Quarterly Report • May 9, 2012
Quarterly Report
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Stockholm 9 May 2012
| 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- | |
|---|---|---|---|
| 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 | |
| 3 months | 3 months | 12 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 |
34.7 362.2 47.2 48.8 0.16 0.16 309.2 166.6 |
33.5 291.8 53.4 55.1 0.18 0.18 238.4 193.6 |
33.3 1,269.5 155.2 160.1 0.51 0.51 1,012.1 676.2 |
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).
I am pleased to report that, after the extremely successful events of 2011, 2012 has begun with continued positive developments for our Company.
The major news during the first quarter of 2012 has been progress with the Luno field, now named Edvard Grieg after the famous Norwegian composer. The Edvard Grieg project, estimated to cost approximately USD 4 billion is now moving forward following approval by the Ministry of Petroleum and Energy and major contract awards have already been announced. The development will take Lundin Petroleum into the league of standalone project operator on the Norwegian Continental Shelf which will certainly increase our standing in Norway with Government, service providers and other companies, and will lead to new opportunities for our Company.
Nevertheless it is important to emphasise that Lundin Petroleum remains an exploration driven Company. We believe that the value creation in the upstream oil and gas business is driven from the ability to find new hydrocarbon resources. We will continue to actively invest in our organic exploration driven growth model and are certainly not now a "development and production" focused company as one institutional investor commented to me recently. We will spend approximately USD 500 million this year on exploration with a major focus on Norway and South East Asia. We will seek to maintain and possibly increase this expenditure as our business grows.
Our financial performance in the first quarter of 2012 was again very strong following the excellent results in 2011. Production which was up four percent compared to 2011 was again the major catalyst for the strong performance resulting in record quarterly EBITDA of USD 309.2 million, operating cash flow of USD 166.6 million and net profit of USD 47.2 million for the period.
We expect that our strong operating cash flow will continue as production increases over the forthcoming years and will be our primary source of funding to develop our pipeline of new projects. Our balance sheet remains strong with net debt of less than USD 100 million. I am very pleased to report that we have seen strong support from the banking market in respect of our proposed new borrowing facility and I expect the new facility which is likely to be in excess of USD 2 billion to be completed during the second quarter of 2012.
First quarter production of 34,700 boepd was at the upper end of our forecast and driven by the continued strong performance from the Alvheim and Volund fields, offshore Norway. The Gaupe field, offshore Norway commenced production at the end of the first quarter and will have a positive impact on production going forward. Production for the second quarter will be negatively impacted by planned maintenance work on the Alvheim FPSO, storm damage stopping production on the Oudna field, offshore Tunisia and the Singa field onshore Indonesia where well maintenance work is ongoing.
Our production forecast for 2012 remains at between 32,000 boepd and 38,000 boepd.
We maintain our target to double production to over 70,000 boepd by the end of 2015 following commencement of production from the Edvard Grieg field.
We have made excellent progress with regard to the Edvard Grieg development project receiving development plan approval from the Norwegian Ministry of Petroleum and Energy in April 2012. Formal confirmation of approval from the Norwegian Parliament is expected this summer. This field is the first standalone development project operated by Lundin Petroleum on the Norwegian Continental Shelf and is a major milestone for our Company. We have built an experienced project team with strong record of completing similar projects and are confident we have the capability to deliver this major project on schedule and on budget. The field will also be the first development of fields recently discovered on Utsira High including the "supergiant" Johan Sverdrup field.
The Edvard Grieg field is located in PL338 and is operated by Lundin Petroleum with a 50 percent working interest. The field was discovered by us in 2007 and following a successful multi well appraisal programme, a plan of development for the field was submitted to the Norwegian Ministry of Petroleum and Energy earlier this year. An agreement with respect to a coordinated development solution for Edvard Grieg and the nearby Draupne field was completed in March 2012. The Edvard Grieg field contains reserves of 186 MMboe and will produce at a gross production rate of close to 100,000 boepd. We are already well advanced with our contracting strategy having awarded contracts to Kværner for the engineering, procurement and construction of both the jacket and topsides for the Edvard Grieg platform as well as to Rowan Companies for the supply of a jack-up drilling unit and to Saipem for marine installation.
We are also progressing well with the Brynhild development project where we recently agreed to increase our working interest to 100 percent. The Brynhild field will be developed as a subsea tieback to Shell's Pierce field facilities located in the United Kingdom and first oil is still expected in late 2013.
In Malaysia I am confident that following last year's successful appraisal drilling on the Bertam field in PM307 we have a commercial development project. Our team in Kuala Lumpur are currently working on the project with a view to firm up plans for the development.
During the first quarter, Lundin Petroleum as operator of PL501 signed a Pre-Unit Agreement with Statoil as operator of PL265 in respect of the development of the Johan Sverdrup field. The field is estimated to contain between 1.7 billion and 3.3 billion barrels of recoverable oil making it one of the largest ever discoveries on the Norwegian Continental Shelf and certainly the largest since the mid-1980s. It has been agreed that Statoil will assume the role of "working operator" of the Johan Sverdrup field to coordinate the work up to the submission of the field development plan. We share with Statoil the common goal of maximising the recoverable resources from the Johan Sverdrup field and finalising a development plan to optimise the value of this huge discovery for the benefit of all stakeholders. Lundin Petroleum will second personnel into the Johan Sverdrup project team.
Lundin Petroleum, as operator of PL501, will retain responsibility for the appraisal programme of Johan Sverdrup contained within the licence. We have already completed two appraisal wells this year and will complete a further two wells before year end. Statoil as operator of PL265 will drill a further three appraisal wells this year. The results of the appraisal programme will be used to update recoverable resources for the field and to assist the development team with its project planning. Our first appraisal well in the southern part of the field was disappointing with the top reservoir coming in low to prognosis and below the oil water contact. Our second appraisal well was positive encountering a 54 metre gross oil column with good reservoir characteristics. A revised resource estimate for the field will be announced after the completion of the ongoing appraisal programme.
In parallel unitisation discussions will be conducted between the respective licence teams with the objective of finalising a unitisation agreement prior to the submission of the Johan Sverdrup development plan.
We have over recent years expressed our view that there remains excellent exploration potential on the Norwegian Continental Shelf. The changes to Norwegian Government policy in opening up the area to independent oil companies coupled with changes to the licensing rounds and fiscal incentives has in our opinion acted as a catalyst to increased activity. The Johan Sverdrup discovery as well as Statoil's recent discoveries in the Barents Sea have resulted from those changes and stimulated even higher levels of activity with new entrants to Norway.
We welcome this increased competition and believe it will stimulate investment from the service sector in much needed new capacity such as drilling units. We believe that further discoveries will be made in Norway and that Lundin Petroleum, with interests in over 50 licences, a proven exploration team and a financial commitment to invest in exploration is well positioned for further success.
We have a work programme for 2012 with eight exploration wells. The harsh winter and the successful exploration wells have meant delays to many rig schedules with programmes taking longer to complete than forecast. As a result a number of our exploration wells have been delayed until later in 2012 and early 2013.
We are focusing on three key strategies for our Norway exploration:
In Malaysia, following last year's successful drilling campaign with four discoveries from five wells, we will be drilling an additional five exploration/appraisal wells commencing in the second quarter of 2012.
Despite the continued economic concerns in Europe and slowing economic growth in China, oil prices remain robust. Our industry continues to struggle with supplying ever increasing world oil demand now totalling 90 million barrels per day. The Edvard Grieg field, which is one of the major field developments in Norway over recent years, costing USD 4 billion would supply the world for only two days. It is the magnitude of this supply challenge facing the industry which necessitates oil companies going to more extreme, deeper water and arctic locations to explore for oil. The harsh reality is that there is limited spare production capacity in the system and as a result I expect oil prices to remain strong. We remain susceptible to supply disruptions which would most certainly result in further price increases.
I believe that the oil industry has over recent years made major investments as well as technological advances to ensure the world continues to be adequately supplied with oil and gas. The fact remains that the single most important driver of world economic growth over the last century has been the availability of affordable energy which has markedly improved the lives of most of the world's population, for example increasing life expectancy, reducing disease and improving education. The availability of cheap energy remains critical not only to the developing world but is important to the competiveness of the developed countries.
Following the year in which Lundin Petroleum made the largest oil discovery in the world I am saddened to see how our Company and our major shareholder, the Lundin family, are the focus of media attacks associated with our former operations in Sudan and Ethiopia. Whilst the political issues associated with these two countries, and indeed many poorer developing countries, are complex, the position of Lundin Petroleum in respect of our investment criteria is very clear. Firstly we believe the primary driver of development in these countries is direct investment and natural resources is a key catalyst in that regard. Aid is important but cannot replace direct investment. Secondly our business model is built around our Code of Conduct and corporate policies which outline our strong commitment to corporate social responsibility, health, safety and environment. The allegations made against the Company are not true and have been refuted by us on numerous occasions over recent years. A preliminary investigation is already ongoing by the International Public Prosecutor in Sweden in relation to past activities in Sudan. We have always stated our willingness to fully cooperate in this process which we suggest should be allowed to run to its final conclusion. In theory the calls for a further independent investigation to "once and for all" clear up this issue may seem to make sense but in practice, due to the complexity of the issues involved, it will simply extend the debate and most certainly will not provide the definitive answers people seek to find. We would therefore ask our shareholders to trust our management and Board of Directors and let us focus on growing our business and continuing to create value for our shareholders. Yours Sincerely,
C. Ashley Heppenstall President and CEO
Production for the three month period ended 31 March 2012 (reporting period) amounted to 34.7 Mboe per day (Mboepd) and was comprised as follows:
| Production in Mboepd |
1 Jan 2012- 31 Mar 2012 3 months |
1 Jan 2011- 31 Mar 2011 3 months |
1 Jan 2011- 31 Dec 2011 12 months |
|---|---|---|---|
| Crude oil | |||
| Norway | 23.0 | 21.4 | 21.1 |
| France | 2.9 | 3.1 | 3.1 |
| Russia | 2.8 | 3.2 | 3.1 |
| Tunisia | 0.4 | 0.8 | 0.7 |
| Total crude oil production | 29.1 | 28.5 | 28.0 |
| Gas | |||
| Norway | 2.5 | 2.1 | 2.1 |
| Netherlands | 2.0 | 2.1 | 2.0 |
| Indonesia | 1.1 | 0.8 | 1.2 |
| Total gas production | 5.6 | 5.0 | 5.3 |
| Total production | |||
| Quantity in Mboe | 3,154.1 | 3,013.0 | 12,151.5 |
| Quantity in Mboepd | 34.7 | 33.5 | 33.3 |
| Production in Mboepd |
Lundin Petroleum Working Interest (WI) |
1 Jan 2012- 31 Mar 2012 3 months |
1 Jan 2011- 31 Mar 2011 3 months |
1 Jan 2012- 31 Dec 2012 12 months |
|---|---|---|---|---|
| Alvheim | 15% | 12.3 | 12.7 | 11.2 |
| Volund | 35% | 13.2 | 10.8 | 12.0 |
| 25.5 | 23.5 | 23.2 |
Production from the Alvheim field continues to perform strongly. A third new development well drilled in 2011 commenced production during January 2012. A further Alvheim development well was spudded during the first quarter of 2012. The cost of operations for the Alvheim field during the first quarter remained at below USD 5 per barrel.
Volund field production continued to exceed forecasts. Continued strong reservoir performance has enabled the field to take advantage of additional capacity through the Alvheim FPSO. An additional Volund development well will be drilled in 2012.
The plan of development for the Gaupe field in PL292 (WI 40%) was approved in June 2010, and first production was achieved on 31 March 2012. 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 5.0 Mboepd.
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 PL001B and operated by Det norske oljeselskap ASA. An agreement for the coordinated development was reached in March 2012.
On 13 April 2012, the Norwegian Ministry of Petroleum and Energy approved the Luno plan of development and renamed the field Edvard Grieg. The plan of development is expected to be approved by the Norwegian Parliament this summer.
The Edvard Grieg field is estimated to contain 186 MMboe of gross reserves with first production expected in late 2015 and forecast gross peak production of approximately 100.0 Mboepd. The Edvard Grieg platform design capacity will accommodate of 160.0 Mboepd when Draupne production is combined with that from the Edvard Grieg field. The gross capital cost of the Edvard Grieg field development is estimated at USD 4 billion to include platform, pipelines and 15 wells. Contracts have been awarded to Kværner covering engineering, procurement and construction of the jacket and the topsides for the platform and to Rowan Companies for a jack up rig to drill the development wells. Saipem has been awarded the contract for marine installation.
A plan of development of the Brynhild field in PL148 (WI 70%) was approved by the Norwegian Ministry of Petroleum and Energy in November 2011. The Brynhild field contains gross reserves of 20 MMboe and is expected to produce at an estimated gross plateau production rate of 12.0 Mboepd 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 March 2012, Lundin Petroleum announced that it had entered into an agreement with Talisman Energy to acquire an additional 30 percent interest in PL148 containing the Brynhild field, offshore Norway. Following completion of the acquisition, Lundin Petroleum will hold a 100 percent interest in PL148.
An oil discovery on the Bøyla prospect in PL340 (WI 15%) was announced in October 2009. 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 is expected to be submitted for the Bøyla field in the first half of 2012 with first oil expected in 2014.
Lundin Petroleum discovered the Avaldsnes field in PL501 (WI 40%) in 2010. In 2011, Statoil made the Aldous Major South discovery on the neighbouring PL265 (WI 10%). Following appraisal drilling, it was determined that the discoveries were connected and in January 2012 the combined discovery was renamed Johan Sverdrup. Lundin Petroleum has announced a range of gross recoverable contingent resources for the Avaldsnes discovery in PL501 of between 800 million and 1.8 billion barrels of oil 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.
In January 2012, a third appraisal well, 16/5-2S, located on PL501 was completed. The objective of the well was to delineate the southern flank of the Johan Sverdrup, PL501 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 be a reduction of current resource estimates in the southern area of the Johan Sverdrup, PL501 discovery.
In March 2012, a further appraisal well, 16/2-11, was drilled on PL501 which encountered a 54 metre gross oil column in Upper and Middle Jurassic sandstone reservoir in an oil-down-to situation. The reservoir was encountered at depth prognosis. A comprehensive logging and coring programme has been successfully completed as well as a production test (DST) in the previously untested Middle Jurassic reservoir. The data obtained from this well confirmed good reservoir properties in line with the earlier Johan Sverdrup wells where the Upper Jurassic reservoir was of excellent quality with a high net to gross ratio. A sidetrack of the well has been successfully completed confirming similar excellent reservoir thickness and quality.
At least a further two appraisal wells will be drilled in PL501 in 2012 and Statoil will drill three further appraisal wells in PL265 in 2012. The appraisal programme will define the recoverable resource and assist with the development planning strategy. Lundin Petroleum, as operator of PL501, has signed a Pre-Unit Agreement with the partners within PL501 and PL265 for the joint field development of the Johan Sverdrup field. The main focus is to jointly deliver a common field development plan to the Norwegian authorities for sanctioning by the government. Statoil has been elected as working operator for the pre-unit phase.
There will be further exploration drilling in 2012 in three core exploration areas; the Southern Utsira High area in the Luno II prospect in PL359 (WI 40%), the Barents Sea area with the Pulk prospect in PL533 (WI 20%) and the Juksa prospect in PL490 (WI 60%) and the Møre Basin area with the Albert prospect in PL519 (WI 40%). In January 2012, Lundin Petroleum was awarded a further ten exploration licences in the 2011 APA Licensing Round of which four will be operated by Lundin Petroleum.
| Production in Mboepd |
Lundin Petroleum Working Interest (WI) |
1 Jan 2012- 31 Mar 2012 3 months |
1 Jan 2011- 31 Mar 2011 3 months |
1 Jan 2011- 31 Dec 2011 12 months |
|---|---|---|---|---|
| Paris Basin | 100% | 2.3 | 2.5 | 2.4 |
| Aquitaine Basin | 50% | 0.6 | 0.6 | 0.7 |
| 2.9 | 3.1 | 3.1 |
The redevelopment of the Grandville field in the Paris Basin is continuing with five of the eight new development wells completed. The installation of new production facilities is substantially completed.
Two exploration wells are planned to be drilled in the Paris Basin area in the second half of 2012.
The net gas production to Lundin Petroleum from the Netherlands averaged 2.0 Mboepd for the reporting period. Development drilling on existing production assets is ongoing to optimize field recovery and several exploration wells are planned to be drilled in 2012.
Following the completion of seismic studies on the Slyne Basin licence 04/06 (WI 50%) discussions regarding future work programme are being considered by the licence partners.
The net production to Lundin Petroleum from the Singa gas field (WI 25.9%) during the reporting period amounted to 1.2 Mboepd. Production in the reporting period has been affected by well maintenance work which is expected to continue into the second quarter of 2012.
Planning is underway for the commencement of exploration drilling on the Baronang and Cakalang Blocks (WI 100%) in 2013.
The interpretation of the 2,400 km 2D seismic acquisition programme, completed in 2011, is ongoing to determine the location for a 3D seismic acquisition programme in 2013.
A 3D seismic acquisition programme of 950 km² will be completed in 2012 on the Gurita Block (WI 100%).
Following interpretation of the 474 km 2D seismic acquisition programme completed on the Rangkas Block (WI 51%) during 2010, a decision was taken in the first quarter of 2012 to relinquish the Block.
Five exploration and appraisal wells will be drilled in 2012 following the five wells that were drilled in 2011.
In June 2011, Lundin Petroleum acquired a 75 percent working interest in Block PM307 offshore peninsular 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. The Bertam discovery is likely a commercial oil field and studies are now progressing to review potential development concepts.
The Tarap and Cempulut exploration wells drilled in Block SB303 (WI 75%), offshore Sabah, east Malaysia in 2011 resulted in gas discoveries alongside the existing discovery named Titik Terang. The three discoveries are in close proximity to one another and have an estimated gross contingent resource (best estimate) of more than 250 bcf and Lundin Petroleum is evaluating the potential for a cluster development. A further exploration well will be drilled on this Block during 2012 to target the Berangan prospect. An exploration well will also be drilled on the neighbouring SB307/308 to target upside exploration potential on the Tiga Papan discovery.
In November 2011, the second exploration well drilled in PM308A Janglau-1 was completed as an oil discovery proving up a new play concept in Oligocene intra-rift sands. The discovery will require further drilling in the area and an additional well is planned in 2012. Two further wells will be drilled in the Penyu Basin contained within Blocks PM308B and PM307.
The net production to Lundin Petroleum from Russia for the period was 2.8 Mboepd. 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.
The net production to Lundin Petroleum from the Oudna field (WI 40%) was 0.4 Mboepd for the reporting period. During March 2012, damage was incurred to a flowline during a storm resulting in a shut-in of the field. An assessment of repair solutions to the flowline is being carried out and in the event that it is determined to be uneconomic to repair, the field will be abandoned.
Lundin Petroleum has decided to relinquish its interest in Block Marine XI (WI 18.75%). The work programme for Block Marine XIV (WI 21.55%) has been fulfilled.
The net result for the three month period ended 31 March 2012 (reporting period) amounted to MUSD 47.2 (MUSD 53.4). The net result attributable to shareholders of the Parent Company for the reporting period amounted to MUSD 48.8 (MUSD 55.1) representing earnings per share on a fully diluted basis of USD 0.16 (USD 0.18).
Earnings before interest, tax, depletion and amortisation (EBITDA) for the reporting period amounted to MUSD 309.2 (MUSD 238.4) representing EBITDA per share on a fully diluted basis of USD 0.99 (USD 0.77). Operating cash flow for the reporting period amounted to MUSD 166.6 (MUSD 193.6) representing operating cash flow per share on a fully diluted basis of USD 0.54 (USD 0.62).
There are no significant changes to the Group for the reporting period.
Net sales of oil and gas for the reporting period amounted to MUSD 359.2 (MUSD 289.6) and are detailed in Note 1. Compared to the comparative period, sales volumes were 11 percent higher and the achieved oil price was 12 percent higher resulting in 24 percent higher oil and gas revenues. The average price achieved by Lundin Petroleum for a barrel of oil equivalent amounted to USD 107.40 (USD 95.86) and is detailed in the following table. The premium over dated Brent on Norwegian crude oil sold during the reporting period averaged USD 4.08 per barrel. The average Dated Brent price for the reporting period amounted to USD 118.60 (USD 105.43) per barrel.
Sales of oil and gas for the reporting period were comprised as follows:
| Sales | 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- |
|---|---|---|---|
| Average price per boe expressed | 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 |
| in USD | 3 months | 3 months | 12 months |
| Crude oil sales | |||
| Norway | |||
| - Quantity in Mboe | 2,048.8 | 1,941.9 | 7,896.0 |
| - Average price per boe | 123.06 | 109.71 | 115.38 |
| France | |||
| - Quantity in Mboe | 279.4 | 291.3 | 1,155.5 |
| - Average price per boe | 119.50 | 105.43 | 110.59 |
| Netherlands | |||
| - Quantity in Mboe | 0.6 | 0.5 | 2.2 |
| - Average price per boe | 107.07 | 95.94 | 103.87 |
| Russia | |||
| - Quantity in Mboe | 265.3 | 301.1 | 1,138.4 |
| - Average price per boe | 77.7 | 63.4 | 69.8 |
| Tunisia | |||
| - Quantity in Mboe | 198.4 | – | 198.2 |
| - Average price per boe | 111.77 | – | 125.12 |
| Total crude oil sales | |||
| - Quantity in Mboe | 2,792.5 | 2,534.8 | 10,390.3 |
| - Average price per boe | 117.59 | 103.71 | 110.25 |
| Gas sales | |||
| Norway | |||
| - Quantity in Mboe | 268.7 | 234.5 | 947.2 |
| - Average price per boe | 61.18 | 61.45 | 61.14 |
| Netherlands | |||
| - Quantity in Mboe | 185.3 | 187.3 | 722.8 |
| - Average price per boe | 60.35 | 54.25 | 60.61 |
| Indonesia | |||
| - Quantity in Mboe | 97.8 | 64.2 | 387.7 |
| - Average price per boe | 32.49 | 32.91 | 32.42 |
| Total gas sales | |||
| - Quantity in Mboe | 551.8 | 486.0 | 2,057.7 |
| - Average price per boe | 55.82 | 54.91 | 54.50 |
| Total sales | |||
| - Quantity in Mboe | 3,344.3 | 3,020.8 | 12,448.0 |
| - Average price per boe | 107.40 | 95.86 | 101.04 |
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 January 2012.
The oil produced in Russia is sold on either the Russian domestic market or exported into the international market. 39 percent (33 percent) of Russian sales for the reporting period were on the international market at an average price of USD 116.30 per barrel (USD 100.91 per barrel) with the remaining 61 percent (67 percent) of Russian sales being sold on the domestic market at an average price of USD 53.21 per barrel (USD 44.75 per barrel).
Other operating income amounted to MUSD 3.0 (MUSD 2.2) for the reporting period and includes MUSD 1.6 (MUSD 1.3) 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. 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 including inventory movements for the reporting period amounted to MUSD 54.3 (MUSD 39.5) and are detailed in Note 2. The production and depletion costs per barrel of oil equivalent produced are detailed in the table below.
| Production cost and depletion |
1 Jan 2012- 31 Mar 2012 |
1 Jan 2011- 31 Mar 2011 |
1 Jan 2011- 31 Dec 2011 |
|---|---|---|---|
| in USD per boe | 3 months | 3 months | 12 months |
| Cost of operations | 7.98 | 7.70 | 8.43 |
| Tariff and transportation | |||
| expenses | 2.17 | 1.98 | 1.88 |
| Royalty and direct taxes | 3.97 | 3.86 | 4.31 |
| Changes in inventory/lifting | |||
| position | 2.94 | -0.62 | 1.08 |
| Other | 0.17 | 0.19 | 0.18 |
| Total production costs | 17.23 | 13.11 | 15.88 |
| Depletion | 13.13 | 13.48 | 13.59 |
| Total cost per boe | 30.36 | 26.59 | 29.47 |
The total cost of operations for the reporting period was MUSD 25.2 compared to MUSD 23.2 for the comparative period. The current reporting period cost is six percent lower than the Capital Market Day forecast for the first quarter of 2012 due primarily to a rephasing of operations to later in the year.
The cost of operations for the first quarter of 2012 was USD 7.98 per barrel, which due to rephased costs and higher production volumes, is nine percent lower than the Capital Market Day forecast of USD 8.75 per barrel for the first quarter. The cost of operations per barrel is expected to increase during the remainder of the year giving an average level for 2012 in line with the Capital Market Day forecast of USD 9.35 per barrel. The increase in the forecast for the year is primarily due to the inclusion of the Gaupe field, Norway and well intervention work planned for the Alvheim and Volund fields, Norway.
The tariff and transportation expenses for the reporting period amounted to MUSD 6.8 compared to MUSD 6.0 for the comparative period. Included in the reporting period are costs of MUSD 0.8 (MUSD -) associated with the reservation of capacity in the third party owned gas infrastructure system for the Gaupe field.
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 23.05 (USD 20.28) 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 56.28 (USD 47.04) 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 9.3 (MUSD -1.9) was charged to the income statement for the reporting period. The main reason for the charge in the reporting period is due to the lifting in January of the hydrocarbon inventory from the Ikdam FPSO on the Oudna field, Tunisia, resulting in a net MUSD 11.4 charge to production costs in the first quarter. There was no Oudna cargo lifted in the comparative period.
Depletion costs amounted to MUSD 41.4 (MUSD 40.6) and are detailed in Note 3. Norway contributed approximately 80 percent of the total depletion charge for the period at a rate of USD 14.30 per barrel.
Exploration costs for the reporting period amounted to MUSD 8.8 (MUSD 10.0) and are detailed in Note 4. As a result of the decision taken to relinquish the Rangkas Block, Indonesia, MUSD 6.8 of capitalised cost associated with the Block was expensed in the quarter. Other costs expensed in the reporting period mainly relate to ongoing costs on the Congo (Brazzaville) Blocks and a relinquished exploration licence in 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 -0.5 (MUSD 14.6) of which MUSD -8.2 (MUSD 6.3) related to non-cash charges in relation to the Group's Longterm Incentive Plan (LTIP) scheme.
The credit in the reporting period is due to the reduction in the LTIP provision as a result of a lower 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 credit 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 of the LTIP by purchasing 6,882,638 of its own shares. For more detail refer to the remuneration section below.
Financial income for the reporting period amounted to MUSD 0.6 (MUSD 17.2) and is detailed in Note 6.
Interest income for the reporting period amounted to MUSD 0.6 (MUSD 1.3). The interest income in the comparative period includes an amount of MUSD 0.9 relating to a loan to Etrion Corporation. The Etrion loan was repaid during the second quarter of 2011.
An amount of MUSD 15.6, relating to the sale of Africa Oil Corporation shares is included in financial income for the comparative period.
Financial expenses for the reporting period amounted to MUSD 27.3 (MUSD 14.0) and are detailed in Note 7.
Foreign exchange losses for the reporting period amounted to MUSD 4.1 (MUSD 8.5). The US Dollar weakened against the Euro and the Norwegian Kroner during the reporting period giving rise to exchange loss movements on the intercompany loans and working capital balances.
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 1.2 (MUSD 1.1) has been charged to the income statement for the reporting period.
The amortisation of the deferred financing fees for the reporting period amounted to MUSD 1.3 (MUSD 0.6) and relates to the expensing of the fees incurred in establishing the current loan facility over the period of usage of the facility. As Lundin Petroleum is in the process of arranging a new financing facility in 2012, the amount expensed was increased in the reporting period.
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, subsequent movements in the fair value of the shares were being recognised 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, it was considered that there had been a permanent diminution in the fair value of the shares of ShaMaran Petroleum held by Lundin Petroleum. The cumulative loss recognised in other comprehensive income of MUSD 18.6 was reclassified from equity and recognised in the income statement in the reporting period.
The tax charge for the reporting period amounted to MUSD 184.2 (MUSD 136.9) and is detailed in Note 8.
The current tax charge for the reporting period amounted to MUSD 141.3 (MUSD 58.7) of which MUSD 132.0 (MUSD 49.0) relates to Norway. The increase in the Norway current tax charge from the comparative period is mainly due to the higher revenues generated by Norway in the reporting period and the utilisation in the comparative period of tax allowances earned on development expenditure brought forward offsetting the 50 percent Norway offshore tax. The Norwegian current tax for the reporting period is calculated using the actual results achieved and the development and exploration expenditure incurred. The low level of development and exploration expenditure in the reporting period compared to that expected for the remainder of the year has resulted in a high rate of current tax charge for the reporting period compared to the forecast for the full year.
The deferred tax charge for the reporting period amounted to MUSD 42.9 (MUSD 78.2) and arises primarily where there is a difference in depreciation for tax and accounting purposes. MUSD 40.1 (MUSD 74.9) 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 80 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 on development expenditure for tax purposes. The effective rate is increased due to a number of non-tax adjusted items in the reporting period including the impairment of the ShaMaran shares and certain other financial items, as well as a lower tax credit on the exploration costs relating to the Rangkas Block, Indonesia. The operational tax rate adjusted for the Rangkas exploration costs is 70 percent for the reporting period.
The net result attributable to non-controlling interest for the reporting period amounted to MUSD -1.6 (MUSD -1.7) and mainly relates to the non-controlling interest's share in a Russian subsidiary which is fully consolidated.
Oil and gas properties amounted to MUSD 2,505.5 (MUSD 2,329.3) and are detailed in Note 9.
Development and exploration expenditure incurred for the reporting period was as follows:
| Development expenditure in MUSD |
1 Jan 2012- 31 Mar 2012 3 months |
1 Jan 2011- 31 Mar 2011 3 months |
1 Jan 2011- 31 Dec 2011 12 months |
|---|---|---|---|
| Norway | 46.9 | 29.5 | 186.8 |
| France | 10.6 | 2.8 | 30.9 |
| Netherlands | 1.6 | 0.4 | 4.1 |
| Indonesia | 0.1 | 2.7 | 6.4 |
| Russia | 1.2 | 1.3 | 4.2 |
| 60.4 | 36.7 | 232.4 |
During the reporting period, an amount of MUSD 46.9 of development expenditure was incurred in Norway, primarily on the Brynhild and Gaupe field developments in Norway. MUSD 29.5 was spent in the comparative period on the development of the Gaupe and Alvheim fields. MUSD 10.6 was incurred in France in the reporting period on the Grandville field redevelopment.
| Exploration expenditure | 1 Jan 2012- 31 Mar 2012 |
1 Jan 2011- 31 Mar 2011 |
1 Jan 2011- 31 Dec 2011 |
|---|---|---|---|
| in MUSD | 3 months | 3 months | 12 months |
| Norway | 47.3 | 59.8 | 288.6 |
| France | 0.4 | 0.3 | 1.7 |
| Indonesia | 1.2 | 2.9 | 16.4 |
| Russia | 1.5 | 2.0 | 10.0 |
| Malaysia | 3.5 | 4.4 | 98.7 |
| Congo (Brazzaville) | 1.2 | 1.5 | 19.0 |
| Other | 0.1 | 0.8 | 3.1 |
| 55.2 | 71.7 | 437.5 |
During the reporting period, exploration expenditure of MUSD 47.3 was incurred in Norway mainly on the appraisal drilling of the Johan Sverdrup field. In the comparative period, MUSD 59.8 was spent in Norway on three exploration wells.
Other tangible assets amounted to MUSD 16.6 (MUSD 16.1) and represent office fixed assets and real estate.
Financial assets amounted to MUSD 38.4 (MUSD 46.6) and are detailed in Note 10. Other shares and participations amounted to MUSD 13.2 (MUSD 17.8) and predominantly relate to the shares held in ShaMaran Petroleum which are reported at market price. Other financial assets amounted to MUSD 11.3 (MUSD 11.0) and include Etrion Corporation bonds of MUSD 9.9 (MUSD 9.6) held by Lundin Petroleum. The deferred tax asset amounted to MUSD 12.5 (MUSD 15.3) and mainly relates to tax losses in the Netherlands.
Receivables and inventories amounted to MUSD 235.9 (MUSD 224.4) and are detailed in Note 11.
Trade receivables amounted to MUSD 161.3 (MUSD 145.0). Higher oil prices have resulted in the value of the trade receivables being higher at 31 March 2012.
Other assets amounted to MUSD 30.2 (MUSD 21.2) and included an amount of MUSD 22.1 (MUSD 11.2) for a carried interest in PL148 Brynhild, Norway, under the terms of a sale agreement with the seller of the interest, Talisman Energy. The amount will be transferred to oil and gas properties on completion of the deal.
Cash and cash equivalents amounted to MUSD 137.6 (MUSD 73.6). Cash balances are held to meet operational and investment requirements.
The non-current part of provisions amounted to MUSD 1,083.3 (MUSD 988.0) and is detailed in Note 12.
The provision for site restoration amounted to MUSD 145.3 (MUSD 119.3) and relates to future decommissioning obligation liabilities. The increase compared to the comparative period mainly results from the change in the discount factor used to calculate the present value of the decommissioning liabilities and the inclusion of the decommissioning liability associated with the Gaupe field pipeline laid in the reporting period.
The provision for deferred taxes amounted to MUSD 878.2 (MUSD 803.5) 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 51.8 (MUSD 58.1).
Other non-current provisions amounted to MUSD 6.4 (MUSD 5.6) and include a termination indemnity provision in Tunisia.
Long-term interest bearing debt amounted to MUSD 227.0 (MUSD 207.0) and relates to the outstanding loan under the Group's MUSD 850 revolving borrowing base facility.
Other non-current liabilities amounted to MUSD 21.3 (MUSD 21.8) and mainly represent funding advances made by a non-controlling interest entity in relation to LLC PetroResurs, Russia.
Other current liabilities amounted to MUSD 410.6 (MUSD 390.6) and are detailed in Note 13.
Tax liabilities amounted to MUSD 307.6 (MUSD 240.1) of which MUSD 290.6 (MUSD 223.0) relates to Norway.
Joint venture creditors amounted to MUSD 68.9 (MUSD 88.4) and relate to ongoing operational costs.
Other liabilities amounted to MUSD 5.3 (MUSD 21.5). Included in other liabilities at 31 December 2011 was 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 PL148 Brynhild, Norway. The liability was settled in the first quarter of 2012.
The current portion of the provision for Lundin Petroleum's LTIP scheme amounted to MUSD 12.1 (MUSD 12.2).
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 6.5 (MSEK -45.1) for the reporting period.
The result includes general and administrative expenses of MSEK -5.9 (MSEK 44.9) and interest expense of MSEK 8.6 (MSEK 5.3). The credit to general and administrative expenses in the reporting period is as a result of the reduction in the provision for the Group's LTIP. The comparative period includes financial income of MSEK 1.6 for supporting certain financial obligations for ShaMaran Petroleum.
During the reporting period, the Group has entered into transactions with related parties on a commercial basis as described below:
The Group received MUSD 0.1 (MUSD 0.1) from ShaMaran Petroleum for the provision of office and other services and MUSD – (MUSD 0.2) for supporting certain financial obligations.
The Group paid MUSD 0.2 (MUSD 0.1) to other related parties in respect of aviation services received.
Lundin Petroleum has a secured revolving borrowing base facility of MUSD 850 with a seven year term expiring in 2014, of which MUSD 227.0 was drawn in cash as at 31 March 2012. 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 87.8. In addition, BNP Paribas has issued additional bank guarantees to cover work commitments in Indonesia amounting to MUSD 2.4.
No significant events have occurred after the end of the first three months of 2012 that are expected to have a substantial effect on this interim report.
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 March 2012, Lundin Petroleum held 6,882,638 of its own shares.
Lundin Petroleums principles for remuneration are provided in the Company's 2011 Annual Report.
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 has a three year duration whereby the initial grant of units vested equally in three tranches: one third after one year; one third after two years; and the final third after three years. The cash payment is conditional upon the holder of the units remaining an employee of the Group at the time of payment. 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.
LTIPs that follow the same principles as the 2008 LTIP have been implemented annually for employees other than Executive Management.
The number of units relating to the 2009, 2010 and 2011 Unit Bonus Plans outstanding as at 31 March 2012 were 209,440, 450,041, and 401,000.
At the AGM on 13 May 2009, the shareholders of Lundin Petroleum approved the implementation of an LTIP for Executive Management (being the President and Chief Executive Officer, the Chief Operating Officer, the Chief Financial Officer and the Senior Vice President Operations) consisting of a grant of phantom options exercisable after five years from the date of grant. The exercise of these options entitles the recipient to receive a cash payment based on the appreciation of the market value of the Lundin Petroleum share. Payment of the award under these phantom options will occur in two equal installments: (i) first on the date immediately following the fifth anniversary of the date of grant and (ii) second on the date which is one year following the date of the first payment.
The LTIP for Executive Management includes 5,500,928 phantom options with an exercise price of SEK 52.91. 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 participants of the phantom option plan 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 the LTIP. The Lundin Petroleum share price at 31 March 2012 was SEK 141.80. The provision for LTIP amounted to MUSD 63.9 as at 31 March 2012 and the market value of the shares held at 31 March 2012 was MUSD 146.1. The gain in the value of the own shares held can not be off set against the cost for the LTIP in accordance with accounting rules.
This interim report has been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial 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 2011.
The financial reporting of the Parent Company has been prepared in accordance with accounting principles generally accepted in Sweden, applying RFR 2 Reporting for legal entities, 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 objective of Business Risk Management is to identify, understand and manage threats and opportunities within the business on a continual basis. This objective is achieved by creating a mandate and commitment to risk management at all levels of the business. This approach actively addresses risk as an integral and continual part of decision making within the Group and is designed to ensure that all risks are identified, fully acknowledged, understood and communicated well in advance. The ability to manage and or mitigate these risks represents a key component in ensuring that the business aim of the Company is achieved. Nevertheless, 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.
A detailed analysis of Lundin Petroleum's strategic, operational, financial and external risks and mitigation of those risks through risk management is described in Lundin Petroleum's 2011 Annual Report.
For the preparation of the financial statements for the reporting period, the following currency exchange rates have been used.
| 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 | ||||
|---|---|---|---|---|---|---|
| Average | Period end | Average | Period end | Average | Period end | |
| 1 USD equals NOK | 5.7867 | 5.6933 | 5.7233 | 5.5135 | 5.5998 | 5.9927 |
| 1 USD equals Euro | 0.7628 | 0.7487 | 0.7316 | 0.7039 | 0.7185 | 0.7729 |
| 1 USD equals Rouble | 30.1660 | 29.4212 | 29.2647 | 28.3557 | 29.3738 | 32.2784 |
| 1 USD equals SEK | 6.7524 | 6.6229 | 6.4833 | 6.2877 | 6.4867 | 6.8877 |
| 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- | ||
|---|---|---|---|---|
| 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 | ||
| Expressed in TUSD | Note | 3 months | 3 months | 12 months |
| Operating income | ||||
| Net sales of oil and gas | 1 | 359,178 | 289,572 | 1,257,691 |
| Other operating income | 3,042 | 2,186 | 11,824 | |
| 362,220 | 291,758 | 1,269,515 | ||
| Cost of sales | ||||
| Production costs | 2 | -54,348 | -39,461 | -193,104 |
| Depletion costs | 3 | -41,408 | -40,619 | -165,138 |
| Exploration costs | 4 | -8,838 | -10,010 | -140,027 |
| Gross profit | 257,626 | 201,668 | 771,246 | |
| General, administration and | ||||
| depreciation expenses | 505 | -14,577 | -67,022 | |
| Operating profit | 5 | 258,131 | 187,091 | 704,224 |
| Result from financial investments | ||||
| Financial income | 6 | 553 | 17,253 | 46,455 |
| Financial expenses | 7 | -27,332 | -14,054 | -21,022 |
| -26,779 | 3,199 | 25,433 | ||
| Profit before tax | 231,352 | 190,290 | 729,657 | |
| Income tax expense | 8 | -184,161 | -136,855 | -574,413 |
| Net result | 47,191 | 53,435 | 155,244 | |
| Net result attributable to the | ||||
| shareholders of the Parent Company: | 48,762 | 55,129 | 160,137 | |
| Net result attributable to non | ||||
| controlling interest: | -1,571 | -1,694 | -4,893 | |
| Net result | 47,191 | 53,435 | 155,244 | |
| Earnings per share – USD1 | 0.16 | 0.18 | 0.51 | |
| Diluted earnings per share – USD1 | 0.16 | 0.18 | 0.51 | |
1 Based on net result attributable to shareholders of the Parent Company.
| 1 Jan 2012- 31 Mar 2012 |
1 Jan 2011- 31 Mar 2011 |
1 Jan 2011- 31 Dec 2011 |
|
|---|---|---|---|
| Expressed in TUSD | 3 months | 3 months | 12 months |
| Net result | 47,191 | 53,435 | 155,244 |
| Other comprehensive income | |||
| Exchange differences foreign operations | 52,745 | 54,568 | -37,525 |
| Cash flow hedges | 170 | 1,936 | 6,971 |
| Available-for-sale financial assets | 9,363 | -20,455 | -50,210 |
| Income tax relating to other | |||
| comprehensive income | -43 | -484 | -1,743 |
| Other comprehensive income, net of | |||
| tax | 62,235 | 35,565 | -82,507 |
| Total comprehensive income | 109,426 | 89,000 | 72,737 |
| Total comprehensive income | |||
| attributable to: | |||
| Shareholders of the Parent Company | 106,559 | 86,837 | 80,466 |
| Non-controlling interest | 2,867 | 2,163 | -7,729 |
| 109,426 | 89,000 | 72,737 |
| Expressed in TUSD | Note | 31 March 2012 | 31 December 2011 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 9 | 2,505,488 | 2,329,270 |
| Other tangible assets | 16,598 | 16,084 | |
| Financial assets | 10 | 38,369 | 46,586 |
| Total non-current assets | 2,560,455 | 2,391,940 | |
| Current assets | |||
| Receivables and inventories | 11 | 235,864 | 224,407 |
| Cash and cash equivalents | 137,610 | 73,597 | |
| Total current assets | 373,474 | 298,004 | |
| TOTAL ASSETS | 2,933,929 | 2,689,944 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Shareholders´ equity | 1,107,441 | 1,000,882 | |
| Non-controlling interest | 72,291 | 69,424 | |
| Total equity | 1,179,732 | 1,070,306 | |
| Non-current liabilities | |||
| Provisions | 12 | 1,083,264 | 987,993 |
| Bank loans | 227,000 | 207,000 | |
| Other non-current liabilities | 21,303 | 21,830 | |
| Total non-current liabilities | 1,331,567 | 1,216,823 | |
| Current liabilities | 410,577 | ||
| Other current liabilities Provisions |
13 12 |
12,053 | 390,600 12,215 |
| Total current liabilities | 422,630 | 402,815 | |
| TOTAL EQUITY AND LIABILITIES | 2,933,929 | 2,689,944 | |
| Pledged assets | 546,159 | 519,624 | |
| Contingent liabilities and assets | – | – |
| CONSOLIDATED STATEMENT OF CASH FLOW | |||||||
|---|---|---|---|---|---|---|---|
| -- | -- | -- | -- | ------------------------------------- | -- | -- | -- |
| 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- | ||
|---|---|---|---|---|
| 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 | ||
| Expressed in TUSD | Note | 3 months | 3 months | 12 months |
| Cash flow from operations | ||||
| Net result | 47,191 | 53,435 | 155,244 | |
| Adjustments for non-cash related items Interest received Interest paid Income taxes paid Changes in working capital |
14 | 251,845 121 -1,531 -86,753 -47,108 |
194,067 630 -1,485 -17,975 -26,885 |
915,174 1,457 -1,597 -183,870 10,528 |
| Total cash flow from operations | 163,765 | 201,787 | 896,936 | |
| Cash flow from investments Proceeds from sale of other shares and participations Change in other financial fixed assets Other payments Investment in oil and gas properties Investment in office equipment and other assets |
– – -351 -115,626 -994 |
28,585 – -557 -108,320 -1,307 |
53,938 1,908 -1,168 -670,032 -3,786 |
|
| Total cash flow from investments | -116,971 | -81,599 | -619,140 | |
| Cash flow from financing Changes in long-term liabilities Dividend paid to non-controlling interest Total cash flow from financing |
19,471 – 19,471 |
-139,821 – -139,821 |
-252,238 -212 -252,450 |
|
| Change in cash and cash equivalents Cash and cash equivalents at the beginning of the period |
66,265 73,597 |
-19,633 48,703 |
25,346 48,703 |
|
| Currency exchange difference in cash and cash | ||||
| equivalents Cash and cash equivalents at the end of the |
-2,252 | -2,506 | -452 | |
| period | 137,610 | 26,564 | 73,597 |
| Additional | ||||||
|---|---|---|---|---|---|---|
| paid-in | Non | |||||
| Expressed in TUSD | Share | capital/Other | Retained | controlling | ||
| capital | reserves | earnings | Net result | interest | Total equity | |
| Balance at 1 January 2011 | 463 | 417,430 | -9,352 | 511,875 | 77,365 | 997,781 |
| Transfer of prior year net result | – | – | 511,875 | -511,875 | – | – |
| Total comprehensive income | – | 31,708 | – | 55,129 | 2,163 | 89,000 |
| Balance at 31 March 2011 | 463 | 449,138 | 502,523 | 55,129 | 79,528 | 1,086,781 |
| Total comprehensive income | – | -111,379 | – | 105,008 | -9,892 | -16,263 |
| Transactions with owners | ||||||
| Distributions | – | – | – | – | -212 | -212 |
| Total transactions with owners | – | – | – | – | -212 | -212 |
| Balance at 31 December 2011 | 463 | 337,759 | 502,523 | 160,137 | 69,424 | 1,070,306 |
| Transfer of prior year net result | – | – | 160,137 | -160,137 | – | – |
| Total comprehensive income | – | 57,797 | – | 48,762 | 2,867 | 109,426 |
| Balance at 31 March 2012 | 463 | 395,556 | 662,660 | 48,762 | 72,291 | 1,179,732 |
| Note 1. Net sales of oil and gas, | 1 Jan 2012- 31 Mar 2012 |
1 Jan 2011- 31 Mar 2011 |
1 Jan 2011- 31 Dec 2011 |
|---|---|---|---|
| TUSD | 3 months | 3 months | 12 months |
| Net sales of: | |||
| Crude oil | |||
| Norway | 252,125 | 213,046 | 911,072 |
| France | 33,392 | 30,714 | 127,789 |
| Netherlands | 64 | 51 | 231 |
| Russia | 20,625 | 19,080 | 79,515 |
| Tunisia | 22,171 | – | 24,795 |
| 328,377 | 262,891 | 1,143,402 | |
| Condensate | |||
| Netherlands | 391 | 250 | 1,314 |
| Gas | |||
| Norway | 16,439 | 14,410 | 57,909 |
| Netherlands | 10,793 | 9,909 | 42,496 |
| Indonesia | 3,178 | 2,112 | 12,570 |
| 30,410 | 26,431 | 112,975 | |
| 359,178 | 289,572 | 1,257,691 | |
| Note 2. Production costs, | 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- |
| 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 | |
| TUSD | 3 months | 3 months | 12 months |
| Cost of operations | 25,175 | 23,192 | 102,476 |
| Tariff and transportation expenses | 6,846 | 5,966 | 22,863 |
| Direct production taxes | 12,518 | 11,623 | 52,390 |
| Change in inventory/lifting position | 9,269 | -1,881 | 13,129 |
| Other | 540 | 561 | 2,246 |
| 54,348 | 39,461 | 193,104 | |
| Note 3. Depletion costs, | 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- |
| 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 | |
| TUSD | 3 months | 3 months | 12 months |
| Norway | 33,001 | 32,134 | 130,011 |
| France | 3,013 | 2,982 | 12,174 |
| Netherlands | 2,787 | 3,249 | 11,939 |
| Indonesia | 1,467 | 1,035 | 6,250 |
| Russia | 1,140 | 1,219 | 4,764 |
| 41,408 | 40,619 | 165,138 | |
| Note 4. Exploration costs, | 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- |
| 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 | |
| TUSD | 3 months | 3 months | 12 months |
| Norway | 566 | 9,209 | 74,060 |
| Malaysia | 75 | – | 11,015 |
| Congo (Brazzaville) | 1,197 | – | 51,263 |
| Indonesia | 6,845 | 93 | 967 |
| Other | 155 | 708 | 2,722 |
| 8,838 | 10,010 | 140,027 |
| Note 5. Operating profit, | 1 Jan 2012- 31 Mar 2012 |
1 Jan 2011- 31 Mar 2011 |
1 Jan 2011- 31 Dec 2011 |
|---|---|---|---|
| TUSD | 3 months | 3 months | 12 months |
| Operating profit | |||
| Norway | 227,454 | 172,929 | 703,711 |
| France | 22,010 | 21,544 | 85,334 |
| Netherlands | 5,639 | 4,401 | 18,868 |
| Indonesia | -6,652 | -25 | 168 |
| Russia | 3,421 | 2,847 | 7,715 |
| Tunisia | 6,044 | -132 | 13,476 |
| Malaysia | -484 | -243 | -11,010 |
| Congo (Brazzaville) | -1,197 | – | -51,273 |
| Other | 1,896 | -14,230 | -62,765 |
| 258,131 | 187,091 | 704,224 |
| Note 6. Financial income, | 1 Jan 2012- 31 Mar 2012 |
1 Jan 2011- 31 Mar 2011 |
1 Jan 2011- 31 Dec 2011 |
|---|---|---|---|
| TUSD | 3 months | 3 months | 12 months |
| Interest income | 553 | 1,342 | 4,138 |
| Foreign currency exchange gain, net | – | – | 8,945 |
| Insurance proceeds | – | – | 1,734 |
| Guarantee fees | – | 250 | 998 |
| Gain on sale of shares | – | 15,633 | 29,974 |
| Other | – | 28 | 666 |
| 553 | 17,253 | 46,455 |
| Note 7. Financial expenses, | 1 Jan 2012- 31 Mar 2012 |
1 Jan 2011- 31 Mar 2011 |
1 Jan 2011- 31 Dec 2011 |
|---|---|---|---|
| TUSD | 3 months | 3 months | 12 months |
| Loan interest expenses | 1,361 | 1,591 | 5,390 |
| Foreign currency exchange loss, net | 4,069 | 8,518 | – |
| Result on interest rate hedge settlement | 200 | 1,695 | 6,995 |
| Unwinding of site restoration discount | 1,216 | 1,102 | 4,494 |
| Amortisation of deferred financing fees | 1,254 | 600 | 2,181 |
| Impairment of other shares | 18,631 | – | – |
| Other | 601 | 548 | 1,962 |
| 27,332 | 14,054 | 21,022 |
| Note 8. Income taxes, | 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- |
|---|---|---|---|
| TUSD | 31 Mar 2012 3 months |
31 Mar 2011 3 months |
31 Dec 2011 12 months |
| Current tax | 141,300 | 58,665 | 400,210 |
| Deferred tax | 42,861 | 78,190 | 174,203 |
| 184,161 | 136,855 | 574,413 |
| Note 9. Oil and gas properties, TUSD |
31 Mar 2012 | 31 Dec 2011 |
|---|---|---|
| Norway | 1,413,703 | 1,269,746 |
| France | 188,369 | 172,467 |
| Netherlands | 46,141 | 43,739 |
| Indonesia | 86,572 | 93,610 |
| Russia | 632,690 | 615,015 |
| Malaysia | 133,168 | 129,830 |
| Other | 4,845 | 4,863 |
| 2,505,488 | 2,329,270 |
| Note 10. Financial assets, TUSD |
31 Mar 2012 | 31 Dec 2011 |
|---|---|---|
| Other shares and participations | 13,201 | 17,775 |
| Capitalised financing fees | 1,325 | 2,506 |
| Deferred tax | 12,517 | 15,345 |
| Other | 11,326 | 10,960 |
| 38,369 | 46,586 | |
| Note 11. Receivables and inventories, TUSD |
31 Mar 2012 | 31 Dec 2011 |
| Inventories | 20,094 | 31,589 |
| Trade receivables | 161,306 | 144,954 |
| Underlift | 1,078 | 1,851 |
| Joint venture debtors | 17,340 | 20,252 |
| Prepaid expenses and accrued income | 5,892 | 4,522 |
| Other | 30,154 | 21,239 |
| 235,864 | 224,407 | |
| Note 12. Provisions, TUSD |
31 Mar 2012 | 31 Dec 2011 |
| Non-current: | ||
| Site restoration | 145,321 | 119,341 |
| Deferred tax | 878,219 | 803,493 |
| Long-term incentive plan | 51,814 | 58,079 |
| Pension | 1,483 | 1,460 |
| Other | 6,427 | 5,620 |
| 1,083,264 | 987,993 | |
| Current: Long-term incentive plan |
12,053 | 12,215 |
| 12,053 | 12,215 | |
| 1,095,317 | 1,000,208 | |
| Note 13. Other current liabilities, TUSD |
31 Mar 2012 | 31 Dec 2011 |
| Trade payables | 7,903 | 16,546 |
| Overlift | 4,845 | 7,670 |
| Tax liabilities | 307,627 | 240,052 |
| Accrued expenses and deferred income | 16,049 | 16,227 |
| Joint venture creditors | 68,864 | 88,417 |
| Derivative instruments | – | 168 |
| Other | 5,289 | 21,520 |
| Note 14. Adjustment for non-cash related items, |
1 Jan 2012- 31 Mar 2012 |
1 Jan 2011- 31 Mar 2011 |
1 Jan 2011- 31 Dec 2011 |
|---|---|---|---|
| TUSD | 3 months | 3 months | 12 months |
| Exploration costs | 8,838 | 10,010 | 140,027 |
| Depletion, depreciation and amortisation | 42,182 | 41,304 | 167,812 |
| Current tax | 141,300 | 58,665 | 400,210 |
| Deferred tax | 42,861 | 78,191 | 174,203 |
| Gain on sale of shares | – | -15,632 | -29,974 |
| Impairment of other shares | 18,631 | – | – |
| Long-term incentive plan | -10,039 | 10,832 | 63,443 |
| Other | 8,072 | 10,697 | -547 |
| 251,845 | 194,067 | 915,174 |
410,577 390,600
| Expressed in TSEK | 1 Jan 2012- 31 Mar 2012 3 months |
1 Jan 2011- 31 Mar 2011 3 months |
1 Jan 2011- 31 Dec 2011 12 months |
|---|---|---|---|
| Operating income | |||
| Other operating income | 9,322 | 3,822 | 42,644 |
| Gross profit | 9,322 | 3,822 | 42,644 |
| General and administration expenses | 5,910 | -44,883 | -206,108 |
| Operating loss | 15,232 | -41,061 | -163,464 |
| Result from financial investments | |||
| Financial income | 11 | 1,626 | 6,560 |
| Financial expenses | -8,742 | -5,709 | -25,495 |
| -8,731 | -4,083 | -18,935 | |
| Profit before tax | 6,501 | -45,144 | -182,399 |
| Income tax expense | – | – | – |
| Net result | 6,501 | -45,144 | -182,399 |
| 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- | |
|---|---|---|---|
| Expressed in TSEK | 31 Mar 2012 3 months |
31 Mar 2011 3 months |
31 Dec 2011 12 months |
| Net result | 6,501 | -45,144 | -182,399 |
| Other comprehensive income | – | – | – |
| Total comprehensive income | 6,501 | -45,144 | -182,399 |
| Total comprehensive income attributable to: |
|||
| Shareholders of the Parent Company | 6,501 | -45,144 | -182,399 |
| 6,501 | -45,144 | -182,399 |
| Expressed in TSEK | 31 March 2012 | 31 December 2011 |
|---|---|---|
| ASSETS | ||
| Non-current assets | ||
| Shares in subsidiaries | 7,871,947 | 7,871,947 |
| Total non-current assets | 7,871,947 | 7,871,947 |
| Current assets | ||
| Receivables | 9,937 | 8,954 |
| Cash and cash equivalents | 594 | 3,849 |
| Total current assets | 10,531 | 12,803 |
| TOTAL ASSETS | 7,882,478 | 7,884,750 |
| SHAREHOLDERS´EQUITY AND LIABILITIES | ||
| Shareholders´ equity including net result for the | ||
| period | 7,176,478 | 7,169,977 |
| Non-current liabilities | ||
| Provisions | 36,403 | 36,403 |
| Payables to Group companies | 666,379 | 673,988 |
| Total non-current liabilities | 702,782 | 710,391 |
| Current liabilities | ||
| Current liabilities | 3,218 | 4,382 |
| Total current liabilities | 3,218 | 4,382 |
| TOTAL EQUITY AND LIABILITIES | 7,882,478 | 7,884,750 |
| Pledged assets | 3,617,160 | 3,579,013 |
| Contingent liabilities | – | – |
| 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- | |
|---|---|---|---|
| 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 | |
| Expressed in TSEK | 3 months | 3 months | 12 months |
| Cash flow from operations | |||
| Net result | 6,501 | -45,144 | -182,399 |
| Adjustment for non-cash related items | 78 | 422 | 207,811 |
| Changes in working capital | -2,214 | -2,909 | -12,492 |
| Total cash flow from operations | 4,365 | -47,631 | 12,920 |
| Cash flow from investments | – | – | – |
| Cash flow from financing | |||
| Change in long-term liabilities | -7,609 | 41,602 | -15,702 |
| Total cash flow from financing | -7,609 | 41,602 | -15,702 |
| Change in cash and cash equivalents | -3,244 | -6,029 | -2,782 |
| Cash and cash equivalents at the | |||
| beginning of the period | 3,849 | 6,735 | 6,735 |
| Currency exchange difference in cash and | |||
| cash equivalents | -11 | -127 | -104 |
| Cash and cash equivalents at the end | |||
| of the period | 594 | 579 | 3,849 |
| Restricted equity | Unrestricted equity | |||||
|---|---|---|---|---|---|---|
| Share | Statutory | Other | Retained | Total | ||
| Expressed in TSEK | capital | reserve | reserves | earnings | Net result | equity |
| Balance at 1 January 2011 | 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 | – | – | – | – | -45,144 | -45,144 |
| Balance at 31 March 2011 | 3,179 | 861,306 | 2,551,805 | 3,936,086 | -45,144 | 7,307,232 |
| Total comprehensive income | – | – | – | – | -137,255 | -137,255 |
| Balance at 31 December 2011 | 3,179 | 861,306 | 2,551,805 | 3,936,086 | -182,399 | 7,169,977 |
| Transfer of prior year net result | – | – | – | -182,399 | 182,399 | – |
| Total comprehensive income | – | – | – | – | 6,501 | 6,501 |
| Balance at 31 March 2012 | 3,179 | 861,306 | 2,551,805 | 3,753,687 | 6,501 | 7,176,478 |
| 1 Jan 2012- | 1 Jan 2011- | 1 Jan 2011- | |
|---|---|---|---|
| 31 Mar 2012 | 31 Mar 2011 | 31 Dec 2011 | |
| Financial data (TUSD) | 3 months | 3 months | 12 months |
| Operating income | 362,220 | 291,758 | 1,269,515 |
| EBITDA | 309,151 | 238,404 | 1,012,063 |
| Net result | 47,191 | 53,435 | 155,244 |
| Operating cash flow | 166,573 | 193,632 | 676,201 |
| Data per share (USD) | |||
| Shareholders' equity per share | 3.56 | 3.24 | 3.22 |
| Operating cash flow per share | 0.54 | 0.62 | 2.17 |
| Cash flow from operations per share | 0.53 | 0.65 | 2.88 |
| Earnings per share | 0.16 | 0.18 | 0.51 |
| Earnings per share fully diluted | 0.16 | 0.18 | 0.51 |
| EBITDA per share fully diluted | 0.99 | 0.77 | 3.25 |
| Dividend per share | – | – | – |
| Number of shares issued at period end | 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 |
| Weighted average number of shares for | |||
| the period | 311,027,942 | 311,027,942 | 311,027,942 |
| Weighted average number of shares for | |||
| the period (fully diluted) | 311,027,942 | 311,027,942 | 311,027,942 |
| Share price | |||
| Quoted price at period end (SEK) | 141.80 | 90.55 | 169.20 |
| Quoted price at period end (CDN) | 21.55 | 13.85 | 24.54 |
| Key ratios (%) | |||
| Return on equity | 4 | 5 | 15 |
| Return on capital employed | 17 | 14 | 53 |
| Net debt/equity ratio | 10 | 22 | 15 |
| Equity ratio | 40 | 43 | 40 |
| Share of risk capital | 70 | 72 | 69 |
| Interest coverage ratio | 15,227 | 6,151 | 5,919 |
| Operating cash flow/interest ratio | 10,665 | 5,893 | 5,460 |
| Yield | – | – | – |
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.
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.
Stockholm, 9 May 2012
C. Ashley Heppenstall President & CEO
The AGM will be held on 10 May 2012 in Stockholm, Sweden.
| 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
This information has been made public in accordance with the Securities Market Act (SFS 2007:528) and/or the Financial Instruments Trading Act (SFS 1991:980).
Certain statements made and information contained herein constitute "forward-looking information" (within the meaning of applicable 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 relied upon. These statements speak only as on the date of the information and the Company does not intend, and does not assume any obligation, to update these forwardlooking 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, reliance on key personnel, reserve estimates, health, safety and environmental issues, legal risks and regulatory changes, competition, geopolitical risk, and financial risks. These risks and uncertainties are described in more detail under the heading "Risks and Risk Management" and elsewhere in the Company's 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 are expressly qualified by this cautionary statement.
Unless otherwise stated, Lundin Petroleum's reserve and resource estimates are as at 31 December 2011, and have been prepared and audited in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Unless otherwise stated, all reserves estimates contained herein are the aggregate of "Proved Reserves" and "Probable Reserves", together also known as "2P Reserves". For further information on reserve and resource classifications, see "Reserves and Resources" in the Company's annual report.
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 are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. There is no certainty that it will be commercially viable for the Company to produce any portion of the Contingent Resources.
Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both a chance of discovery and a chance of development. There is no certainty that any portion of the Prospective Resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the Prospective Resources.
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
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