010 APA Licensing Round of which six licences will be 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 to contain between 150 and 250 MMboe. Lundin Petroleum has now interests in five exploration licences in the Barents Sea.
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 280 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 May 2011 Lundin Petroleum acquired a 30 percent interest in PL330 located in the northern Norwegian Sea.
In July 2011, Lundin Petroleum completed the drilling of well 25/10-11 on the Earb South prospect in PL505. 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 and further work will be required to determine whether the discovery can be commercialised.
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 2,450 boepd and in the Aquitaine Basin (WI 50%) averaged 650 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. Development drilling will continue into 2012.
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%) is completed.
The net production to Lundin Petroleum from the Singa gas field (WI 25.9%) during the reporting period amounted to 900 boepd. Production from the Singa field commenced in 2010. Current gross production from the first production well is in excess of 20 million standard cubic feet per day (MMscfd) of sales gas. A second development well has been completed during the reporting period and is having a positive impact on production rates.
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 block (WI 100%) was completed in 2010. Interpretation has been completed and exploration drilling will commence in 2012. In addition a 1,500 km 2D seismic acquisition programme will be 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 program will be completed in 2011.
A new Production Sharing Contract for the Gurita block was signed in March 2011 (WI 100%). A 400km² 3D seismic acquisition programme will be completed in 2011.
The 2009 3D seismic data programme identified numerous drilling targets for the 2011/2012 drilling campaign. Five exploration and appraisal wells will be 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. There are various options for the commercialisation of gas in the Sabah area.
The Cempulut exploration well also in SB303 is currently drilling.
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 is planned for 2011 plus the drilling of an appraisal well on the Bertram discovery.
The net production from Russia for the period was 3,200 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 due to its offshore location is deemed to be strategic 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 will target new exploration drilling locations.
The net production from the Oudna field (WI 40%) was 800 boepd for the reporting period.
Exploration drilling will resume in 2011 with one well on Block Marine XI (WI 18.75%) and a further well on Block Marine XIV (WI 21.55%).
The net result for the six month period ended 30 June 2011 (reporting period), from continuing operations amounted to MUSD 130.3 (MUSD 20.8). The net result attributable to shareholders of the Parent Company for the reporting period, from continuing operations amounted to MUSD 133.1 (MUSD 25.9) representing earnings per share on a fully diluted basis of USD 0.43 (USD 0.08).
Earnings before interest, tax, depletion and amortisation (EBITDA) for the reporting period amounted to MUSD 505.3 (MUSD 258.4) representing EBITDA per share on a fully diluted basis of USD 1.62 (USD 0.83). Operating cash flow for the reporting period amounted to MUSD 390.3 (MUSD 256.3) representing operating cash flow per share on a fully diluted basis of USD 1.26 (USD 0.82).
There are no 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 32.3 Mboe per day (Mboepd) (28.6 Mboepd) and was comprised as follows:
| 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- | |
|---|---|---|---|---|---|
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| Production | 6 months | 3 months | 6 months | 3 months | 12 months |
| Norway | |||||
| - Quantity in Mboe | 4,034.8 | 1,919.6 | 2,917.5 | 1,627.2 | 6,629.8 |
| - Quantity in Mboepd | 22.3 | 21.1 | 16.1 | 17.9 | 18.2 |
| France | |||||
| - Quantity in Mboe | 556.8 | 281.5 | 568.1 | 286.7 | 1,160.8 |
| - Quantity in Mboepd | 3.1 | 3.1 | 3.1 | 3.1 | 3.2 |
| Netherlands | |||||
| - Quantity in Mboe | 368.3 | 180.5 | 389.1 | 192.1 | 756.7 |
| - Quantity in Mboepd | 2.0 | 2.0 | 2.2 | 2.1 | 2.1 |
| Indonesia | |||||
| - Quantity in Mboe | 164.1 | 94.0 | 402.8 | 205.4 | 887.1 |
| - Quantity in Mboepd | 0.9 | 1.0 | 2.2 | 2.3 | 2.4 |
| Russia | |||||
| - Quantity in Mboe | 577.7 | 284.6 | 700.1 | 343.7 | 1,321.2 |
| - Quantity in Mboepd | 3.2 | 3.1 | 3.9 | 3.8 | 3.6 |
| Tunisia | |||||
| - Quantity in Mboe | 144.1 | 72.6 | 198.3 | 95.6 | 372.2 |
| - Quantity in Mboepd | 0.8 | 0.8 | 1.1 | 1.0 | 1.0 |
| Total from continuing | |||||
| operations | |||||
| - Quantity in Mboe | 5,845.8 | 2,832.8 | 5,175.9 | 2,750.7 | 11,127.8 |
| - Quantity in Mboepd | 32.3 | 31.1 | 28.6 | 30.2 | 30.5 |
| Discontinued operations - | |||||
| United Kingdom | |||||
| - Quantity in Mboe | - | - | 812.2 | - | 812.2 |
| - Quantity in Mboepd | - | - | 4.5 | - | 2.2 |
| Total excluding non | |||||
| controlling interest | |||||
| - Quantity in Mboe | 5,845.8 | 2,832.8 | 5,988.1 | 2,750.7 | 11,940.0 |
| - Quantity in Mboepd | 32.3 | 31.1 | 33.1 | 30.2 | 32.7 |
The increase in Norway production volumes from the comparative reporting period is attributable to the Volund field which came onstream in April 2010. The Volund field contributed 11.0 Mboepd (2.1 Mboepd) for the reporting period and 11.2 Mboepd (4.2 Mboepd) for the second quarter of 2011. Norwegian production was negatively impacted in the second quarter of 2011 by the 13 day unplanned shutdown of the Alvheim facilities during May 2011.
The 2010 production figures for Indonesia include the contributions of the Salawati assets of 2.1 Mboepd for the first six months of 2010 and 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 614.2 (MUSD 354.4) and are detailed in Note 1. Sales volumes for the reporting period were 18 percent higher and the achieved oil price was 46 percent higher than the comparative period. The average price achieved by Lundin Petroleum for a barrel of oil equivalent amounted to USD 101.23 (USD 69.16) and is detailed in the following table. The premium on Norwegian crude oil sold during the reporting period averaged USD 3.73 per barrel. The average Dated Brent price for the reporting period amounted to USD 111.09 (USD 77.29) per barrel.
Sales for the reporting period were comprised as follows:
| Sales Average price per boe expressed in USD |
1 Jan 2011- 30 Jun 2011 6 months |
1 Apr 2011- 30 Jun 2011 3 months |
1 Jan 2010- 30 Jun 2010 6 months |
1 Apr 2010- 30 Jun 2010 3 months |
1 Jan 2010- 31 Dec 2010 12 months |
|---|---|---|---|---|---|
| Norway | |||||
| - Quantity in Mboe | 4,188.8 | 2,012.4 | 3,041.9 | 1,768.3 | 6,712.5 |
| - Average price per boe | 109.68 | 115.27 | 75.31 | 76.78 | 77.93 |
| France | |||||
| - Quantity in Mboe | 576.8 | 285.5 | 590.6 | 296.5 | 1,168.0 |
| - Average price per boe | 109.52 | 113.70 | 76.72 | 76.07 | 79.35 |
| Netherlands | |||||
| - Quantity in Mboe | 368.3 | 180.5 | 389.1 | 192.1 | 756.7 |
| - Average price per boe | 58.46 | 62.71 | 39.61 | 35.43 | 44.37 |
| Indonesia | |||||
| - Quantity in Mboe | 158.9 | 94.7 | 227.0 | 102.3 | 607.7 |
| - Average price per boe | 32.73 | 32.61 | 69.23 | 67.67 | 65.31 |
| Russia | |||||
| - Quantity in Mboe | 577.0 | 275.9 | 679.5 | 340.0 | 1,290.0 |
| - Average price per boe | 69.50 | 76.20 | 49.38 | 49.31 | 51.65 |
| Tunisia | |||||
| - Quantity in Mboe | 198.2 | 198.2 | 195.6 | - | 382.6 |
| - Average price per boe | 125.12 | 125.12 | 78.27 | - | 77.15 |
| Total from continuing operations |
|||||
| - Quantity in Mboe | 6,068.0 | 3,047.2 | 5,123.7 | 2,699.2 | 10,917.5 |
| - Average price per boe | 101.23 | 106.55 | 69.16 | 69.96 | 71.92 |
| Discontinued operations - United Kingdom |
|||||
| - Quantity in Mboe | - | - | 814.4 | - | 814.4 |
| - Average price per boe | - | - | 76.82 | - | 76.82 |
| Total | |||||
| - Quantity in Mboe | 6,068.0 | 3,047.2 | 5,938.1 | 2,699.2 | 11,731.9 |
| - Average price per boe | 101.23 | 106.55 | 70.22 | 69.96 | 72.26 |
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 is forecast to be 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. 36 percent (39 percent) of Russian sales for the reporting period were on the international market at an average price of USD 108.68 per barrel (USD 74.10 per barrel) with the remaining 64 percent (61 percent) of Russian sales being sold on the domestic market at an average price of USD 47.12 per barrel (USD 33.61 per barrel).
Other operating income amounted to MUSD 4.7 (MUSD 1.8) for the reporting period and includes MUSD 2.0 (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 1.3 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.
Production costs for the reporting period amounted to MUSD 97.9 (MUSD 85.5) 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- 30 Jun 2011 6 months |
1 Apr 2011- 30 Jun 2011 3 months |
1 Jan 2010- 30 Jun 2010 6 months |
1 Apr 2010- 30 Jun 2010 3 months |
1 Jan 2010- 31 Dec 2010 12 months |
|---|---|---|---|---|---|
| Cost of operations | 8.31 | 8.96 | 8.53 | 8.48 | 8.63 |
| Tariff and transportation | |||||
| expenses | 2.12 | 2.28 | 1.34 | 1.48 | 1.57 |
| Royalty and direct taxes | 4.35 | 4.87 | 4.12 | 3.89 | 3.74 |
| Changes in inventory/overlift | 1.77 | 4.32 | 2.29 | 2.78 | -0.31 |
| Other | 0.19 | 0.20 | 0.23 | 0.19 | 0.38 |
| Total production costs | 16.74 | 20.63 | 16.51 | 16.82 | 14.01 |
| Depletion | 13.45 | 13.42 | 12.67 | 12.76 | 12.85 |
| Total cost per boe | 30.19 | 34.05 | 29.18 | 29.58 | 26.86 |
The total cost of operations for the reporting period was MUSD 48.6 compared to MUSD 44.2 for the comparative period. The current reporting period includes costs of the Volund field, Norway and Singa field, Indonesia for a full six month period whereas the Volund and Singa fields contributed costs partially in the second quarter of 2010 having commenced production in that quarter. In addition, in the second quarter of 2011 the cost of operations includes an amount of MUSD 1.2 associated with the unplanned shutdown of the Alvheim FPSO. The increases are partly offset by a reduction compared to the prior reporting period following the disposal of the Salawati assets, Indonesia in December 2010.
The cost of operations for the second quarter of 2011 were MUSD 25.4, corresponding to USD 8.96 per barrel compared to MUSD 23.2 corresponding to USD 7.70 per barrel for the first quarter of 2011. The costs associated with the inspecting and testing of the deluge system on the Alvheim FPSO including an additional standby boat amounted to MUSD 1.2. The cost of operations in the second quarter of 2011 also includes expenditure related to re-certification of the FPSO used on the Oudna field, Tunisia as well as additional activity across various fields deferred from the first quarter of 2011. Costs of operations for 2011 are in line with forecast.
The tariff and transportation expenses for the reporting period amounted to MUSD 12.4 compared to MUSD 6.9 for the comparative reporting 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. Lundin Petroleum has a 15 percent working interest in the Alvheim field and a 35 percent interest in the Volund field and the tariff self-to-self element 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 20.86 (USD 13.45) 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 54.92 (USD 37.88) per barrel for the reporting period. The royalty and direct taxes have increased compared to the comparative period 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 10.4 (MUSD 11.9) was charged to the income statement for the reporting period.
Depletion costs amounted to MUSD 78.6 (MUSD 65.6) and are detailed in Note 3. The main increase from the comparative period is in Norway where the depletion cost expensed has increased by 36 percent in line with the production increase of 39 percent. Norway contributed approximately 80 percent of the total depletion charge for the period at a rate of USD 15.27 per barrel and this increases the overall rate from the comparative period. Depletion per barrel for the reporting period is in line with forecast.
Exploration costs for the reporting period amounted to MUSD 16.2 (MUSD 46.2) and are detailed in Note 4. The costs relate mainly to previously capitalised expenses in respect of Norway licence PL304 which was relinquished in January 2011, additional costs associated with the unsuccessful Norway PL409 Norall well drilled in the fourth quarter of 2010 and the expensing of the capitalised expenses on Norway licence PL301 following a technical review.
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 17.7 (MUSD 14.2) of which MUSD 5.7 (MUSD -0.1) related to non-cash charges in relation to a part of the Group's Long-term Incentive Plan (LTIP) scheme. The MUSD 14.2 reported in the comparative reporting period includes an amount of MUSD 5.4 relating to Etrion.
The cost for the second quarter of 2011 was low compared to the first quarter of 2011 due primarily to the partial reversal of the LTIP provision during the second quarter resulting from a lower share price at the balance sheet date. Awards to employees under the Group's LTIP scheme are valued using the Black & Scholes calculation method using the share price as at 30 June 2011. The cost is accrued over the vesting period of the awards in accordance with accounting rules. During the first quarter of 2011, the Lundin Petroleum share price increased by over 9 percent compared to the share price at the end of the fourth quarter of 2010 and accordingly, the cost associated with the LTIP was reflected in the first quarter of 2011. During the second quarter of 2011, the share price decreased by 6 percent compared to the share price at the end of the first quarter of 2011.
Financial income for the reporting period amounted to MUSD 35.0 (MUSD 4.0) and is detailed in Note 5.
Interest income for the reporting period amounted to MUSD 2.6 (MUSD 1.3). 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.
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 24.2 (MUSD 16.1) and are detailed in Note 6.
Interest expenses for the reporting period amounted to MUSD 2.8 (MUSD 2.6). In addition, an amount of MUSD 0.6 of interest expense associated with the funding of the development of the Gaupe field was capitalised in the reporting period. In the comparative period an amount of MUSD 1.5 associated with the development of Volund field was capitalised.
Foreign exchange losses amounted to MUSD 13.4 (MUSD 0.6) in the reporting period. The Euro strengthened against both the US Dollar and the Norwegian Kroner during the reporting period giving rise to exchange loss movements on the intercompany loans receivable by a subsidiary using a functional currency of the Euro.
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 3.4 (MUSD 3.5) 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 2.3 (MUSD 2.0) has been charged to the income statement for the reporting period.
The tax charge for the reporting period amounted to MUSD 289.6 (MUSD 112.2) and is detailed in Note 7.
The current tax charge on continuing operations for the reporting period amounted to MUSD 130.7 (MUSD 14.4). In the reporting period, there is a MUSD 112.6 (MUSD 1.9) current tax charge relating to Norway. The tax charge in Norway consists of both the 28 percent onshore regime and the 50 percent offshore regime.
The deferred tax charge amounted to MUSD 158.9 (MUSD 97.9) for the reporting period and arises where tax losses have offset the current tax charge and there is a difference in depreciation for tax and accounting purposes. MUSD 148.2 (MUSD 99.7) 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 69 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 main contributor to the tax charge is Norway where the tax rate is 78 percent reduced by the effect of uplift for tax purposes on development expenditure. The effective rate of cash tax payable in the reporting period is 31 percent primarily because exploration expenditure and tax allowances on development expenditure provided a tax deduction in Norway during the reporting period. Cash taxes payable in Norway for the reporting period were MUSD 112.6 (MUSD 1.9) and the increase from the comparative period is mainly due to the utilisation of the tax losses in 2010.
The net result attributable to non-controlling interest for the reporting period amounted to MUSD -2.8 (MUSD -5.1) 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 369.3). 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 8.
Oil and gas properties amounted to MUSD 2,346.1 (MUSD 1,999.0) and are detailed in Note 9.
Development and exploration expenditure incurred for the reporting period was as follows:
| Development expenditure | 1 Jan 2011- 30 Jun 2011 |
1 Apr 2011- 30 Jun 2011 |
1 Jan 2010- 30 Jun 2010 |
1 Apr 2010- 30 Jun 2010 |
1 Jan 2010- 31 Dec 2010 |
|---|---|---|---|---|---|
| in MUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Norway | 92.1 | 62.6 | 62.3 | 20.3 | 106.3 |
| France | 9.4 | 6.6 | 7.4 | 4.2 | 13.2 |
| Netherlands | 1.2 | 0.8 | 2.1 | 1.3 | 4.5 |
| Indonesia | 4.1 | 1.4 | 8.1 | 3.1 | 10.2 |
| Russia | 2.7 | 1.4 | 3.7 | 2.2 | 6.6 |
| Development expenditures | |||||
| from continuing operations | 109.5 | 72.8 | 83.6 | 31.1 | 140.8 |
| Discontinued operations - | |||||
| United Kingdom | - | - | 17.1 | - | 17.1 |
| Development expenditures | 109.5 | 72.8 | 100.7 | 31.1 | 157.9 |
During the reporting period, an amount of MUSD 92.1 of development expenditure was incurred in Norway on the Gaupe field development and the Phase 2 drilling on the Alvheim field. MUSD 62.3 was spent on development projects in Norway in the comparative period, predominantly on the Volund field development and Alvheim drilling.
| Exploration expenditure | 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- |
|---|---|---|---|---|---|
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| in MUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Norway | 152.3 | 92.5 | 29.8 | 1.3 | 160.8 |
| France | 0.5 | 0.2 | 0.3 | 0.1 | 1.0 |
| Indonesia | 6.4 | 3.5 | 8.0 | 6.8 | 13.5 |
| Russia | 4.5 | 2.5 | 10.7 | 5.3 | 18.3 |
| Malaysia | 26.4 | 22.0 | 4.7 | 3.1 | 10.6 |
| Congo (Brazzaville) | 2.7 | 1.2 | 1.3 | 0.7 | 2.5 |
| Vietnam | 0.4 | 0.3 | 9.0 | 5.1 | 15.3 |
| Other | 0.0 | -0.7 | 0.3 | -0.8 | 4.4 |
| Exploration expenditures | |||||
| from continuing operations | 193.2 | 121.5 | 64.1 | 21.6 | 226.4 |
| Discontinued operations - | |||||
| United Kingdom | - | - | 0.2 | - | 0.2 |
| Exploration expenditures | 193.2 | 121.5 | 64.3 | 21.6 | 226.6 |
During the reporting period, an amount of MUSD 152.3 of exploration expenditure was incurred in Norway mainly on the Tellus discovery well on licence PL338, the Caterpillar discovery well on licence PL340, the Earb well on licence PL505, the Skalle well on licence PL438 and the Avaldsnes appraisal well on licence PL501. MUSD 26.4 was incurred in Malaysia and was primarily for the drilling and testing of the Tarap well on block SB303.
Other tangible assets amounted to MUSD 16.2 (MUSD 15.3) and represent office fixed assets and real estate.
Financial assets amounted to MUSD 75.5 (MUSD 114.9) and are detailed in Note 10.
Other shares and participations amounted to MUSD 39.8 (MUSD 68.6) and predominantly relate to the shares held in ShaMaran Petroleum which are reflected at market price. Long-term receivables amounted to MUSD - (MUSD 23.8) following the conversion of the convertible loan of MUSD 23.8 provided to AOC during the reporting period. Other financial assets amounted to MUSD 31.8 (MUSD 17.8) and mainly represent recoverable VAT paid on costs in Russia amounting to MUSD 19.3 (MUSD 16.5) and Etrion Corporation bonds of MUSD 11.0 (MUSD -) held by Lundin Petroleum.
The deferred tax asset amounted to MUSD 15.7 (MUSD 15.1) and mainly relates to unutilised tax losses in the Netherlands.
Receivables and inventories amounted to MUSD 176.9 (MUSD 236.2) and are detailed in Note 11.
Trade receivables amounted to MUSD 121.8 (MUSD 94.2). Higher oil prices have resulted in the value of the trade receivables being higher at 30 June 2011.
Short-term loan receivable amounted to MUSD - (MUSD 74.5) following repayment of the Etrion loan.
Cash and cash equivalents amounted to MUSD 38.1 (MUSD 48.7). Cash balances are held to meet operational and investment requirements.
Provisions amounted to MUSD 1,005.3 (MUSD 769.7) and are detailed in Note 12.
The provision for site restoration amounted to MUSD 116.2 (MUSD 93.8) and relates to future decommissioning obligation liabilities in the countries of operations. An amount of MUSD 7.1 was recognised during the second quarter of 2011 for the decommissioning liability following the drilling of the Gaupe wells. A further provision for the liability will be added in the second half of the year as the Gaupe development progresses and the subsea facilities are installed.
The provision for deferred taxes amounted to MUSD 860.8 (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 provision for Lundin Petroleum's LTIP scheme amounted to MUSD 20.7 (MUSD 18.8).
Other provisions amounted to MUSD 5.8 (MUSD 5.0) and include a termination indemnity provision in Tunisia.
Long term interest bearing debt amounted to MUSD 157.0 (MUSD 458.8) and relates to the outstanding loan under the Group's MUSD 850 revolving borrowing base facility.
Other current liabilities amounted to MUSD 312.9 (MUSD 185.0) and are detailed in Note 13.
Tax payables amounted to MUSD 129.7 (MUSD 39.7). The amount includes both a tax accrual for the current reporting period and liabilities which relate to the 2010 taxable results which were not due to be settled as at 30 June 2011, but will be paid when they become due in 2011.
Joint venture creditors amounted to MUSD 152.5 (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 3.7 (MUSD 6.9).
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 -48.7 (MSEK -24.3) for the reporting period.
The result includes general and administrative expenses of MSEK 52.9 (MSEK 28.0), financial income of MSEK 2.8 (MSEK 12.0) for supporting certain financial obligations for ShaMaran Petroleum and interest expense of MSEK 11.8 (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 0.3 (MUSD 0.3) from ShaMaran Petroleum for the provision of office and other services and MUSD 0.5 (MUSD 1.5) for supporting certain financial obligations.
The Group received MUSD 0.2 (MUSD 0.2) from AOC being interest on a loan of MUSD - (MUSD 23.8) that was converted into shares in the reporting period.
The Group paid MUSD 0.3 (MUSD 0.1) to other related parties in respect of aviation services received.
Furthermore, Etrion has reimbursed the 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 0.3) 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 157.0 was drawn in cash as at 30 June 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 740 and will continue to reduce until maturity of the facility.
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 103.2. In addition, BNP Paribas has issued additional bank guarantees to cover work commitments in Indonesia amounting to MUSD 4.2.
In July 2011, Lundin Petroleum completed the drilling of well 25/10-11 on the Earb South prospect in PL505. 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 and further work will be required to determine whether the discovery can be commercialised.
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 30 June 2011, Lundin Petroleum held 6,882,638 of its own shares.
In 2008, Lundin Petroleum implemented a 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 will be 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 5 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) 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 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 number of units relating to the 2009, 2010 and 2011 Unit Bonus Plans outstanding as at 30 June 2011 were 219,985, 470,619, and 425,850.
The financial statements of the Group have 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 financial statements of the Parent Company are 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 financial statements are still 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 30 June 2011, there is a current liability in the balance sheet amounting to MUSD 3.7 (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.
| 30 Jun 2011 | 30 Jun 2010 | 31 Dec 2010 | ||||
|---|---|---|---|---|---|---|
| Average | Period end | Average | Period end | Average | Period end | |
| 1 USD equals NOK | 5.5763 | 5.3882 | 6.0286 | 6.4970 | 6.0345 | 5.8564 |
| 1 USD equals Euro | 0.7127 | 0.6919 | 0.7527 | 0.8149 | 0.7537 | 0.7484 |
| 1 USD equals Rouble | 28.6112 | 27.9527 | 30.0521 | 31.1971 | 30.3570 | 30.5493 |
| 1 USD equals SEK | 6.3699 | 6.3474 | 7.3733 | 7.7629 | 7.1954 | 6.7097 |
| 1 Jan 2011- 30 Jun 2011 |
1 Apr 2011- 30 Jun 2011 |
1 Jan 2010- 30 Jun 2010 |
1 Apr 2010- 30 Jun 2010 |
1 Jan 2010- 31 Dec 2010 |
||
|---|---|---|---|---|---|---|
| Expressed in TUSD | Note | 6 months | 3 months | 6 months | 3 months | 12 months |
| Continuing operations Operating income |
||||||
| Net sales of oil and gas | 1 | 614,244 | 324,672 | 354,375 | 188,826 | 785,162 |
| Other operating income | 4,724 | 2,538 | 1,804 | 860 | 13,437 | |
| 618,968 | 327,210 | 356,179 | 189,686 | 798,599 | ||
| Cost of sales | ||||||
| Production costs | 2 | -97,922 | -58,461 | -85,470 | -46,288 | -157,065 |
| Depletion costs | 3 | -78,634 | -38,015 | -65,622 | -35,123 | -145,316 |
| Exploration costs | 4 | -16,186 | -6,176 | -46,173 | -12,670 | -127,534 |
| Gross profit | 426,226 | 224,558 | 158,914 | 95,605 | 368,684 | |
| Gain on sale of assets | - | - | - | - | 66,126 | |
| Other income | 515 | 289 | 428 | 224 | 1,044 | |
| General, administration and | ||||||
| depreciation expenses | -17,658 | -2,855 | -14,177 | -5,503 | -42,004 | |
| Operating profit | 409,083 | 221,992 | 145,165 | 90,326 | 393,850 | |
| Result from financial investments | ||||||
| Financial income | 5 | 35,045 | 17,792 | 3,991 | -2,025 | 20,956 |
| Financial expenses | 6 | -24,216 | -10,162 | -16,120 | -9,419 | -33,463 |
| 10,829 | 7,630 | -12,129 | -11,444 | -12,507 | ||
| Profit before tax | 419,912 | 229,622 | 133,036 | 78,882 | 381,343 | |
| Tax | 7 | -289,568 | -152,713 | -112,226 | -71,663 | -251,865 |
| Net result from continuing | ||||||
| operations | 130,344 | 76,909 | 20,810 | 7,219 | 129,478 | |
| Discontinued operations | ||||||
| Net result from discontinued operations |
8 | - | - | 369,275 | 358,353 | 368,992 |
| Net result | 130,344 | 76,909 | 390,085 | 365,572 | 498,470 | |
| Net result attributable to the | ||||||
| shareholders of the Parent Company: |
||||||
| From continuing operations | 133,148 | 78,019 | 25,918 | 10,041 | 142,883 | |
| From discontinued operations | - | - | 369,275 | 358,353 | 368,992 | |
| 133,148 | 78,019 | 395,193 | 368,394 | 511,875 | ||
| Net result attributable to Non | ||||||
| controlling interest: | ||||||
| From continuing operations | -2,804 | -1,110 | -5,108 | -2,822 | -13,405 | |
| From discontinued operations | - | - | - | - | - | |
| -2,804 | -1,110 | -5,108 | -2,822 | -13,405 | ||
| Net result | 130,344 | 76,909 | 390,085 | 365,572 | 498,470 | |
| Earnings per share – USD 1 | ||||||
| From continuing operations | 0.43 | 0.25 | 0.08 | 0.02 | 0.46 | |
| From discontinued operations | - | - | 1.18 | 1.15 | 1.18 | |
| 0.43 | 0.25 | 1.26 | 1.17 | 1.64 | ||
| Diluted earnings per share – USD 1 From continuing operations |
0.43 | 0.25 | 0.08 | 0.02 | 0.46 | |
| From discontinued operations | - | - | 1.18 | 1.15 | 1.18 | |
| 0.43 | 0.25 | 1.26 | 1.17 | 1.64 |
1 Based on net result attributable to shareholders of the Parent Company.
| Expressed in TUSD | 1 Jan 2011- 30 Jun 2011 6 months |
1 Apr 2011- 30 Jun 2011 3 months |
1 Jan 2010- 30 Jun 2010 6 months |
1 Apr 2010- 30 Jun 2010 3 months |
1 Jan 2010- 31 Dec 2010 12 months |
|---|---|---|---|---|---|
| Net result | 130,344 | 76,909 | 390,085 | 365,572 | 498,470 |
| Other comprehensive income | |||||
| Exchange differences foreign operations | 74,456 | 19,888 | -103,877 | -70,207 | -43,972 |
| Cash flow hedges | 3,635 | 1,699 | -1,004 | -47 | -378 |
| Available-for-sale financial assets | -31,058 | -10,603 | 6,183 | -2,600 | 53,128 |
| Income tax relating to other | |||||
| comprehensive income | -909 | -425 | -243 | 1,429 | -1,771 |
| Other comprehensive income, net of | |||||
| tax | 46,124 | 10,559 | -98,941 | -71,425 | 7,007 |
| Total comprehensive income | 176,468 | 87,468 | 291,144 | 294,147 | 505,477 |
| Total comprehensive income attributable to: |
|||||
| Shareholders of the Parent Company | 174,655 | 87,818 | 297,946 | 299,458 | 510,165 |
| Non-controlling interest | 1,813 | -350 | -6,802 | -5,311 | -4,688 |
| 176,468 | 87,468 | 291,144 | 294,147 | 505,477 |
| Expressed in TUSD | Note | 30 June 2011 | 31 December 2010 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 9 | 2,346,132 | 1,998,971 |
| Other tangible assets | 16,232 | 15,271 | |
| Financial assets | 10 | 75,452 | 114,878 |
| Deferred tax | 15,681 | 15,066 | |
| Total non-current assets | 2,453,497 | 2,144,186 | |
| Current assets | |||
| Receivables and inventories | 11 | 176,905 | 236,247 |
| Cash and cash equivalents | 38,127 | 48,703 | |
| Total current assets | 215,032 | 284,950 | |
| TOTAL ASSETS | 2,668,529 | 2,429,136 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Shareholders´ equity | 1,095,071 | 920,416 | |
| Non-controlling interest | 78,966 | 77,365 | |
| Total equity | 1,174,037 | 997,781 | |
| Non-current liabilities | |||
| Provisions | 12 | 1,005,253 | 769,687 |
| Bank loans | 157,000 | 458,835 | |
| Other non-current liabilities | 19,355 | 17,836 | |
| Total non-current liabilities | 1,181,608 | 1,246,358 | |
| Current liabilities | |||
| Other current liabilities | 13 | 312,884 | 184,997 |
| Total current liabilities | 312,884 | 184,997 | |
| TOTAL EQUITY AND LIABILITIES | 2,668,529 | 2,429,136 | |
| Pledged assets Contingent liabilities |
735,322 - |
459,220 - |
| Expressed in TUSD | 1 Jan 2011- 30 Jun 2011 6 months |
1 Apr 2011- 30 Jun 2011 3 months |
1 Jan 2010- 30 Jun 2010 6 months |
1 Apr 2010- 30 Jun 2010 3 months |
1 Jan 2010- 31 Dec 2010 12 months |
|---|---|---|---|---|---|
| Cash flow from operations | |||||
| Net result | 130,344 | 76,909 | 390,085 | 365,572 | 498,470 |
| Gain on sale of assets | - | - | -358,353 | -358,353 | -424,196 |
| Adjustments for non-cash related items | 384,345 | 190,278 | 255,030 | 126,612 | 575,955 |
| Interest received | 1,090 | 460 | 294 | 266 | 589 |
| Interest paid | -4,386 | -2,901 | -467 | 851 | -2,937 |
| Income taxes paid | -44,668 | -26,693 | -10,383 | -3,913 | -25,029 |
| Changes in working capital | 93,120 | 120,005 | -55,837 | -29,090 | -65,734 |
| Total cash flow from operations | 559,845 | 358,058 | 220,369 | 101,945 | 557,118 |
| Cash flow used for investments | |||||
| Investment in subsidiary assets | - | - | -8,633 | -8,633 | -22,553 |
| Investment in associated company | - | - | 225 | 225 | 235 |
| Proceeds from sale of other shares and participations | 53,938 | 25,353 | 478 | 314 | 446 |
| Change in other financial fixed assets | -10,984 | -10,984 | 247 | 327 | 39 |
| Other payments | -911 | -354 | -1,278 | -1,163 | -3,085 |
| Divestment | - | - | -25,003 | - | -65,808 |
| Investment in intangible assets | - | - | -184 | -184 | -200 |
| Investment in oil and gas properties | -302,748 | -194,428 | -165,721 | -53,242 | -348,819 |
| Investment in solar power properties | - | - | -9,310 | -6,477 | -21,210 |
| Investment in office equipment and other assets | -2,071 | -764 | -2,459 | -1,708 | -4,853 |
| Total cash flow used for investments | -262,776 | -181,177 | -211,638 | -70,541 | -465,808 |
| Cash flow used for/from financing | |||||
| Changes in long-term receivables | - | - | - | - | -75,324 |
| Changes in long-term liabilities | -304,713 | -164,892 | 11,018 | -15,993 | -49,609 |
| Paid financing fees | - | - | -51 | -3 | -51 |
| Purchase of own shares | - | - | -7,889 | -7,889 | -10,712 |
| Proceeds from share issuance subsidiary company | - | - | - | - | 15,191 |
| Dividend paid to non-controlling interests | -212 | -212 | - | - | - |
| Total cash flow used for/from financing | -304,925 | -165,104 | 3,078 | -23,885 | -120,505 |
| Change in cash and cash equivalents Cash and cash equivalents at the beginning of the |
-7,856 | 11,777 | 11,809 | 7,519 | -29,195 |
| period Currency exchange difference in cash and cash |
48,703 | 26,564 | 77,338 | 85,326 | 77,338 |
| equivalents | -2,720 | -214 | 727 | -2,971 | 560 |
| Cash and cash equivalents at the end of the period |
38,127 | 38,127 | 89,874 | 89,874 | 48,703 |
| Cash flow from operations | |||||
| From continuing operations | 559,845 | 358,058 | 543,362 | 460,298 | 880,394 |
| Used for discontinued operations | - | - | -322,993 | -358,353 | -323,276 |
| 559,845 | 358,058 | 220,369 | 101,945 | 557,118 | |
| Cash flow used for investments | |||||
| Used for continuing operations | -262,776 | -181,177 | -169,252 | -70,541 | -423,422 |
| Used for discontinued operations | - | - | -42,386 | - | -42,386 |
| -262,776 | -181,177 | -211,638 | -70,541 | -465,808 | |
| Cash flow used for/from financing Used for/from continuing operations Used for/from discontinued operations |
-304,925 - |
-165,104 - |
3,078 - |
-23,885 - |
-120,505 - |
| -304,925 | -165,104 | 3,078 | -23,885 | -120,505 |
| Additional | ||||||
|---|---|---|---|---|---|---|
| paid-in | Non | |||||
| Expressed in TUSD | Share | capital/Other | Retained | controlling | ||
| capital | reserves | earnings | Net result | interest | Total equity | |
| Balance at 1 January 2010 | 463 | 840,378 | 712,085 | -411,268 | 95,555 | 1,237,213 |
| Transfer of prior year net result | - | - | -411,268 | 411,268 | - | - |
| Total comprehensive income | - | -96,905 | -342 | 395,193 | -6,802 | 291,144 |
| Transactions with owners | ||||||
| Acquired on consolidation | - | - | - | - | 333 | 333 |
| Distributions | - | -358,049 | -298,288 | - | - | -656,337 |
| Purchase of own shares | - | -7,889 | - | - | - | -7,889 |
| Transfer of share based payments | - | 3,785 | -3,785 | - | - | - |
| Share based payments | - | - | 1,598 | - | - | 1,598 |
| Total transactions with owners | - | -362,153 | -300,475 | - | 333 | -662,295 |
| Balance at 30 June 2010 | 463 | 381,320 | - | 395,193 | 89,086 | 866,062 |
| Total comprehensive income | - | 94,946 | 591 | 116,682 | 2,114 | 214,333 |
| Transactions with owners | ||||||
| Acquired on consolidation | - | - | - | - | -239 | -239 |
| Divestments | - | 4,660 | -10,520 | - | -13,596 | -19,456 |
| Distributions | - | -61,267 | - | - | - | -61,267 |
| Purchase of own shares | - | -2,823 | - | - | - | -2,823 |
| Transfer of share based payments | - | 594 | -594 | - | - | - |
| Share based payments | - | - | 1,171 | - | - | 1,171 |
| Total transactions with owners | - | -58,836 | -9,943 | - | -13,835 | -82,614 |
| Balance at 31 December 2010 | 463 | 417,430 | -9,352 | 511,875 | 77,365 | 997,781 |
| Transfer of prior year net result | - | - | 511,875 | -511,875 | - | - |
| Total comprehensive income | - | 41,507 | - | 133,148 | 1,813 | 176,468 |
| Transactions with owners | ||||||
| Distributions | - | - | - | - | -212 | -212 |
| Total transactions with owners | - | - | - | - | -212 | -212 |
| Balance at 30 June 2011 | 463 | 458,937 | 502,523 | 133,148 | 78,966 | 1,174,037 |
| Note 1. Segment information, | 1 Jan 2011- 30 Jun 2011 |
1 Apr 2011- 30 Jun 2011 |
1 Jan 2010- 30 Jun 2010 |
1 Apr 2010- 30 Jun 2010 |
1 Jan 2010- 31 Dec 2010 |
|---|---|---|---|---|---|
| TUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Operating income | |||||
| Net sales of: | |||||
| Crude oil | |||||
| - Norway | 431,989 | 218,943 | 216,810 | 128,599 | 490,390 |
| - France | 63,174 | 32,460 | 45,306 | 22,552 | 92,681 |
| - Netherlands | 115 | 64 | 37 | - | 128 |
| - Indonesia | - | - | 15,109 | 6,388 | 34,994 |
| - Russia | 40,104 | 21,024 | 33,548 | 16,761 | 66,624 |
| - Tunisia | 24,795 | 24,795 | 15,308 | - | 29,517 |
| 560,177 | 297,286 | 326,118 | 174,300 | 714,334 | |
| Condensate | |||||
| - Netherlands | 608 | 358 | 482 | 338 | 1,088 |
| - Indonesia | - | - | 45 | 23 | 200 |
| 608 | 358 | 527 | 361 | 1,288 | |
| Gas | |||||
| - Norway | 27,450 | 13,040 | 12,276 | 7,180 | 32,687 |
| - Netherlands | 20,809 | 10,900 | 14,892 | 6,470 | 32,357 |
| - Indonesia | 5,200 | 3,088 | 562 | 515 | 4,496 |
| 53,459 | 27,028 | 27,730 | 14,165 | 69,540 | |
| Net sales from continuing operations | 614,244 | 324,672 | 354,375 | 188,826 | 785,162 |
| Net sales from discontinued operations | - | - | 62,567 | - | 62,567 |
| Total net sales | 614,244 | 324,672 | 416,942 | 188,826 | 847,729 |
| Operating profit contribution | |||||
| - Norway | 353,996 | 181,067 | 136,330 | 95,186 | 303,892 |
| - France | 43,170 | 21,626 | 26,121 | 12,735 | 52,309 |
| - Netherlands | 9,593 | 5,192 | 2,873 | 656 | 7,273 |
| - Indonesia | -60 | -35 | 3,228 | 1,284 | 18,203 |
| - Russia | 4,812 | 1,965 | 1,635 | 729 | 4,734 |
| - Tunisia | 13,743 | 13,875 | 3,157 | -829 | 11,500 |
| - Congo (Brazzaville) | - | - | - | - | -19 |
| - Vietnam | -440 | -314 | -15,035 | -15,035 | -31,906 |
| - Other | -15,731 | -1,384 | -13,144 | -4,400 | 27,864 |
| Operating profit contribution from | |||||
| continuing operations | 409,083 | 221,992 | 145,165 | 90,326 | 393,850 |
| Operating profit contribution from | |||||
| discontinued operations – United Kingdom | - | - | 20,774 | - | 20,774 |
| Total operating profit contribution | 409,083 | 221,992 | 165,939 | 90,326 | 414,624 |
| Note 2. Production costs, | 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- |
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| 6 months | 3 months | 6 months | 3 months | 12 months |
| Note 2. Production costs, | 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- |
|---|---|---|---|---|---|
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| TUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Cost of operations | 48,579 | 25,387 | 44,162 | 23,334 | 97,179 |
| Tariff and transportation expenses | 12,415 | 6,449 | 6,916 | 4,078 | 17,438 |
| Direct production taxes | 25,428 | 13,805 | 21,328 | 10,712 | 41,624 |
| Change in inventory/lifting position | 10,366 | 12,247 | 11,865 | 7,651 | -3,409 |
| Other | 1,134 | 573 | 1,199 | 513 | 4,233 |
| Production costs from continuing | |||||
| operations | 97,922 | 58,461 | 85,470 | 46,288 | 157,065 |
| Production costs from discontinued | |||||
| operations – United Kingdom | - | - | 32,030 | - | 32,030 |
| Total production costs | 97,922 | 58,461 | 117,500 | 46,288 | 189,095 |
| Note 3. Depletion costs, | 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- |
|---|---|---|---|---|---|
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| TUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Norway | 61,628 | 29,494 | 45,356 | 25,069 | 101,643 |
| France | 5,992 | 3,010 | 6,795 | 3,448 | 14,623 |
| Netherlands | 6,187 | 2,938 | 8,404 | 3,953 | 16,490 |
| Indonesia | 2,422 | 1,387 | 1,858 | 1,060 | 4,218 |
| Russia | 2,405 | 1,186 | 3,180 | 1,564 | 6,002 |
| Tunisia | - | - | - | - | 6 |
| Depletion of oil and gas properties | 78,634 | 38,015 | 65,593 | 35,094 | 142,982 |
| Italy | - | - | 29 | 29 | 2,334 |
| Depletion of solar properties | - | - | 29 | 29 | 2,334 |
| Depletion from continuing operations | 78,634 | 38,015 | 65,622 | 35,123 | 145,316 |
| Depletion from discontinued operations – | |||||
| United Kingdom | - | - | 11,362 | - | 11,362 |
| Total depletion costs | 78,634 | 38,015 | 76,984 | 35,123 | 156,678 |
| Note 4. Exploration costs, | 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- |
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| TUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Norway | 14,550 | 5,341 | 30,582 | -2,469 | 94,526 |
| Vietnam | 427 | 314 | 15,035 | 15,035 | 31,906 |
| Other | 1,209 | 521 | 556 | 104 | 1,102 |
| Exploration costs from continuing | |||||
| operations | 16,186 | 6,176 | 46,173 | 12,670 | 127,534 |
| Exploration costs from discontinued | |||||
| operations - United Kingdom | - | - | 61 | - | 61 |
| Total exploration costs | 16,186 | 6,176 | 46,234 | 12,670 | 127,595 |
| Note 5. Financial income, | 1 Jan 2011- 30 Jun 2011 |
1 Apr 2011- 30 Jun 2011 |
1 Jan 2010- 30 Jun 2010 |
1 Apr 2010- 30 Jun 2010 |
1 Jan 2010- 31 Dec 2010 |
|---|---|---|---|---|---|
| TUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Interest income | 2,587 | 1,245 | 1,296 | 648 | 3,409 |
| Foreign exchange gain, net | - | - | - | -4,854 | 13,360 |
| Insurance proceeds | 1,726 | 1,726 | 377 | 15 | 377 |
| Guarantee fees | 489 | 239 | 89 | 44 | 2,348 |
| Gain on sale of loan conversion shares | 29,974 | 14,341 | - | - | - |
| Other financial income | 269 | 241 | 2,229 | 2,122 | 1,462 |
| Financial income from continuing | |||||
| operations | 35,045 | 17,792 | 3,991 | -2,025 | 20,956 |
| Financial income from discontinued | |||||
| operations – United Kingdom | - | - | 360 | - | 360 |
| Total financial income | 35,045 | 17,792 | 4,351 | -2,025 | 21,316 |
| Note 6. Financial expenses, | 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- |
|---|---|---|---|---|---|
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| TUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Loan interest expenses | 2,840 | 1,249 | 2,573 | 1,329 | 10,047 |
| Foreign exchange loss, net | 13,365 | 4,847 | 626 | 626 | - |
| Result on interest rate hedge settlement | 3,434 | 1,739 | 3,516 | 1,765 | 6,990 |
| Change in market value of interest rate | |||||
| hedge | - | - | 1,803 | 861 | 3,872 |
| Unwinding of site restoration discount | 2,259 | 1,157 | 1,996 | 970 | 3,989 |
| Amortisation of deferred financing fees | 1,202 | 602 | 772 | 375 | 2,360 |
| Loss on sale of shares | - | - | 3,884 | 2,912 | 3,879 |
| Other financial expenses | 1,116 | 568 | 950 | 581 | 2,326 |
| Financial expenses from continuing | |||||
| operations | 24,216 | 10,162 | 16,120 | 9,419 | 33,463 |
| Financial expenses from discontinued | |||||
| operations – United Kingdom | - | - | 1,224 | - | 1,224 |
| Total financial expenses | 24,216 | 10,162 | 17,344 | 9,419 | 34,687 |
| 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- 31 Dec 2010 |
|---|---|---|---|---|
| 6 months | 3 months | 6 months | 3 months | 12 months |
| 130,705 | 72,040 | 14,371 | 7,551 | 68,152 |
| 158,863 | 80,673 | 97,855 | 64,112 | 183,713 |
| 289,568 | 152,713 | 112,226 | 71,663 | 251,865 |
| - | - | 7,315 | - | 7,315 |
| - | - | 1,673 | - | 1,673 |
| - | - | 8,988 | - | 8,988 |
| 289,568 | 152,713 | 121,214 | 71,663 | 260,853 |
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 |
| Note 8. Discontinued operations, | 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- |
|---|---|---|---|---|---|
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| TUSD | 6 months | 3 months | 6 months | 3 months | 12 months |
| Net sales | - | - | 62,567 | - | 62,567 |
| Other operating income | - | - | 1,983 | - | 1,983 |
| Operating income | - | - | 64,550 | - | 64,550 |
| Production costs | - | - | -32,030 | - | -32,030 |
| Depletion costs | - | - | -11,362 | - | -11,362 |
| Exploration costs | - | - | -61 | - | -61 |
| General, administration and depreciation | |||||
| expenses | - | - | -323 | - | -323 |
| Operating profit | - | - | 20,774 | - | 20,774 |
| Financial income | - | - | 360 | - | 360 |
| Financial expenses | - | - | -1,224 | - | -1,224 |
| Profit before tax | - | - | 19,910 | - | 19,910 |
| Tax | - | - | -8,988 | - | -8,988 |
| Net result from discontinued | |||||
| operations | - | - | 10,922 | - | 10,922 |
| Gain on sale of assets | - | - | 358,353 | 358,353 | 358,070 |
| Net result from discontinued | |||||
| operations | - | - | 369,275 | 358,353 | 368,992 |
| Note 9. Oil and gas properties, TUSD |
30 Jun 2011 | 31 Dec 2010 |
|---|---|---|
| Norway | 1,294,327 | 1,018,533 |
| France | 175,461 | 159,168 |
| Netherlands | 48,924 | 49,721 |
| Indonesia | 85,670 | 78,011 |
| Russia | 633,930 | 614,731 |
| Malaysia | 68,186 | 42,058 |
| Congo (Brazzaville) | 34,959 | 32,256 |
| Ireland | 4,467 | 4,099 |
| Others | 208 | 394 |
| 2,346,132 | 1,998,971 |
| Note 10. Financial assets, TUSD |
30 Jun 2011 | 31 Dec 2010 |
|---|---|---|
| Other shares and participations | 39,807 | 68,613 |
| Capitalised financing fees | 3,833 | 4,650 |
| Long-term receivable | - | 23,791 |
| Other financial assets | 31,812 | 17,824 |
| 75,452 | 114,878 |
| Note 11. Receivables and inventories, TUSD |
30 Jun 2011 | 31 Dec 2010 |
|---|---|---|
| Inventories | 19,467 | 20,039 |
| Trade receivables | 121,750 | 94,190 |
| Underlift | 5,986 | 13,452 |
| Short-term loan receivable | - | 74,527 |
| Joint venture debtors | 18,506 | 21,389 |
| Prepaid expenses and accrued income | 7,306 | 6,351 |
| Other assets | 3,890 | 6,299 |
| 176,905 | 236,247 |
| Note 12. Provisions, TUSD |
30 Jun 2011 | 31 Dec 2010 |
|---|---|---|
| Site restoration | 116,212 | 93,766 |
| Deferred taxes | 860,798 | 650,695 |
| Long-term incentive plan | 20,708 | 18,821 |
| Pension | 1,725 | 1,421 |
| Other provisions | 5,810 | 4,984 |
| 1,005,253 | 769,687 |
| Note 13. Other current liabilities, TUSD |
30 Jun 2011 | 31 Dec 2010 |
|---|---|---|
| Trade payables | 10,036 | 16,031 |
| Overlift | 283 | 1,761 |
| Tax payables | 129,741 | 39,679 |
| Accrued expenses | 10,609 | 7,667 |
| Acquisition liabilities | - | 5,680 |
| Joint venture creditors | 152,489 | 100,931 |
| Short-term loans | - | 450 |
| Derivative instruments | 3,683 | 6,866 |
| Other liabilities | 6,043 | 5,932 |
| 312,884 | 184,997 |
| 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- | |
|---|---|---|---|---|---|
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| Expressed in TSEK | 6 months | 3 months | 6 months | 3 months | 12 months |
| Operating income | |||||
| Other operating income | 13,133 | 9,311 | 11,139 | 2,961 | 25,822 |
| Gross profit | 13,133 | 9,311 | 11,139 | 2,961 | 25,822 |
| General and administration expenses | -52,858 | -7,975 | -28,019 | -9,594 | -72,222 |
| Operating loss | -39,725 | 1,336 | -16,880 | -6,633 | -46,400 |
| Result from financial investments | |||||
| Financial income | 2,885 | 1,259 | 13,418 | 12,927 | 4,012,086 |
| Financial expenses | -11,831 | -6,122 | -28,117 | -28,087 | -36,928 |
| -8,946 | -4,863 | -14,699 | -15,160 | 3,975,158 | |
| Profit before tax | -48,671 | -3,527 | -31,579 | -21,793 | 3,928,758 |
| Corporation tax | - | - | 7,328 | 7,878 | 7,328 |
| Net result | -48,671 | -3,527 | -24,251 | -13,915 | 3,936,086 |
| Expressed in TSEK | 1 Jan 2011- 30 Jun 2011 6 months |
1 Apr 2011- 30 Jun 2011 3 months |
1 Jan 2010- 30 Jun 2010 6 months |
1 Apr 2010- 30 Jun 2010 3 months |
1 Jan 2010- 31 Dec 2010 12 months |
|---|---|---|---|---|---|
| Net result | -48,671 | -3,527 | -24,251 | -13,915 | 3,936,086 |
| Other comprehensive income | - | - | - | - | - |
| Total comprehensive income | -48,671 | -3,527 | -24,251 | -13,915 | 3,936,086 |
| Total comprehensive income attributable to: |
|||||
| Shareholders of the Parent Company | -48,671 | -3,527 | -24,251 | -13,915 | 3,936,086 |
| -48,671 | -3,527 | -24,251 | -13,915 | 3,936,086 |
| Expressed in TSEK | 30 June 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 | 6,454 | 7,175 |
| Cash and cash equivalents | 3,302 | 6,735 |
| Total current assets | 9,756 | 13,910 |
| TOTAL ASSETS | 7,881,703 | 7,885,857 |
| SHAREHOLDERS´EQUITY AND LIABILITIES Shareholders´ equity including net result for the |
||
| period | 7,303,705 | 7,352,376 |
| Non-current liabilities | ||
| Provisions | 36,403 | 36,403 |
| Payables to Group companies | 539,574 | 482,281 |
| Total non-current liabilities | 575,977 | 518,684 |
| Current liabilities | ||
| Current liabilities | 2,021 | 14,797 |
| Total current liabilities | 2,021 | 14,797 |
| TOTAL EQUITY AND LIABILITIES | 7,881,703 | 7,885,857 |
| Pledged assets | 4,667,381 | 3,081,228 |
| Contingent liabilities | - | - |
| 1 Jan 2011- | 1 Apr 2011- | 1 Jan 2010- | 1 Apr 2010- | 1 Jan 2010- | |
|---|---|---|---|---|---|
| 30 Jun 2011 | 30 Jun 2011 | 30 Jun 2010 | 30 Jun 2010 | 31 Dec 2010 | |
| Expressed in TSEK | 6 months | 3 months | 6 months | 3 months | 12 months |
| Cash flow used for/from operations | |||||
| Net result | -48,671 | -3,527 | -24,251 | -13,915 | 3,936,086 |
| Non-cash items | 1,252 | 830 | 40,492 | 39,985 | -3,918,807 |
| Changes in working capital | -13,335 | -10,426 | 11,309 | 11,231 | -798 |
| Total cash flow used for/from | |||||
| operations | -60,754 | -13,123 | 27,550 | 37,301 | 16,481 |
| Cash flow from investments | |||||
| Change in other financial fixed assets | - | - | -6,640 | -6,640 | 1,590 |
| Total cash flow from investments | - | - | -6,640 | -6,640 | 1,590 |
| Cash flow from/used for financing | |||||
| Change in long term liabilities | 57,293 | 15,691 | 45,188 | 35,297 | 71,870 |
| Purchase of own shares | - | - | -61,242 | -61,242 | -83,157 |
| Total cash flow from/used for | |||||
| financing | 57,293 | 15,691 | -16,054 | -25,945 | -11,287 |
| Change in cash and cash equivalents | -3,461 | 2,568 | 4,856 | 4,716 | 6,784 |
| Cash and cash equivalents at the | |||||
| beginning of the period | 6,735 | 579 | 532 | 681 | 532 |
| Currency exchange difference in cash and | |||||
| cash equivalents | 28 | 155 | 86 | 77 | -581 |
| Cash and cash equivalents at the end | |||||
| of the period | 3,302 | 3,302 | 5,474 | 5,474 | 6,735 |
| Restricted equity | Unrestricted equity | ||||
|---|---|---|---|---|---|
| Statutory | Other | Retained | |||
| capital | reserve | reserves | earnings | Net result | Total equity |
| 3,179 | 861,306 | 5,120,750 | 1,887,788 | -32,271 | 7,840,752 |
| - | |||||
| - | - | - | - | -24,251 | -24,251 |
| - | - | -2,123,457 | -1,826,272 | - | -3,949,729 |
| - | - | -61,242 | - | - | -61,242 |
| - | - | 29,380 | -29,380 | - | - |
| - | - | - | 135 | - | 135 |
| - | - | -2,155,319 | -1,855,517 | - | -4,010,836 |
| 3,179 | 861,306 | 2,965,431 | - | -24,251 | 3,805,665 |
| 3,960,337 | |||||
| - | - | -391,711 | - | - | -391,711 |
| - | - | -21,915 | - | - | -21,915 |
| - | - | -413,626 | - | - | -413,626 |
| 3,179 | 861,306 | 2,551,805 | - | 3,936,086 | 7,352,376 |
| - | - | - | 3,936,086 | -3,936,086 | - |
| - | - | - | - | -48,671 | -48,671 |
| 7,303,705 | |||||
| Share - - 3,179 |
- - 861,306 |
- - 2,551,805 |
-32,271 - 3,936,086 |
32,271 3,960,337 -48,671 |
Key financial data is based on continuing operations.
| 1 Jan 2011- 30 Jun 2011 |
1 Apr 2011- 30 Jun 2011 |
1 Jan 2010- 30 Jun 2010 |
1 Apr 2010- 30 Jun 2010 |
1 Jan 2010- 31 Dec 2010 |
|
|---|---|---|---|---|---|
| Financial data (TUSD) | 6 months | 3 months | 6 months | 3 months | 12 months |
| Operating income | 618,968 | 327,210 | 356,179 | 189,686 | 798,599 |
| EBITDA | 505,327 | 266,923 | 258,388 | 138,802 | 603,450 |
| Net result | 130,344 | 76,909 | 20,810 | 7,219 | 129,478 |
| Operating cashflow | 390,341 | 196,709 | 256,338 | 135,847 | 573,380 |
| Data per share (USD) | |||||
| Shareholders' equity per share | 3.52 | 3.52 | 2.48 | 2.48 | 2.96 |
| Operating cash flow per share | 1.26 | 0.64 | 0.82 | 0.44 | 1.84 |
| Cash flow from operations per share | 1.80 | 1.15 | 0.70 | 0.32 | 1.79 |
| Earnings per share | 0.43 | 0.25 | 0.08 | 0.02 | 0.46 |
| Earnings per share fully diluted | 0.43 | 0.25 | 0.08 | 0.02 | 0.46 |
| EBITDA per share fully diluted | 1.62 | 0.85 | 0.83 | 0.45 | 1.93 |
| Dividend per share | - | - | 2.10 | 2.10 | 2.30 |
| Quoted price at the end of the financial | |||||
| period | 13.55 | 13.55 | 4.46 | 4.46 | 12.47 |
| Number of shares issued at period end | 317,910,580 | 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 | 311,665,278 | 311,665,278 | 311,027,942 |
| Weighted average number of shares for | |||||
| the period | 311,027,942 | 311,027,942 | 313,183,758 | 312,949,835 | 312,096,990 |
| Weighted average number of shares for | |||||
| the period (fully diluted) | 311,027,942 | 311,027,942 | 313,183,758 | 312,949,835 | 312,096,990 |
| Key ratios (%) | |||||
| Return on equity | 12 | 7 | 2 | 1 | 12 |
| Return on capital employed | 31 | 17 | 9 | 5 | 24 |
| Return on capital employed | 31 | 17 | 9 | 5 | 24 |
|---|---|---|---|---|---|
| Net debt/equity ratio | 13 | 13 | 64 | 64 | 36 |
| Equity ratio | 44 | 44 | 37 | 37 | 41 |
| Share of risk capital | 76 | 76 | 60 | 60 | 67 |
| Interest coverage ratio | 7,006 | 7,946 | 1,794 | 2,233 | 1,860 |
| Operating cash flow/interest ratio | 6,221 | 6,582 | 3,248 | 3,434 | 2,742 |
| Yield | - | - | 47 | 47 | 18 |
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.
The Board of Directors and the President & CEO certify that the half-yearly financial report gives a fair view of the performance of the business, position and profit or loss of the Company and the Group, and describes the principal risks and uncertainties that the Company and the companies in the Group face.
Stockholm, 3 August 2011
Ian H. Lundin Chairman
C. Ashley Heppenstall President & CEO
William A. Rand
Asbjørn Larsen Lukas H. Lundin Magnus Unger
Dambisa F. Moyo Kristin Færøvik
We have reviewed this report for the period 1 January 2011 to 30 June 2011 for Lundin Petroleum (publ). The board of directors and the President & CEO are responsible for the preparation and presentation of this interim report in accordance with IAS 34 and the Swedish Annual Accounts Act. Our responsibility is to express a conclusion on this interim report based on our review.
We conducted our review in accordance with the Swedish Standard on Review Engagements SÖG 2410, Review of Interim Report Performed by the Independent Auditor of the Entity. A review consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing, ISA, and other generally accepted auditing standards in Sweden. The procedures performed in a review do not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
Based on our review, nothing has come to our attention that causes us to believe that the interim report is not prepared, in all material respects, in accordance with IAS 34 and the Swedish Annual Accounts Act, regarding the Group, and with the Swedish Annual Accounts Act, regarding the Parent Company.
Stockholm, 3 August 2011
PricewaterhouseCoopers AB
Bo Hjalmarsson Bo Karlsson Authorised Public Accountant Authorised Public Accountant Lead Auditor
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. The information was published at 7.30 CET on 3 August 2011.
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.
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.
Building tools?
Free accounts include 100 API calls/year for testing.
Have a question? We'll get back to you promptly.