Annual Report • Apr 9, 2013
Annual Report
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| Building value | 1 |
|---|---|
| Highlights | 3 |
| Business model | 4 |
| Chief Executive's review – C. Ashley Heppenstall | 7 |
| Chairman's statement – Ian H. Lundin | 11 |
| Reserves, resources and production | 12 |
| Oil market overview | 19 |
| Economic evaluation of an exploration and production company | 20 |
| 22 |
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| 24 |
| 34 |
| 37 |
| 39 |
| Corporate responsibility | 40 |
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| Corporate governance report 2012 | 48 |
| – Board of Directors | 52 |
| – Management | 58 |
| – Remuneration | 59 |
| – Internal control and risk management for fi nancial reporting | 62 |
| – Board of Directors summary table | 64 |
| – Investment Committee/Executive Management summary table | 66 |
| The Lundin Petroleum share and shareholders | 68 |
| Risk and risk management | 70 |
| Contents of fi nancial report | 72 |
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| Directors' report of the Group | 73 |
| Financial tables of the Group | 82 |
| Accounting policies | 87 |
| Notes to the fi nancial statements of the Group | 92 |
| Annual accounts of the Parent Company | 105 |
| Financial tables of the Parent Company | 105 |
| Notes to the fi nancial statements of the Parent Company | 109 |
| Board assurance | 111 |
| Auditor's report | 112 |
| ADDITIONAL INFORMATION | |
| Five year fi nancial data | 113 |
|---|---|
| Key fi nancial data | 114 |
| Reserve quantity information | 115 |
| Shareholder information | 116 |
| Defi nitions | 117 |
References in this Annual Report to gross estimated contingent resources of the Johan Sverdrup discovery of 1,700 to 3,300 MMboe, include 800 to 1,800 MMboe in PL501 (Lundin Petroleum working interest 40%) and 900 to 1,500 MMboe in PL265 (Lundin Petroleum working interest 10%). Lundin Petroleum's estimated contingent resources as at 31 December 2012 of 922.9 MMboe worldwide, 715.5 MMboe in Norway and 640.0 MMboe in the Johan Sverdrup discovery, include Lundin Petroleum's working interest share of the mid-range estimated contingent resources for the Johan Sverdrup discovery of 520.0 MMboe in PL501 and 120.0 MMboe in PL265. The contingent resource estimates in PL501 have been prepared by Lundin Petroleum, as operator of PL501, and were audited by Gaff ney, Cline & Associates on behalf of Lundin Petroleum as at 31 December 2011. The contingent resource estimates in PL265 have been prepared by Statoil, as operator of PL265, and have not been audited on behalf of Lundin Petroleum. See Reserves, Resources and Production on pages 12 to 17.
References to "Lundin Petroleum" or "the Company" pertain to the corporate group in which Lundin Petroleum AB (publ) (company registration number 556610–8055) is the Parent Company or to Lundin Petroleum AB (publ), depending on the context.
Unless otherwise stated, all reserves estimates in this Annual Report are the aggregate of "Proved Reserves" and "Probable Reserves", together also known as "2P Reserves". See "Reserves, Resources and Production" on pages 12 to 17.
OVER THE LAST DECADE LUNDIN PETROLEM HAS ADOPTED A SUCCESFUL EXPLORATION DRIVEN ORGANIC GROWTH STRATEGY. EXPLORATION DISCOVERIES ARE CONVERTED INTO RESERVES AND PRODUCTION FOLLOWING APPRAISAL AND DEVELOPMENT PROGRAMMES WHICH ARE THEN OPTIMISED THROUGHOUT THEIR LIFESPAN BY UTILISING THE LATEST TECHNOLOGY AND THE EXPERIENCE OF HIGHLY SKILLED PEOPLE. THE STRATEGY HAS BEEN SUCCESSFUL IN OUR FRENCH, MALAYSIAN AND IN PARTICULAR, OUR NORWEGIAN OPERATIONS WHERE WE ARE IN THE PROCESS OF DEVELOPING THE BRYNHILD, BØYLA, EDVARD GRIEG AND THE GIANT JOHAN SVERDRUP DISCOVERIES.
THIS IS BY NO MEANS THE END OF OUR ORGANIC GROWTH PHASE. WE BELIEVE THAT WE HAVE THE ASSETS, TECHNOLOGY AND EXPERTISE TO MAKE FURTHER SIGNIFICANT DISCOVERIES. OVER THE COMING YEARS IT IS OUR PLAN TO DRILL 10 to 15 EXPLORATION WELLS PER YEAR.
| OPERATIONAL HIGHLIGHTS 2012 |
» Major appraisal programme on Johan Sverdrup, off shore Norway with successful drilling of six wells |
|---|---|
| » Geitungen discovery, off shore Norway – Statoil's resource estimate of 140 – 270 MMboe |
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| » Successful appraisal of the Bertam discovery, off shore Malaysia |
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| » Two gas discoveries, off shore Malaysia, Berangan and Tembakau |
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| » Record production of 35,700 boepd | |
| » Reserves and contingent resources > 1 billion barrels | |
FINANCIAL RESULTS 2012
| FORECAST 2013 |
» MUSD 1,100 of development expenditure predominantly off shore Norway - Edvard Grieg - Brynhild - Bøyla |
|---|---|
| » MUSD 150 of appraisal expenditure predominantly on Johan Sverdrup, off shore Norway |
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| » MUSD 460 of exploration expenditure predominantly off shore Norway, off shore Malaysia and off shore Indonesia - 18 exploration wells targeting over 600 MMboe unrisked, net prospective resources |
LUNDIN PETROLEUM'S BUSINESS MODEL IS TO GENERATE SHAREHOLDER VALUE THROUGH THE EXPLOITATION OF HYDROCARBONS. LUNDIN PETROLEUM'S STRATEGY OF ORGANIC GROWTH INVOLVES IDENTIFYING CORE AREAS OF FOCUS AND THEN ESTABLISHING A TEAM OF PROFESSIONAL TECHNICAL STAFF WITH EXPERIENCE IN THOSE AREAS TO USE THE LATEST TECHNOLOGIES TO EXPLORE FOR OIL AND GAS. COMMERCIAL DISCOVERIES WILL BE APPRAISED, AND WHERE THEY ARE DEEMED TO BE ECONOMIC, PROGRESSED THROUGH THE DEVELOPMENT PHASE TO THE PRODUCTION STAGE. THE CASH FLOW GENERATED FROM PRODUCTION WILL BE REINVESTED IN EXPLORATION AND DEVELOPMENT. LUNDIN PETROLEUM BELIEVES THAT IT IS THROUGH THE DEVELOPMENT OF THIS BUSINESS MODEL THAT IT HAS ACHIEVED SUCCESS IN THE PAST AND WILL CONTINUE TO DELIVER RESULTS IN THE FUTURE.
As an international oil and gas exploration and production company operating globally, Lundin Petroleum aims to explore for and produce oil and gas in an economically, socially and environmentally responsible way, for the benefi t of all stakeholders, including shareholders, employees, business partners, host and home governments and local communities.
Lundin Petroleum applies the same standards to its activities worldwide to satisfy both its commercial and ethical requirements. Lundin Petroleum strives to continuously improve its performance and to act in accordance with good oilfi eld practice and high standards of corporate citizenship.
Lundin Petroleum is pursuing the following strategy:
Lundin Petroleum focuses on building core exploration areas in specifi c countries with a clear objective to grow organically. Our strategy is to improve our technical understanding and thereby to develop new play concepts. We achieve this by using the latest technology including acquiring and processing 3D seismic and by building teams of talented and experienced people.
Lundin Petroleum focuses on organically increasing its reserves base. Following exploration and appraisal, shareholder value is created through the conversion of discoveries into reserves and production. Our strategy is to continuously optimise the reserves and production throughout the life cycle of the asset by utilising the latest technologies and, above all, skilled people.
Throughout all stages of the business cycle, Lundin Petroleum seeks to generate shareholder value. All elements of the asset portfolio are constantly reviewed to determine that their value is fully refl ected in the Lundin Petroleum share price. If it is determined that the value of an asset is not being fully refl ected within the Lundin Petroleum share price, Lundin Petroleum will review all available options to determine how to realise the full value of that asset.
2012 was yet another successful year for our Company. We have exceeded our production forecasts once again and this, coupled with our low operating costs and cash taxes, has resulted in a record operating cash fl ow of more than MUSD 830 for the year.
Since the end of 2001, we have increased our share price by over 50 times to a current market capitalisation exceeding USD 8 billion. This has been done without any issuance of new cash equity other than employee stock options. Our strong operating cash fl ow coupled with the availability of a new USD 2.5 billion bank facility means that we will be able to grow our business without further dilution to our shareholders. We have the ability to quadruple our existing production to over 150,000 boepd over the next seven years through the development of our existing Norwegian discoveries Brynhild, Bøyla, Edvard Grieg and Johan Sverdrup. This growth in production will have a major positive impact on our future fi nancial performance. At the same time we will continue to concentrate on increasing our resource base through a major exploration drilling programme focused predominantly on Norway and South East Asia.
For the fi nancial year 2012, we generated record operating cash fl ow of MUSD 831.4 and EBITDA of MUSD 1,144.1 which represent increases of 23 percent and 13 percent respectively when compared to the previous year. Profi t after tax for the period was MUSD 103.9 and was negatively impacted by non-cash exploration and asset impairment costs incurred in the fourth quarter. The nature of our business involves the drilling of successful exploration wells, such as Johan Sverdrup where the asset continues to be valued in our balance sheet based upon historical costs, as well as unsuccessful wells where the costs are immediately expensed. We have increased the number of wells to be drilled per year as our business has grown and this will likely mean that our profi tability will continue to be negatively impacted by expensing unsuccessful wells. However the valuation of our business will continue to be driven by our ability to discover new resources through our exploration drilling programmes - even though this will not immediately be refl ected in the profi tability of the Company.
Lundin Petroleum's success has been due to our ability to increase our resource base. Today we have net resources, including reserves and contingent resources of over 1 billion barrels recoverable, which are predominantly oil. Our reserves at the end of 2012 were 201.5 million barrels of oil equivalent. Whilst last year's reserve replacement ratio was lower than in previous years, I think everyone would agree that this will change when the contingent resources from the Johan Sverdrup fi eld in Norway are booked as reserves. There is little doubt that the Johan Sverdrup fi eld is commercial but reserves will not be booked until the signing of a unitisation agreement and the submission of the fi eld development plan both scheduled for the end of 2014.
The Johan Sverdrup appraisal programme is ongoing and will continue throughout 2013 with at least four more appraisal wells. Johan Sverdrup is the largest discovery in the North Sea since the mid 1980's covering a large area. 15 appraisal wells, including the discovery well, have already been drilled and the preparation of a geological and reservoir model to incorporate all the acquired data is ongoing. Statoil as a working operator for the Johan Sverdrup fi eld development has decided to delay the release of updated resource numbers until later this year when the appraisal programme and a conceptual development plan will be completed.
Production for 2012 was 35,700 boepd, which was again, in the upper half of our original 32,000 to 38,000 boepd production guidance. Strong performance from the Alvheim and Volund fi elds, off shore Norway more than made up for lower production than forecast from the Gaupe fi eld, off shore Norway and the early termination of production from the Oudna fi eld, off shore Tunisia. I am pleased that we have consistently achieved our production forecasts over recent years despite the uncertainties and risks in our business.
In 2013 we expect our net production to average between 33,000 boepd and 38,000 boepd for the year and to exit the year at in excess of 40,000 boepd when the Brynhild fi eld reaches plateau production.
We reiterate our guidance of production in excess of 70,000 boepd by the end of 2015 following fi rst production from the Edvard Grieg fi eld.
Our development projects, Brynhild, Bøyla and Edvard Grieg in Norway, are all progressing satisfactorily.
We have increased our equity interest in the Brynhild fi eld to 90 percent. Brynhild is a subsea tie-back to Shell's Pierce FPSO facility in the United Kingdom with a forecast gross plateau production of 12,000 boepd. The Maersk Guardian rig will commence the four Brynhild development wells during the second quarter of 2013. The Edvard Grieg development project is also progressing satisfactorily as we progress through the execution phase. It is very encouraging to see recent photographs of the Kværner Verdal yard on the west coast of Norway where the Edvard Grieg jacket is starting to take shape. The Edvard Grieg project remains on budget and on schedule for fi rst oil in late 2015.
We are in the process of awarding a front end engineering (FEED) contract for the Bertam fi eld development project, off shore Malaysia and still plan to make a fi nal investment decision in 2013.
Five new appraisal wells were drilled on Johan Sverdrup in 2012 by Lundin Petroleum and Statoil. Each of the new wells provides important information for development planning as well as an understanding of the size of the resource. The resource estimates are primarily infl uenced by depth conversion, reservoir thickness and quality and oil/water contact assumptions. Lundin Petroleum will drill at least a further two appraisal wells and one exploration well in PL501 in 2013 and Statoil will drill two wells in PL265 and one in PL502.
The forward plan still remains for Statoil as working operator of Johan Sverdrup to complete a conceptual development plan by the end of 2013 and a development plan submission by the end of 2014.
We are very excited about our 2013 exploration programme which involves the drilling of 18 exploration wells in Norway, South East Asia, France and the Netherlands. The budget of over MUSD 460 will be the largest in the Company's history and will be predominantly focused on Norway which will account for about 75 percent of the expenditure.
In Norway, we will concentrate on three core exploration themes being:
We are drilling six exploration wells in the Utsira High area with high expectations for the Luno II (PL359), Kopervik (PL625) and Torvastad (PL501) prospects which all individually have the potential to be material discoveries. In the Barents Sea we continue to increase our acreage in the ongoing licensing rounds and are today one of the largest players in the region. Our exploration drilling programme will continue in 2013 with the drilling of the Gohta prospect in PL492. We have acquired a large acreage position in the northern Norwegian Sea targeting an underexplored Jurassic high area where we will drill a large prospect in 2013 in PL330. I hope this will result in the opening up of the area which contains numerous prospects and leads in both PL330 and adjoining licences which we have secured.
We continue to make good progress with our exploration programme in Malaysia. Following the successful appraisal of the Bertam discovery in PM307 we acquired new 3D seismic on trend with the discovery. This led to the discovery of the 300 bcf Tembakau gas discovery in 2012 also located in PM307. I believe Tembakau which is a material discovery close to existing gas infrastructure has the potential to be commercialised. It is clear that the key to exploration success in Malaysia is to have access to modern 3D seismic data and we plan to continue our proactive exploration of the area in 2013.
The markets have begun 2013 with oil prices increasing. There is a growing realisation that the world economy is slowly recovering and if this continues will result in an increase in oil demand. China is the largest growth market for oil and with its growth rates appearing to bottom out I think we can expect this to further support demand. The geopolitical climate remains an issue with increasing instability in North Africa and little signs of improvement in the Middle East. This will put further pressure on forecasts of oil supply which I believe are already over estimated. Unconventional oil production in North America is certainly increasing but I believe the increased supply will be easily accommodated through growing demand from the developing world and supply declines from mature production areas. As a result I believe oil prices will remain fi rm.
The oil industry places a great responsibility upon people to make the correct decisions, whether it is in relation to the correct site at which to drill a well or the best plan of development to take a discovery through to production. All of these decisions have to be based upon detailed technical knowledge supported by a sound commercial understanding.
At Lundin Petroleum we have the experienced people capable of making these decisions. On pages 30 to 33 of this annual report, in an extract from a speech I gave at the ONS conference, I explain how people have contributed to the growth of our business, particularly through the discovery of the giant Johan Sverdrup fi eld off shore Norway.
Finding and retaining experienced professionals in our industry is a challenge we face every day. Exploration success has led to development projects for which we have recruited experienced development personnel and these developments will lead to operated production activities for which we are in the process of building an operating team.
We believe that the rewards for our employees provide both a competitive remuneration structure as well as providing the opportunities and challenges that our portfolio of assets off er for personal development.
There is no new information to report in respect of the allegations regarding our historical operations in Sudan and Ethiopia. We have and will continue to assist the Swedish prosecutor as requested in relation to his investigation.
In respect of our ongoing commitment to Corporate Social Responsibility we have re-affi rmed our engagement towards transparency by becoming an Extractive Industries Transparency Initiative (EITI) Supporting Company. As an EITI Supporting Company, Lundin Petroleum will report in accordance with EITI requirements in Norway and will promote transparency especially within the oil and gas industry and contribute to the fi ght against corruption.
Lundin Petroleum has delivered on its promise to generate shareholder value through exploration success. Our challenge now is to deliver further exploration success and to convert the discoveries that we have already made into cash fl ow through the completion of our operated development projects.
Yours sincerely,
C. Ashley Heppenstall President and CEO
Lundin Petroleum achieved a record year in terms of production and cash fl ow generation in 2012. To put our annual production of 13 million barrels of oil equivalent in context, it represents about 21.5 percent of Sweden's annual consumption of transport fuel or the energy output from three medium to large sized power plants. The ongoing development projects in Norway will ensure a steady growth in production throughout the coming years. When Johan Sverdrup reaches plateau production, I expect the Company's production to have grown by some 400 percent.
What is even more impressive is that over 90 percent of that growth will come from Norway, a politically and fi scally stable country where our product is priced at a premium to Dated Brent crude. However we should not forget that the underlying value of the Company is based on the number of barrels of oil equivalent of reserves and resources in the ground. Total booked reserves today stand at 202 million boe compared to contingent resources of almost 1 billion boe. In order for a contingent resource to be upgraded into reserves, it has to go through several stages of investigation from appraisal drilling to the formulation of a conceptual development plan and in some cases unitisation. The discovery known as Johan Sverdrup on PL501 and PL265, the largest discovery anywhere in the world in 2010, continues with appraisal drilling and it is expected that the PDO will be submitted in the fourth quarter of 2014. A unitisation process will proceed in parallel with the PDO submission (Lundin Petroleum has 40 percent working interest in PL501 and 10 percent in PL265). We would therefore expect to book Johan Sverdrup as reserves in 2015. But we will not stop there; Lundin Petroleum will drill 15 exploration wells in 2013 in Norway and South East Asia. Apart from the ongoing exploration programme in Malaysia and Indonesia, we are evaluating an oil discovery on Block PM308A off shore Peninsular Malaysia, which I hope will result in Lundin Petroleum's fi rst development in that part of the world.
Since the acquisition of the North Sea assets in 2003, Lundin Petroleum's growth has been purely organic (i.e. without acquisitions or share issues for fi nancing purposes). The Company's market value has grown exponentially during that period. This growth coupled with a dividend to shareholders in 2010 of USD 750 million, through the sale of the UK assets is a most impressive achievement. The Company is suffi ciently funded to carry out the extensive exploration and development programme thanks to a combination of a USD 2.5 billion credit line established by 25 strong international banks and, of course, to our own strong cash fl ow. In 2013 alone, the Company expects to spend approximately USD 1.7 billion on exploration, appraisal and development. This capital spending programme should certainly unlock further value and ensure continued growth.
I am very proud of the men and women at Lundin Petroleum who work around the world and around the clock to deliver energy to meet the world's ever increasing needs. They do so without losing sight of the impact we have on the local communities and of the critical importance of following rules and regulations and best industry practice concerning health, safety and the environment. Lundin Petroleum is regularly rated for its ESG (environmental, social and governance) performance by various agencies such as MSCI and was placed on STOXX's ESG Leadership Index in 2012. The Board of Directors pays close attention to these matters which are of critical importance to the Company's raison d'être. I am indebted to the Board, the management, and every employee for taking Lundin Petroleum to new heights as we seek outstanding returns for our shareholders in a socially and environmentally responsible manner.
Finally a big thank you to you, fellow shareholders, for your continued support and loyalty.
Yours sincerely,
Ian H. Lundin Chairman of the Board
Production forecast 2013 33,000–38,000 boepd
LUNDIN PETROLEUM IS ACTIVE IN ALL STAGES OF THE LIFE CYCLE OF AN UPSTREAM OIL COMPANY. CONCENTRATED ACREAGE POSITIONS PROVIDE DRILLING PROSPECTS WHICH ARE CLASSIFIED AS PROSPECTIVE RESOURCES. HYDROCARBONS DISCOVERED THROUGH EXPLORATION DRILLING ARE CLASSIFIED AS CONTINGENT RESOURCES AND ARE APPRAISED TO DETERMINE COMMERCIALITY AND FUTURE DEVELOPMENT POTENTIAL. WHEN A DISCOVERY IS DEEMED COMMERCIAL AND THERE IS A CERTAINTY AS TO DEVELOPMENT, THE HYDROCARBONS ARE CLASSIFIED AS RESERVES.
1 Excludes Torvastad prospect and proposed well in PL410 in Norway, Malaysia exploration drilling and Gurita well in Indonesia.
2 PL501 mid range of previously guided 800 -1,800 MMboe gross and PL265 mid range of Statoil estimate for Johan Sverdrup and Geitungen discovery
| End 2011 | 210.7 |
|---|---|
| – Produced (excluding sales/acquisitions) | -13.1 |
| + New Reserves (excluding sales/acquisitions) | -0.2 |
| – Sales/ + Acquisitions | +4.1 |
| End 2012 | 201.5 |
Oil price (Brent) USD 100/bbl + 2% escalation on oil price and costs
Lundin Petroleum had 201.5 million barrels oil equivalent (MMboe) of reserves at the end of 2012. After ten years of reserves growth (see graph on this page), 2012 resulted in a two percent increase in reserves when compared to end year 2011, following the acquisition of an extra 20 percent of the Brynhild fi eld in Norway and excluding 2012 production of 13.1 MMboe.
The Reserves Changes graph on this page shows a signifi cant reserves addition related to the Bertam development in Malaysia which passed the conceptual development phase and is moving towards a fi eld development plan submission in 2013. Furthermore the development plan for the Brynhild fi eld in Norway was revised with the inclusion of a fourth development well, resulting in a reserves increase. Lundin Petroleum's two main producing fi elds in Norway, Alvheim and Volund also saw a reserves increase due to good production results and the inclusion of an Alvheim infi ll well to be drilled in 2014.
These increases in reserves were off set by strong 2012 production as well as reserves reductions due to poor production performance in the Gaupe fi eld in Norway and the Komi fi elds in Russia.
Of the 201.5 MMboe of reserves, 91 percent is related to oil reserves and 92 percent of the total reserves are situated in tax-royalty regimes. Lundin Petroleum quotes all of its reserves in working interest barrels of oil equivalent. All reserves are independently audited by ERC-Equipoise Ltd. (ERCE).
Lundin Petroleum also has a number of discovered oil and gas resources which classify as contingent resources. Contingent resources are known oil and gas resources not yet classifi ed as reserves due to one or more contingencies. Work is continuously on going to remove these contingencies and to move contingent resources to reserves.
The Johan Sverdrup fi eld in Norway constitutes almost two thirds of the 923 MMboe1 of Lundin Petroleum's best estimate contingent resources. The fi eld was discovered in 2010 and included in contingent resources at the end of 2010. At that stage the fi eld size was uncertain and an appraisal campaign was started to delineate the fi eld and establish a conceptual development plan. This work resulted in a large contingent resource update in 2011 as results indicated a much larger structure (see Contingent Resource History graph). Although there is no doubt that the Johan Sverdrup fi eld will be developed and will be moved to reserves in the near future, the booking of reserves is contingent upon the formulation of a conceptual development plan as well as the successful outcome of unitisation discussions.
Following exploration success in the 2011 and 2012 drilling campaigns in Malaysia, 82 MMboe of gas contingent resources (net to Lundin Petroleum) were discovered in Sabah, east Malaysia and in Peninsular Malaysia. In Peninsular Malaysia there is an established gas market and infrastructure is relatively close. The Tembakau gas discovery (306 bcf gross best estimate contingent resources) is contingent on appraisal and the formulation of a conceptual development plan. In Sabah, east Malaysia the resource is contingent on certain local gas market aspects.
Most of the contingent resource estimates have been independently audited by ERCE. Gross contingent resources in the PL501 part of Johan Sverdrup (WI 40%) have been estimated at between 800 and 1,800 MMboe as audited by Gaff ney Cline and Associates (GCA) as at the end of 2011. Appraisal is still ongoing and ERCE has not reviewed any update to the end 2011 estimates. In 2011, Statoil, the operator of PL265, has estimated gross contingent resources of 900 to 1,500 MMboe in the PL265 part of Johan Sverdrup (WI 10%). Statoil has also estimated that the 2012 Geitungen discovery in PL265 contains between 140 and 270 million barrels of gross recoverable oil (WI 10%). The Statoil estimates have not been independently audited by ERCE or GCA on behalf of Lundin Petroleum.
Lundin Petroleum has a substantial contingent resource portfolio which provides a strong resource base for future production growth.
1 PL501 mid range of previously guided 800 -1,800 MMboe gross and PL265 mid range of Statoil estimate for Johan Sverdrup and Geitungen discovery
1 Excludes Torvastad prospect and proposed well in PL410 in Norway, Malaysia exploration drilling and Gurita well in Indonesia.
2 PL330 resources are partner estimates
Lundin Petroleum's business model is to grow organically through exploration. This means identifying and maturing exploration targets, drill exploration wells, appraise discoveries, develop and fi nally produce. To be successful with this strategy access to world class exploration acreage and fi rst class people is needed. Lundin Petroleum has concentrated on two core exploration areas, Norway and South East Asia.
In Norway, Lundin Petroleum is now the second largest operated acreage holder after Statoil. The graph on this page shows the continuous growth in the number of licences held by Lundin Petroleum in Norway. In the 2012 APA round Lundin Petroleum were awarded seven new licences.
Since South East Asia was established as a core area in 2007, Lundin Petroleum now has a total of 12 exploration licences in Malaysia and Indonesia. In Malaysia, Lundin Petroleum is the second largest acreage holder after Petronas.
In 2013, Lundin Petroleum is planning to drill (operated and non-operated) 18 exploration wells, targeting in excess of 600 MMboe of net unrisked prospective resources. Ten exploration wells are planned to be drilled in Norway and fi ve are planned to be drilled as part of the drilling campaign in Malaysia and Indonesia. Three wells are planned to be drilled in France and the Netherlands.
Lundin Petroleum only discloses prospective resource estimates for those prospects that will be drilled in the following year. However, many more prospects and leads have been identifi ed from the large exploration licence portfolio and are being matured to be drilled in future years. In Norway rig capaciity is already secured until 2016 to drill some nine to twelve exploration wells per year. In South East Asia, large areas of new 3D seismic have been acquired in core areas to help mature additional prospectivity and to formulate drilling campaigns in the years to come.
Lundin Petroleum produced 13.1 MMboe during 2012 at an average rate of 35,700 boepd. In early 2012 production for 2012 was forecasted to between 32,000 and 38,000 boepd and for the fourth consecutive year Lundin Petroleum produced within the guided range.
Continued strong production in the Alvheim and Volund fi elds was partly off set by disappointing production from the Gaupe fi eld in Norway and the Singa fi eld in Indonesia. Gaupe was brought onstream at the end of the fi rst quarter 2012 and has proved to be a more compartmentalised reservoir than initially envisaged, resulting in a signifi cant reserves write down. Singa production was impacted by a prolonged shut down of one of the producing wells awaiting repairs to the wellhead. In early 2012 all the production from the Oudna fi eld in Tunisia was also lost following a rupture of one of the risers to the Ikdam FPSO during very heavy weather. The repairs were deemed uneconomic and the Oudna fi eld was abandoned during 2012.
Lundin Petroleum's production forecast for 2013 is in the range of 33,000 to 38,000 boepd, at similar levels to 2012. Good production is expected from the Alvheim and Volund fi elds following the completion of one new Alvheim well at the end of 2012 and the start-up of one newly drilled Volund well in early 2013. Production for the third quarter of 2013 will be negatively impacted by a maintenance shutdown on the Alvheim FPSO. The Brynhild fi eld is expected to come onstream in the fourth quarter of 2013. The project is currently on schedule and is expected to increase our net production to 40,000 boepd by the end of the year.
During 2012, the development plans for the Bøyla and Edvard Grieg fi elds were approved and with fi rst oil expected in 2014 and 2015 respectively, Lundin Petroleum is forecasted to double its production by end 2015. This increase excludes any contribution from the potential Bertam fi eld development in Malaysia for which a development plan is scheduled to be submitted in 2013, with fi rst oil in 2015 at an estimated gross plateau rate of about 15,000 bopd. Lundin Petroleum has a 75 percent interest in Bertam.
The giant oil fi eld Johan Sverdrup, with fi rst oil planned in 2018, has the potential to quadruple the current net production when Johan Sverdrup reaches plateau production. This excludes any contribution from the rest of the contingent resource base, or any contribution from the 10 to 15 exploration wells Lundin Petroleum is planning to drill each year.
Lundin Petroleum calculates reserves and resources according to 2007 Petroleum Resources Management System (PRMS) Guidelines of the Society of Petroleum Engineers (SPE), World Petroleum Congress (WPC), American Association of Petroleum Geologists (AAPG) and Society of Petroleum Evaluation Engineers (SPEE) and in compliance with the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) and the Canadian National Instrument 51–101 Standards of Disclosure for Oil and Gas Activities. Lundin Petroleum's reserves are audited by ERC-Equipoise Ltd. (ERCE), an independent reserves auditor. Reserves are defi ned as those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. Estimation of reserves is inherently uncertain and to express an uncertainty range, reserves are subdivided in Proved, Probable and Possible categories. Lundin Petroleum reports its reserves as Proved plus Probable (2P) reserves.
Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and governmental regulations. Proved reserves can be categorised as developed or undeveloped. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confi dence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimates.
Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of estimated Proved plus Probable reserves.
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 an associated chance of discovery and 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.
18 Lundin Petroleum ANNUAL REPORT 2012
Oil remains the primary source of world energy consumption and is estimated to remain so for decades to come. Apart from the years 2008/2009 the world's oil demand has increased every year since 1994 with a CAGR (Compounded Annual Growth Rate) of 1.4 percent over this period up to 2012. The world's oil demand in 2012 amounted to just below 90 million barrels per day compared to less than 70 million barrels per day as recently as the mid-nineties. Non-OECD economic growth is continuing to fuel the demand for oil whilst OECD oil demand is continuing to fall due to sluggish economic growth and due to gains in fuel effi ciency. The oil consumption propensity in the non-OECD economies is still relatively low but as these economies continue to grow and become more industrialised this propensity of consumption will also grow despite the continued improvement in energy effi ciency. Oil consumption is forecast to increase further over the next decades driven by demand from the transportation sector, in particular from heavy duty vehicles. Demand from personal vehicles is forecast to remain relatively fl at despite that the world fl eet of personal vehicles is projected to double to 1.6 billion vehicles by 2040.
The world's current annual oil consumption amounts to roughly 32 billion barrels. This means that to retain a constant reserve base, which in turn ensures a suffi cient level of oil supply, the world needs to replace 32 billion barrels of oil every year either through new discoveries or through improved recovery from existing discoveries. Over recent years the average amount of oil discovered per year amounts to only roughly one third of the world's annual oil consumption. In addition to annual consumption consistently exceeding new volumes discovered the supply level of oil is also facing challenges from continuous decline from the older fi elds. The world oil supplies are to a large degree coming from older oil fi elds where production is now in decline. There are diff ering opinions on the world's decline rate from the currently producing fi elds but researchers point to a decline rate of more than 5 percent per annum which translates to a reduction of daily production from existing fi elds of around 4.5 million barrels or more.
The average oil price for Dated Brent through 2012 was USD 112 per barrel which essentially is fl at relative to the 2011 Dated Brent price. Since the beginning of the 20th century the oil price level, adjusted for infl ation, during 2011 and 2012 has not been surpassed by any other year during this period. The recent strong oil price has enabled certain discovered resources to become commercially viable despite the high development and production costs associated with such resources. Typical resources falling into this high cost category are very deep water and/or deep reservoir developments and unconventional resources such as shale oil and tar sands. Whilst such marginal developments increase the supply of oil, such supply can only be relied on as long as the oil price stays strong because in a lower oil price environment these projects become uneconomic.
A continued increase in the demand for oil and a relatively large decline rate on the older producing fi elds makes Lundin Petroleum a fi rm believer in strong oil prices going forward.
Source: IEA WEO 2012
Investors rely on numerous valuation metrics when deciding which company to invest in. As illustrated in the table on page 21 there are many metrics that can be used to value a company and each of these metrics serves a unique and particular valuation estimate. Each of these metrics focuses upon a diff erent valuation component and provides a diff erent valuation outcome. An investor, however, will normally not base his investment decision on any singular valuation metric, instead such an investment decision will in all likelihood be based upon a combination of valuation metrics, fi nancial ratios and other factors such as the company's funding situation, management's track record and prospects for growth.
The diffi culty that an investor faces when comparing companies using these valuation metrics is that companies are often at a diff erent stage in the lifecycle of an oil company and direct comparisons may not give a meaningful valuation measurement. A company with mature assets may give good results on cash fl ow multiples but may have no resources for future growth. A company with substantial development projects will give a poor result on the same cash fl ow metric whilst having enormous growth potential.
The relevance of each metric to a company must be fully understood before meaningful comparisons can be made.
Companies with excess cash have the choice of re-investing this cash into their existing asset base, to repay debt or to return this cash to its shareholders through dividends or through buying back its own shares. As companies grow and become more and more cash generative, they have a tendency to gravitate towards becoming regular dividend paying companies. Once a company becomes a proven and reliable regular dividend paying company the overriding valuation metric for such a company tends to be its dividend yield.
| BANK/BROKER | ANALYST | CONTACT |
|---|---|---|
| ABG Sundal Collier | Anders Holte | [email protected] |
| Arctic Securities | Christian Yggeseth | [email protected] |
| Bank of America Merrill Lynch | Alexander Holbourn | [email protected] |
| BMO Capital Markets | Kimberley Thompson | [email protected] |
| Canaccord Genuity | Thomas Martin | [email protected] |
| Carnegie ASA | Alexander Vilval | [email protected] |
| Cheuvreux Nordic | Joakim Ahlberg | [email protected] |
| Citigroup Global Market | Michael Alsford | [email protected] |
| Credit Suisse | Thomas Adolff | thomas.adolff @credit-suisse.com |
| Danske Capital | Andre Baustad Benonisen |
[email protected] |
| Deutsche Bank | Phil Corbett | [email protected] |
| DnB Nor | Espen Hennie | [email protected] |
| First Securities AS | Teodor Sveen Nilsen | tsn@fi rst.no |
| GMP Securities Europe LLP | Tao Ly | [email protected] |
| Goldman Sachs International | Christophor Jost | [email protected] |
| Handelsbanken Capital Markets |
Anne Gjøen | [email protected] |
| Macquarie Securities Group | Mark Wilson | [email protected] |
| Morgan Stanley | Jamie Maddock | [email protected] |
| Nomura | Tom Robinson | [email protected] |
| Nordea | Christian Kopfer | [email protected] |
| Öhman | Petter Hjertstedt | [email protected] |
| Royal Bank of Canada | James Hosie | [email protected] |
| Scotia Capital | Gavin Wylie | [email protected] |
| SEB Enskilda | Julian Beer | [email protected] |
| Société Générale | David Mirzai | [email protected] |
| Spare Bank 1 | Kristoff er Dahlberg | kristoff [email protected] |
| TD Securities | Shahin Amini | [email protected] |
| Wood Mackenzie | Tom Ellacott | [email protected] |
| Valuation Metrics | ||||
|---|---|---|---|---|
| Nominator | Denominator | Result | Strength | Weakness |
| EV / 2P RESERVES USD/boe | ||||
| Enterprise Value (EV) = Market Capitalisation + net debt |
Proved + Probable reserves as certifi ed by a reserves auditor as per standardised reserves defi nition (2P) |
Measures what value the stock market puts on each barrel of 2P reserves |
Enterprise value is easily derived as it is a function of the company's market capitalisation and net debt, both of which are normally readily available. 2P reserves are reported as per standardised defi nitions and are normally independently certifi ed. Most E&P companies report 2P reserves once per year. |
The valuation metric ignores all non-reserve assets such as contingent resources (2C) and prospective resources (exploration). The valuation metric also does not diff erentiate between reserves which are producing (more valuable) and reserves which are undeveloped or under development (less valuable) and nor does the metric refl ect on the cash generation of the business. |
| EV / 2P + 2C RESOURCES USD/boe | ||||
| Enterprise Value = Market Capitalisation + net debt |
2P reserves + contingent resources (2C) which may or may not be certifi ed independently |
Measures what value the stock market puts on each barrel of 2P reserves + 2C resources |
Enterprise value is easily derived as it is a function of the company's market capitalisation and net debt, both of which are normally readily available. Includes all discovered resources in the portfolio (reserves and resources). Most E&P companies report 2P reserves and 2C resources once per year. |
The valuation metric ignores prospective resources (exploration) in the company's portfolio. The valuation metric also does not diff erentiate between reserves which are producing (more valuable) and reserves which are undeveloped or under development (less valuable) and neither does the valuation metric take account of diff ering development costs or tax rates applicable to the undeveloped reserves and contingent resources. The valuation metric does not refl ect on the cash generation of the business. |
| EV / 2P + 2C + RP RESOURCES USD/boe | ||||
| Enterprise Value = Market Capitalisation + net debt |
2P reserves + 2C resources + Risked Prospective resources (RP resources) which may or may not be certifi ed independently |
Measures what value the stock market puts on each barrel of 2P reserves + 2C resources + risked prospective resources |
Enterprise value is easily derived as it is a function of the company's market capitalisation and net debt, both of which are normally readily available. Includes all discovered resources in the portfolio (reserves and resources) and all risked undiscovered resources in the portfolio. Most E&P companies report 2P reserves and 2C resources and risked prospective resources once per year. |
The valuation metric does not diff erentiate between reserves which are producing (more valuable) and reserves which are undeveloped or under development (less valuable) and neither does the valuation metric take account of diff ering development costs or tax rates applicable to the undeveloped reserves and contingent resources. The risked prospective resources is a highly subjective measurement as these resources have not been proven to exist. The valuation metric does not refl ect on the cash generation of the business. |
| P/E RATIO | ||||
| P = share price of the company |
E = Net post tax profi t per share (EPS) on an annualised basis |
Measures how many times annual earnings the market is valuing the company at |
The share price of a company is always readily available. The annual net profi t of a company is always readily available and is reported and audited according to standardised defi nitions all around the world. |
The net profi t of an E&P company only refl ects the assets which are in production. Undeveloped 2P reserves and 2C resources are not reported in the income statement until such time that these assets are in production and nor are any prospective resources (exploration) reported in the income statement. The valuation metric does not refl ect on the cash generation of the business. |
| EV/EBITDA | ||||
| Enterprise Value = Market Capitalisation + net debt |
EBITDA = Earnings before Interest, Tax, Depreciation and Amortization on an annualised basis |
Measures how many times annual EBITDA the market is valuing the company at including the company's net debt |
Enterprise value is easily derived as it is a function of the company's market capitalisation and net debt, both of which are normally readily available. The annual EBITDA of a company is always readily available and is reported and audited according to standardised defi nitions all around the world. |
The EBITDA of an E&P company only refl ects the assets which are in production. Undeveloped 2P reserves and 2C resources are not reported in the income statement until such time that these assets are in production and nor are any prospective resources (exploration) reported in the income statement. The EBITDA measure does not refl ect the possible cash taxes the producing reserves attract - the cash taxes can vary signifi cantly from concession to concession and therefore the post tax cash generation is not necessary linearly related to the EBITDA measure. |
| EV/OCF | ||||
| Enterprise Value = Market Capitalisation + net debt |
OCF = Operating Cash Flow on an annualised basis, normally the OCF is reported after cash tax payments |
Measures how many times annual OCF the market is valuing the company at including the company's net debt |
Enterprise value is easily derived as it is a function of the company's market capitalisation and net debt, both of which are normally readily available. The annual OCF of a company is always readily available and is reported and audited according to standardised defi nitions all around the world. |
The reported OCF of an E&P company only refl ects the assets which are in production. Undeveloped 2P reserves and 2C resources are not reported in the income statement until such time that these assets are in production and nor are any prospective resources (exploration) reported in the income statement |
| NET ASSET VALUE (NAV) | ||||
| Measures the value of projected discounted cash fl ows from the company's asset base |
Refl ects the company's entire cash generation from its asset base including as yet undeveloped 2P reserves and 2C resources and a deemed risked valuation of the company's prospective resources (exploration assets). |
Requires very detailed information on 2P reserves, 2C resources and risked prospective resources as well as fi scal regimes (tax) for each concession. This level of detail is normally not available to outsiders/third parties. Also requires discretionary assumptions on oil/gas prices, exchange rates and discount rates as well as estimates on development costs, costs which may not be incurred until many years in the future and hence diffi cult to estimate. |
Lundin Petroleum has exploration and production assets focused upon two core areas, Norway and South East Asia, as well as assets in France, Netherlands and Russia. Lundin Petroleum maintains an exploration focus seeking to generate shareholder value through exploration success and also has the resources to take exploration successes through to the production phase.
Lundin Petroleum entered Norway in 2003 and now holds 61 licences with activities spread between exploration, appraisal, development and production. It is planned to drill ten exploration wells in Norway in 2013. Exploration success has led to the Brynhild and Edvard Grieg developments, which will be the beginning of Lundin Norway operating its own production facilities. The Norwegian portfolio is dominated by the giant Johan Sverdrup fi eld, discovered by Lundin Petroleum in 2010 on PL501. Johan Sverdrup sits in two licences, PL501 and PL265, and is therefore subject to a unitisation process to allocate resources to all of the licence partners. 15 wells have been drilled on the structure to date to determine the size of the resources. Statoil, operator of PL265, has been appointed working operator of the Johan Sverdrup development planning phase. The Alvheim and Volund fi elds continue to produce at or above forecast generating strong cash fl ows for reinvestment in the business.
Lundin Petroleum has continued to develop its business in South East Asia through a second year of drilling operations in Malaysia as well as the preparation for commencement of a drilling campaign in Indonesia in 2013. Following discoveries in seven out of the ten wells drilled in Malaysia, Lundin Petroleum is looking for technical and commercial solutions to be able to develop the hydrocarbon resources discovered. The most mature discovery is the Bertam fi eld. Initial engineering studies are being carried out for a fi eld development.
Lundin Petroleum continues to generate good cash fl ow from its operations in France, Netherlands and Russia. Operations in Tunisia ceased during 2012 when the Oudna fi eld was decommissioned.
Top left: Bredford Dolphin semisubmersible drilling rig used for operations, off shore Norway. Top right: Containerised equipment aboard the Bredford Dolphin. Middle right: Drilling in the Paris Basin, onshore France. Bottom right: Drilling off shore Peninsular Malaysia.
Hydrocarbon Volume (MMboe) NORWAY IS LUNDIN PETROLEUM'S PRINCIPAL AREA OF OPERATION. LUNDIN PETROLEUM'S STRATEGY OF ORGANIC GROWTH HAS LED TO A PORTFOLIO OF NORWEGIAN LICENCES COMPRISING THE FULL SPECTRUM OF EXPLORATION AND APPRAISAL, DEVELOPMENT AND PRODUCTION ASSETS.
| NORWAY KEY DATA | 2012 | 2011 |
|---|---|---|
| Reserves (MMboe) | 152 | 162 |
| Contingent resources (MMboe) | 7151,2 | 697 1 |
| Average net production per day (Mboepd) | 27 | 23 |
| Net turnover (MUSD) | 1,057 | 975 |
| Sales price achieved (USD/boe) | 107 | 110 |
| Cost of operations (USD/boe) | 5 | 4 |
| Operating cash fl ow contribution (USD/boe) | 72 | 64 |
1 PL501 mid range of previously guided 800-1800 MMboe gross and PL265 mid range of Statoil estimate for Johan Sverdrup and Geitungen discovery for Johan Sverdrup PL265
2 Excludes Ragnarrock and Luno South discoveries
Norway continues to represent the majority of Lundin Petroleum's operational activities with production during 2012 accounting for 76 percent of total 2012 production and accounting for 75 percent of total reserves as at the end of 2012. Lundin Petroleum's contingent resources are also concentrated in Norway with 77 percent of total best estimate contingent resources as at year end 2012 relating to discoveries in Norway and thus underpinning Norway as the major production contributor for Lundin Petroleum in the years to come. Over the next three years the majority of Lundin Petroleum's development expenditure will be channelled into development projects in Norway.
The growth in production from the Norwegian assets continued in 2012 to an annual average production of 27,200 boepd, an increase of 17 percent over the 2011 production.
The net production from the Alvheim fi eld (Working Interest (WI) 15%) during 2012 was 11,800 boepd, an increase of fi ve percent relative to 2011. This increase was driven by two additional infi ll wells being completed on Alvheim during 2012, as well as an excellent uptime performance for the Alvheim FPSO of in excess of 95 percent. Two new infi ll wells on Alvheim were put into production in 2012 and this combined with the additional two infi ll wells drilled on Alvheim in 2011, and better than expected reservoir quality have resulted in an increase in gross ultimate recovery on Alvheim from 167 MMboe as at year end 2005 when the Alvheim plan of development was completed to 291 MMboe as at year end 2012, a 74 percent increase. The gross best estimate contingent resources associated with the Alvheim fi eld amounted to 52 MMboe as at year end 2012 and represent possible targets for future infi ll wells. In January 2013, the Alvheim partnership was awarded additional acreage to the north of the Alvheim fi eld through the 2012 APA licensing round, adding growth potential to the asset through securing near-fi eld acreage to unlock additional drilling targets. The cost of operations for the Alvheim fi eld for 2012 was below USD 5 per barrel excluding certain planned well intervention work.
The Volund fi eld (WI 35%) achieved average net production of 13,100 boepd during 2012 which is an increase of nine percent relative to 2011. The production during 2012 exceeded expectations due to better than expected reservoir performance and better than expected Alvheim FPSO uptime. An additional Volund development well was drilled during 2012 and commenced production in early 2013. Since commencing production in 2010 the reservoir performance from the Volund fi eld has exceeded expectations and as a result the certifi ed gross ultimate recovery has increased from 50 MMboe at the time of submitting the plan of development for the fi eld to 62 MMboe as at year end 2012. The cost of operations for the Volund fi eld during 2012 was below USD 2 per barrel driven by lower than expected production costs and better than expected production.
First production from the Gaupe fi eld (WI 40%) was achieved on 31 March 2012. Production from the Gaupe fi eld has been below forecast since the commencement of production. Technical analysis indicates that the two production wells are connected to lower hydrocarbon volumes than was forecast prior to production startup due to increased compartmentalisation of the reservoir.
The Edvard Grieg fi eld (WI 50%) was discovered by Lundin Petroleum in 2007 and the Norwegian Parliament approved the plan of development in June 2012. The development plan incorporates the provision for the coordinated development solution of the Edvard Grieg fi eld with the nearby Ivar Aasen fi eld (formerly Draupne) located in PL001B and operated by Det norske oljeselskap ASA. A plan of development was submitted for the Ivar Aasen fi eld in December 2012.
The Edvard Grieg fi eld is estimated to contain 186 MMboe of gross reserves with fi rst production expected in late 2015 and forecast gross peak production of approximately 100,000 boepd. The gross capital cost of the Edvard Grieg fi eld development is estimated at USD 4 billion and includes platform, pipelines and 15 wells. Contracts have been awarded to Kværner covering engineering, procurement and construction of the jacket and the
Illustrations of the Edvard Grieg platform and Brynhild subsea manifold.
Information brochures on the Edvard Grieg and Brynhild developments are available on www.lundin-petroleum.com
»
Left to right: Erik Sverre Jenssen, Chief Operating Offi cer and Torstein Sanness, Managing Director, Lundin Norway.
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. The development is progressing well and the construction work on the jacket which commenced in 2012 is ongoing. An appraisal well is planned to be drilled in the southeastern part of the Edvard Grieg fi eld in 2013 to target additional resources and ensure optimum development well placement.
A plan of development of the Brynhild fi eld in PL148 (WI 90%) was approved by the Norwegian Ministry of Petroleum and Energy in November 2011. The Brynhild fi eld contains gross reserves of 23.1 MMboe and is expected to produce at an estimated gross plateau production rate of 12,000 boepd with fi rst oil forecast in late 2013. The development involves the drilling of four wells tied back to the existing Shell operated Pierce fi eld infrastructure in the United Kingdom sector of the North Sea. The development is well advanced in respect of engineering and construction work and the Maersk Guardian jack-up rig will commence development drilling in the second quarter of 2013. During 2012, Lundin Petroleum announced the completion of a transaction with Talisman Energy to acquire an additional 20 percent interest in PL148, taking Lundin Petroleum's interest in the fi eld to 90 percent.
A plan of development for the Bøyla fi eld in PL340 (WI 15%) was approved by the Ministry of Petroleum and Energy in 2012. The Bøyla fi eld contains gross reserves of 21 MMboe and will be developed as a 28 km subsea tie-back to the Alvheim FPSO. Development drilling is planned to commence in 2013 with fi rst oil from the Bøyla fi eld targeted in the fourth quarter of 2014 at a gross plateau production rate of 19,000 boepd.
Lundin Petroleum discovered the Avaldsnes fi eld in PL501 (WI 40%) in 2010. In 2011, Statoil made the Aldous Major South discovery on the neighbouring PL265 (WI 10%) and following continuous appraisal drilling through 2011 it was determined that the discoveries were connected. In January 2012 the combined discovery was renamed Johan Sverdrup. Lundin Petroleum, as operator of PL501, and Statoil, as operator of PL265, have guided that the total resource range for Johan Sverdrup is between 800 and 1,800 MMboe on PL501 and between 900 and 1,500 MMboe on PL265. Both Lundin Petroleum and Statoil have also announced that a resource update is likely to be given towards the end of 2013 when a development concept selection is scheduled to be fi nalised.
The discovery is estimated to cover 180 km2 and appraisal wells have been drilled on both PL501 and PL265 that confi rm the oil water contact and the reservoir quality at each well location as well as the likely areal extent of the reservoir and the likely distribution of sands.
The Johan Sverdrup fi eld contains two major reservoir units of Jurassic age, the Draupne sandstone, also referred to as Volgian sandstone and the underlying Vestland group. The Draupne sandstone has excellent reservoir characteristics and contains the majority of the Johan Sverdrup resources. The Vestland group is still very good quality reservoir with multi Darcy sands, but has more shaly intervals (lower net to gross) and is laterally more variable. Seismic is good enough to allow accurate prediction of the reservoir top in most of the wells. The total Jurassic package thickness is variable throughout the fi eld but is in general thicker towards the west. During 2012, a total of three appraisal wells and two sidetracks on PL501 have been drilled and a further two appraisal wells on PL265 have also been completed, giving a total of 15 wells drilled on the structure.
In January 2012, the appraisal well 16/5-2S, located on PL501 was completed. The objective of the well was to delineate the southern fl ank of the Johan Sverdrup discovery within PL501. The well was deep to prognosis and as a result the reservoir was below the oil water contact.
Whilst Lundin Petroleum has not released any resource updates on Johan Sverdrup at the end of 2012, the results of the appraisal drilling to date, taken as a whole lead us to the view that the current most likely mid case Johan Sverdrup resources located in PL501 will be within the lower half of the previously guided 800 to 1,800 MMboe range.
It is likely that at least two further appraisal wells will be drilled in both PL501 and PL265 in 2013 with the main purpose of better defi ning the recoverable resource and to assist with the development planning strategy. One of the appraisal wells on PL501 will target the southwestern section of the discovery to the north of well 16/5-2 and one will target the northeastern section of the discovery to the east of well 16/2-13. One of the two appraisal wells on PL265 will target the fault margin with a
| Johan Sverdrup Well Summary | ||||
|---|---|---|---|---|
| WELL | LICENCE | STATUS | GROSS RESERVOIR | GROSS OIL COLUMN |
| 16/2-6 Avaldsnes | PL501 | Discovery | 23.5m | 17m |
| 6/2-6 T2 | PL501 | Sidetrack | 25m | 18m |
| 16/3-4 | PL501 | Appraisal | 14.5m | 14m |
| 16/3-4A | PL501 | Sidetrack | 4.5m | 4.5m |
| 16/2-8 Aldous MS | PL265 | Appraisal | 73m | 67.5m |
| 16/2-7 | PL501 | Appraisal | 47m | 7m |
| 16/2-9S Aldous MN | PL265 | Discovery | N/A | 8m |
| 16/2-7A | PL501 | Sidetrack | 23m | 16m |
| 16/2-10 Espevær | PL265 | Appraisal | 71m | 64.5m |
| 16/5-2S | PL501 | Appraisal | 9m | 0m |
| 16/2-11 | PL501 | Appraisal | 55.5m | 55.5m |
| 16/2-11A | PL501 | Sidetrack | 48.5m | 32.5m |
| 16/2-13S | PL501 | Appraisal | 25m | 25m |
| 16/2-13A | PL501 | Sidetrack | 27.5m | 11.5m |
| 16/2-12 Geitungen | PL265 | Discovery | 35m | 35m |
| 16/2-14 Esp. High | PL265 | Appraisal | 31.5m | 30m |
| 16/2-16 | PL501 | Appraisal | 55m | 1.5m |
| 16/2-16A T2 | PL501 | Sidetrack | 70m | 30m |
| 16/2-15 Kvitsøy | PL265 | Appraisal | 52m | 32m |
| 16/3-5 | PL501 | Appraisal | 30m | 30m |
drilling location between the wells 16/2-8 and 16/2-15 and one of the appraisal wells will be drilled on the western side of the fault close to the well 16/2-14.
Lundin Petroleum, as operator of PL501, has signed a Pre-Unit agreement with the partners within PL501 and PL265 for the joint fi eld development of the Johan Sverdrup fi eld. Statoil has been elected as working operator for the Pre-Unit phase. All parties in PL501 and PL265 have agreed a timetable for the Johan Sverdrup fi eld with development concept selection to be made by the fourth quarter of 2013, a plan of development to be submitted by the fourth quarter of 2014 and fi rst oil production by the end of 2018.
Lundin Petroleum follows an exploration strategy of identifying core areas and taking a major position with high ownership percentages and operatorship. Annual exploration programmes are then based around working these core areas as well as identifying new core areas.
The current core areas are:
In 2007 Lundin Petroleum found the key to the geological setting on the Utsira High area with the Edvard Grieg discovery. Subsequent drilling on similar structures around the Utsira High area led to the Avaldsnes discovery (Johan Sverdrup) in 2010. The work carried out in the area aligned with a greater understanding of the geology has generated multiple prospects.
In August 2012, the exploration well 16/2-12 targeting the Geitungen structure in PL265 (WI 10%) was successfully completed as an oil discovery. The well was located to the north of the Johan Sverdrup discovery and to the south of 16/2-9S Aldous Major North discovery. Data acquisition in the well indicates that the Geitungen structure is in communication with the Johan Sverdrup discovery. Preliminary calculations issued by the operator, Statoil, indicate that the size of the Geitungen discovery is between 140 and 270 million barrels of gross recoverable oil. Geitungen will be developed as part of the Johan Sverdrup development.
Lundin Petroleum's exploration programme in 2013 on the Utsira High area consists of six exploration wells, among others, targeting the Luno II, Kopervik and Torvastad prospects which are similar play concepts as Johan Sverdrup and Edvard Grieg.
Lundin Petroleum has one of the largest acreage positions in the Barents Sea close to Statoil's Skrugard and Havis oil discoveries. Lundin Petroleum drilled its fi rst operated well in the Barents Sea in 2011 resulting in the Skalle gas discovery. Two further wells were drilled in 2012.
In 2012, Lundin Petroleum drilled the Salina structure located on the west fl ank of the Loppa High in the Barents Sea, PL533 (WI 20%) and discovered gas/condensate. Preliminary calculations, made by the Norwegian Petroleum Directorate, give a range of gross discovered volume of between 174 and 246 bcf (29 and 41 MMboe) of recoverable gas/condensate. Further resource upside exists in fault compartments associated with the Salina structure.
A further exploration well was drilled in the Barents Sea in PL490 (WI 50%). The well was located 10 km to the north west of the Snøhvit fi eld and was targeting stacked targets Snurrevad and Juksa at the lower Cretaceous and upper Jurassic reservoirs. No reservoir was found to be present in the Snurrevad target at the Jurassic level. The thin oil bearing sands in the Juksa discovery are unlikely to be commercial although it is encouraging that the well encountered oil bearing sands as opposed to gas.
In 2013 Lundin Petroleum plans to drill the Gohta prospect on PL492 (WI 40%) targeting a stacked prospect at the Triassic and Carboniferous levels.
In June 2012, the drilling of exploration well 2/8-18S targeting the Clapton prospect on PL440s (WI 18%) in the southern North Sea was completed by the operator Faroe Petroleum. The well did not encounter hydrocarbons and was plugged and abandoned.
Lundin Petroleum has a two well programme in the southern North Sea in 2013. The Ogna well on PL453s (WI 35%), spudded in January 2013, targeting hydrocarbons in Upper to Middle Jurassic reservoirs was plugged and abandoned as a dry hole. The second well will be targeting the Carlsberg prospect on PL495 (WI 60%).
In October 2012, Lundin Petroleum announced the results of the Albert well in PL519 (WI 40%). The well encountered oil in thin Cretaceous reservoir sequence at the predicted level for the primary target but due to the thin thickness and uncertain distribution of the reservoir the discovery is currently deemed uncommercial. Further potential exists within the Albert structure if thicker Cretaceous reservoir section in this large structure can be identifi ed. Further exploration activity is planned in this area in 2014 with the drilling of the Storm prospect in PL555 where Lundin Petroleum holds a 60 percent interest and is operator.
Lundin Petroleum has built a signifi cant acreage position around the Utgard High area in the Norwegian Sea. The Utgard High area is on trend with the prolifi c Halten and Donna terraces. In 2013 the Sverdrup prospect on PL330 (WI 30%) will be drilled targeting Cretaceous and Jurassic reservoirs.
In January 2012, Lundin Petroleum was awarded ten exploration licences in the APA 2011 licensing round of which four are operated by Lundin Petroleum. In January 2013, Lundin Petroleum was awarded a further seven exploration licences in the APA 2012 licensing round of which two are operated by Lundin Petroleum. Four of the seven licences awarded are in the North Sea, two in the Norwegian Sea and one in the Barents Sea. Lundin Petroleum has submitted several licence applications for the 22nd Norwegian licensing round with awards expected to be announced by the Ministry of Petroleum and Energy in the fi rst half of 2013.
Lundin Petroleum's exploration programme in Norway for 2013 will consist of ten exploration wells for which drilling rigs have been secured.
Norway licence map showing core areas of operation
1 PL265 range provided by Statoil
» 15 producing wells, 8 multilaterals
» Net reserves 10.7 MMboe
» Skalle gas discovery in 2011
» Salina gas discovery in 2012
» Juksa drilled in 2012 - encountered thin oil bearing sands
» Gohta prospect planned to be drilled in 2013
» Carlsberg prospect PL495 (WI 60%) planned to be drilled in 2013
» Sverdrup prospect PL330 (WI 30%) planned to be drilled in 2013
HOW COULD A SMALL SWEDISH OIL AND GAS COMPANY FIND A MULTIBILLION BARREL RECOVERABLE OIL FIELD IN THE HEART OF THE NORWEGIAN NORTH SEA 45 YEARS AFTER THE AREA WAS OPENED UP FOR EXPLORATION?
The North Sea continental shelves of the United Kingdom and Norway are essentially the same geological formations and in sharing the hydrocarbon resources of the North Sea between Norway and the United Kingdom nature seems to have treated each country pretty much equally. However, the development of the United Kingdom and Norwegian sectors has taken place at a very diff erent speed over the last 45 years. Since 1965, approximately 1,400 exploration and appraisal wells have been drilled in Norway compared to over 4,500 in the United Kingdom. The drill density of exploration wells in the United Kingdom is much higher than in Norway, in some areas up to two to three times higher. So why is this the case?
It isn't because the geological risk is higher in Norway than the United Kingdom as it is essentially the same geological formations. In my opinion there are two reasons for the lower historical exploration activity in Norway.
Firstly, lower taxes in the United Kingdom encouraged more active exploration drilling than in Norway where taxes were higher. This does not mean that taxes are high in Norway relative to world norms but faced with the same prospect in the United Kingdom versus Norway with the same chance of success then the prospect in the United Kingdom would be drilled fi rst. Secondly, until ten years ago the Norwegian upstream, business was exclusively controlled by the major oil companies with no participation from the independent sector. I believe that independent companies have perhaps more appetite for risk than the majors and most certainly have a lower
Left to right: Hans Christen Rønnevik, Exploration Manager and Arild Jørstad, Senior Geophysicist, Lundin Norway
fi eld reserve threshold in terms of the size of prospects which they are willing to drill. I believe that the earlier participation of the independent sector in the United Kingdom contributed to an increased level of exploration drilling. Today however the lower level of historical exploration drilling in Norway has created the opportunity for Lundin Petroleum and other independents on the Norwegian Continental Shelf (NCS).
Now I would like to turn to the regulatory environment in Norway. I fi rstly want to congratulate the Norwegian government for the regulatory and fi scal environment it has created on the Norwegian Continental Shelf. Stability of the fi scal regime is critical for our business where we are making investment decisions based upon projects expected to produce for 20 or 30 years. The fi scal regime in Norway has probably been the most stable in the world. In addition, the Oil Ministry and Norwegian Petroleum Directorate are managed by people who understand the oil and gas business, many of whom have worked in the industry rather than being career civil servants. This is a huge benefi t to us from an industry operating perspective and facilitates the decision making process. There still remains a perception from the wider investment community that oil and gas taxes are high in Norway. I guess this is because historically they have always been compared with the lower rates in the United Kingdom. But if we take account of the exploration incentives, a country wide ring fence, capital uplift and interest deductibility the 78 percent taxes in Norway compares favourably with other petroleum producing regimes. We believe the fi scal regime in Norway encourages exploration driven companies such as Lundin Petroleum.
However there are times when it is necessary to make changes. I believe the changes made 10 years ago in Norway to fi scal policy and licensing rounds have played a major part in revitalising the Norwegian Continental Shelf. Faced with reductions in exploration activity and declining oil production new players were encouraged to come to Norway. Licence awards in pre-defi ned areas, the APA rounds, were introduced to encourage more exploration activity. Changes were also made to fi scal policy to allow cash refunds of exploration expenditure. This has encouraged diversity on the NCS, has brought in new players leading to increased levels of activity. These policy changes have been one of the reasons for the recent exploration successes such as those in the Greater Luno Area. As an outsider looking into Norway, I am sometimes astounded by the constant criticism the oil and gas industry receives from Norwegian society. The Norwegian Oil Ministry and industry should be applauded for the way they have managed the development of its natural resources and the huge value they have created for everyone in Norway. The changes made ten years ago are another clear example of this - doing the right thing at the right time.
So based upon this macro environment of exploration potential in a stable regulatory environment, Lundin Petroleum decided to invest in Norway. We bought certain Norwegian assets from DNO in 2004 including its interest in the recently discovered Alvheim fi eld operated by Marathon. But we also persuaded Torstein Sanness and Hans Christen Rønnevik to join us with a mandate of trying to grow a Norwegian focused independent oil company which could grow organically through exploration drilling.
Alvheim has performed extremely well but our investment in Torstein and Hans Christen was really the catalyst for our future success. Certainly one of the best investments we have ever made. Without good professional staff we are nothing.
Our overriding philosophy at Lundin Petroleum is that you have to delegate responsibility to the people on the ground. And in this respect, Norway is no diff erent. The best people to run our Norwegian business are the Norwegians. Over the last 50 years Norway has invested heavily in educating a group of industry professionals who are now highly regarded across the world. I don't think anyone has ever questioned that Hans Christen and his exploration team are some of the best in the business having an excellent track record of fi nding oil. We did not try to reinvent the wheel. We simply had to harness their knowledge and expertise in the right environment.
Other companies in Norway have also excellent people – but the key to success is how you leverage on the knowledge and learning capabilities of your organisation. I cannot overemphasise the importance of our people and encouraging them to continuously challenge conventional thinking. It is often too easy to accept conventional thinking which leads to an adoption of the status quo. We want our people to think outside the box and in doing so appreciating the limitations of data, tools, methods and theories. The ability of our people to innovate has been critical to our success.
I would now like to turn to the issue of risk assessment and corporate decision making process. I personally believe that the decision making process in diff erent corporations is critical to whether exploration prospects actually get drilled. I have talked earlier about our philosophy to put the decision making in respect of exploration prospectivity in the hands of local technical team. They have worked up the prospects, they best understand the risks and as such they should play a big part in the fi nal decision. As I will explain later this was obviously critical for us when we drilled our fi rst exploration well in the Greater Luno Area in 2007 which discovered the Edvard Grieg fi eld. If this well would not have been drilled then it is likely Johan Sverdrup would still remain undrilled today.
In my opinion many oil and gas companies have become too risk averse with more focus on exploitation rather that exploration. I also believe that in many companies there are so many layers of management involved in an investment decision, so many committees, so many reviews that by the time the decision making process has moved from Stavanger to Houston, the fi nal decision is so far removed from the individual with the real knowledge that wrong decisions are made. It often only takes one person up the decision chain to say "no" and the proposal doesn't proceed any further. At Lundin Petroleum our overriding philosophy is we try to support the recommendations of the people on the ground. If we don't then we should question whether we have the right people.
Let us now look at the impact of technology on our success. I have heard various technology providers state that the discovery of Johan Sverdrup was primarily due to their technology. This is simply not true. There is no question that
recent developments in seismic imaging technology such as Geostreamer and Broadseis have provided the industry with excellent new tools which are a step change in the ability to better image the subsurface. Being at the forefront of applying emerging technology and methods is critical to our exploration model.
But the fact is that the Edward Grieg discovery well, which really was the critical well in unearthing the jewels of the Greater Luno Area, was drilled based upon old vintage 3D data. Today new technologies are widely available to all industry players as they are usually developed by service providers rather than by the oil and gas companies themselves. This means the diff erentiating factor is how organisations and people use and apply the technology – not necessarily the technology itself.
Nature was kind to Norway, the government developed an excellent regulatory regime, we have access to the best people and technology and put together in a corporate environment where the right decisions can be made. Let's take a quick walk through history to see how the discoveries in the Greater Luno Area were made.
The area of our focus here is what we call the Greater Luno Area. It is also referred to as the Haugaland High or the southern Utsira High. It is part of the area awarded to Esso in 1965 when it was granted the fi rst licence on the Norwegian Continental Shelf PL001. Esso, now named Exxon, and others subsequently found over 1 billion barrels of recoverable oil in the northern Utsira High.
The southern Utsira High despite exploration activity from Exxon, Elf and Statoil in the years since 1965 had yielded limited success. The Ragnarrock oil and gas discovery in poor chalk reservoir had been discovered by Statoil in 1967 on the crest of the High.
Elf had drilled a dry exploration well in 1976 to the east of the High. We now know this well barely missed the Johan Sverdrup fi eld by a matter of metres. It was almost 25 years before our discovery well on the fi eld.
In 2004 after Lundin Petroleum acquired a non-operated interest in the Alvheim fi eld our strategy was to grow organically through exploration. We wanted to fi nd a new core exploration area where we could operate and hold much larger equity interests. The area where we focused was the southern Utsira High, an area which according to conventional industry thinking had limited potential. Conventional thinking was one of complex geology with reservoir and structural uncertainty. So when we applied for PL338 in the 2004 APA I don't think we had any competition.
Our team had a diff erent view of the area than the conventional thinking. Our base concept back then was an area containing Jurassic sands of varying thickness over inlier basins and basement, a saturated hydrocarbon system with a 40 to 50 metres oil leg, and a common oil water contact over the whole of the high. We identifi ed various potential stratigraphic traps fringing the High in the west and southwest including the Luno prospect.
I remember so well sitting down with Hans Christen and our team at the time to discuss our application for PL338. Our potential partners had fallen by the wayside and we were looking at taking the licence with a well commitment with a 100 percent equity interest. The quality of the seismic over the main Luno (now named Edvard Grieg) prospect raised more questions than answers about the trapping mechanism. In fact I remember one of our senior corporate explorationists at the time saying "these Norwegians must be crazy if they think this is a valid prospect". The reality is that in many corporations this prospect would not have been drilled. But our Norwegian team stuck to their guns – this was their number one exploration pick. For them the facts were clear – they had developed a clear geological model with Draupne sands surrounding the High. Despite the poor quality seismic the trapping mechanism was the Jurassic sands pinching out against the basement High. This is much easier to see on the multicube 3D seismic available today.
Ultimately the investment decision for us was easy. We fully supported our team. And importantly if the well was successful and our concept proven to be correct then there was lots of additional prospectivity on the Haugaland High. So before we drilled the exploration well in 2007 we made sure we secured as much of the acreage in the area as possible. We picked up licences PL359 and PL410 in subsequent APA rounds in 2006 and 2007.
Edvard Grieg was drilled in 2007 and was an oil discovery. It has subsequently been appraised with two further wells. We have reserves of close to 200 million barrels of oil equivalent. The plan of development for Edvard Grieg was approved by the Norwegian Parliament in 2012. Major contracts for the jacket and topsides have already been awarded to Kværner and the development wells will be drilled using a Rowan jack-up rig. First oil is expected in late 2015 at a rate of close to 100,000 boepd. We have recruited an experienced team led by Bjørn Sund to build these facilities for us. They are predominately Norwegian and have a track record of building similar structures on the NCS for Norsk Hydro.
But for us the Edvard Grieg story was only the beginning of unearthing the potential of the Greater Luno Area. The discovery was absolutely fundamental to the story because it proved the concept. We believed, and indeed still believe, that wherever on the Haugaland High we can fi nd reservoir, we have a very high probability of fi nding further oil fi elds.
But life is not always perfect. We subsequently drilled two further exploration wells on the Haugaland High in 2009 and 2010. Both wells were chasing Jurassic reservoir in inlier basins on the High. One found oil in porous basement called the Edvard Grieg South discovery but neither well found any material amount of Jurassic reservoir. After these two wells the sceptics started to question our ability to fi nd more oil in the Greater Luno Area.
Discoveries on the southern Utsira High
We had already started to focus our attention in the eastern side of the Haugaland High and applied in the APA 2009 for PL501. Our Draupne sandstone depositional model from 2006 had been proven correct with the Edvard Grieg discovery and this was the breakthrough event that turned Avaldsnes from a high to a low risk prospect. Interestingly Statoil who had previously held the PL501 acreage bid against Lundin Petroleum in the APA 2009 application. Lundin Petroleum was granted the operatorship of PL501 and were forced married with Statoil and Maersk as partners. I suppose only the Ministry can answer the question as to why we were given operatorship. I would like to think it was due to the fact that we had in our application already identifi ed the prospect which is now the Johan Sverdrup fi eld which we were keen to drill and make a commitment well in the application.
We had identifi ed that the Johan Sverdrup prospect extended into the adjoining PL265 and as a result we negotiated a deal to buy a ten percent working interest in this licence. I guess at that time the PL265 partners had either not identifi ed the prospect or if they had then they didn't share our vision on its prospectivity. Despite the Edvard Grieg discovery the conventional thinking was still that Avaldsnes was a questionable prospect. The sceptics questioned the oil migration risk – how could the oil generated in the kitchen to the west of the Haugaland High have migrated to the east and they still questioned the reservoir risk.
We however were confi dent and pushed forward with the Avaldsnes exploration well in 2010. We had obtained valuable data particularly cores from the earlier wells as well as updating our subsurface models using updated 3D seismic data. The exploration well was a signifi cant discovery. We found extremely good Volgian reservoir sandstone overlying good Upper to Middle Jurassic reservoir. These are the moments in the exploration business which we all dream about. We knew we had found something potentially big but we really didn't know how big. We knew that the areal closure of the structure against the boundary fault to the west was large – potentially 200 km2 . We knew at this location we had found good quality reservoir. But we didn't know how the continuity, thickness and quality of the reservoir would change over the whole structure. As a result of this uncertainty we announced that the discovery area proven by the fi rst well contained between 100 and 400 million barrels of recoverable oil but we always had an idea we could be onto something much bigger.
During 2011 we drilled further appraisal wells as did Statoil in the adjoining PL265. As we had anticipated, these discoveries were part of one connected giant oil fi eld now called Johan Sverdrup. Each of the further appraisal wells
drilled to date have found this excellent quality reservoir which appears to be transgressive over the whole structure. It was also confi rmed that the reservoir thickness increased to the west of the fi eld. The end result is that when such a thick and good quality reservoir is compounded over such a large area the recoverable resources grow exponentially and we end up with a multibillion barrel oil fi eld.
And there is still upside in the Greater Luno Area as the recent exploration discovery at Geitungen has proven. As we originally said – whenever you fi nd good reservoir in the Greater Luno Area above the regional oil water contact you have a good chance to fi nd further oil fi elds.
The question of "how Johan Svedrup was found" and "why did it take so long" will be debated for a long time. There is no question that Lundin Petroleum and particularly our team in Norway played a big part in the process. We identifi ed back in 2006 the correct geological model prior to drilling the Edvard Grieg discovery and a concept that oil could have migrated around the High to fi ll what we now know is the Johan Sverdrup discovery. The presence of non biodegraded oil in Edvard Grieg and Johan Sverdrup fl anking a saturated system was new knowledge that could not have been predicted by forward modelling. We had to drill the exploration wells.
Unconventional thinking was critical to the success. To quote from Piet Hein the Danish mathematician "To know what thou knowest not is in essence omniscience". Or put another way "to know what you don't know gives you the capacity to know everything".
Lundin Petroleum's assets in South East Asia are located off shore Malaysia and off shore and onshore Indonesia. Lundin Petroleum's assets off shore Malaysia consist of approximately 40,000 km2 of exploration acreage, fi ve gas discoveries and four oil discoveries. The Indonesian assets consist of approximately 23,000 km2 of exploration acreage and one producing fi eld onshore Sumatra.
Since commencing its ten well exploration drilling programme off shore Malaysia in 2011 Lundin Petroleum has at the end of 2012 discovered 12.7 MMboe of reserves and 81.7 MMboe of net best estimate contingent resources. Lundin Petroleum operates in two core areas in Malaysia.
Lundin Petroleum holds four production sharing contracts (PSC) offshore Peninsular Malaysia and has drilled six exploration wells in the area resulting in two oil discoveries, Janglau and Ara, confi rmed one existing oil discovery, Bertam, and made one gas discovery, Tembakau. Bertam and Tembakau are likely to be commercial discoveries, with engineering studies being carried out for a Bertam development.
In January 2012, the Bertam-2 appraisal well on PM307 (WI 75%) was successfully completed proving the continuity and quality of the K10 oil reservoir sandstone and at the end of 2012, gross reserves of 17.0 MMboe were assigned to the fi eld. Conceptual development studies are substantially complete in relation to a potential development of the Bertam fi eld and a development decision will likely be taken in 2013. In November 2012, Lundin Petroleum announced the Tembakau-1 well in PM307, as a gas discovery. Given the relatively close proximity to existing gas infrastructure coupled with the forecast strong demand for gas on Peninsular Malaysia the building blocks for a commercial development are present and further studies will be undertaken to assess the commerciality of this discovery. It is estimated that the Tembakau discovery contains 306 bcf (51 MMboe) of gross best estimate contingent gas resources.
Block PM308A (WI 35%) contains the Janglau and Rhu oil discoveries. A further exploration well targeting the Ara prospect on Block PM308A was drilled during 2012 and completed in early 2013. The well was targeting the same Oligocene intra-rift sands as discovered in the Janglau discovery. The Ara-1 well encountered oil in nine individual sand units in a high pressured intra-rift section extending over a vertical interval of 800 metres. The well penetrated a total of approximately 40 metres net oil bearing reservoir.
South East Asia licence location map
In December 2012, Lundin Petroleum announced the award of a new PSC off shore Peninsular Malaysia. Block PM319 is operated by Lundin Petroleum with an 85 percent working interest with Petronas holding a 15 percent working interest. The block covers an area of approximately 8,400 km2 and is located west of PM307. The area has very limited 3D coverage and work commitments include a full tensor gravity survey, 550 km2 of 3D seismic and one xploration well.
An acquisition of 1,450 km2 of new 3D seismic in PM308A (WI 35%) was completed during 2012 and an acquisition of 1,450 km2 of new 3D seismic in PM307 (WI 75%) and partially PM319 (WI 85%) was shot during 2012 and completed in early 2013.
Two exploration wells off shore Peninsular Malaysia are planned to be drilled in 2013.
Lundin Petroleum holds two PSCs off shore Sabah in east Malaysia. Lundin Petroleum has drilled four exploration wells off shore Sabah in east Malaysia since 2011 resulting in three gas discoveries, Tarap, Cempulut and Berangan.
SB303 (WI 75%) contains the Tarap, Cempulut, Berangan and Titik Terang gas discoveries with an estimated gross best estimate contingent resource of 347 bcf (57.8 MMboe). Lundin Petroleum continues to evaluate the potential for commercialisation of these gas discoveries, most likely through a cluster development.
In September 2012, the Berangan-1 exploration well in SB303 was successfully completed as a gas discovery. The well is 10 km to the southeast of the Tarap gas discovery made by Lundin Petroleum in 2011, and 15 km to the south of the Cempulut gas discovery also made in 2011. The Berangan-1 discovery is estimated to contain 69 bcf (11.5 MMboe) of gross best estimate contingent gas resources and it is likely that it will be included in a cluster development with the other SB303 gas discoveries.
The commerciality of a potential gas cluster development is dependent upon getting access to the gas market in Sabah. There is a gas terminal at Kota Kinabalu around 140 km away which potentially could host the produced gas from a cluster development. There is also the possibility to connect a gas cluster development to the pipeline infrastructure going to the Sabah Oil and Gas Terminal at Kimanis, which is currently under construction.
An acquisition of 500 km2 of new 3D seismic in SB307/308 (WI 42.5%) was completed during 2012.
One exploration well is planned to be drilled off shore Sabah in 2013.
Lundin Petroleum has a 25.88 percent ownership in the gas producing fi eld Singa, onshore Sumatra. During 2012 the fi eld has produced below expectation due to necessary well maintenance work on the fi eld. The current PSC expires in 2017 and the reserves associated with the fi eld do not extend beyond 2017. Lundin Petroleum has booked additional best estimate contingent resources on Singa which will be converted to reserves if and when the PSC expiry date is extended.
Lundin Petroleum has four PSCs in the Natuna Sea area. It has a 100 percent working interest and is the operator in the Cakalang, Baronang and the Gurita PSCs and a 60 percent working interest and operator of the South Sokang PSC.
A 3D seismic acquisition programme of 950 km2 has been completed in 2012 on the Gurita Block (WI 100%) and an exploration well will be drilled in 2013. In 2013 an exploration well will also be drilled on the Baronang Block (WI 100%) and a 3D seismic acquisition programme is planned to be completed on the South Sokang Block (WI 60%).
Above: Drilling operations, off shore Malaysia Opposite page: Oil pumps in Paris Basin, France
PM307 (WI 75%)
» 3D seismic acquired 2009–2011
» 3D seismic acquired in 2009/2010
| INDONESIA KEY DATA | 2012 | 2011 |
|---|---|---|
| Reserves (MMboe) | 3 | 4 |
| Contingent resources (MMboe) | 3 | 2 |
| Average net production per day (Mboepd) | 1 | 1 |
| Net turnover (MUSD) | 11 | 13 |
| Sales price achieved (USD/boe) | 32 | 32 |
| Cost of operations (USD/boe) | 15 | 13 |
| Operating cash fl ow contribution (USD/boe) | 13 | 15 |
» One exploration well planned to be drilled in 2013 targeting the Balqis and Boni prospects
» 3D seismic planned to be shot in 2013
The French assets consist of mature onshore oil producing fi elds in the Paris Basin operated by Lundin Petroleum and mature onshore oil producing fi elds in the Aquitaine Basin operated by Vermilion. The Dutch assets consist of mature onshore and off shore gas producing fi elds operated by Vermilion, Gaz de France, ONE and Total.
The French and Dutch assets were acquired through a corporate acquisition of Coparex in 2002. The combined net reserves at the time of acquiring the assets in 2002 was around 32 MMboe and the net cumulative production from the date of acquisition up to year end 2012 amounted to 22 MMboe. The remaining net reserves as at year end 2012 was 27.6 MMboe demonstrating that a signifi cant portion of the produced volume has been replaced with additional reserves through a pro-active infi ll drilling and reservoir management strategy. The French assets also contain best estimate contingent resources of 12.8 MMboe net to Lundin Petroleum.
The combined operating cash fl ow from the French and Dutch assets amounted to approximately MUSD 100 for 2012 driven by high realised sales prices and a relatively low level of operating costs and cash taxes.
During 2012 the Grandville (WI 100%) redevelopment in the Paris Basin was substantially completed with the wells being brought onstream late in 2012. Two exploration wells were drilled in the Paris Basin through the course of 2012. The Amaltheus exploration well on the Val des Marais concession (WI 100%) was a discovery and the well has been put on long-term production test.
Lundin Petroleum is participating in one exploration well in the Paris Basin in 2013 with the drilling of the Hoplites-1 well on the Est Champagne concession (WI 100%).
In the Netherlands the Vinkega-2 exploration well in the Gorredijk concession (WI 7.75%) was successfully completed as a gas discovery during 2012 and the discovery is planned to commence production in 2013.
Lundin Petroleum is participating in two exploration wells onshore Netherlands in 2013.
| FRANCE KEY DATA | 2012 | 2011 |
|---|---|---|
| Reserves (MMboe) | 24 | 25 |
| Contingent resources (MMboe) | 13 | 10 |
| Average net production per day (Mboepd) | 3 | 3 |
| Net turnover (MUSD) | 118 | 129 |
| Sales price achieved (USD/boe) | 110 | 111 |
| Cost of operations (USD/boe) | 23 | 19 |
| Operating cash fl ow contribution (USD/boe) | 63 | 65 |
| NETHERLANDS KEY DATA | 2012 | 2011 |
|---|---|---|
| Reserves (MMboe) | 4 | 4 |
| Average net production per day (Mboepd) | 2 | 2 |
| Net turnover (MUSD) | 55 | 45 |
| Sales price achieved (USD/boe) | 60 | 61 |
| Cost of operations (USD/boe) | 15 | 15 |
| Operating cash fl ow contribution (USD/boe) | 52 | 40 |
Above: Ikdam FPSO, Oudna, Tunisia Opposite page: Paris Basin exploration drilling operations, France
| RUSSIA KEY DATA | 2012 | 2011 |
|---|---|---|
| Reserves (MMboe) | 7 | 16 |
| Contingent resources (MMboe) | 110 | 110 |
| Average net production per day (Mboepd) | 5 | 3 |
| Net turnover (MUSD) | 152 | 80 |
| Sales price achieved (USD/boe) | 77 | 70 |
| Cost of operations (USD/boe) | 13 | 11 |
| Operating cash fl ow contribution (USD/boe) | 10 | 10 |
| TUNISIA KEY DATA | 2012 | 2011 |
|---|---|---|
| Reserves (MMboe) | – | 0.3 |
| Average net production per day (Mboepd) | 0 | 1 |
| Net turnover (MUSD) | 25 | 25 |
| Sales price achieved (USD/boe) | 108 | 125 |
| Cost of operations (USD/boe) | 211 | 64 |
| Operating cash fl ow contribution (USD/boe) | 26 | 45 |
» Lundin Petroleum has exited the country in 2012
» One licence 04/06 (WI 50%)
LUNDIN PETROLEUM'S COMMITMENT TO ITS STAFF, SHAREHOLDERS, HOST GOVERNMENTS, LOCAL COMMUNITIES AND SOCIETY IS TO ACT AS A RESPONSIBLE CORPORATE CITIZEN. THIS MEANS MAKING THE RIGHT DECISIONS IN THE BOARD ROOM AND IN THE FIELD, DAY AFTER DAY.
Lundin Petroleum is committed to carry out its worldwide operations in a responsible manner. This means that the strategic decisions and fi eld activities take into consideration potential impacts on people and the environment. Lundin Petroleum has developed a Corporate Responsibility (CR) framework that establishes systems and procedures to protect the health, safety and security of its stakeholders and the environment. The commitments to responsible corporate citizenship by which the Company is guided are set out in its Code of Conduct. Lundin Petroleum's policies, guidelines and the management system further detail how operations must implement the principles in their activities. Corporate Responsibility is an evolving fi eld which requires continuous improvement; in practice it means seeking to achieve social, environmental and economic benefi ts simultaneously.
In 2012 Lundin Petroleum focused on further embedding the United Nations Global Compact Principles in its operational sites. The UN Global Compact is an initiative of the United Nations to encourage businesses and other societal actors to adopt sustainable and socially responsible practices by endorsing and reporting on the implementation of the ten principles covering human rights, labour standards, environment and anti-corruption. Lundin Petroleum formally became a member of the Global Compact in 2010 and has taken numerous steps to embed the principles in its daily operation. In 2012, the Company continued to train operational staff on the principles and focused on their relevance to everyone's day to day work.
Internal Corporate Documents International Initiatives
BY JOINING THE UNITED NATIONS GLOBAL COMPACT, LUNDIN PETROLEUM AFFIRMS ITS COMMITMENT TO ABIDE BY ITS 10 PRINCIPLES ON HUMAN RIGHTS, LABOUR STANDARDS, ENVIRONMENT AND ANTI-CORRUPTION.
Lundin Petroleum's Board of Directors strengthened the Company's commitment towards human rights in September 2012 by formally endorsing the UN Guiding Principles on Business and Human Rights and adopting a Human Rights Policy in December 2012.
Lundin Petroleum's Vice President Corporate Responsibility attended the Forum on Business and Human Rights at the United Nations in Geneva in order to learn about means to implement the Guiding Principles and to engage with its stakeholders.
Lundin Petroleum guarantees in its Code of Conduct the right to freedom of association. It ensures equal opportunity without discrimination on the basis of age, culture, disability, gender, race, religion, etc. by selecting candidates based on their competence and qualifi cations to perform the job.
Robust processes for contractor selection and evaluation ensure that there is no child or other form of forced labour in relation to Lundin Petroleum's worldwide operations.
In its Code of Conduct Lundin Petroleum recognises fi ve key stakeholder groups: shareholders, staff , host countries, host communities and society at large. The type of engagement diff ers for each group; shareholders are informed of the Company's activities through public disclosure in the form of quarterly and annual reports, website and Annual General Meeting, whereas, engagement with staff is a daily occurrence. Contacts with host governments take place prior to the acquisition of a licence and throughout the lifetime of an asset, while local communities engagement takes place prior to the commencement of and throughout the period of fi eld activities. As for society at large, the Company seeks to contribute to the better understanding of the importance and impact of Corporate Responsibility in its business conduct and to the sector by participating as speaker (The University of Stockholm
The Company continues to promote environmental protection and awareness. Preservation of biodiversity and environmental protection were of particular focus in 2012; operations assessed potential eff ects of their activities and supported environmental projects.
Climate Change remains an important issue for Lundin Petroleum; the Company has adopted a new Climate Change Statement, emphasising the commitment to seek energy effi ciency measures to reduce its carbon footprint and in 2012 participated for the fourth time in the Carbon Disclosure Project.
The Anti-corruption Policy and the Guidelines, adopted in 2011, were the subject of staff training in 2012. There were no cases of corruption reported throughout the Group under the Guidelines or the Whistleblowing Procedure.
To further reinforce Lundin Petroleum's commitment to transparency, as per the Board of Directors' resolution, Lundin Petroleum became an EITI supporting company in 2013.
and the Graduate Institute of International and Development Studies, Geneva), panellist (Global Energy Forum 2012, Geneva) or participant (CSR Conference, Oslo, ISO 26000 Open Forum, Geneva, Forum on Business and Human Rights, Geneva, Risk Management Master Class, Amsterdam) in various conferences or workshops which also off er the opportunity to meet experts in relevant corporate responsibility fi elds from whom the Company can learn about best practice. In 2012, Lundin Petroleum's Vice President Corporate Responsibility contributed an article on "The Evolution of Corporate Social Responsibility in the Past Ten Years: the Viewpoint of a Practitioner" to Oil Gas and Energy Law Intelligence (OGEL). Lundin Petroleum continued to support research on governance in, and the economic impact of, the extractive industry at the Center on Confl ict, Development and Peace Building of the Graduate Institute of International and Development Studies.
"
HAVING A STRONG SAFETY CULTURE MEANS THAT PEOPLE WORK SAFELY NOT JUST BECAUSE THEY ARE BEING TOLD TO BUT BECAUSE THEY SEE THE VALUE TO THEMSELVES, OUR COMPANY AND OUR STAKEHOLDERS IN DOING SO.
MIKE NICHOLSON, General Manager - South East Asia
The purpose of an HSE management system (the Green Book) is to have systems and procedures in place to prevent accidents or incidents with an impact on people, environment and assets. Since the Company was created, there have not been any work-related fatalities in its operations. In 2012, Lundin Petroleum's Key Performance Indicators (KPIs) are all better than in 2011 (see table on page 43), except for the number of Lost Time Incidents and Incident Rate among contractors. Incidents reported were of low severity with no lasting impact on people or the environment.
The Company uses KPIs as the basis of its pro-active HSE management approach, focussing on areas where incidents have occurred. In 2012 the emphasis was placed on contractor evaluations and management through onsite reviews, as well as sharing experiences and lessons learned within the Group on an ongoing basis and through bi-monthly HSE teleconferences.
Lundin Petroleum also reinforced its management of risk (see page 71) to continue to prevent accidents.
The Oudna fi eld, off shore Tunisia, had produced most of its recoverable reserves when in March 2012 exceptionally bad weather caused damage to one of the risers, beyond economic repair. Field decommissioning was declared in June 2012. As operator, Lundin Tunisia promptly mobilised the required resources and commenced the decommissioning of the Ikdam Floating Production, Storage and Offl oading Unit (FPSO) in July.
The scope of work included dismantling of the mooring system components. A total of 170 tons of steel components with up to seven tons loads were dismantled subsea by divers and recovered to the surface with a dynamic positioned vessel. The chafe chain, the main part of the mooring system under more than 500 tons tension, was safely released from the FPSO bow and passed on to a support vessel which was positioned only a few metres from the FPSO. Concurrently, tank cleaning was conducted to prepare for gas free certifi cation.
These operations involved over 15 contractors including fi ve support vessels from various nationalities and backgrounds. Over 150 persons were involved in the FPSO decommissioning operations for a highly active 70 day-period.
WE ARE PROUD TO REPORT THAT THE DECOMMISSIONING OF THE FPSO WAS COMPLETED EFFICIENTLY AND INCIDENT FREE
CHERIF BEN KHELIFA, General Manager, Tunisia
"
| HSE INDICATOR DATA | 2012 | 2011 | 2010 | 2009 5 | |
|---|---|---|---|---|---|
| Employees | 909,196 | 1,036,831 | 731,793 | 905,166 | |
| Exposure Hours | Contractors | 1,561,482 | 2,354,452 | 2,336,409 | 3,454,980 |
| Employees | 0 | 0 | 0 | 0 | |
| Fatalities | Contractors | 0 | 0 | 0 | 0 |
| Employees | 2 | 3 | 2 | 2 | |
| Lost Time Incidents 1 | Contractors | 5 | 3 | 2 | 1 |
| Employees | 0 | 0 | 0 | 1 | |
| Restricted Work Incidents 2 | Contractors | 0 | 3 | 7 | 0 |
| Employees | 1 | 1 | 0 | 2 | |
| Medical Treatment Incidents 3 | Contractors | 0 | 4 | 17 | 7 |
| Employees | 0.44 | 0.58 | 0.55 | 0.44 | |
| Lost Time Incident Rate 4 | Contractors | 0.64 | 0.25 | 0.17 | 0.06 |
| Total Recordable Incident | Employees | 0.66 | 0.77 | 0.55 | 1.10 |
| Rate 4 | Contractors | 0.64 | 0.85 | 2.23 | 0.46 |
| No. | 2 | 7 | 1 | 1 | |
| Oil Spills | Vol. (m3 ) |
4.18 | 33 | 10 | 40 |
| No. | 1 | 2 | 1 | 2 | |
| Chemical Spills | Vol. (m3 ) |
1.75 | 3.50 | 7.70 | 129.78 |
| No. | 0 | 0 | 0 | 1 | |
| Hydrocarbon Leaks | Mass (kg) | 0 | 0 | 0 | 4 |
| Near Misses with High Potential |
No. | 5 | 3 | 3 | 24 |
| Non-compliance with Permits/ Consents |
No. | 0 | 0 | 6 | 19 |
The crew and the management of the West Courageous jack-up rig used by Lundin Malaysia in Block PM308A achieved its fourth year with no recordable injuries.
Senior management from Lundin Malaysia went off shore to recognise the outstanding eff orts by the crew each and every day and to emphasise the importance of the human factor as a key element in this success story.
LUNDIN NORWAY'S SUSTAINABILITY APPROACH IS KEY TO ITS STRATEGIC GROWTH AND SUCCESS "
ERIK SVERRE JENSSEN, Chief Operating Offi cer, Norway
Lundin Norway is committed to carry out its activities in a responsible way, in adherence with the Company's Code of Conduct, HSE Policies and Management System, as well as in conformity with applicable Norwegian legislation including the Framework Regulations, the Petroleum Act, the Pollution Control Act, the Working Environment Act and the Health Act.
The Company's HSE Policy states that "Lundin Norway shall perform all operations in line with the principle of sustainable growth. Company profi t, the society in which we operate and communicate with, and the environment, are interdependent factors."
In the exploration phase, as part of its sustainability strategy, Lundin Norway gathers environmental data and conducts comprehensive analysis of ecosystems beyond what is required by the authorities. It acquires a full understanding of the natural environment in its licence areas before it commences any fi eld activity whether seismic, exploration or appraisal drilling, fi eld development, and eventually production. Once the environmental data has been duly collected and analysed, Lundin Norway shares its fi ndings with partners, authorities and the public.
For all fi eld development projects such as Edvard Grieg, the facilities design ensures that emissions to air and discharges to sea are minimised through closed fl aring, low NOx turbines, the possibility to receive electricity from the shore, heat recovery, re-injection of produced water in the reservoir, amongst others.
The Best Available Technique principle is adhered to and energy effi ciency is optimised, through heat recovery from exhaust gas and variable speed drive on large pumps and compressors.
Lundin Norway does not commence seismic acquisition, drilling, fi eld development or production unless it has ascertained that it is environmentally sound.
Seabed mapping in the Barents Sea consists of visual, sediment and species sampling, as well as geophysical methods, within and adjacent to its licence areas, with the purpose of:
The results of Lundin Norway's mapping work have been widely shared through academic articles, presentations at seminars and international conferences, as well as through the Norwegian Government Marine Research Programme (Mareano).
Based on the positive experience in the Barents Sea, Lundin Norway plans to expand detailed seabed mapping to other core areas on the Norwegian Continental Shelf such as the North Sea.
"
In 2006, Lundin Petroleum established a Sustainable Investment Programme to promote social, economic, and environmental projects and organisations as well as citizenship among its staff . Since then, the Company has funded a signifi cant number of projects, primarily in its areas of operations.
In 2012, Lundin Petroleum continued to fund some of its long standing projects, such as SOS Children Villages, while it initiated new ones focussing on the preservation of the environment. The main projects supported by Lundin Petroleum and its affi liates in 2012 can be seen on the adjacent map.
Lundin Petroleum intends to pursue sustainable investments and community development projects associated to its operations. However, as the Company's operations grow, so does the need to engage in larger scale and more sustainable projects whose impact can be measured over time. This will better fulfi l the commitment the Company made under the United Nations Global Compact to further the Millennium Development Goals. Lundin Petroleum has therefore decided to seek the support of an organisation with a strong track record in philanthropy and social investments.
In 2013 Lundin Petroleum entered into a partnership agreement with the Lundin Foundation in order to increase the scale and impact of the Company's sustainable investment projects and benefi t from the Lundin Foundation's expertise and network of implementing organisations. Lundin Petroleum has committed to annually contribute 0.1 percent of its previous year's operating income to the Lundin Foundation. At least 70 percent of the funds will be NORWAY » Scholarships for 6 students participating in the seabed mapping initiative
NORWAY » Seabed mapping » CO2 storage For more information see pages 44–45
» Lundin Petroleum supported the restoration of the Belvédère Park, the biggest inner city park in Tunis, Association des Amis du Belvédère
» Staff in Geneva participated in a national initiative promoting commuting by bicycle, Bike to Work
» Matching program - volunteer work Lundin France HR Manager volunteered for a two month period at the Population Caring Organization in Ghana
FRANCE
TUNISIA
» Contribution to running costs of House 1, Gammarth Village, SOS Children Village
TUNISIA
» Funding of 2 rural solar workshops serving 200 households and nearly 1,000 people, Barefoot College Solar Initiative
CAPACITY BUILDING
SOCIAL WELFARE
ENVIRONMENTAL PROTECTION
attributed to Lundin Petroleum's thematic focus, namely energy, environment, good governance and sustainability, primarily in its countries of operation. The remaining funds will go to the Lundin Foundation's other projects. The Lundin Foundation has adopted the Impact Reporting Investment Standards, which provide a standardised set of metrics and defi nitions that permit comparison on social and economic performance, to measure its impact on the projects it supports.
To ensure that the projects are aligned with Lundin Petroleum's Community Relations Policy and Sustainable Investment Programme a Management Committee will be formed by respectively two representatives of Lundin Petroleum and the Lundin Foundation. Furthermore, Lundin Petroleum will have a representative on Lundin Foundation's board of directors.
Lundin Petroleum will report on an annual basis on the Lundin Foundation's projects, progress and their impact.
» Artificial breeding of sturgeons in the Volga Delta area, Society for Nature Conservation » Nesting of Siberian cranes, Oksky and Astrakhan reserves, Society for Nature Conservation
» Matching Programme - Race for a Purpose, Lundin Malaysia employees raised funds for Mercy Malaysia
» Contribution to running costs of Cibubur
»
INDONESIA » Donation of 2,500 mahogany trees planted in school grounds to emphasise the importance of environmental protection, Go Green
The Lundin Foundation is a philanthropic organisation founded by the Lundin family. The Lundin Foundation is currently supported by a number of publicly traded natural resource companies committed to the highest standards of corporate social responsibility. The Lundin Foundation provides early stage capital, technical assistance, and strategic grants to outstanding social enterprises and organisations across the globe, with a view to contributing to sustained improvements in social and economic development. The Lundin Foundation works collaboratively with a number of leading private, bilateral and multilateral organisations both to leverage impacts and ensure alignment with host communities and governments. To date, Lundin Foundation's investments have supported 35 enterprises, which in turn have generated USD 42 million in annual revenue, hired over 1,800 employees, paid over USD 8.7 million in wages, transacted over USD 22.8 million in business with over 55,000 rural farmers and microenterprises, and enabled over 375,000 rural customers gain access to improved agricultural products and equipment, fi nancial services and off -grid energy. All proceeds realised from impact investments are reinvested in charitable purposes. The Lundin Foundation additionally provides strategic grants to support education and health initiatives needed to create the enabling conditions for social enterprise to fl ourish.
For more information about the Lundin Foundation and its projects see www.lundinfoundation.org.
As Chairman of the Board of Directors of Lundin Petroleum, my primary duty is to ensure that the Board performs its functions to provide guidance to, and oversee the work of, Group management. For the Board to function effi ciently, it is critical that the fl ow of information is smooth, timely and of course comprehensive without being excessive. My work as Chairman has been made straightforward by the excellent quality and very high standard of the information provided by Group management. When a company is as active as Lundin Petroleum in terms of evaluating and acquiring new projects, it is very important to have a short response time to consider and respond to management proposals. The Board has to be not only reactive, but have insightful input in the decision-making process. The Board has to be able to rely on Group management and have full confi dence in their ability, without
FULL TRANSPARENCY BETWEEN THE BOARD AND GROUP MANAGEMENT IS A MUST IN ANY PUBLIC COMPANY, BUT FOR LUNDIN PETROLEUM IT IS SECOND NATURE
IAN H. LUNDIN Chairman of the Board
being complacent in any way. I attach a lot of importance to open lines of communication and informal interaction between the Board and Group management at all levels. Full transparency between the Board and Group management is a must in any public company, but for Lundin Petroleum it is second nature. Written rules and procedures are of course there to guide the Board, putting on paper practices which have always been applied. To me, these refl ect good corporate governance, common sense and the high level of ethical conduct that is set in stone within Lundin Petroleum. It has been an honour and a most fulfi lling experience to serve as Chairman of Lundin Petroleum since 2002 and I look forward to doing so well into the future, if this is the wish of our shareholders.
The object of Lundin Petroleum's business is to explore for, develop and produce oil and gas and to develop other energy resources, as laid down in the Articles of Association. The Company aims to create value for its shareholders through exploration and organic growth, while operating in an economically, socially and environmentally responsible way for the benefi t of all stakeholders. To achieve this value creation, Lundin Petroleum applies a governance structure that favours straightforward decision making processes, with easy access to relevant decision makers, while nonetheless providing the necessary checks and balances for the control of the activities, both operationally and fi nancially. Lundin Petroleum is committed to applying good corporate governance practices that are best suited for the Company and its activities, to ensure that the Company is managed in an eff ective manner, in the best interests of all shareholders, for continued delivery of value creation for shareholders.
This Corporate Governance Report has been subject to a review by the Company's statutory auditor.
Since its creation in 2001, Lundin Petroleum has been guided by general principles of corporate governance to:
Lundin Petroleum adheres to principles of corporate governance found in both internal and external rules and regulations. As a Swedish public limited company listed on the NASDAQ OMX Stockholm, Lundin Petroleum is subject to the Swedish Companies Act (SFS 2005:551) and the Annual Accounts Act (SFS 1995:1554), as well as the Rule Book for Issuers of the NASDAQ OMX Stockholm, which can be found on www. nasdaqomx.com. Lundin Petroleum is also listed on the Toronto Stock Exchange and is as a result subject to Canadian securities regulations as well, including the Toronto Stock Exchange Rule Book available on www.tmx.com.
In addition, the Company abides by principles of corporate governance found in a number of internal and external documents.
The Swedish Code of Corporate Governance (Code of Governance) is based on the tradition of self-regulation and acts as a complement to the corporate governance rules contained in the Companies Act, the Annual Accounts Act and other regulations such as the Rule Book for Issuers and good practice on the securities market. The Code of Governance can be found on www.bolagsstyrning.se.
The Code of Governance is based on the "comply or explain principle", which entails that a company may choose to apply another solution than the one provided by the Code of Governance if it fi nds an alternative solution to be more appropriate in a particular case. The company must however explain why it did not comply with the rule in question and describe the company's preferred solution, as well as the reasons for it. Lundin Petroleum complied with all the rules of the Code of Governance in 2012, other than in one instance as mentioned in the schedule on page 51 regarding the composition of the Nomination Committee. Furthermore, there were no infringements of applicable stock exchange rules during the year, nor any breaches of good practice on the securities market.
Lundin Petroleum's Articles of Association, which form the basis of the governance of the Company's operations, set forth the Company's name, the seat of the Board, the object of the business activities, the shares and share capital of the Company and contain rules with respect to the Shareholders' Meetings. The Articles of Association do not contain any limitations as to how many votes each shareholder may cast at Shareholders' Meetings, nor any provisions regarding the appointment and dismissal of Board members or amendments to the Articles of Association. The Articles of Association can be found on www. lundin-petroleum.com.
Lundin Petroleum's Code of Conduct is a set of principles formulated by the Board to give overall guidance to employees, contractors and partners on how the Company is to conduct its activities in an economically, socially and environmentally responsible way, for the benefi t of all its stakeholders, including
shareholders, employees, business partners, host and home governments and local communities. The Company applies the same standards to its activities worldwide to satisfy both its commercial and ethical requirements and strives to continuously improve its performance and to act in accordance with good oilfi eld practice and high standards of corporate citizenship. The Code of Conduct is an integral part of the Company's contracting procedures and any violations of the Code of Conduct will be the subject of an inquiry and appropriate remedial measures. Performance under the Code of Conduct is assessed on an annual basis by the Board. The Code of Conduct can be found on www.lundin-petroleum.com.
While the Code of Conduct provides Lundin Petroleum's ethical framework, dedicated policies, guidelines and procedures have been developed to outline specifi c rules and controls applicable in the diff erent business areas. The Company has policies, guidelines and procedures covering for example Operations, Accounting and Finance, Health, Safety and Environment (HSE), Community Relations, Anti-Corruption, Human Rights, Legal, Information Systems, Human Resources (HR) and Corporate Communications. The policies, guidelines and procedures are reviewed on a continuous basis and are modifi ed and up-dated as and when required. Some of these documents can be found on www.lundin-petroleum.com, whereas others are only available internally.
In addition, Lundin Petroleum has a dedicated HSE Management System (Green Book), modelled after the ISO 14001 standard, which gives guidance to management, employees and contractors regarding the Company's intentions and expectations in HSE matters. The Green Book serves to ensure that all operations meet Lundin Petroleum's legal and ethical obligations, responsibilities and commitments within the HSE fi eld. A more detailed description of the Green Book is available on www.lundin-petroleum.com.
The Rules of Procedure of the Board contain the fundamental rules regarding the division of duties between the Board, the Committees, the Chairman of the Board and the Chief Executive Offi cer (CEO). The Rules of Procedure also include instructions to the CEO, instructions for the fi nancial reporting to the Board and the terms of reference of the Board Committees and the Investment Committee. The Rules of Procedure are approved annually by the Board.
The shares of Lundin Petroleum are listed on the Large Cap list of the NASDAQ OMX Stockholm and on the Toronto Stock Exchange. At the end of 2012, the issued share capital of Lundin Petroleum amounted to SEK 3,179,106 divided into 317,910,580 shares with a quota value of SEK 0.01 each. All shares carry the same voting rights and the same rights to a share of the Company's assets and net result.
Lundin Petroleum had at the end of 2012 a total of 43,954 shareholders listed with Euroclear Sweden, which represents an increase of 7,057 shareholders compared to 2011, i.e. an increase of approximately 20 percent. As at 31 December 2012, the major shareholders of the Company, which held more than ten percent of the shares and votes, were Lorito Holdings (Guernsey) Ltd. and Zebra Holdings and Investment (Guernsey) Ltd., two investment companies wholly owned by Lundin family trusts, which together held 27.4 percent of the shares. In addition, Landor Participations Inc., an investment company wholly owned by a trust whose settler is Ian H. Lundin, held 3.6 percent of the shares.
As in previous years, the Annual General Meeting (AGM) held on 10 May 2012 authorised the Board to repurchase and sell its own shares as an instrument to optimise the Company's capital structure and to secure the Company's obligations under its incentive plans. Based on the authorisation, Lundin Petroleum purchased 485,647 of its own shares during the second quarter of 2012 and as a result, held 7,368,285 of its own shares as at 31 December 2012, representing 2.3 percent of the share capital. The average purchase price for the shares is SEK 51.90. Further information regarding the shares and shareholders of Lundin Petroleum in 2012, as well as the Company's dividend policy, can be found on page 68.
The shareholders of the Company decide at each AGM how the Nomination Committee is to be formed. The tasks of the Nomination Committee include making recommendations to the AGM regarding the election of the Chairman of the AGM, election of Board members and the Chairman of the Board, remuneration of the Chairman and other Board members, including remuneration for Board Committee work, election of the auditor, remuneration of the auditor and the Nomination Committee Process for the AGM of the following year. The Nomination Committee members are, regardless of how they are appointed, required to promote the interests of all shareholders of the Company. No remuneration is paid to the Chairman or any other member of the Nomination Committee for their work on the Nomination Committee.
In accordance with the Nomination Committee Process approved by the 2012 AGM, the Nomination Committee for the 2013 AGM consists of members appointed by four of the larger shareholders of the Company based on shareholdings as per 1 August 2012. The names of the members of the Nomination Committee were announced and posted on the Company's website on 24 October 2012, i.e. within the time frame of six months before the AGM as prescribed by the Code of Governance. The Company's Vice President Legal, Jeff rey Fountain, acts as the secretary of the Nomination Committee. The Nomination Committee has held four meetings during its mandate and informal contacts have taken place between such meetings. Further information regarding the Nomination Committee and its work is included in the schedule that follows on the next page and the full Nomination Committee report, including the fi nal proposals to the 2013 AGM, are published on the Company's website together with the notice of the AGM.
| Nomination Committee for the 2013 AGM | ||||||
|---|---|---|---|---|---|---|
| Member | Appointed by | Meeting attendance |
Shares represented as at 1 August 2012 |
Shares represented as at 31 December 2012 |
Independent of the Company and the Group management |
Independent of the Company's major shareholders |
| Åsa Nisell | Swedbank Robur fonder | 4/4 | 2.6 percent | 2.6 percent | Yes | Yes |
| Ossian Ekdahl | Första AP-fonden | 4/4 | 1.1 percent | 0.9 percent | Yes | Yes |
| Arne Lööw | Fjärde AP-fonden | 4/4 | 1.2 percent | 1.2 percent | Yes | Yes |
| Ian H. Lundin | Lorito Holdings (Guernsey) Ltd., Zebra Holdings and Investment (Guernsey) Ltd. and Landor Participations Inc., also non-executive Chairman of the Board of Lundin Petroleum |
4/4 | 31.0 percent | 31.0 percent | Yes | No1 |
| Magnus Unger | Non-executive Board member of Lundin Petroleum who acts as the Chairman of the Nomination Committee |
4/4 | – | – | Yes | Yes |
| Total 35.9 percent | Total 35.7 percent | |||||
| Summary of the Nomination Committee's work during their mandate | Other requirements | |||||
– Consideration of a report regarding the Board's work, as well as the results of the evaluation of the Board's work.
For details, please see schedule on pages 64-65
The Shareholders' Meeting is the highest decision-making body of Lundin Petroleum where the shareholders exercise their voting rights and infl uence the business of the Company. Shareholders may request that a specifi c issue be included in the agenda provided such request reaches the Board in due time. The AGM is to be held each year before the end of June at the seat of the Board in Stockholm. The notice of the AGM, which is to be given no more than six and no less than four weeks prior to the meeting, is to be announced in the Post- och Inrikes Tidningar (the Swedish Gazette) and on the Company's website. The documentation for the AGM is provided on the Company's website in Swedish and in English at the latest three weeks, however usually four weeks, before the AGM.
At the AGM, the shareholders decide on a number of key issues regarding the governance of the Company, such as election of the members of the Board and the auditor, the remuneration of the Board, management and the auditor, including approval of the Policy on Remuneration for the Executive Management, discharge of the Board members and the CEO from liability and – The Nomination Committee fulfi ls the independence requirements of the Code of Governance and no member of Group management is a member of the Committee.
– Magnus Unger was again unanimously elected as Chairman, a function that he has held since the Nomination Committee formed for the 2006 AGM. The fact that he is the Chairman of the Nomination Committee and a Board member of Lundin Petroleum constitutes a deviation from rule 2.4 in the Code of Governance, however, as in previous years, this deviation was considered justifi ed both by the Company and the Nomination Committee given Magnus Unger's experience and support from the major shareholders of the Company.
the adoption of the annual accounts and appropriation of the Company's result. Extraordinary General Meetings are held as and when required for the operations of the Company.
The 2012 AGM was held on 10 May 2012 at Grand Hotel in Stockholm. The AGM was attended by 664 shareholders, personally or by proxy, representing 54.4 percent of the share capital. The Chairman of the Board, all Board members and the CEO were present, as well as the Company's auditor and the majority of the members of the Nomination Committee for the 2012 AGM. The members of the Nomination Committee for the 2012 AGM were Kerstin Stenberg (Swedbank Robur fonder), Ulrika Danielson (Andra AP-fonden), Anders Algotsson (AFA Försäkring), Ian H. Lundin (Lorito Holdings (Guernsey) Ltd., Zebra Holdings and Investment (Guernsey) Ltd. and Landor Participations Inc., as well as non-executive Chairman of the Board of Lundin Petroleum) and Magnus Unger (non-executive Board member of Lundin Petroleum and Chairman of the Nomination Committee). In order for all participants to be able to follow the AGM, all proceedings were simultaneously translated
from Swedish to English and from English to Swedish and all AGM materials were provided both in Swedish and English.
The resolutions passed by the 2012 AGM include:
The minutes of the 2012 AGM and all AGM materials, in Swedish and English, are available on the Company's website www. lundin-petroleum.com, together with the Chairman's and the CEO's addresses to the AGM.
The 2013 AGM will be held on 8 May 2013 at 1 p.m. in Vinterträdgården at Grand Hotel, Södra Blaiseholmshamnen 8, in Stockholm. Shareholders who wish to attend the meeting must be recorded in the share register maintained by Euroclear Sweden on 2 May 2013 and must notify the Company of their intention to attend the AGM no later than 2 May 2013. Further information about registration to the AGM, as well as voting by proxy, can be found in the notice of the AGM, available on www. lundin-petroleum.com.
Lundin Petroleum's statutory auditor audits annually the Company's fi nancial statements, the consolidated fi nancial statements, the Board's and the CEO's administration of the Company's aff airs and reports on the Corporate Governance Report. In addition, the auditor performs a review of the Company's half year report. The Board of Directors meets at least once a year with the auditor without any member of Group management present at the meeting. In addition, the auditor participates regularly in Audit Committee meetings, in
particular in connection with the Company's half year and year end reports. At the 2012 AGM, no election of auditor took place as the audit fi rm PricewaterhouseCoopers AB was elected at the 2009 AGM as the auditor of the Company for a period of four years until the 2013 AGM. The auditor in charge is the authorised public accountant Bo Hjalmarsson.
The auditor's fees are described in the notes to the fi nancial statements – see Note 35 on page 104 and Note 10 on page 109. The auditor's fees also detail payments made for assignments outside the regular audit mandate. Such assignments are kept to a minimum to ensure the auditor's independence towards the Company.
Lundin Petroleum's independent qualifi ed reserves auditor audits annually the Company's oil and gas reserves and contingent resources, i.e. the Company's core assets, although such assets are not separately reported in the Company's balance sheet or income statement. The auditor is appointed by the Board, based on the recommendation of the Reserves Committee. The auditor meets at least once a year with the Company's Reserves Committee and Group management to discuss the reserves reporting and the audit process, and provides a yearly report on reserves data as required by applicable Canadian securities regulation. The current auditor is ERC-Equipoise Ltd. For further information regarding the Company's reserves and resources, please see the Reserves, Resources and Production section on pages 12-17.
The Board of Directors of Lundin Petroleum is responsible for the organisation of the Company and management of the Company's operations. The Board of Directors is to manage the Company's aff airs in the interests of the Company and all shareholders with the aim of creating long-term shareholder value.
The Board shall, according to the Articles of Association, consist of a minimum of three and a maximum of ten directors with a maximum of three deputies, and the AGM decides the fi nal number each year. The Board members are elected for a term of one year and as mentioned previously, Ian H. Lundin, also Chairman of the Board, Magnus Unger, William A. Rand, Lukas H. Lundin, C. Ashley Heppenstall, also CEO of the Company, Asbjørn Larsen and Kristin Færøvik were re-elected as Board members at the 2012 AGM for the period until the next AGM. Dambisa F. Moyo declined re-election. There are no deputy members and no members appointed by employee organisations. The Board members, with the exception of the CEO, are not employed by the Company, do not receive any salary from the Company and are not eligible for participation in the Company's incentive programmes. In addition, the Board is supported by a corporate secretary who is not a Board member. The appointed corporate secretary is Jeff rey Fountain, the Company's Vice President Legal.
The Chairman of the Board, Ian H. Lundin, is responsible for ensuring that the Board's work is well organised and conducted in an effi cient manner. He upholds the reporting instructions for management, as drawn up by the CEO and as approved by the Board, however, he does not take part in the day-to-day decision-making concerning the operations of the Company. The Chairman maintains close contacts with the CEO to ensure the Board is at all times suffi ciently informed of the Company's operations and fi nancial status, and to provide support to the CEO in his tasks and duties. The Chairman further meets, at various occasions during the year, shareholders of the Company to discuss shareholder questions and ownership issues in general, as well as other Company stakeholders. In addition, the Chairman actively promotes the Company and its interests in the various operational locations and in respect of potential new business opportunities.
All Board members elected at the 2012 AGM have extensive experience from the world of business and several members are also highly experienced within the oil and gas fi eld. The Nomination Committee for the 2012 AGM considered, taking into account the business operations of Lundin Petroleum and its current phase of development, that the Board is composed of multi-faceted individuals who are well-suited for the job and whose expertise, experience and background is extensive. Further, in preparation of the elections at the 2012 AGM, the Nomination Committee considered the independence of each proposed Board member and determined that the composition of the proposed Board met the independence requirements of the Code of Governance both in respect of independence towards the Company and the Group management and towards the Company's major shareholders. The independence of each Board member is presented in the schedule on pages 64–65.
The Board is guided by the Rules of Procedure, which set out how the Board is to conduct its work. In addition to the statutory meeting following the AGM, the Board normally holds at least six ordinary meetings per calendar year. At the meetings, the CEO reports on the status of the business, prospects and the fi nancial situation of the Company. In addition, decision items and issues of material importance to the Company are considered by the Board and the Board Committees report on matters as and when required. The Board's yearly work cycle is illustrated in the below chart.
Chairman since 2002 Director since 2001 Member of the Nomination Committee Chairman of the Reserves Committee
Lukas H. Lundin Director since 2001
C. Ashley Heppenstall Director since 2001 President and Chief Executive Offi cer since 2002
Kristin Færøvik Director since 2011 Member of the Compensation Committee
Director since 2008 Member of the Audit and Reserves Committees CR/HSE Board Representative
»
William A. Rand Director since 2001 Chairman of the Audit and Compensation Committees
Director since 2001 Member of the Audit and Compensation Committees Chairman of the Nomination Committee
More information on the Board of Directors can be found on pages 64–65 and on www. lundin-petroleum.com
During 2012, eight board meetings took place, including the statutory meeting. To develop the Board's knowledge of the Company and its operations, a yearly fi eld trip is in general carried out to one of the Company's operational locations. In September 2012, the Board visited the Norwegian operations and an executive session, together with Group management, was held in connection with the Board meeting. At the executive session, an in-depth operations review regarding the Group's exploration and development activities was given, as well as a reserves and production update. A fi nancial overview of the Group was presented and a Corporate Responsibility (CR) and HSE report, with a particular focus on the UN Guiding Principles on Business and Human Rights, was given. Group management also attended a number of Board meetings during the year to present and report on specifi c questions, as and when required.
The Board is also responsible for evaluating the work of the CEO on a continuous basis and shall carry out, at least once a year, a formal performance review . In 2012, the Compensation Committee, on behalf of the Board, undertook a review of the work and performance of Group management, including the CEO, and presented the results of the review at a Board meeting, including proposals regarding the compensation of the CEO and other Group management. Neither the CEO nor other Group management were present at the Board meetings when such discussions took place.
A formal review of the work of the Board was conducted in November 2012 through a questionnaire submitted to all Board members, with the objective of ensuring that the Board functions in an effi cient manner and, as applicable, to enable the Board to strengthen its focus on matters which may be raised. The topics considered included several aspects of the Board's structure, work, meetings and general issues such as support and information given to the Board.
Individual feedback from all Board members was received and the overall conclusions were very positive and showed that the structure and composition of the Board is appropriate and that the Board members are experienced professionals who are well informed about the Company and its operations. The Board Committees function effi ciently and the duties and decision-making powers within the Board are clear. The meetings are well planned and prepared, with high quality presentations, which enables the Board to function in a well-informed and effi cient manner. Individual suggestions received for future issues to consider were that it would be advantageous to have more discussions regarding the overall strategy of the Company, in an ever rapidly changing environment.
The results and conclusions of the review were presented to the Nomination Committee.
The remuneration of the Chairman and other Board members follows the resolution adopted by the AGM. At the 2012 AGM, the Chairman was awarded an amount of SEK 1,000,000 and each
other Board member, with the exception of the CEO, an amount of SEK 450,000. The AGM further decided to award SEK 100,000 for each ordinary Board Committee assignment and SEK 150,000 for each assignment as Committee Chairman, however, limited to a total of SEK 800,000 for Committee work. No remuneration is paid for any assignments in relation to the Reserves Committee. In addition, the 2012 AGM approved an amount of SEK 2,000,000 to be paid to Board members for special assignments outside the directorship.
The remuneration of the Board of Directors is detailed further in the schedule on pages 64–65 and in the notes to the fi nancial statements – see Note 33 on pages 102–103.
To maximise the effi ciency of the Board's work and to ensure a thorough review of certain issues, the Board has established a Compensation Committee, an Audit Committee and a Reserves Committee and has appointed a CR/HSE Board Representative. The tasks and responsibilities of the Committees are detailed in the terms of reference of each Committee, which are annually adopted as part of the Rules of Procedure of the Board. Minutes are kept at Committee meetings and matters discussed are reported to the Board. In addition, informal contacts take place between ordinary meetings as and when required by the operations.
The Compensation Committee assists the Board in Group management remuneration matters and receives information and prepares the Board's and the AGM's decisions on matters relating to the principles of remuneration, remunerations and other terms of employment of Group management. The objective of the Committee in determining compensation for Group management is to provide a compensation package that is based on market conditions, is competitive and takes into account the scope and responsibilities associated with the position, as well as the skills, experience and performance of the individual. The Committee's tasks also include monitoring and evaluating programmes for variable remuneration, the application of the Policy on Remuneration as well as the current remuneration structures and levels in the Company. For further information regarding Group remuneration matters, see the remuneration sections of this report on pages 59–61.
The Audit Committee assists the Board in ensuring that the Company's fi nancial reports are prepared in accordance with International Financial Reporting Standards (IFRS), the Swedish Annual Accounts Act and accounting practices applicable to a company incorporated in Sweden and listed on the NASDAQ OMX Stockholm and the Toronto Stock Exchange. The Audit Committee itself does not perform audit work, however, it supervises the Company's fi nancial reporting and assesses the effi ciency of the Company's fi nancial internal controls, internal audit and risk management, with the primary objective of providing support to the Board in the decision making processes regarding such matters. In addition, the Committee is empowered by the Committee's terms of reference to make decisions on certain issues delegated to it, such as review and approval of the Company's fi rst and third quarter interim fi nancial statements on behalf of the Board. The Audit Committee also regularly liaises with the Group's statutory auditor as part of the annual audit process and reviews the audit fees and the auditor's independence and impartiality. The Audit Committee further assists the Company's Nomination Committee in the preparation of proposals for the election of auditor at the AGM, as and when required.
The Reserves Committee was created in connection with the listing of Lundin Petroleum's shares on the Toronto Stock Exchange in 2011 and reviews and reports to the Board on matters relating to the Company's policies and procedures for reporting oil and gas reserves and related information as per National Instrument 51–101 (NI 51–101) issued under applicable Canadian securities regulation. The Reserves Committee reports to the Board on the Company's procedures for disclosing oil and gas reserves and other related information, on the appointment of the independent qualifi ed reserves auditor and on the Company's procedures for providing information to the independent qualifi ed reserves auditor. The Reserves Committee also meets with Group management and the independent qualifi ed reserves auditor to review, and determine whether to recommend that the Board approve, the statement of reserves and other oil and gas information required to be submitted annually under NI 51–101.
The Board of Directors has a leadership and supervisory role in all CR and HSE matters within the Group and appoints yearly one non-executive Director to act as the CR/HSE Board Representative. The tasks of the CR/HSE Board Representative include to liaise with Group management regarding CR and HSE related matters and to regularly report on such matters to the Board of Directors. The current CR/HSE Board Representative is Asbjørn Larsen. More information about the Company's CR/HSE activities can be found in the Corporate Responsibility section on pages 40–47.
In June 2010, the Swedish International Public Prosecution Offi ce commenced an investigation into alleged violations of international humanitarian law in Sudan during 1997-2003. The Company has been asked by the Prosecution Offi ce to provide information regarding its operations in Block 5A in Sudan during the relevant time period. As repeatedly stated, Lundin Petroleum categorically refutes all allegations of wrongdoing and will cooperate with the Prosecution Offi ce's investigation. Lundin Petroleum strongly believes that it was a force for good in Sudan and that its activities contributed to the improvement of the lives of the people of Sudan.
| Audit Committee 2012 | |||
|---|---|---|---|
| Members | Meeting attendance | Audit Committee work during the year | Other requirements |
| William A. Rand, Chairman Magnus Unger Asbjørn Larsen |
6/6 6/6 6/6 |
– Assessment of the 2011 year end report and the 2012 half year report for completeness and accuracy and recommendation for approval to the Board. – Assessment and approval of the fi rst and third quarter reports 2012 on behalf of the Board. – Evaluation of accounting issues in relation to the assessment of the fi nancial reports. – Follow-up and evaluation of the results of the internal audit of the Group. – Three meetings with the statutory auditor to discuss the fi nancial reporting, internal controls, etc. – Evaluation of the audit performance and the independence and impartiality of the statutory auditor. – Review and approval of auditor's fees. – Assisting the Nomination Committee in its work to propose an auditor for election at the 2013 AGM. |
– The composition of the Audit Committee fulfi lled the independence requirements of the Swedish Companies Act and the Code of Governance. – William A. Rand has chaired the Audit Committee since its inception in 2002 and all Audit Committee members have fi nancial/legal management expertise. In addition, Asbjørn Larsen's previous assignments include the position of CFO and CEO of a Norwegian listed upstream petroleum company and he has extensive experience in accounting and audit matters. |
| Compensation Committee 2012 | |||
| Members | Meeting attendance | Compensation Committee work during the year | Other requirements |
| William A. Rand, Chairman Magnus Unger Kristin Færøvik |
3/3 3/3 2/3 |
– Review of the performance of the CEO, the other members of Executive Management and other Group management as per the Performance Management Process. – Preparing a report regarding the Board's evaluation of remuneration of the Executive Management in 2011. – Continuous monitoring and evaluation of remuneration structures, levels, programmes and the Policy on Remuneration. – Preparing a proposal for the 2012 Policy on Remuneration for Board and AGM approval. – Preparing a proposal for remuneration and other terms of employment for the CEO for Board approval. – Review of the CEO's proposals for remuneration and other terms of employment of the other members of Executive Management and VP level employees for Board approval. – Review and approval of the CEO's proposals for the principles of compensation of other Group management and employees. – Review and approval of the CEO's proposals for 2012 LTIP awards. – Undertaking a remuneration benchmark study and engaging the HayGroup to assist with the study. |
– The composition of the Compensation Committee fulfi lled the independence requirements of the Code of Governance. – William A. Rand has chaired the Compensation Committee since its inception in 2002 and thus possesses extensive experience in compensation matters. In addition, considering the varied backgrounds and experience of the Committee members in general, the Compensation Committee has ample knowledge and experience of management remuneration issues. |
| Reserves Committee 2012 | |||
| Members | Meeting attendance | Reserves Committee work during the year | Other requirements |
| Ian H. Lundin, Chairman Asbjørn Larsen |
1/1 1/1 |
– General review of the Company's oil and gas reserves procedures and practices. – Review of the Company's procedures for assembling and reporting other information associated with oil and gas activities. – Meeting with management and Gaff ney, Cline & Associates, the independent qualifi ed reserves auditor, to discuss the 2011 reserves reporting. – Review of reserves data. – Consideration of a change of independent qualifi ed reserves auditor to ERC-Equipoise Ltd. as of the 2012 reserves reporting. |
– The composition of the Reserves Committee fulfi lled the independence requirements of Canadian securities regulation as per NI 51-101. |
C. Ashley Heppenstall President and Chief Executive Offi cer, Director
Christine Batruch Vice President Corporate Responsibility
Alexandre Schneiter Executive Vice President and Chief Operating Offi cer
Jeff rey Fountain Vice President Legal
Geoff rey Turbott Vice President Finance and Chief Financial Offi cer
»
Teitur Poulsen Vice President Corporate Planning and Investor Relations
Chris Bruijnzeels Senior Vice President Operations
More information on the management can be found on page 66 and on www. lundin-petroleum.com
The President and CEO of the Company, C. Ashley Heppenstall, is responsible for the management of the day-to-day operations of Lundin Petroleum. He is appointed by, and reports to, the Board and is also the only executive Board member. The tasks of the CEO and the division of duties between the Board and the CEO are defi ned in the Rules of Procedure and the Board's instructions to the CEO. In addition to the overall management of the Company, the CEO's tasks include ensuring that the Board receives all relevant information regarding the Company's operations, including profi t trends, fi nancial position and liquidity, as well as information regarding important events such as signifi cant disputes, agreements and developments in important business relations. The CEO is also responsible for preparing the required information for Board decisions and for ensuring that the Company complies with applicable legislation, securities regulations and other rules such as the Code of Governance. Furthermore, the CEO maintains regular contacts with the Company's stakeholders, including shareholders, the fi nancial markets, business partners and public authorities. To fulfi l his duties, the CEO works closely with the Chairman of the Board to discuss the Company's operations, fi nancial status, up-coming Board meetings, implementation of decisions and other relevant matters.
The CEO is assisted in his functions by Group management, being:
Group management works closely together in respect of commercial, technical, HSE, fi nancial and legal issues with the aim of creating long-term shareholder value. Group management is also responsible for ensuring that the operations are conducted in compliance with all Group policies, guidelines and procedures.
The Company's Investment Committee, which consists of the members of the Executive Management, was established by the Board in 2009 to assist the Board in discharging its responsibilities in overseeing the Company's investment portfolio. The role of the Investment Committee is to determine that the Company has a clearly articulated investment policy, to develop, review and recommend to the Board investment strategies and guidelines in line with the Company's overall policy, to review and approve investment transactions and to monitor compliance with investment strategies and guidelines. The responsibilities and duties include considering annual budgets, supplementary budget approvals, investment proposals, commitments, relinquishment of licences, disposal of assets and performing other investment related functions as the Board may designate. The Investment Committee has scheduled meetings every two weeks and meets more frequently if required by the operations.
Lundin Petroleum aims to offer all its employees compensation packages that are competitive and in line with market conditions to ensure it can recruit, motivate and retain highly skilled individuals, in a manner that also enhances shareholder value. The principles of remuneration within the Group are therefore made up of four elements, being (i) basic salary; (ii) yearly variable salary; (iii) long-term incentive plans; and (iv) other benefi ts. As part of the yearly assessment process, the Company has established a Performance Management Process to align individual and team performance to the strategic and operational goals and objectives of the overall business. Individual performance measures are formally agreed and key elements of variable remuneration are clearly linked and defi ned to the achievement of stated and agreed performance measures. To ensure compensation packages within the Group remain competitive and in line with market conditions, the Compensation Committee undertakes regular benchmarking studies. The Compensation Committee may also request the advice and assistance of external reward consultants, which it did in 2012 through the HayGroup. The HayGroup did not perform any other assignments for the Company or the Executive Management.
The remuneration of Executive Management follows the principles that are applicable to all employees, however, the principles must be approved by the AGM. The Compensation Committee therefore prepares yearly for approval to the Board, and for submission for fi nal approval to the AGM, a Policy on Remuneration for the Executive Management. Based on the approved Policy on Remuneration, the Compensation Committee subsequently proposes to the Board for approval the remuneration and other terms of employment of the CEO, and the CEO proposes to the Compensation Committee, for approval by the Board, the remuneration and other terms of employment of the other members of the Executive Management.
The tasks of the Compensation Committee include monitoring and evaluating the application of the Policy on Remuneration approved by the AGM, and to fulfi l this task, the Compensation Committee prepares a yearly report, for approval by the Board, on the evaluation of remuneration of the Executive Management. The statutory auditor of the Company also verifi es on a yearly basis whether the Company has complied with the Policy on Remuneration. Both reports are available on the Company's website and the Policy on Remuneration approved by the 2012 AGM is included in this Corporate Governance Report. Further details regarding the remuneration of Executive Management in 2012 can be found in the notes to the fi nancial statements – see Notes 33–34 on pages 102–104.
For information regarding the Board's proposal for remuneration to the Executive Management to the 2013 AGM, please see page 81.
In this Policy on Remuneration, the terms "Executive Management" or "Executives" refers to the President and Chief Executive Offi cer (CEO), the Executive Vice President and Chief Operating Offi cer, the Vice President Finance and Chief Financial Offi cer, and the Senior Vice President Operations.
It is the aim of Lundin Petroleum to recruit, motivate and retain high calibre Executives capable of achieving the objectives of the Group, and to encourage and appropriately reward performance in a manner that enhances shareholder value. Accordingly, the Group operates this Policy on Remuneration to ensure that there is a clear link to business strategy and a close alignment with shareholder interests and current best practice, and aims to ensure that the Executive Management is rewarded fairly for its contribution to the Group's performance.
The Board of Directors of Lundin Petroleum has established the Compensation Committee to, among other things, administer this Policy on Remuneration. The Compensation Committee is to receive information and prepare the Board of Directors' and the Annual General Meeting's decisions on matters relating to the principles of remuneration, remunerations and other terms of employment of the Executive Management. The Compensation Committee meets regularly and its tasks include monitoring and evaluating programmes for variable remuneration for the Executive Management and the application of this Policy on Remuneration, as well as the current remuneration structures and levels in the Company.
There are four key elements to the remuneration of Executive Management:
The Executive's basic salary shall be based on market conditions, shall be competitive and shall take into account the scope and responsibilities associated with the position, as well as the skills, experience and performance of the Executive. The Executive's basic salary, as well as the other elements of the Executive's remuneration, shall be reviewed annually to ensure that such remuneration remains competitive and in line with market conditions. As part of this assessment process, the Company, as well as the Compensation Committee, periodically undertakes benchmarking comparisons in respect of its remuneration policy and practices. In such circumstances, the comparator group is chosen with regard to:
a) companies both within and outside the oil and gas industry;
b) the size of the company (market capitalisation, turnover, profi ts and employee numbers);
c) the diversity and complexity of the company's business; d) the geographical nature of the company's business; and e) the company's growth, expansion and change profi le.
The advice and assistance of specialised consultants may be requested in connection with these comparisons and the Compensation Committee shall ensure that there is no confl ict of interest regarding other assignments such consultants may have for the Company and the Executive Management.
The Company considers that yearly variable salary is an important part of the Executive's remuneration package where associated performance targets refl ect the key drivers for value creation and growth in shareholder value. Through its Performance Management Process, the Company sets predetermined and measurable performance criteria for each Executive, aimed at promoting long-term value creation for the Company's shareholders.
At the end of each year, the CEO will make a recommendation to the Compensation Committee regarding the payment of the yearly variable salary to the other Executives based upon the achievement of their respective performance criteria. After consideration of the CEO's recommendations, the Compensation Committee will recommend to the Board of Directors for approval the level of the yearly variable salary of the CEO and of the other Executives.
The yearly variable salary shall, in the normal course of business, be based upon a predetermined limit, being within the range of 1 - 12 monthly salaries. However, the Compensation Committee may recommend to the Board of Directors for approval yearly variable salary outside of this range in circumstances or in respect of performance which the Compensation Committee considers to be exceptional.
The Company believes that it is appropriate to structure the long-term incentive plan (LTIP) to align Executive Management's incentives with shareholder interests. Therefore, the Company's LTIP for Executive Management is an incentive plan related to the Company's share price.
The LTIP for Executive Management approved by the 2009 AGM provided for the issuance by Lundin Petroleum of phantom options exercisable after 13 May 2014, being fi ve years from the date of grant. The exercise of these options does not entitle the recipient to acquire shares of Lundin Petroleum, but to receive a cash payment based on the appreciation of the market value of such shares.
The Executives were granted phantom options with an exercise price equal to 110 percent of the average of the closing prices of the Company's shares on the NASDAQ OMX Stockholm for the ten trading days immediately following the 2009 AGM. In accordance with the terms of the 2009 LTIP, the exercise price was adjusted in connection with the distribution by Lundin Petroleum to its shareholders of shares of EnQuest plc and Etrion Corporation, and such adjusted exercise price is equal to SEK 52.91. The total number of phantom options granted to Executive Management is 5,500,928, following adjustments in connection with such distributions of shares of EnQuest plc and Etrion Corporation.
Such options will vest on 13 May 2014, being the fi fth anniversary of the date of grant. The Executive will be entitled to receive a cash payment equal to the average closing price of Lundin Petroleum's shares during the fi fth year following grant, less the exercise price, multiplied by the number of options then held by the Executive. Payment of the award under these phantom options will occur in two equal instalments: (i) fi rst on the date immediately following the fi fth anniversary of the date of grant (May 2014), and (ii) second on the date which is one year following the date of the fi rst payment (May 2015).
No Executive who received an award of phantom options will be eligible for a grant of awards under the Company's unit bonus plan during the fi ve year vesting period of the phantom options.
If the recipient of an award of phantom options resigns from the Group or if the recipient's employment is terminated for cause or similar during the fi ve year vesting period, the award of phantom options will immediately terminate. If the recipient's employment is terminated for any other reason during such period, the award of phantom options will vest and become immediately payable, based on the average closing price of Lundin Petroleum's shares during the 90 day period prior to such termination. If a third party acquires more than 50 percent of the then outstanding Lundin Petroleum shares, the award of phantom options will vest and become immediately payable based on the value per Lundin Petroleum share paid by such third party.
From an accounting perspective the 2009 LTIP for Executive Management is regarded as compensation for services provided and will, under IFRS 2, result in accounting costs which will be distributed over the fi ve year vesting period. Lundin Petroleum's liability under the LTIP will be measured at fair market value and will be revalued at each reporting period. The changes in value will be recognised in the income statement over the fi ve year period so that the accumulated cost over the period corresponds to the value of the LTIP on the fi nal date.
Other benefi ts shall be based on market terms and shall facilitate the discharge of each Executive's duties. Such benefi ts include statutory pension benefi ts comprising a defi ned contribution scheme with premiums calculated on the full basic salary. The pension contributions in relation to the basic salary are dependent upon the age of the Executive.
A mutual termination period of between one month and six months applies between the Company and Executives, depending on the duration of the employment with the Company. In addition, severance terms are incorporated into the employment contracts for Executives that give rise to compensation, equal to two years' basic salary, in the event of termination of employment due to a change of control of the Company.
The Compensation Committee shall approve termination packages that exceed USD 150,000 in value per individual.
The Board of Directors is authorised to deviate from the Policy on Remuneration in accordance with Chapter 8, section 53 of the Swedish Companies Act in case of special circumstances in a specifi c case.
The responsibility of the Board of Directors for internal control over fi nancial reporting is regulated by the Swedish Companies Act, the Swedish Annual Accounts Act and the Swedish Code of Governance. The information in this report is limited to internal control and risk management regarding fi nancial reporting and describes how internal control over the fi nancial reporting is organised, but does not comment on its eff ectiveness.
Lundin Petroleum's objective for fi nancial reporting is to provide reliable and relevant information for internal and external purposes, in compliance with existing laws and regulations, in a timely and accurate manner. An internal control system for fi nancial reporting has been created to ensure that this objective will be met. An internal control system can only provide reasonable and not absolute assurance against material misstatement or loss, and is designed to manage rather than eliminate the risk of failure to achieve the fi nancial reporting objectives.
Lundin Petroleum's Financial Reporting Internal Control System consists of fi ve key components, as described below and is based upon the Committee of Sponsoring Organisations of the Treadway Commission (COSO) model. The internal control of fi nancial reporting is a continuous evaluation of the risks and control activities within the Group. The evaluation work is an ongoing process that involves internal and external benchmarking, as well as improvement and development of control activities.
Lundin Petroleum's Board of Directors has the overall responsibility for establishing an eff ective internal control system. The Audit Committee assists the Board in relation to the fi nancial reporting, internal control and the reporting of fi nancial risks. The Audit Committee also supervises the effi ciency of the internal auditing, internal control and fi nancial reporting and reviews all interim and annual fi nancial reports.
The CEO is responsible for maintaining in the daily operations an eff ective control environment and for operating the system of internal control and risk management in the Group and is assisted by Group management at varying levels. Lundin Petroleum further has an internal auditor whose main responsibility is to ensure adherence to the internal control framework. The internal auditor reports to the Audit Committee.
The development and implementation of a Group-wide framework of consistent policies and procedures, to strengthen the internal control of the Group, is a continuous process. Together with laws and external regulations, these internal policies and procedures form the control environment which is the foundation of the internal control and risk management process at Lundin Petroleum. All employees are accountable for compliance with these policies and procedures within their areas of control and risk management.
The internal control environment of Lundin Petroleum has been further strengthened by a risk management policy that was adopted during 2012. The purpose of the policy is to establish a common understanding of the Company's minimum requirements and principles to be followed in relation to the management of risk for all activities undertaken.
Risk assessment is an integrated part of the internal control framework and is performed on an ongoing basis at Lundin Petroleum. Risk assessment is a process that identifi es, sources and measures the risk of material error in the fi nancial reporting and accounting systems of the Group. This process is the basis for designing control activities to mitigate identifi ed risks.
Risks relating to fi nancial reporting are monitored and assessed by the Board through the Audit Committee. As part of the risk assessment, Lundin Petroleum reviews and analyses the risks that exist within the fi nancial reporting process and structures its internal control systems around the risks identifi ed. The risks are assessed through a standardised methodology based on likelihood and impact and are then documented in a Group-wide risk map. When risks are identifi ed and evaluated, control activities are implemented to minimise the risks in the fi nancial reporting process. Conclusions of the risk assessment are reported to management and the Board through the Audit Committee. Identifi ed risk areas are mitigated through business processes with incorporated risk management, policies and procedures, segregation of duties and delegation of authority. For further details on the diff erent risks, see the Risks and Risk Management section on pages 70–71.
The fi nance department of each Group company is responsible for the regular analysis of the fi nancial results and for reporting thereon to the fi nance department at Group level. Various other control activities are also incorporated into the fi nancial reporting process to ensure that the fi nancial reporting gives a true and fair view at any reporting date and that business is conducted effi ciently.
The Investment Committee, which consists of members of the Executive Management, oversees the Group's investment decisions through the annual budget process, supplementary budget requests submitted during the year etc., and makes recommendations to the Board as required. The Investment Committee meets at least twice per month and its review and approval process constitutes an important control activity within the Group.
The internal auditor performs on a regular basis risk assessments and audits as per an internal audit plan which is approved by the Audit Committee twice per year. In addition, the internal auditor coordinates joint venture audits that are undertaken by Lundin Petroleum. In the oil and gas industry, operations are conducted through joint venture arrangements, where partners share the costs and risks of the activities. To ensure that accounting procedures are followed and costs are incurred in accordance with the joint operating agreement, for non-operated assets, joint venture partners have audit rights over the operating partner.
Communicating relevant information throughout all levels of the Group, as well as to external parties, in a complete, correct and timely manner is an important part of the internal control framework.
Internal policies and procedures relating to the fi nancial reporting, such as the Authorisation Policy, the Group Accounting Principles Manual and the Finance and Accounting Manual, are updated and communicated on a regular basis by Group management to all aff ected employees and are accessible through the information system network.
For communication to external parties, a communications policy has been formulated. The policy has been approved by the Board and defi nes how external information is to be issued, by whom and the way in which the information should be given.
In order to ensure the eff ectiveness of the internal control in respect of the fi nancial reporting, monitoring activities are conducted by the Board, the Audit Committee and the Executive Management, including the Company's CFO. The internal auditor and the Group fi nance department monitor compliance with internal policies, procedures and other policy documents. Further, an important monitoring activity carried out by the internal auditor is to follow-up on the results of the previous years' internal audits and risk assessments to ensure that the appropriate corrective measures have been implemented. Monitoring takes place at a central level, but also locally in the Group companies.
| BOARD OF DIRECTORS | |||||
|---|---|---|---|---|---|
| Name | Ian H. Lundin | C. Ashley Heppenstall | Kristin Færøvik | Asbjørn Larsen | |
| Function | Chairman (since 2002) | President and Chief Executive Offi cer, Director |
Director | Director, CR and HSE Representative |
|
| Elected | 2001 | 2001 | 2011 | 2008 | |
| Born | 1960 | 1962 | 1962 | 1936 | |
| Education | Bachelor of Science degree in Petroleum Engineering from the University of Tulsa. |
Bachelor of Science degree in Mathematics from the University of Durham. |
Master of Science degree in Petroleum Engineering from the University of Trondheim. |
Norwegian School of Economics and Business Administration (NHH). |
|
| Experience | Ian H. Lundin was previously CEO of International Petroleum Corp. during 1989–1998, of Lundin Oil AB during 1998–2001 and of Lundin Petroleum during 2001–2002. |
C. Ashley Heppenstall has worked with public companies where the Lundin family has a major shareholding since 1993. He was CFO of Lundin Oil AB during 1998–2001 and of Lundin Petroleum during 2001–2002. |
Kristin Færøvik is currently the Executive Vice President Off shore of Bergen Group. She worked with Marathon Petroleum Company 2003–2010 and with BP 1986–2003. |
Asbjørn Larsen was CFO of Saga Petroleum during 1978–1979 and President and CEO during 1979–1998. |
|
| Other board duties | Chairman of the board of Etrion Corporation and Bukowski Auktioner AB. |
Member of the board of Etrion Corporation, Vostok Nafta Investment Ltd. and Gateway Storage Company Limited. |
Member of the board of GC Rieber Shipping AS. |
Member of the board of Selvaag Gruppen AS, GreenStream Network Oyj, The Montebello Cancer Rehabilitation Foundation and The Tom Wilhelmsen Foundation. |
|
| Shares in Lundin Petroleum (as at 31 December 2012) |
Nil1 | 1,391,283 | 9,000 | 12,000 | |
| Board Attendance | 8/8 | 8/8 | 8/8 | 8/8 | |
| Audit Committee Attendance |
– | – | – | 6/6 | |
| Compensation Committee Attendance |
– | – | 2/3 | – | |
| Reserves Committee Attendance |
1/1 | – | – | 1/1 | |
| Remuneration for Board and Committee work |
SEK 916,673 | Nil | SEK 525,000 | SEK 525,000 | |
| Remuneration for special assignments outside the directorship 6 |
SEK 1,920,000 | Nil | Nil | Nil | |
| Independent of the Company and the Group management |
Yes2 | No3 | Yes | Yes | |
| Independent of the Company's major shareholders |
No1 | No3 | Yes | Yes |
1 Ian H. Lundin is the settler of a trust that owns Landor Participations Inc., an investment company that holds 11,538,956 shares in the Company, and is a member of the Lundin family that holds, through a family trust, Lorito Holdings (Guernsey) Ltd. which holds 76,342,895 shares in the Company and Zebra Holdings and Investment (Guernsey) Ltd. which holds 10,844,643 shares in the Company.
2 Ian H. Lundin has been regularly retained by management to perform remunerated work duties which fall outside the scope of the regular work of the Board. It is the Nomination Committee's and the Company's opinion that despite his work, he remains independent of the Company and the Group management.
3 C. Ashley Heppenstall is in the Nomination Committee's and the Company's opinion not deemed independent of the Company and the Group management since he is the President and CEO of Lundin Petroleum, and not of the Company's major shareholders since he holds directorships in two companies in which entities associated with the Lundin family hold ten percent or more of the share capital and voting rights.
| BOARD OF DIRECTORS | |||
|---|---|---|---|
| Lukas H. Lundin | William A. Rand | Magnus Unger | Name |
| Director | Director | Director | Function |
| 2001 | 2001 | 2001 | Elected |
| 1958 | 1942 | 1942 | Born |
| Graduate from the New Mexico Institute of Mining, Technology and Engineering. |
Commerce degree (Honours Economics) from McGill University, Law degree from Dalhousie University, Master of Laws degree in International Law from the London School of Economics and Doctorate of Laws from Dalhousie University (Hon.). |
MBA from the Stockholm School of Economics. |
Education |
| Lukas H. Lundin has held several key positions within companies where the Lundin family has a major shareholding. |
William A. Rand practised law in Canada until 1992, after which he co founded an investment company and pursued private business interests. |
Magnus Unger was an Executive Vice President within the Atlas Copco group during 1988–1992. |
Experience |
| Chairman of the board of Lundin Mining Corp., Vostok Nafta Investment Ltd., Denison Mines Corp., Lucara Diamond Corp., NGEx Resources Inc., Sirocco Mining Inc. and Lundin Foundation, member of the board of Fortress Minerals Corp. and Bukowski Auktioner AB. |
Member of the board of Lundin Mining Corp., Vostok Nafta Investment Ltd., Denison Mines Corp., New West Energy Services Inc. and NGEx Resources Inc. |
Chairman of the board of CAL-Konsult AB and member of the board of Black Earth Farming Ltd. |
Other board duties |
| 788,3314 | 120,441 | 50,000 | Shares in Lundin Petroleum (as at 31 December 2012) |
| 7/8 | 8/8 | 8/8 | Board Attendance |
| – | 6/6 | 6/6 | Audit Committee Attendance |
| – | 3/3 | 3/3 | Compensation Committee Attendance |
| – | – | – | Reserves Committee Attendance |
| SEK 425,000 | SEK 675,000 | SEK 625,000 | Remuneration for Board and Committee work |
| Nil | Nil | SEK 100,000 | Remuneration for special assignments outside the directorship 6 |
| Yes | Yes | Yes | Independent of the Company and the Group management |
| No4 | No5 | Yes | Independent of the Company's major shareholders |
4 Lukas H. Lundin is a member of the Lundin family that holds, through a family trust, Lorito Holdings (Guernsey) Ltd. which holds 76,342,895 shares in the Company and Zebra Holdings and Investment (Guernsey) Ltd. which holds 10,844,643 shares in the Company.
5 William A. Rand is in the Nomination Committee's and the Company's opinion not deemed independent of the Company's major shareholders since he holds directorships in companies in which entities associated with the Lundin family hold ten percent or more of the share capital and voting rights.
6 The remuneration paid during 2012 relates to fees paid for special assignments undertaken on behalf of the Group. The payment of such fees was in accordance with fees approved by the 2012 AGM.
Dambisa F. Moyo declined re-election at the AGM on 10 May 2012. During the period of 1 January to 10 May 2012, she attended 2 out 3 Board meetings, as well as 1 out 1 Compensation Committee meeting. For additional information regarding Dambisa F. Moyo, please see the Company's 2011 Annual Report, and for remuneration paid to her during 2012, please refer to Note 33 on pages 102-103.
| EXECUTIVE MANAGEMENT/ INVESTMENT COMMITTEE | ||||
|---|---|---|---|---|
| Name | C. Ashley Heppenstall | Alexandre Schneiter | Geoff rey Turbott | Chris Bruijnzeels |
| Function | President and Chief Executive Offi cer, Director |
Executive Vice President and Chief Operating Offi cer |
Vice President Finance and Chief Financial Offi cer |
Senior Vice President Operations |
| With Lundin Petroleum since |
2001 | 2001 | 2001 | 2003 |
| Born | 1962 | 1962 | 1963 | 1959 |
| Education | Bachelor of Science degree in Mathematics from the University of Durham. |
Graduate from the University of Geneva with a degree in Geology and a Masters degree in Geophysics. |
Member of the Institute of Chartered Accountants of New Zealand. |
Graduate from the University of Delft with a degree in Mining Engineering. |
| Experience | C. Ashley Heppenstall has worked with public companies where the Lundin family has a major shareholding since 1993. He was CFO of Lundin Oil AB during 1998–2001 and of Lundin Petroleum during 2001–2002. |
Alexandre Schneiter has worked with public companies where the Lundin family has a major shareholding since 1993. |
Geoff rey Turbott has worked with public companies where the Lundin family has a major shareholding since 1995. |
Chris Bruijnzeels worked with Shell International during 1985–1998 in several reservoir engineering functions and with PGS Reservoir Consultants during 1998-2003 as Principal Reservoir Engineer and Director Evaluations. |
| Board duties | Member of the board of Etrion Corporation, Vostok Nafta Investment Ltd. and Gateway Storage Company Limited. |
Member of the board of ShaMaran Petroleum Corp. and Swiss Sailing Team AG. |
None. | None. |
| Shares in Lundin Petroleum (as at 31 December 2012) |
1,391,283 | 223,133 | 45,000 | 21,333 |
| Phantom options | 2,062,848 | 1,512,755 | 962,662 | 962,662 |
Stockholm, 9 April 2013
The Lundin Petroleum share is listed on the Large Cap list of the Nasdaq OMX (OMX) Stockholm in Sweden and is part of the OMX 30 index. The share is also listed on the Toronto Stock Exchange (TSX) in Canada.
Lundin Petroleum's market capitalisation as at 31 December 2012 was MSEK 47,528.
During the year a total of 320.9 million shares were traded on the OMX to a value of approximately MSEK 47,452. A daily average of 1.3 million Lundin Petroleum shares were traded on the OMX in Stockholm. 0.6 million shares were traded on the TSX to a value of approximately CAD 12.6 million. A daily average of 3,741 Lundin Petroleum shares were traded on the TSX.
The registered share capital as at 31 December 2012 amounted to SEK 3,179,106 represented by 317,910,580 shares with a quota value of SEK 0.01 each and representing one vote each. All outstanding shares are common shares and carry equal rights to participation in Lundin Petroleum's assets and earnings.
The Annual General Meeting (AGM) of Lundin Petroleum held on 10 May 2012 resolved to authorise the Board of Directors to decide on the repurchase and sale of Lundin Petroleum shares on the OMX and TSX during the period until the next AGM. The maximum number of shares that can be repurchased and held in treasury from time to time cannot exceed fi ve percent of all shares of Lundin Petroleum. The purpose of the authorisation is to provide the Board of Directors with a means to optimise Lundin Petroleum's capital structure and to secure Lundin Petroleum's exposure in relation to the LTIPs.
The total number of repurchased shares held by Lundin Petroleum on 31 December 2012 amounted to 7,368,285.
During the AGM in 2012 it was resolved that the Board of Directors is authorised to issue no more than 35 million new shares, without the application of the shareholders' pre-emption rights, in order to enable the Company to raise capital for the Company's business operations and business acquisitions. If the authorisation is fully utilised the dilution eff ect on the share capital will amount to ten percent.
Lundin Petroleum's primary objective is to add value to the shareholders, employees and society through profi table operations and growth. This will be achieved by increased hydrocarbon reserves, developing discoveries and thereby increasing production and ultimately cash fl ow and operating income. This added value will be expressed partly by a long-term increase in the share price and dividends.
The size of any dividend would have to be determined by Lundin Petroleum's fi nancial position and the possibilities for growth through profi table investments. Dividends will be paid when Lundin Petroleum generates suffi cient cash fl ow and operating income from operations to maintain long-term fi nancial strength and fl exibility. Over time the total return to shareholders is expected to transfer from an increase in share price to dividends received.
Lundin Petroleum is progressing on a number of transformational development projects which will require funding. This development funding will take priority over dividend payments.
Since Lundin Petroleum was incorporated in May 2001 and up to 31 December 2012 the Parent Company share capital has developed as shown below.
| Share data | Year | Quota value (SEK) |
Change in number of shares |
Total number of shares |
Total share capital (SEK) |
|---|---|---|---|---|---|
| Formation of the Company | 2001 | 100.00 | 1,000 | 1,000 | 100,000 |
| Share split 10,000:1 | 2001 | 0.01 | 9,999,000 | 10,000,000 | 100,000 |
| New share issue | 2001 | 0.01 | 202,407,568 | 212,407,568 | 2,124,076 |
| Warrants | 2002 | 0.01 | 35,609,748 | 248,017,316 | 2,480,173 |
| Incentive warrants | 2002–2008 | 0.01 | 14,037,850 | 262,055,166 | 2,620,552 |
| Valkyries Petroleum Corp. acquisition | 2006 | 0.01 | 55,855,414 | 317,910,580 | 3,179,106 |
| Total | 317,910,580 | 317,910,580 | 3,179,106 |
| 2012 | |
|---|---|
| Number of shares issued | 317,910,580 |
| Number of shares owned by Lundin Petroleum | 7,368,285 |
| Number of shares in circulation | 310,542,295 |
Lundin Petroleum had 43,954 shareholders as at 31 December 2012. The proportion of shares held by Swedish retail investors amounted to 12 percent. Foreign investors held 70 percent of the shares.
| The 10 largest shareholders as at 31 Dec 2012 |
Number of shares |
Subscription capital/votes,% |
|---|---|---|
| Lorito Holdings (Guernsey) Ltd.1 | 76,342,895 | 24.01 |
| Landor Participations Inc.2 | 11,538,956 | 3.63 |
| Zebra Holdings and Investment (Guernsey) Ltd.1 |
10,844,643 | 3.41 |
| Swedbank Robur fonder | 8,248,334 | 2.59 |
| Lundin Petroleum AB | 7,368,285 | 2.32 |
| Norges Bank Investment Management (Pension Fund Global) |
5,314,647 | 1.67 |
| Fjärde AP-fonden | 3,657,851 | 1.15 |
| Länsförsäkringar fondförvaltning AB | 2,918,807 | 0.92 |
| Första AP-Fonden | 2,901,928 | 0.91 |
| Danske Capital Sverige AB | 2,795,260 | 0.88 |
| Other shareholders | 185,978,974 | 58.51 |
| Total | 317,910,580 | 100.00 |
1 An investment company wholly owned by a Lundin family trust.
An investment company wholly owned by a trust whose settler is Ian H. Lundin.
The top 10 shareholder list excludes shareholdings through nominee accounts. The above list only includes institutional shareholders who hold the shares directly as reported by Euroclear Sweden with the exception of the shareholding of Norges Bank Investment Management (NBIM) whose holding has been obtained directly from NBIM.
| Size categories | Numbers of shareholders |
Percentage of shares,% |
|---|---|---|
| 1–500 | 30,813 | 1.53 |
| 501–1,000 | 5,786 | 1.53 |
| 1,001–10,000 | 6,275 | 5.85 |
| 10,001–50,000 | 706 | 4.81 |
| 50,001–100,000 | 118 | 2.58 |
| 100,001–500,000 | 168 | 12.62 |
| 500,001– | 88 | 71.08 |
| Total | 43,954 | 100.00 |
SHARE PRICE 2012
Traded daily volume OMX (monthly average)
180
The objective of 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 Company and is designed to ensure that all risks are identifi ed, 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 fi nancial 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 has identifi ed the following principal risks relative to the Group's performance. The impact of risks within any one of these segments can infl uence the reputation of the Company (reputational risk).
| Description of risk | Mitigation – Risk management |
|---|---|
| STRATEGIC RISK | |
| Failure to create shareholder value and meet shareholder expectations A strategy that is ineff ective and poorly communicated or executed may lead to a loss of investor confi dence and a reduction in the share price. |
Lundin Petroleum's business model clearly defi nes the vision and strategy of the Company. Throughout all stages of the business cycle, Lundin Petroleum seeks to generate shareholder value by proactively investing in exploration to organically grow the reserve base, exploiting the existing asset base and acquiring new or disposing of reserves, as well as through an opportunistic approach. Strong communication channels are coupled with eff ective leadership in order to maintain creativity and an entrepreneurial spirit. This ensures that the entire organisation works |
| towards the same goal. | |
| Inadequate asset portfolio management Ineff ective management may lead to a failure to understand and unlock the full value of an asset which could negatively impact shareholder value. |
Lundin Petroleum continually reviews the economic value of the existing asset portfolio in order to ensure that the value of each asset within the portfolio is well understood, communicated and fully refl ected within the share price. |
| Ineff ective recruitment, retention and management of human capital An inability to attract and retain employees could cause short and medium term disruption to the business. |
The Lundin Petroleum recruitment and compensation strategy is aligned with corporate goals and objectives and takes into consideration industry trends. The Performance Management process is designed to drive engagement and create a philosophy of ownership at all levels of the Company. |
| Lack of corporate responsibility and environmental awareness A real or perceived lack of corporate responsibility and environmental awareness can have an adverse impact on the people the Company works with, on the environment in which the Company operates and as well as on its reputation. Any such impact on the Company's reputation could in turn impact its license to operate, fi nancing or access to new opportunities. |
Lundin Petroleum's Corporate Responsibility framework is applied to all its activities and includes monitoring of risk mitigation measures, reporting and investigation of all incidents. Communication plans and management of stakeholder relations are designed to maintain good and eff ective relationships. (See also pages 40–47 Corporate Responsibility for more information). The Company's aim is to explore for and produce oil and gas in an economically, socially and environmentally responsible way, for the benefi t of all its stakeholders, including shareholders, employees, business partners, host and home governments and local communities. |
| FINANCIAL RISK 1 | |
| Cost escalation and investment oversight Adequate policies must be in place to ensure that all necessary internal and external approvals are in place prior to the commitment to spend. Any change in expenditures must be captured in a timely manner through the reporting requirements. |
Through the Lundin Petroleum annual budget and supplementary budget approval process the Company has implemented a rigorous process of oversight of all expenditure on a continual basis. This process ensures that expenditure is in line with approvals from the Investment Committee and that change is communicated in a thorough and timely manner. |
| Liquidity risk The risk that the Group may not be able to settle or meet its obligations on time or at a reasonable price, could lead to inability to fund exploration and development work programmes. |
Lundin Petroleum monitors rolling forecasts of the Group's liquidity requirements to ensure that it has suffi cient cash to meet operational needs. The economics and planning department continuously monitors the macro and micro economic environment impacting the Group's business to ensure that management is informed of developments impacting capital decision making. |
| Credit risk The risk arises from cash and cash equivalents, deposits with banks and fi nancial institutions as well as credit exposure to customers. |
Lundin Petroleum's policy is to limit credit risk by limiting the customers and partners to major oil companies and only use major banks. If there is a credit risk for oil and gas sales, the policy is to require an irrevocable letter of credit for the full value of the sale. |
| Financial reporting risk The risk that material misstatements in fi nancial reporting and failure to accurately report fi nancial data could lead to regulatory action, legal liability and damage to the Company's reputation. |
The internal control system for fi nancial reporting is in place to ensure the Group's objective for fi nancial reporting is fulfi lled. |
1 For more detailed information regarding fi nancial risks see also Note 13 in notes to the fi nancial statements pages 97–99. More information on the internal control is found in the Corporate Governance report 48–66.
| Description of risk | Mitigation – Risk management |
|---|---|
| OPERATIONAL RISK | |
| Development projects do not achieve stated objectives Ensuring that development projects remain on budget, on schedule and achieve operational objectives is essential in ensuring that shareholder value is maximised. |
All development projects must pass through the Lundin Petroleum value process that requires technical, fi nancial, Investment Committee and Board approval of all investment decisions. The development project management process assigns a steering committee that provides guidance, direction and control to the project. Government organisations, partners and third party groups also provide independent oversight. In Norway the Company is governed by the detailed guidelines for plan for development and operation of a petroleum deposit (PDO) and plan for installation and operation of facilities for transport and utilisation of petroleum (PIO) as published by the Norwegian Petroleum Directorate. |
| Health, safety and environment (HSE) A major operational HSE event could have a negative impact on the people and environment in which the Company works. This in turn can have an adverse impact on valuation. |
Lundin Petroleum promotes active management of HSE issues throughout the Group. Proactive risk management, HSE policies, and an HSE management system in compliance with statutory requirements are an integral part of operations. (See also pages 40–47 Corporate Responsibility for more information.) |
| Increase in production costs Production costs are aff ected by the normal economic drivers of supply and demand as well as by various fi eld operating conditions. |
Eff ective procurement and cost control management processes are essential in ensuring that reasonable cost levels are achieved relative to business plans. Diligent operations management and eff ective maintenance planning help to ensure effi ciency during operations. Production delays and declines from normal fi eld operating conditions cannot be eliminated and may adversely aff ect revenue and cash fl ow levels to varying degrees. |
| Availability of operational equipment Oil and gas exploration and development activities are dependent on the availability of drilling and related equipment. An inability to procure equipment on a timely basis may delay exploration and development activities. |
Advanced planning of the Company's operational programme includes ensuring that the contracting strategy and procurement process is in place. Regular engagement with contractors and suppliers as well as consideration for equipment as part of the licence application process mitigates the risk. |
| Reserve and resources estimates In general, estimates of economically recoverable oil and gas reserves and the future net cash fl ows therefrom are based upon a number of variable factors and assumptions. All such estimates are to some degree speculative, and classifi cations of reserves are only attempts to defi ne the degree of speculation involved. |
Reserves and resource calculations undergo a comprehensive internal peer review process and adhere to industry standards. All reserves are independently audited by ERC-Equipoise Ltd. as part of the annual reserves audit process unless otherwise stated. (See also pages 12–17 Reserves, Resources and Production for more information.) |
| Inability to replace and grow reserves The ability to increase reserves will depend not only on the ability to explore and develop the Company's present portfolio of opportunities, but also on the ability to select and acquire suitable producing assets or prospects. |
The use of eff ective peer review for subsurface analysis and well site selection together with a well defi ned strategy for recruitment and retention of talented personnel mitigates the risk. (See also pages 12–17 Reserves, Resources and Production for more information.) |
| Ineff ective systems to prevent bribery and corruption Corruption can occur in any country of operation. Incidents of non-compliance with anti-bribery and anti-corruption laws could be damaging to Lundin Petroleum, its reputation and shareholder value. |
A consistent application of Lundin Petroleum's Code of Conduct, together with policies and procedures that clearly defi ne levels of authority and internal control requirements help to mitigate risk. In 2010 Lundin Petroleum joined the UN Global Compact to further confi rm the Company's commitment to ethical business practice and the Board of Directors adopted in 2011 an anti-corruption policy and guidelines. (See also pages 40–47 Corporate Responsibility for more information.) |
| EXTERNAL RISK | |
| Geopolitical Risk The Company is, and will be, actively engaged in oil and gas operations in various countries. Changes to laws within these countries may lead to negative consequences such as but not limited to the expropriation of property, cancellation of or modifi cation of contract rights, and or increased taxation. |
The Company reviews its portfolio of assets in relation to its fi nancial performance on a regular basis. The consideration of political risk elements is a key component driving investment decisions for the Company as a whole. Local laws are monitored and the Company strives to ensure comprehensive interpretation and compliance with any changes that may impact the business. |
| Fluctuation in the price of oil and gas The price of oil and gas are aff ected by the normal economic drivers of supply and demand as well as the fi nancial investors and market uncertainty. |
Lundin Petroleum's policy is to adopt a fl exible approach towards oil price hedging based on an assessment of the benefi ts of the hedge contract in specifi c circumstances. |
| Fluctuation in currency rates Crude oil prices are generally set in US dollars, whereas costs may be in a variety of currencies. Fluctuation in exchange rates can therefore give rise to foreign exchange exposures |
Lundin Petroleum's policy on currency rate hedging is, in case of currency exposure, is to consider setting the rate of exchange for known costs in non-US Dollar currencies to US Dollars in advance so that future US Dollar cost levels can be forecasted with a reasonable degree of certainty. The functional currencies of the companies in the Group are reviewed annually. |
| Interest rate risk The uncertainty in future interest rates could have an impact on the Company's earnings. The Group's interest rate risk arises from long-term borrowings. |
Lundin Petroleum regularly assesses the benefi ts of interest rate hedging on borrowings. |
| Directors' report | 73 |
|---|---|
| Consolidated income statement | 82 |
| Consolidated statement of comprehensive income | 83 |
| Consolidated balance sheet | 84 |
| Consolidated statement of cash fl ow | 85 |
| Consolidated statement of changes in equity | 86 |
| Accounting policies | 87 |
| Notes to the fi nancial statements of the Group - Note 1 – Segment information - Note 2 – Production costs - Note 3 – Depletion and decommissioning costs - Note 4 – Exploration costs - Note 5 – Impairment costs of oil and gas properties - Note 6 – Financial income - Note 7 – Financial expenses - Note 8 – Income taxes - Note 9 – Oil and gas properties - Note 10 – Other tangible assets - Note 11 – Shares in jointly controlled entities and associated companies - Note 12 – Other shares and participations - Note 13 – Financial risks, sensitivity analysis |
92 92 92 93 93 93 93 93 93 95 96 97 97 |
| and derivative instruments - Note 14 – Other fi nancial assets |
97 99 |
| - Note 15 – Inventories - Note 16 – Trade receivables - Note 17 – Prepaid expenses and accrued income - Note 18 – Other receivables - Note 19 – Cash and cash equivalents - Note 20 – Other reserves - Note 21 – Provision for site restoration - Note 22 – Pension provision - Note 23 – Other provisions - Note 24 – Financial liabilities - Note 25 – Accrued expenses and deferred income - Note 26 – Other liabilities |
99 99 99 100 100 100 100 100 100 100 101 101 |
| - Note 27 – Pledged assets | 101 |
| - Note 28 – Contingent liabilities and assets | 101 |
|---|---|
| - Note 29 – Earnings per share | 101 |
| - Note 30 – Adjustment for non-cash related items | 101 |
| - Note 31 – Related party transactions | 101 |
| - Note 32 – Average number of employees | 102 |
| - Note 33 – Remuneration to the Board of directors, | |
| Executive Management and other employees | 102 |
| - Note 34 – Long-term incentive plans | 104 |
| - Note 35 – Remuneration to the Group's auditors | 104 |
| - Note 36 – Subsequent events | 104 |
| Annual accounts of the Parent Company | 105 |
| Parent Company income statement | 105 |
| Parent Company statement of comprehensive income 105 | |
| Parent Company balance sheet | 106 |
| Parent Company statement of cash fl ow | 107 |
| Parent Company statement of changes in equity | 108 |
| Notes to the fi nancial statements of the | |
| Parent Company | 109 |
| - Note 1 – Other operating income per country | 109 |
| - Note 2 – Financial income | 109 |
| - Note 3 – Financial expenses | 109 |
| - Note 4 – Income taxes | 109 |
| - Note 5 – Other receivables | 109 |
| - Note 6 – Provisions | 109 |
| - Note 7 – Accrued expenses and prepaid income | 109 |
| - Note 8 – Financial instruments by category | 109 |
| - Note 9 – Pledged assets, contingent liabilities and assets 109 | |
| - Note 10 – Remuneration to the auditor | 109 |
| - Note 11 – Shares in subsidiaries | 110 |
| Board assurance | 111 |
| Auditor's report | 112 |
| Five year fi nancial data | 113 |
| Key fi nancial data | 114 |
| Reserve quantity information | 115 |
| Shareholder information | 116 |
The address of Lundin Petroleum AB's registered offi ce is Hovslagargatan 5, Stockholm, Sweden.
The main business of Lundin Petroleum is the exploration for, the development of, and the production of oil and gas. Lundin Petroleum maintains a portfolio of oil and gas production assets and development projects in various countries with exposure to exploration opportunities.
The Group does not carry out any signifi cant research and development. The Group maintains branches in most of its areas of operation. The Parent Company has no foreign branches.
On 27 August 2012, Lundin Petroleum acquired a further 60 percent equity in Ikdam Production SA, a company which owns the Ikdam FPSO vessel, bringing its total ownership to 100 percent. The fi nancial results of Ikdam Production SA are fully consolidated in the Group's fi nancial statements from the end of August 2012.
| (Cy) | Cyprus | (R) | Russia |
|---|---|---|---|
| (F) | France | (S) | Sweden |
| (N) | Netherlands | (Sw) | Switzerland |
| (No) | Norway |
See Group Financial Statements Note 11 and Parent Company Financial Statements Note 11 for full legal names and all subsidiaries Note: The Group structure shows significant subsidiaries only
Production for the fi nancial year 2012 amounted to 35.7 thousand barrels of oil equivalent per day (Mboepd) (33.3 Mboepd) and was comprised as follows:
| Production | ||
|---|---|---|
| in Mboepd | 2012 | 2011 |
| Crude oil | ||
| Norway | 23.3 | 21.1 |
| France | 2.8 | 3.1 |
| Russia | 2.7 | 3.1 |
| Tunisia | 0.1 | 0.7 |
| Total crude oil production | 28.9 | 28.0 |
| Gas | ||
| Norway | 3.9 | 2.1 |
| Netherlands | 1.9 | 2.0 |
| Indonesia | 1.0 | 1.2 |
| Total gas production | 6.8 | 5.3 |
| Total production | ||
| Quantity in Mboe | 13,050.4 | 12,151.5 |
| Quantity in Mboepd | 35.7 | 33.3 |
| Production |
|---|
| ------------ |
| Production in Mboepd |
Lundin Petroleum Working Interest (WI) |
2012 | 2011 |
|---|---|---|---|
| Alvheim | 15% | 11.8 | 11.2 |
| Volund | 35% | 13.1 | 12.0 |
| Gaupe | 40% | 2.3 | – |
| 27.2 | 23.2 |
The net production from the Alvheim fi eld during the year exceeded expectations due to the excellent uptime performance of the Alvheim FPSO at over 95 percent and the cancellation of the anticipated second quarter shut-down of the SAGE system. An Alvheim development well was drilled during the fi rst half of 2012 and was tied-in and put on production in October 2012. In January 2013, the Alvheim partnership was awarded additional acreage to the north of the Alvheim fi eld through the 2012 APA licensing round. The work programme for this new acreage involves 3D seismic reprocessing with the objective of identifying potential new drilling targets in the Alvheim area. The cost of operations for the Alvheim fi eld for the year was below USD 5 per barrel excluding planned well intervention work during the third quarter of 2012.
Volund fi eld production during the year exceeded expectations due to better than expected reservoir performance and the Alvheim FPSO uptime. An additional Volund development well has been drilled and was put onstream in the fi rst quarter of 2013. The cost of operations for the Volund fi eld for the year was below USD 2 per barrel driven by lower than expected production costs and better than expected production.
First production from the Gaupe fi eld in PL292 was achieved on 31 March 2012. Production from the Gaupe fi eld has been below forecast since the commencement of production. Technical analysis indicates that the two production wells are connected to lower hydrocarbon volumes than was forecast prior to production start-up. Consequently the reserves have been reduced based on the conservative assumption that no additional production wells will be drilled.
The Norwegian Parliament approved the Edvard Grieg (WI 50%) plan of development in June 2012. The development plan incorporates the provision for the coordinated development solution of the Edvard Grieg fi eld with the nearby Ivar Aasen fi eld (formerly Draupne) located in PL001B and operated by Det norske oljeselskap ASA. A plan of development was submitted for the Ivar Aasen fi eld in December 2012.
The Edvard Grieg fi eld is estimated to contain 186 million barrels of oil equivalents (MMboe) of gross reserves with fi rst production expected in late 2015 and forecast gross peak production of approximately 100.0 Mboepd. The gross capital cost of the Edvard Grieg fi eld 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. The development is progressing well and construction work on the jacket is ongoing. Construction and engineering work on the jacket, topside and export pipelines will continue throughout 2013. An appraisal well is planned to be drilled in the southeastern part of the Edvard Grieg reservoir in 2013 to target additional resources.
A plan of development of the Brynhild fi eld in PL148 (WI 90%) was approved by the Norwegian Ministry of Petroleum and Energy in November 2011. The Brynhild fi eld contains gross reserves of 23.1 MMboe and is expected to produce at an estimated gross plateau production rate of 12.0 Mboepd with fi rst oil forecast in late 2013. The development involves the drilling of four wells tied back to the existing Shell operated Pierce fi eld infrastructure in the United Kingdom sector of the North Sea. The development is well advanced in respect of engineering and construction work and the Maersk Guardian jack-up rig will commence development drilling in the second quarter of 2013. In December 2012, Lundin Petroleum announced that it had completed a transaction with Talisman Energy to acquire an additional 20 percent interest in PL148, taking Lundin Petroleum's interest in the fi eld to 90 percent.
A plan of development for the Bøyla fi eld in PL340 (WI 15%) was submitted in June 2012 and approved by the Ministry of Petroleum and Energy in October 2012. The Bøyla fi eld contains gross reserves of 21 MMboe and will be developed as a 28 km subsea tie-back to the Alvheim FPSO. First oil from the Bøyla fi eld is expected in the fourth quarter of 2014 at a gross plateau production rate of 19.0 Mboepd.
Lundin Petroleum discovered the Avaldsnes fi eld in PL501 (WI 40%) in 2010. In 2011, Statoil made the Aldous Major South discovery on the neighboring 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. An appraisal programme is ongoing to defi ne the recoverable resource and assist with the development planning strategy.
During the year, a total of four appraisal wells and two sidetracks on PL501 were drilled and a further two appraisal wells on PL265 were also completed.
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 fl ank 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.
In March 2012, a further appraisal well, 16/2-11, was completed 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 sidetrack of the well was successfully completed encountering a 35 metre gross oil column confi rming similar excellent reservoir thickness and quality.
In the third quarter of 2012, the drilling of the appraisal well 16/2-13S on the northeastern part of the Johan Sverdrup discovery and a sidetrack well 16/2-13A were successfully completed. The results from the wells were excellent in respect of reservoir quality and thickness, validating the fi eld geological model and confi rming a deeper oil water contact at this location. Well 16/2-13S encountered a 25 metre gross oil column in Upper and Middle Jurassic sandstone reservoir in an oil-down-to situation. The sidetrack well 16/2-13A encountered a gross reservoir column of approximately 22 metres, of which 12 metres were above the oil water contact. The oil water contact was established at approximately 1,925 metres below Mean Sea Level (MSL) which is approximately 3 metres deeper than observed in earlier PL501 wells.
In December 2012, the drilling of appraisal well 16/2-16 in the northeastern fl ank of the discovery was successfully completed. The well encountered a total of 15 metres of sand within a 60 metre Jurassic sequence. The oil water contact was encountered at the same depth as for well 16/2-13A to the east at 1,925 metres below MSL, resulting in an oil bearing reservoir column at this location of approximately 1 metre. A further sidetrack 16/2-16AT2 was drilled to the west of well 16/2-16 with a step-out of approximately 1,000 metres. The sidetrack, which was successfully completed in January 2013, encountered a gross oil column of 30 metres with largely excellent reservoir qualities within the Jurassic reservoir sequence. Oil was encountered at the same depth as at well 16/2-10 on PL265 which is the deepest oil water contact encountered in Johan Sverdrup so far.
Appraisal well 16/3-5 in the southeastern part of Johan Sverdrup in PL501 has been successfully completed and tested in the fi rst quarter of 2013.
In November 2012, Statoil announced the successful completion of appraisal well 16/2-14 on Johan Sverdrup in PL265. Well 16/2-14 was drilled in a northwestern segment of Johan Sverdrup approximately 6 km northwest of the discovery well 16/2-6 drilled by Lundin Petroleum. The well 16/2-14 encountered an approximately 30 metre reservoir section saturated with oil. The well confi rmed good reservoir quality at this location.
In early January 2013, the Norwegian Petroleum Directorate announced the successful completion of appraisal well 16/2-15 drilled in the southwestern part of Johan Sverdrup in PL265. The well was drilled 5 km southeast of the discovery well 16/2-6 and encountered a gross oil column of 30 metres of which 20 metres contained excellent reservoir quality.
It is likely that at least two further appraisal wells will be drilled in both PL501 and PL265 in 2013.
Lundin Petroleum, as operator of PL501, has signed a Pre-Unit agreement with the partners within PL501 and PL265 for the joint fi eld development of the Johan Sverdrup fi eld. Statoil has been elected as working operator for the Pre-Unit phase. All parties in PL501 and PL265 have agreed a timetable for the Johan Sverdrup fi eld with development concept selection to be made by the fourth quarter of 2013, a plan of development to be submitted by the fourth quarter of 2014 and fi rst oil production by the end of 2018.
During the year a total of fi ve exploration wells have been completed in Norway.
In June 2012, the drilling of exploration well 2/8-18S targeting the Clapton prospect on PL440s (WI 18%) was completed by the operator Faroe Petroleum. The well, which is located in the southern North Sea, did not encounter hydrocarbons. The well was drilled to a depth of 2,619 metres below MSL and was plugged and abandoned.
In August 2012, the exploration well 16/2-12 targeting the Geitungen structure in PL265 (WI 10%) was successfully completed as an oil discovery. The well, which was located to the north of the Johan Sverdrup discovery and to the south of 16/2-9S Aldous Major North discovery, has proved a gross oil column of 35 metres in high quality sandstone of Jurassic age. Oil was also proven in the basement rock. Data acquisition in the well, including coring, wireline logging and fl uid sampling, indicates that the Geitungen structure is in communication with the Johan Sverdrup discovery made by Lundin Petroleum in 2010. Preliminary calculations indicate that the size of the Geitungen discovery is between 140 and 270 million barrels of gross recoverable oil1 . Geitungen will be developed as part of the Johan Sverdrup development.
In October 2012, Lundin Petroleum announced the results of the Albert well in PL519 (WI 40%). The main objective of well 6201/11-3 was to test Cretaceous and Triassic age sandstones of a multiple target structure. The well encountered oil in thin Cretaceous reservoir sequence at the predicted level for the primary target. The thin thickness and uncertain distribution of the reservoir do not give a basis for resource estimation at this stage and as such the discovery is currently deemed uncommercial. Further potential exists within the Albert structure if thicker Cretaceous reservoir section in this large structure can be identifi ed. The Triassic secondary reservoir was tight without movable hydrocarbons. A minor column of movable hydrocarbons was also encountered in a Paleocene secondary target. Further exploration activity is planned in this area in 2014 with the drilling of the Storm prospect in PL555 where Lundin Petroleum holds a 60 percent interest and is operator.
In October 2012, Lundin Petroleum announced that exploration well 7220/10-1 in PL533 (WI 20%) had discovered gas/condensate in the Salina structure located on the west fl ank of the Loppa High in the Barents Sea. The well has proved two gas columns in sandstone of Cretaceous and Jurassic age. Data acquisition in the well, including coring, wireline logging and fl uid sampling, has proven good reservoir quality in the sandstone. Preliminary calculations, made by the Norwegian Petroleum Directorate, give a range of gross discovered volume in the Salina structure of between 174 and 246 billion cubic feet (bcf ) (29 and 41 MMboe) of recoverable gas/condensate. Further resource upside exists in fault compartments associated with the Salina structure.
In November 2012, Lundin Petroleum successfully completed the exploration well 7120/6-3S in PL490 (WI 50%) in the Barents Sea. The well was located 10 km to the northwest of the Snøhvit fi eld and was targeting stacked targets Snurrevad and Juksa at the lower Cretaceous and upper Jurassic reservoirs. The preliminary analysis of a cored section of the reservoir indicate thin oil bearing sands in a 8 to 9 metres zone at the top of a 25 metre lower Cretaceous sand sequence. No reservoir was found to be present in the Snurrevad target at the Jurassic level. The thin oil bearing sands in the Juksa discovery are unlikely to be commercial however it is encouraging that the well encountered oil bearing sands as opposed to gas.
Lundin Petroleum announced in July 2012 that it had entered into farm-out agreements to reduce its holdings in a number of licences. Spring Energy Norway AS has acquired a 10 percent interest in PL490, with Lundin Petroleum retaining 50 percent and Norwegian Energy Company ASA has acquired a 10 percent interest in PL492, with Lundin Petroleum retaining 40 percent; both licences are located in the Barents
1 Estimated by PL265 operator, Statoil
Sea. Explora Petroleum AS has acquired a 30 percent interest in PL544 and Lundin Petroleum retains 40 percent; the licence is located in the North Sea. The Norwegian authorities have approved these farm-out agreements. In January 2012, Lundin Petroleum was awarded ten exploration licences in the APA 2011 licensing round of which four are operated by Lundin Petroleum. In January 2013, Lundin Petroleum was awarded a further seven exploration licences in the APA 2012 licensing round of which two are operated by Lundin Petroleum. Four of the seven licences awarded are in the North Sea, two in the Norwegian Sea and one in the Barents Sea. Lundin Petroleum has submitted several licence applications for the 22nd Norwegian licensing round with awards expected to be announced by the Ministry of Petroleum and Energy in the fi rst half of 2013.
Lundin Petroleum's exploration programme in Norway for 2013 will consist of 10 exploration wells with a continued focus on the Utsira High area with six exploration wells targeting similar play concepts as Johan Sverdrup and Edvard Grieg. In addition, one exploration well has been drilled in the fi rst quarter 2013 in the southern North Sea and a second well is expected to be drilled and completed in the second quarter 2013. One well is planned to be drilled in the Barents Sea and one well is scheduled to be drilled on PL330 (WI 30%) in the northern Norwegian Sea. Rigs have been secured for all of the 2013 exploration wells.
| Production in Mboepd |
Lundin Petroleum Working Interest (WI) |
2012 | 2011 |
|---|---|---|---|
| Paris Basin | 100% | 2.3 | 2.4 |
| Aquitaine Basin | 50% | 0.5 | 0.7 |
| 2.8 | 3.1 |
The redevelopment of the Grandville fi eld in the Paris Basin was substantially completed during the year with the development wells brought onstream during the fourth quarter of 2012.
Two exploration wells were drilled in the year. The Amaltheus exploration well in the Paris Basin on the Val des Marais concession (WI 100%) was successfully completed in the fourth quarter of 2012 as an oil discovery. The well has been put on long-term test. A second exploration well targeting the Contault prospect in the Paris Basin on the Est Champagne concession (WI 100%) was completed during the fourth quarter of 2012 as a dry hole. Lundin Petroleum is drilling one exploration well in the Paris Basin in 2013. The Hoplites-1 well will be drilled on the Est Champagne concession (WI 100%) targeting the Nettancourt prospect.
The net gas production to Lundin Petroleum from the Netherlands averaged 1.9 Mboepd for the year. Development drilling on existing production assets is ongoing to optimise fi eld recovery. The Vinkega-2 exploration well in the Gorredijk concession (WI 7.75%) was a gas discovery in the third quarter of 2012 and is currently planned to commence production in the second quarter of 2013.
Lundin Petroleum is participating in two exploration wells onshore Netherlands in 2013.
Following the completion of seismic studies on the Slyne Basin licence 04/06 (WI 50%), the licence partners are considering the way forward.
The net production to Lundin Petroleum from the Singa gas fi eld (WI 25.9%) during the year amounted to 1.0 Mboepd. Production in the year has been negatively aff ected by well maintenance work which was completed in September 2012.
Exploration drilling on the Baronang Block (WI 100%) will commence in 2013.
A 3D seismic acquisition programme is planned to be completed in 2013 on South Sokang (WI 60%).
A 3D seismic acquisition programme of 950 km2 has been completed in 2012 on the Gurita Block (WI 100%) and an exploration well will be drilled in 2013.
East Malaysia, off shore Sabah
Lundin Petroleum holds two licences off shore Sabah in east Malaysia.
SB303 (WI 75%) contains the Tarap, Cempulut and Titik Terang gas discoveries with an estimated gross contingent resource of more than 270 bcf. Lundin Petroleum continues to evaluate the potential for commercialisation of these gas discoveries, most likely through a cluster development.
In September 2012, the Berangan-1 exploration well in SB303 was successfully completed as a gas discovery. The well penetrated a gross gas column of over 165 metres in the target mid-Miocene aged sands 10 km to the southeast of the Tarap gas discovery made by Lundin Petroleum in 2011, and 15 km to the south of the Cempulut gas discovery also made in 2011. The Berangan discovery is estimated to contain 69 bcf (11.5 MMboe) of gross contingent gas resources and it is likely that it will be included in a cluster development with the other SB303 gas discoveries.
In July 2012, the Tiga Papan 5 well in SB307/308 (WI 42.5%) targeting mid-Miocene aged sands of the Tiga Papan Unit was plugged and abandoned as a dry hole.
One exploration well will be drilled off shore Sabah in 2013.
Lundin Petroleum holds four licences off shore Peninsular Malaysia.
In June 2011, Lundin Petroleum acquired a 75 percent working interest in Block PM307. 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. Conceptual development studies are substantially complete in relation to a potential development of the Bertam fi eld and a decision will be taken in 2013. In November 2012, Lundin Petroleum announced the Tembakau-1 well, drilled on Block PM307, as a gas discovery. The Tembakau-1 well was drilled to a total depth of 1,565 metres and encountered a series of stacked gas pay sands at the Miocene level. The net pay was 60 metres over fi ve high quality sand intervals. Given the relatively close proximity to existing gas infrastructure coupled with the forecast strong demand for gas on Peninsular Malaysia the building blocks for a commercial development are present and further studies will be undertaken to assess the commerciality of this discovery. It is estimated that the Tembakau discovery contains 306 bcf (51 MMboe) of gross contingent gas resources. A 3D seismic acquisition programme over the northern part of Block PM307 is currently ongoing. The 3D seismic acquisition is also stretching into the recently awarded Block PM319 (WI 75%).
Block PM308A (WI 35%) contains the Janglau and Rhu oil discoveries. A further exploration well targeting the Ara prospect on Block PM308A has been completed in the fi rst quarter 2013. The well is targeting the Oligocene intra-rift sands discovered by the Janglau exploration well drilled in 2011. An acquisition of 1,450 km2 of new 3D seismic in PM308A was completed during the year.
In Block PM308B (WI 75%) the Merawan Batu-1 exploration well was completed in October 2012 and plugged and abandoned as a dry hole.
In December 2012, Lundin Petroleum announced the award of a new block off shore Peninsular Malaysia. Block PM319 is operated by Lundin Petroleum with a 85 percent working interest, with Petronas holding a 15 percent working interest. The block covers an area of approximately 8,400 km2 and is located west of Block PM307 where Lundin Petroleum and Petronas have achieved success during 2012 with the appraisal of the Bertam oil fi eld and the discovery of gas with the Tembakau-1 well. The area has very limited 3D coverage and work commitments include a full tensor gravity survey, 550 km2 of 3D seismic and one exploration well.
Two exploration wells off shore Peninsular Malaysia will be drilled in 2013.
The net production to Lundin Petroleum from onshore assets located in the Komi Republic, Russia for the year was 2.7 Mboepd. Production has been below expectations through the year and consequently the remaining reserves as at 31 December 2012 have been reduced.
In the Lagansky Block (WI 70%) in the northern Caspian a major oil discovery was made on the Morskaya discovery in 2008. The discovery is deemed to be strategic, due to its off shore location, by the Russian Government under the Foreign Strategic Investment Law (FSIL). As a result a 50 percent ownership by a state owned company is required prior to appraisal and development. Discussions continue with third parties to meet the requirements of the FSIL.
The production from the Oudna fi eld (WI 40%) for the fi rst quarter of 2012 was 0.4 Mboepd and 0.1 Mboepd for the year. Following storm damage to a fl owline in March 2012, the Oudna fi eld was shut-in. An assessment of repair solutions to the fl owline was carried out and it was determined to be uneconomic to repair. During 2012, the Ikdam FPSO was disconnected from the Oudna fi eld and the wells were permanently abandoned. During the year Lundin Petroleum has increased its ownership in the Ikdam FPSO to 100 percent and will now seek new opportunities for the vessel.
With the relinquishment of its interest in the Block Marine XI licence (WI 18.75%) in June 2012 and the expiry of the Block Marine XIV licence (WI 21.55%) in October 2012, Lundin Petroleum has exited Congo (Brazzaville).
The net result for the fi nancial year 2012 amounted to MUSD 103.9 (MUSD 155.2). The net result attributable to shareholders of the Parent Company for the year amounted to MUSD 108.2 (MUSD 160.1) representing earnings per share of USD 0.35 (USD 0.51).
Earnings before interest, tax, depletion and amortisation (EBITDA) for the year amounted to MUSD 1,144.1 (MUSD 1,012.1) representing EBITDA per share of USD 3.68 (USD 3.25). Operating cash fl ow for the year amounted to MUSD 831.4 (MUSD 676.2) representing operating cash fl ow per share of USD 2.68 (USD 2.17).
Net sales of oil and gas for the year amounted to MUSD 1,319.5 (MUSD 1,257.7) and are detailed in Note 1. The average price achieved by Lundin Petroleum for a barrel of oil equivalent amounted to USD 100.89 (USD 101.04) and is detailed in the following table. The average Dated Brent price for the year amounted to USD 111.67 (USD 111.26) per barrel. The Alvheim and Volund fi eld crude cargoes sold during the year, which represented 61 percent (63 percent) of the total volumes sold, averaged USD 3.53 (USD 3.87) per barrel over Dated Brent for the pricing period for each lifting.
Sales of oil and gas for the year were comprised as follows:
| Sales | ||
|---|---|---|
| Average price per boe expressed in USD | 2012 | 2011 |
| Crude oil sales | ||
| Norway | ||
| – Quantity in Mboe | 8,270.1 | 7,896.0 |
| – Average price per boe | 115.29 | 115.38 |
| France | ||
| – Quantity in Mboe | 1,041.1 | 1,155.5 |
| – Average price per boe | 110.44 | 110.59 |
| Netherlands | ||
| – Quantity in Mboe | 1.7 | 2.2 |
| – Average price per boe | 100.09 | 103.87 |
| Russia | ||
| – Quantity in Mboe | 981.6 | 1,138.4 |
| – Average price per boe | 77.23 | 69.85 |
| Tunisia | ||
| – Quantity in Mboe | 227.5 | 198.2 |
| – Average price per boe | 108.14 | 125.12 |
| Total crude oil sales | ||
| – Quantity in Mboe | 10,522.0 | 10,390.3 |
| – Average price per boe | 110.90 | 110.25 |
| Gas and NGL sales | ||
| Norway | ||
| – Quantity in Mboe | 1,513.9 | 947.2 |
| – Average price per boe | 64.18 | 61.14 |
| Netherlands | ||
| – Quantity in Mboe | 704.2 | 722.8 |
| – Average price per boe | 60.18 | 60.61 |
| Indonesia | ||
| – Quantity in Mboe | 338.1 | 387.7 |
| – Average price per boe | 32.43 | 32.43 |
| Total gas and NGL sales | ||
| – Quantity in Mboe | 2,556.2 | 2,057.7 |
| – Average price per boe | 59.69 | 54.50 |
| Total sales | ||
| – Quantity in Mboe | 13,078.2 | 12,448.0 |
| – Average price per boe | 100.89 | 101.04 |
Sales quantities in a period can diff er from production quantities as a result of permanent and timing diff erences. Timing diff erences can arise due to inventory, storage and pipeline balances eff ects. Permanent diff erences arise as a result of paying royalties in kind as well as the eff ects from production sharing agreements.
The oil produced in Russia is sold on either the Russian domestic market or exported into the international market. 45 percent (37 percent) of Russian sales for the year were on the international market at an average price of USD 109.93 per barrel (USD 109.92 per barrel) with the remaining 55 percent (63 percent) of Russian sales being sold on the domestic market at an average price of USD 49.98 per barrel (USD 46.45 per barrel).
Other operating income amounted to MUSD 25.7 (MUSD 11.8) for the year and included MUSD 11.0 (MUSD -) relating to a pre-tax settlement of an equity redetermination that was agreed between the parties in Blocks K4a, K4b/K5a and K5b, off shore Netherlands, and MUSD 6.5 (MUSD 5.8) of income relating to a quality diff erential compensation received from the Vilje fi eld owners to the Alvheim and Volund fi eld owners in Norway. The quality compensation adjustment in Norway arises as all three fi elds 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 year amounted to MUSD 172.5 (MUSD 193.1) and are detailed in Note 2. The production costs in the year included a MUSD 15.9 credit for change in the lifting position and inventory movements compared to a MUSD 13.1 charge in the comparative period as explained below. The production and depletion costs per barrel of oil equivalent produced are detailed in the table below.
| Production cost and depletion in USD per boe |
2012 | 2011 |
|---|---|---|
| Cost of operations | 8.09 | 8.43 |
| Tariff and transportation expenses | 2.27 | 1.88 |
| Royalty and direct taxes | 3.93 | 4.31 |
| Changes in inventory/lifting position | -1.22 | 1.08 |
| Other | 0.14 | 0.18 |
| Total production costs | 13.21 | 15.88 |
| Depletion 1 | 14.26 | 13.59 |
| Total cost per boe | 27.47 | 29.47 |
1 excludes decommissioning costs
The total cost of operations for the year was MUSD 105.6 compared to MUSD 102.5 for the comparative period and includes cost of operations of MUSD 12.0 associated with the Gaupe fi eld, Norway which came onstream on 31 March 2012. The cost of operations for the Oudna fi eld, Tunisia was MUSD 8.6 for the year compared to MUSD 17.0 for the comparative period following the shut-in of production in March 2012. The cost of operations per barrel for the year was lower than the comparative period due to the higher production.
The tariff and transportation expenses for the year amounted to MUSD 29.7 compared to MUSD 22.9 for the comparative period. Included in the year are costs associated with the Gaupe fi eld of MUSD 7.4.
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 22.92 (USD 21.21) per barrel of Russian production for the year. The rate of export duty on Russian oil is revised monthly by the Russian Federation and is dependent on the average price obtained for Urals Blend for the preceding one month period. The export duty is levied on the volume of oil exported from Russia and averaged USD 57.08 (USD 57.52) per barrel for the year.
There are both permanent and timing diff erences 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 diff erences and a net amount of MUSD 15.9 was credited to the income statement for the year compared to a MUSD 13.1 charge for the comparative period. There was a net underlift movement of MUSD 18.5 on the Alvheim/Volund fi elds, Norway, where crude sales volumes during the year were lower than production volumes compared to a MUSD 18.7 net overlift movement for the comparative period. In addition, the Gaupe fi eld, Norway, was underlifted during the year resulting in a MUSD 12.9 (MUSD -) credit to production costs. The Gaupe fi eld hydrocarbons are processed across the non-operated Armada host platform and there is an allocation agreement whereby new fi elds compensate existing fi elds through volume for production deferred by the new production stream. The resultant underlift position is repaid by the existing fi elds in future periods. There were also liftings of inventory from the Ikdam FPSO on the Oudna fi eld, Tunisia, resulting in a MUSD 14.6 (MUSD -6.2) charge to production costs in the year.
Depletion charges amounted to MUSD 186.2 (MUSD 165.1) and are detailed in Note 3. Norway contributed 83 percent of the total depletion charge for the year at an average rate of USD 15.54 per barrel. The increase in depletion charges over the comparative period is mainly a result of the inclusion of the Gaupe fi eld, Norway.
Decommissioning costs charged to the income statement in the year amounted to MUSD 5.3 (MUSD -) and are detailed in Note 3. This represents the costs of decommissioning the Oudna fi eld, Tunisia, in excess of the provision for this work. The Oudna fi eld was fully decommissioned in 2012.
Exploration costs for the year amounted to MUSD 168.5 (MUSD 140.0) and are detailed in Note 4. Exploration and appraisal costs are capitalised as they are incurred. When exploration drilling is unsuccessful, the capitalised costs are expensed. All capitalised exploration costs are reviewed on a regular basis and are expensed where there is uncertainty regarding their recoverability.
During 2012, MUSD 103.1 (MUSD 74.1) of exploration costs relating to Norway were expensed. In the fourth quarter of 2012 the costs related to the Albert well on PL519 and the Juksa well and associated licence costs on PL490 were expensed for amounts of MUSD 36.6 and MUSD 50.1 respectively. Costs of MUSD 12.3 associated with the Clapton well on PL440S drilled in the second quarter of 2012 were also expensed.
In Malaysia, an amount of MUSD 46.7 (MUSD 11.0) of exploration costs was expensed in 2012. This primarily related to the costs of drilling the Merawan Batu prospect and associated licence costs on PM308B of MUSD 36.1 which were expensed in the fourth quarter of 2012. The costs of the Tiga Papan 5 well and associated licence costs in SB307/308 of MUSD 9.8 were also expensed in the second quarter of 2012.
In France, the expensed exploration costs for the unsuccessful exploration well drilled in the fourth quarter of 2012 on the Est Champagne concession amounted to MUSD 4.5.
Other exploration costs expensed during the year relate to the expensing of capitalised costs following technical reviews and include licence relinquishments.
Impairment costs for the year amounted to MUSD 237.5 (MUSD -) and are detailed in Note 5. Following poor performance since the start of production from the Gaupe fi eld, Norway, the reserves have been reduced based on the conservative assumption that no further production wells will be drilled resulting in an impairment charge of MUSD 205.8. In addition, poor reservoir performance from the onshore Russian assets has led to an impairment charge of MUSD 31.7.
The general, administrative and depreciation expenses for the year amounted to MUSD 31.7 (MUSD 67.0) of which MUSD 9.1 (MUSD 44.9) related to non-cash charges in relation to the Group's Long-term Incentive Plan (LTIP) scheme.
The provision for the LTIP is calculated based on Lundin Petroleum's share price at the balance sheet date using the Black and Scholes method and is applied to the portion of the outstanding LTIP awards which are recognised at the balance sheet date. Any change in the value of the awards due to a change in the share price impacts all awards recognised at the balance sheet date including those of previous periods with the change in the provision being refl ected in the income statement. The Lundin Petroleum share price decreased by 12 percent during 2012 compared to a 102 percent increase during 2011. Lundin Petroleum has mitigated the cash exposure of the LTIP by purchasing its own shares. For more detail refer to the remuneration section below.
Depreciation charges for the year amounted to MUSD 3.1 (MUSD 2.6).
Financial income for the year amounted to MUSD 27.2 (MUSD 46.5) and is detailed in Note 6.
Interest income for the year amounted to MUSD 5.1 (MUSD 4.1) and included MUSD 1.3 in relation to the Brynhild transaction with Talisman Energy.
Net foreign exchange gains for the year amounted to MUSD 6.2 (MUSD 8.9). During the year, there was an exchange loss of MUSD 5.5 (MUSD -8.9) on the non-USD denominated intercompany loans and working capital balances and this loss was off set by a realised exchange gain of MUSD 11.7 (MUSD -) on settled foreign exchange hedges.
A gain on consolidation of a subsidiary of MUSD 13.4 (MUSD -) was reported in the third quarter of 2012 and relates to the accounting for the full consolidation of Ikdam Production SA (IPSA) following the acquisition of the outstanding 60 percent of the shares of the company at the end of August 2012. Lundin Petroleum already held 40 percent of the shares in IPSA which was acquired as part of the Coparex acquisition in 2002. At the time of the Coparex acquisition, no value was assigned to the shares of IPSA and a provision was made against a loan to IPSA from the Group. Following the acquisition of the remaining 60 percent equity, a step-up in the carrying value of the existing 40 percent interest based on the fair value of the assets and liabilities of the company at the end of August 2012 was recorded and the provision made against the original loan was released.
An amount of MUSD 30.0 relating to the gain on sale of Africa Oil Corporation shares is included in fi nancial income for the comparative period.
Financial expenses for the year amounted to MUSD 48.5 (MUSD 21.0) and are detailed in Note 7.
Interest expenses for the year amounted to MUSD 6.8 (MUSD 5.4). An additional amount of interest of MUSD 3.4 (MUSD 1.4) associated with the funding of the Norwegian development projects was capitalised in the year.
A provision for the costs of site restoration is recorded in the balance sheet at the discounted value of the estimated future cost. The eff ect of the discount is unwound each year and charged to the income statement. An amount of MUSD 5.1 (MUSD 4.5) has been charged to the income statement for the year.
The amortisation of the deferred fi nancing fees for the year amounted to MUSD 6.6 (MUSD 2.2) and relates to the expensing of the fees incurred in establishing the loan facility over the period of usage of that facility. Lundin Petroleum arranged a new USD 2.5 billion fi nancing facility which was signed on 25 June 2012 and the fees associated with this facility are being amortised on a going forward basis.
Loan facility commitment fees for the year amounted to MUSD 10.3 (MUSD 1.0). The increase over the comparative period relates to the commitment fees on the undrawn portion of the larger USD 2.5 billion fi nancing facility entered into in June 2012.
Lundin Petroleum owns 50 million shares in ShaMaran Petroleum which were 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 subsequent movements in the fair value of the shares are recognised in other 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. As a result of the permanent diminution in the fair value of the shares, the cumulative loss recognised in other comprehensive income of MUSD 18.6 was reclassifi ed from equity and recognised in the income statement in the fi rst quarter of 2012. The subsequent gain on the shares since the impairment has been recognised in other comprehensive income.
The tax charge for the year amounted to MUSD 418.4 (MUSD 574.4) and is detailed in Note 8.
The current tax charge for the year amounted to MUSD 341.3 (MUSD 400.2) of which MUSD 311.8 (MUSD 365.6) relates to Norway. The Norwegian current tax charge for the year is lower than the comparative period primarily as a result of higher development and exploration expenditure spent in 2012.
The deferred tax charge for the year amounted to MUSD 77.1 (MUSD 174.2) and arises primarily where there is a diff erence in depletion for tax and accounting purposes. In Norway, there is a deferred tax charge for the year of MUSD 80.4 (MUSD 166.2) which is net of a deferred tax release on the impairment of the Gaupe fi eld amounting to MUSD 160.6 in the fourth quarter of 2012.
The Group operates in various countries and fi scal regimes where corporate income tax rates are diff erent from the regulations in Sweden. Corporate income tax rates for the Group vary between 20 percent and 78 percent. The eff ective tax rate for the Group for the year amounted to 80 percent. This eff ective rate is calculated from the face of the income statement and does not refl ect the eff ective rate of tax paid within each country of operation. The overall eff ective rate of tax is driven by Norway where the tax rate is 78 percent reduced by the eff ect of uplift on development expenditure for tax purposes. The eff ective rate is increased due to a number of non-tax adjusted items in the year including the impairment of the ShaMaran shares, the Malaysian expensed exploration costs and certain general and administrative costs, as well as a lower tax credit on the impairment of the Russian onshore assets and exploration costs relating to the Rangkas Block, Indonesia. There is no tax expense associated with the fi nancial income booked on full consolidation of Ikdam Production SA.
The net result attributable to non-controlling interest for the year amounted to MUSD -4.3 (MUSD -4.9) and relates mainly to the non-controlling interest's share in a Russian subsidiary which is fully consolidated.
Oil and gas properties amounted to MUSD 2,864.4 (MUSD 2,329.3) and are detailed in Note 9.
Development and exploration expenditure incurred for the year was as follows:
| Development expenditure in MUSD |
2012 | 2011 |
|---|---|---|
| Norway | 369.0 | 186.8 |
| France | 29.2 | 30.9 |
| Netherlands | 8.5 | 4.1 |
| Indonesia | -0.4 | 6.4 |
| Russia | 7.5 | 4.2 |
| 413.8 | 232.4 |
An amount of MUSD 369.0 of development expenditure was incurred in Norway during the year, primarily on the Brynhild and Edvard Grieg fi eld developments. In the previous year, MUSD 186.8 was spent on the development of the Gaupe and Alvheim fi elds. During the year, MUSD 29.2 was incurred in France, primarily on the Grandville fi eld redevelopment.
| Exploration expenditure | ||
|---|---|---|
| in MUSD | 2012 | 2011 |
| Norway | 323.2 | 288.6 |
| France | 9.8 | 1.7 |
| Indonesia | 16.4 | 16.4 |
| Russia | 3.6 | 10.0 |
| Malaysia | 100.5 | 98.7 |
| Congo (Brazzaville) | 1.3 | 19.0 |
| Other | 2.5 | 3.1 |
| 457.3 | 437.5 |
Exploration and appraisal expenditure of MUSD 323.2 was incurred in Norway during the year, mainly on the appraisal drilling of the Johan Sverdrup fi eld and exploration drilling of the Clapton prospect on PL440S, the Albert prospect on PL519, the Salina prospect on PL533 and the Juksa well on PL490. In the comparative period, MUSD 288.6 was spent in Norway on the Johan Sverdrup fi eld appraisal drilling and four exploration wells. MUSD 100.5 (MUSD 98.7) was spent in Malaysia primarily on drilling fi ve wells and the acquisition of seismic data.
Tangible fi xed assets amounted to MUSD 49.4 (MUSD 16.1) and represent offi ce fi xed assets and real estate, as well as the accounting value of the Ikdam FPSO which was consolidated for the fi rst time in August 2012.
Other shares and participations amounted to MUSD 20.0 (MUSD 17.8) and mainly relates to the shares held in ShaMaran Petroleum which are reported at market value.
Deferred tax assets amounted to MUSD 13.3 (MUSD 15.3) and is mainly relating to the part of the tax loss carry forwards in the Netherlands that are expected to be utilised.
Inventories amounted to MUSD 18.7 (MUSD 31.6) and include both hydrocarbon inventories and well supplies. The reduction compared to 31 December 2011 is mainly due to the lifting of the Oudna fi eld, Tunisia hydrocarbon inventory during the year.
Prepaid expenses and accrued income amounted to MUSD 32.9 (MUSD 4.5) and includes prepaid insurance on the Edvard Grieg development project, Norway and 2013 licence fees.
Derivative instruments amounted to MUSD 9.1 (MUSD -) and relates to the mark-to-market on the unsettled foreign currency hedges contracts that were entered into during 2012.
Other receivables amounted to MUSD 40.3 (MUSD 23.1) and are detailed in Note 18. Included in other receivables is the underlift position which amounted to MUSD 26.4 (MUSD 1.9) of which MUSD 24.5 related to the Norwegian producing fi elds, including the Gaupe fi eld.
Cash and cash equivalents amounted to MUSD 97.4 (MUSD 73.6). Cash balances are held to meet operational and investment requirements.
The provision for site restoration amounted to MUSD 190.5 (MUSD 119.3) and relates to future decommissioning obligations, as detailed in Note 21. The increase compared to 31 December 2011 mainly results from updated estimates for decommissioning costs and the use of a lower discount factor to calculate the present value of the decommissioning liabilities.
The provision for deferred taxes amounted to MUSD 942.2 (MUSD 803.5) as detailed in Note 8 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.
Other provisions amounted to MUSD 70.4 (MUSD 63.4) and are detailed in Note 23. Included in other provisions is the non-current portion of the provision for Lundin Petroleum's LTIP scheme which amounted to MUSD 67.1 (MUSD 58.1).
Financial liabilities amounted to MUSD 384.2 (MUSD 204.5) and are detailed in Note 24. Bank loans amounted to MUSD 432.0 (MUSD 207.0) and relates to the outstanding loan under the Group's USD 2.5 billion revolving borrowing base facility. Capitalised fi nancing fees amounted to MUSD 47.8 (MUSD 2.5) and relate to the new seven year USD 2.5 billion fi nancing facility entered into in June 2012. The capitalised fees are being amortised over the expected life of the fi nancing facility. The comparative amount relates to the balance of the capitalised fi nancing fees for the previous fi nancing facility which were fully expensed during the year.
Other non-current liabilities amounted to MUSD 22.6 (MUSD 21.8) and mainly arises from the full consolidation of a subsidiary in which the non-controlling interest entity has made funding advances in relation to LLC PetroResurs, Russia.
Tax liabilities amounted to MUSD 170.0 (MUSD 240.1) of which MUSD 163.6 (MUSD 223.0) relates to Norway.
Joint venture creditors amounted to MUSD 209.6 (MUSD 88.4) and relates to the high level of development and drilling activity in Norway and Malaysia.
Other liabilities amounted to MUSD 15.5 (MUSD 29.2) and are detailed in Note 26.
The Annual General Meeting will be held in Stockholm on 8 May 2013.
The intention of the Board of Directors is to propose to the 2013 AGM the adoption of a Policy on Remuneration for 2013 that follows in essence the same principles as applied in 2012 and that contains similar elements of remuneration for the Executive Management as the 2012 Policy on Remuneration being basic salary, yearly variable salary, Long-term Incentive Plan (LTIP) and other benefi ts. An LTIP for the Executive Management consisting of a phantom option plan was approved by the 2009 AGM, however, following the exceptional performance of the Company and its share price since the 2009 AGM, the Board of Directors has reviewed the terms of the 2009 LTIP. As a result, the Board of Directors has decided to propose to the 2013 AGM that the 2009 LTIP be replaced by a new 2013 LTIP, with an equal number and allocation of LTIP awards to the members of the Executive Management as under the 2009 LTIP. The proposed 2013 LTIP does not change the Company's fi nancial obligation to the Executive Management, however, it will provide the Executive Management with the opportunity to receive the LTIP award entitlement in: (a) cash; and/or (b) shares of the Company. These shares will be transferred from the previously issued shares held by the Company and therefore, no new shares of the Company will be issued under the proposed 2013 LTIP. The details of the proposal are available on www.lundin-petroleum.com.
In addition, as in previous years, the Board of Directors will further seek authorisation to deviate from the Policy on Remuneration in case of special circumstances in a specifi c case.
For a detailed description of the Policy on Remuneration applied in 2012, refer to the Corporate Governance report on pages 48–66. The remuneration to Board and Executive Management is detailed in Note 33 of the consolidated fi nancial statements.
For the AGM resolution on the authorisation to issue new shares, see page 68, The Lundin Petroleum Share and Shareholders.
The Directors propose that no dividend be paid for the year. For details of the dividend policy refer to the dividend policy, page 68, The Lundin Petroleum Share and Shareholders.
The Board of Directors propose that the unrestricted equity of the Parent Company of TSEK 7,005,298, including the net result for the year of TSEK 762,231 be brought forward.
At the AGM held on 10 May 2012, the current members of the Board of Directors of Lundin Petroleum were re-elected. Dambisa F. Moyo had declined to stand for re-election. At the 2013 AGM, the current members of the Board of Directors will be proposed for re-election, with the exception of Kristin Færøvik, who has declined to stand for re-election. Peggy Bruzelius and Cecilia Vieweg will further be proposed for election as new members of the Board of Directors.
The result of the Group's operations and fi nancial position at the end of the fi nancial year are shown in the following income statement, statement of comprehensive income, balance sheet, statement of cash fl ow, statement of changes in equity and related notes, which are presented in US Dollars.
The Parent Company's income statement, balance sheet, statement of cash fl ow, statement of changes in equity and related notes presented in Swedish Kroner can be found on pages 105–110.
Lundin Petroleum has issued a Corporate Governance report which is separate from the Financial Statements. The Corporate Governance report is included in this document, on the pages 48–66.
FOR THE FINANCIAL YEAR ENDED 31 DECEMBER
| Expressed in TUSD | Note | 2012 | 2011 |
|---|---|---|---|
| Operating income | |||
| Net sales of oil and gas | 1 | 1,319,490 | 1,257,691 |
| Other operating income | 1 | 25,652 | 11,824 |
| 1,345,142 | 1,269,515 | ||
| Cost of sales | |||
| Production costs | 2 | -172,474 | -193,104 |
| Depletion and decommissioning costs | 3 | -191,444 | -165,138 |
| Exploration costs | 4 | -168,480 | -140,027 |
| Impairment costs of oil and gas properties | 5 | -237,490 | – |
| Gross profi t | 575,254 | 771,246 | |
| General, administration and depreciation expenses | -31,722 | -67,022 | |
| Operating profi t | 1 | 543,532 | 704,224 |
| Result from fi nancial investments | |||
| Financial income | 6 | 27,241 | 46,455 |
| Financial expenses | 7 | -48,522 | -21,022 |
| -21,281 | 25,433 | ||
| Profi t before tax | 522,251 | 729,657 | |
| Income tax expense | 8 | -418,401 | -574,413 |
| Net result | 103,850 | 155,244 | |
| Net result attributable to the shareholders of the Parent Company: | 108,161 | 160,137 | |
| Net result attributable to non-controlling interest: | -4,311 | -4,893 | |
| Net result | 103,850 | 155,244 | |
| Earnings per share – USD 1 | 29 | 0.35 | 0.51 |
1 Based on net result attributable to shareholders of the Parent Company.
| Expressed in TUSD | Note | 2012 | 2011 |
|---|---|---|---|
| Net result | 103,850 | 155,244 | |
| Other comprehensive income | |||
| Exchange diff erences foreign operations | 61,661 | -37,525 | |
| Cash fl ow hedges | 9,222 | 6,971 | |
| Available for sale fi nancial assets | 16,053 | -50,210 | |
| Income tax relating to other comprehensive income | 8 | -2,306 | -1,743 |
| Other comprehensive income, net of tax | 84,630 | -82,507 | |
| Total comprehensive income | 188,480 | 72,737 | |
| Total comprehensive income attributable to: | |||
| Shareholders of the Parent Company | 190,233 | 80,466 | |
| Non-controlling interest | -1,753 | -7,729 | |
| 188,480 | 72,737 |
AT 31 DECEMBER
| Expressed in TUSD | Note | 2012 | 2011 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 9 | 2,864,395 | 2,329,270 |
| Other tangible assets | 10 | 49,418 | 16,084 |
| Other shares and participations | 12 | 19,983 | 17,775 |
| Deferred tax | 8 | 13,270 | 15,345 |
| Other fi nancial assets | 14 | 10,852 | 10,960 |
| Total non-current assets | 2,957,918 | 2,389,434 | |
| Current assets | |||
| Inventories | 15 | 18,700 | 31,589 |
| Trade receivables | 16 | 125,905 | 144,954 |
| Prepaid expenses and accrued income | 17 | 32,906 | 4,522 |
| Derivative instruments | 13 | 9,056 | – |
| Joint venture debtors | 13 | 11,539 | 20,252 |
| Other receivables | 18 | 40,277 | 23,090 |
| Cash and cash equivalents | 19 | 97,425 | 73,597 |
| Total current assets | 335,808 | 298,004 | |
| TOTAL ASSETS | 3,293,726 | 2,687,438 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Share capital | 463 | 463 | |
| Additional paid in capital | 474,855 | 483,565 | |
| Other reserves | 20 | -63,734 | -145,806 |
| Retained earnings | 662,660 | 502,523 | |
| Net result | 108,161 | 160,137 | |
| Shareholders' equity | 1,182,405 | 1,000,882 | |
| Non-controlling interest | 67,648 | 69,424 | |
| Total equity | 1,250,053 | 1,070,306 | |
| Non-current liabilities | |||
| Provision for site restoration | 21 | 190,470 | 119,341 |
| Pension provision | 22 | 1,510 | 1,460 |
| Provision for deferred tax | 8 | 942,235 | 803,493 |
| Other provisions | 23 | 70,410 | 63,699 |
| Financial liabilities | 24 | 384,188 | 204,494 |
| Other non-current liabilities | 22,556 | 21,830 | |
| Total non-current liabilities | 1,611,369 | 1,214,317 | |
| Current liabilities | |||
| Trade payables | 13 | 15,718 | 16,546 |
| Tax liabilities | 8 | 170,007 | 240,052 |
| Derivative instruments | 13 | – | 168 |
| Accrued expenses and deferred income | 25 | 12,687 | 16,227 |
| Joint venture creditors | 13 | 209,594 | 88,417 |
| Other liabilities | 26 | 15,473 | 29,190 |
| Provisions | 23 | 8,825 | 12,215 |
| Total current liabilities | 432,304 | 402,815 | |
| TOTAL EQUITY AND LIABILITIES | 3,293,726 | 2,687,438 | |
| Pledged assets | 27 | 1,831,294 | 1,790,617 |
| Contingent liabilities and assets | 28 | – | – |
FOR THE FINANCIAL YEAR ENDED 31 DECEMBER
| Expressed in TUSD | Note | 2012 | 2011 |
|---|---|---|---|
| Cash fl ow from operations | |||
| Net result | 103,850 | 155,244 | |
| Gain on sale of assets | -1,117 | – | |
| Adjustments for non-cash related items | 30 | 1,056,898 | 915,174 |
| Interest received | 3,489 | 1,457 | |
| Interest paid | -8,871 | -1,597 | |
| Income taxes paid | -428,842 | -183,870 | |
| Changes in working capital: | |||
| Change in inventories | 12,889 | -11,550 | |
| Change in underlift position | -24,588 | 11,601 | |
| Change in receivables | 7,973 | 36,605 | |
| Change in overlift position | -7,180 | 5,909 | |
| Change in liabilities | 104,453 | -32,037 | |
| Total cash fl ow from operations | 818,954 | 896,936 | |
| Cash fl ow from investments | |||
| Investment in oil and gas properties | -919,356 | -670,032 | |
| Investment in offi ce equipment and other assets | -9,702 | -3,786 | |
| Investment in subsidiaries | -11,000 | – | |
| Decommissioning costs paid | -18,550 | – | |
| Proceeds from sale of other shares and participations | – | 53,938 | |
| Change in other fi nancial fi xed assets | – | 1,908 | |
| Other payments | -3,188 | -1,168 | |
| Total cash fl ow from investments | -961,796 | -619,140 | |
| Cash fl ow from fi nancing | |||
| Proceeds from borrowings | 592,000 | 175,000 | |
| Repayments of borrowings | -366,274 | -427,238 | |
| Paid fi nancing fees | -49,225 | – | |
| Purchase of own shares | -8,710 | – | |
| Dividend paid to non-controlling interest | -23 | -212 | |
| Total cash fl ow from fi nancing | 167,768 | -252,450 | |
| Change in cash and cash equivalents | 24,926 | 25,346 | |
| Cash and cash equivalents at the beginning of the year | 73,597 | 48,703 | |
| Cash acquired on consolidation of a subsidiary | 815 | – | |
| Currency exchange diff erence in cash and cash equivalents | -1,913 | -452 | |
| Cash and cash equivalents at the end of the year | 97,425 | 73,597 |
The eff ects of acquisitions of subsidiary companies have been excluded from the changes in the balance sheet items. The eff ects of currency exchange diff erences due to the translation of foreign group companies have also been excluded as these eff ects do not aff ect the cash fl ow. Cash and cash equivalents comprise cash and short-term deposits maturing within less than three months.
| Total Equity comprises: Expressed in TUSD |
Share capital 1 |
Additional paid-in capital |
Other reserves 2 |
Retained earnings |
Net result | Non controlling interest |
Total equity |
|---|---|---|---|---|---|---|---|
| Balance at 1 January 2011 | 463 | 483,565 | -66,135 | -9,352 | 511,875 | 77,365 | 997,781 |
| Transfer of prior year net result | – | – | – | 511,875 | -511,875 | – | – |
| Net result | – | – | – | – | 160,137 | -4,893 | 155,244 |
| Currency translation diff erence | – | – | -34,689 | – | – | -2,836 | -37,525 |
| Cash fl ow hedges | – | – | 6,971 | – | – | – | 6,971 |
| Available for sale fi nancial assets | – | – | -50,210 | – | – | – | -50,210 |
| Income tax relating to other comprehensive income | – | – | -1,743 | – | – | – | -1,743 |
| Total comprehensive income | – | – | -79,671 | – | 160,137 | -7,729 | 72,737 |
| Transactions with owners | |||||||
| Distributions | – | – | – | – | – | -212 | -212 |
| Total transactions with owners | – | – | – | – | – | -212 | -212 |
| Balance at 31 December 2011 | 463 | 483,565 | -145,806 | 502,523 | 160,137 | 69,424 | 1,070,306 |
| Transfer of prior year net result | – | – | – | 160,137 | -160,137 | – | – |
| Net result | – | – | – | – | 108,161 | -4,311 | 103,850 |
| Currency translation diff erence | – | – | 59,103 | – | – | 2,558 | 61,661 |
| Cash fl ow hedges | – | – | 9,222 | – | – | – | 9,222 |
| Available for sale fi nancial assets | – | – | 16,053 | – | – | – | 16,053 |
| Income tax relating to other comprehensive income | – | – | -2,306 | – | – | – | -2,306 |
| Total comprehensive income | – | – | 82,072 | – | 108,161 | -1,753 | 188,480 |
| Transactions with owners | |||||||
| Distributions | – | – | – | – | – | -23 | -23 |
| Purchase of own shares | – | -8,710 | – | – | – | – | -8,710 |
| Total transactions with owners | – | -8,710 | – | – | – | -23 | -8,733 |
| Balance at 31 December 2012 | 463 | 474,855 | -63,734 | 662,660 | 108,161 | 67,648 | 1,250,053 |
Lundin Petroleum AB's issued share capital at 31 December 2012 amounted to SEK 3,179,106 represented by 317,910,580 shares with a quota value of SEK 0.01 each, the USD equivalent of the issued share capital is TUSD 463. Included in the number of shares issued at 31 December 2012 are 7,368,285 shares which Lundin Petroleum holds in its own name.
Other reserves are described in detail in Note 20.
The main business of Lundin Petroleum is the exploration for, the development of, and the production of oil and gas. Lundin Petroleum maintains a portfolio of oil and gas production assets and development projects in various countries with exposure to exploration opportunities.
The Group does not carry out any signifi cant research and development. The Group maintains branches in most of its areas of operation. The Parent Company has no foreign branches.
The address of Lundin Petroleum AB's registered offi ce is Hovslagargatan 5, Stockholm, Sweden.
Lundin Petroleum's annual report has been prepared in accordance with prevailing International Financial Reporting Standards (IFRS) and International Financial Reporting Interpretation Committee (IFRIC) interpretations adopted by the EU Commission and the Swedish Annual Accounts Act (SFS 1995:1554). In addition RFR 1 "Supplementary Rules for Groups" has been applied as issued by the Swedish Financial Reporting Board. The Parent Company applies the same accounting policies as the Group, except as specifi ed in the Parent Company accounting policies on page 105.
The preparation of fi nancial statements in conformity with IFRS requires the use of certain critical accounting estimates and also requires management to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are signifi cant to the consolidated fi nancial statements are disclosed under the headline "Critical accounting estimates and judgements".
The consolidated fi nancial statements have been prepared under the historical cost convention, as modifi ed by the revaluation of available for sale fi nancial assets and fi nancial assets and liabilities (including derivative instruments) at fair value through profi t or loss.
There have not been any new and revised standards or interpretations issued, that have had a material impact to the Group's fi nancial statements for the fi nancial year 2012.
The following newly issued standards are not mandatory for the 2012 fi nancial statements and have not been adopted early. These standards might lead to signifi cant changes in the accounting and standard practice for the industry. Careful consideration will be required to assess the practical implication for the Group.
IFRS 9, 'Financial instruments' The standard addresses the classifi cation, measurement and recognition of fi nancial assets and fi nancial liabilities. IFRS 9 is eff ective from 1 January 2015 and not from 1 January 2013 as originally intended. The Group is yet to assess IFRS 9's full impact and intends to adopt IFRS 9 no later than the accounting period beginning on or after 1 January 2015.
IFRS 10, 'Consolidated fi nancial statements' The objective of the standard is to build on existing principles by identifying the concept of control as the determining factor in whether an entity should be included within the consolidated fi nancial statements of the parent company. The Group is yet to assess IFRS 10's full impact and intends to adopt IFRS 10 from 1 January 2014.
IFRS 11, 'Joint arrangements' The standard is focusing on the rights and obligations of the joint arrangement rather than its legal form. There are two types of joint arrangement: joint operations and joint ventures. Joint operations arise where a joint operator has rights to the assets and obligations relating to the arrangement and hence accounts for its interest in assets, liabilities, revenue and expenses. Joint ventures arise where the joint operator has rights to the net assets of the arrangement and hence equity accounts for its interest. The Group is yet to assess IFRS 11's full impact and intends to adopt IFRS 11 from 1 January 2014.
IFRS 12, 'Disclosures of interests in other entities' The standard introduces a range of new and expanded disclosure requirements. These will require the disclosure of signifi cant judgements and assumptions made by management in determining whether there is joint control and if there is a joint venture, a joint operation or another form of interest. The Group is yet to assess IFRS 12's full impact and intends to adopt IFRS 12 from 1 January 2014.
IFRS 13, 'Fair value measurement' The standard aims to improve consistency and reduce complexity by providing a precise defi nition of fair value and a single source of fair value measurement and disclosure requirements for use across IFRSs. IFRS 13 is eff ective from 1 January 2013 and is not expected to have any signifi cant eff ect on the consolidated fi nancial statements of the Group.
Subsidiaries are all entities over which the Group has the sole right to exercise control over the operations and govern the fi nancial policies generally accompanying a shareholding of more than half of the voting rights. The existence and eff ect of potential voting rights that are currently exercisable or convertible are considered when assessing the Group's control. Subsidiaries are fully consolidated from the date on which control is transferred to the Group and are de-consolidated from the date that control ceases.
The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair values of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifi able assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.
The non-controlling interest in a subsidiary represents the portion of the subsidiary not owned by the Group. The equity of the subsidiary relating to the non-controlling shareholders is shown as a separate item within equity for the Group. The Group recognises any non-controlling interest on an acquisition-by-acquisition basis, either at fair value or at the non-controlling interest's proportionate share of the recognised amounts of acquiree's identifi able net assets.
If the business combination is achieved in stages, the acquisition date carrying value of the acquirer's previously held equity interest in the acquiree is re-measured to fair value at the acquisition date; any gains or losses arising from such re-measurement are recognised in profi t or loss.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred and the fair value of non-controlling interest over the net identifi able assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net assets of the subsidiary acquired, the diff erence is recognised in profi t or loss.
Inter-company transactions, balances, income and expenses on transactions between Group companies are eliminated. Profi ts and losses resulting from intercompany transactions that are recognised in assets are also eliminated. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Group.
As stated above, a subsidiary that is controlled by the Group will be fully consolidated within the results of Lundin Petroleum. Joint control exists when the Group does not have the control to determine the strategic operating, investing and fi nancing policies of a partially owned entity without the co-operation of others. When this is the case the entity is proportionally consolidated.
Oil and gas operations are conducted by the Group as co-licencees in unincorporated joint ventures with other companies. The Group's fi nancial statements refl ect the relevant proportions of production, capital costs, operating costs and current assets and liabilities of the joint venture applicable to the Group's interests.
An investment in an associated company is an investment in an undertaking where the Group exercises signifi cant infl uence but not control, generally accompanying a shareholding of at least 20 percent but not more than 50 percent of the voting rights. Such investments are accounted for in the consolidated fi nancial statements in accordance with the equity method and are initially recognised at cost.
Investments where the shareholding is less than 20 percent of the voting rights are treated as available for sale fi nancial assets. If the value of these assets has declined signifi cantly or has lasted for a longer period, the cumulative loss is removed from equity and an impairment charge is recognised in the income statement. Dividends received attributable to these assets is recognised in the income statement as part of net fi nancial items.
Items included in the fi nancial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates (functional currency). The consolidated fi nancial statements are presented in US Dollars, which is the currency the Group has elected to use as the presentation currency.
Monetary assets and liabilities denominated in foreign currencies are translated at the rates of exchange prevailing at the balance sheet date and foreign exchange currency diff erences are recognised in the income statement. Transactions in foreign currencies are translated at exchange rates prevailing at the transaction date. Exchange diff erences are included in fi nancial income/expenses in the income statement except deferred exchange diff erences on qualifying cash fl ow hedges which are recorded in other comprehensive income.
The balance sheets and income statements of foreign Group companies are translated for consolidation purposes using the current rate method. All assets and liabilities are translated at the balance sheet date rates of exchange, whereas the income statements are translated at average rates of exchange for the year, except for transactions where it is more relevant to use the rate of the day of the transaction. The translation diff erences which arise are recorded directly in the foreign currency translation reserve within other comprehensive income. Upon disposal of a foreign operation the translation diff erences relating to that operation will be transferred from equity to the income statement and included in the result on sale. Translation diff erences arising from net investments in subsidiaries, used for fi nancing exploration activities, are recorded directly in other comprehensive income.
For the preparation of the annual fi nancial statements, the following currency exchange rates have been used.
| 2012 Average |
2012 Period end |
2011 Average |
2011 Period end |
|
|---|---|---|---|---|
| 1 USD equals NOK | 5.8148 | 5.5639 | 5.5998 | 5.9927 |
| 1 USD equals EUR | 0.7778 | 0.7579 | 0.7185 | 0.7729 |
| 1 USD equals RUR | 31.0546 | 30.5665 | 29.3738 | 32.2784 |
| 1 USD equals SEK | 6.7725 | 6.5045 | 6.4867 | 6.8877 |
Non-current assets, long-term liabilities and provisions consist of amounts that are expected to be recovered or paid more than twelve months after the balance sheet date. Current assets and current liabilities consist solely of amounts that are expected to be recovered or paid within twelve months after the balance sheet date.
Oil and gas properties are recorded at historical cost less depletion. All costs for acquiring concessions, licences or interests in production sharing contracts and for the survey, drilling and development of such interests are capitalised on a fi eld area cost centre basis.
Costs directly associated with an exploration well are capitalised until the determination of reserves is evaluated. If it is determined that a commercial discovery has not been achieved, these exploration costs are charged to the income statement. During the exploration and development phases, no depletion is charged. The fi eld will be transferred from the non-production cost pool to the production cost pool within oil and gas properties once production commences, and accounted for as a producing asset. Routine maintenance and repair costs for producing assets are expensed to the income statement when they occur.
Net capitalised costs to reporting date, together with anticipated future capital costs for the development of the proved and probable reserves determined at the balance sheet date price levels, are depleted based on the year's production in relation to estimated total proved and probable reserves of oil and gas in accordance with the unit of production method. Depletion of a fi eld area is charged to the income statement once production commences.
Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and governmental regulations. Proved reserves can be categorised as developed or undeveloped. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confi dence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimates.
Probable reserves are those unproved reserves which analysis of geological and engineering data suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of estimated proved plus probable reserves.
Proceeds from the sale or farm-out of oil and gas concessions in the exploration stage are off set against the related capitalised costs of each cost centre with any excess of net proceeds over all costs capitalised included in the income statement. In the event of a sale in the exploration stage, any defi cit is included in the income statement.
Impairment tests are performed annually or when there are facts and circumstances that suggest that the net book value of capitalised costs within each fi eld area cost centre less any provision for site restoration costs, royalties and deferred production or revenue related taxes is higher than the anticipated future net cash fl ow from oil and gas reserves attributable to the Group's interest in the related fi eld areas. Capitalised costs cannot be carried unless those costs can be supported by future cash fl ows from that asset. Provision is made for any impairment, where the net carrying value, according to the above, exceeds the recoverable amount, which is the higher of value in use and fair value less costs to sell, determined through estimated future discounted net cash fl ows using prices and cost levels used by Group management in their internal forecasting. If there is no decision to continue with a fi eld specifi c exploration programme, the costs will be expensed at the time the decision is made.
Other tangible fi xed assets are stated at cost less accumulated depreciation. Depreciation is based on cost and is calculated on a straight line basis over the estimated economic life of 20 years for real estate and 3 to 5 years for offi ce equipment and other assets. The FPSO vessel will be depreciated over its remaining useful life once the upgrade of the vessel has been completed.
Additional costs to existing assets are included in the assets' net book value or recognised as a separate asset, as appropriate, only when it is probable that future economic benefi ts associated with the item will fl ow to the Group and the cost of the item can be measured reliably. The net book value of any replaced parts is written off . Other additional expenses are deemed to be repair and maintenance costs and are charged to the income statement when they are incurred.
The net book value is written down immediately to its recoverable amount when the net book value is higher. The recoverable amount is the higher of an asset's fair value less cost to sell and value in use.
The excess of the cost of acquisition over the fair value of the Group's share of the identifi able net assets acquired is recorded as goodwill. If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the diff erence is recognised directly in the income statement.
In order to classify an asset as a non-current asset held for sale the carrying value needs to be assumed to be recovered through a sale transaction rather than through continuing use. It must also be available for immediate sale in its present condition and a sale must be highly probable. If the asset is classifi ed as a non-current asset held for sale it will be recorded at the lower of its carrying value and fair value less estimated cost of sale.
At each balance sheet date the Group assesses whether there is an indication that an asset may be impaired. Where an indicator of impairment exists or when impairment testing for an asset is required, the Group makes a formal assessment of the recoverable amount. Where the carrying value of an asset exceeds its recoverable amount the asset is considered impaired and is written down to its recoverable amount.
The recoverable amount is the higher of fair value less costs to sell and value in use. Value in use is calculated by discounting estimated future cash fl ows to their present value using a discount rate that refl ects current market assessments of the time value of money and the risks specifi c to the asset. When the recoverable amount is less than the carrying value an impairment loss is recognised with the expensed charge to the income statement. If indications exist that previously recognised impairment losses no longer exist or are decreased, the recoverable amount is estimated. When a previously recognised impairment loss is reversed the carrying amount of the asset is increased to the estimated recoverable amount but the increased carrying amount may not exceed the carrying amount after depreciation that would have been determined had no impairment loss been recognised for the asset in prior years.
Assets and liabilities are recognised initially at fair value plus transaction costs and subsequently measured at amortised cost unless stated otherwise. Financial assets are derecognised when the rights to receive cash fl ows from the investments have expired or have been transferred and the Group has transferred substantially all risks and rewards of ownership.
Lundin Petroleum recognises the following fi nancial instruments:
The Group has only cash fl ow hedges which qualify for hedge accounting. The eff ective portion of changes in the fair value of derivatives that qualify as cash fl ow hedges are recognised in other comprehensive income. The gain or loss relating to the ineff ective portion is recognised immediately in the income statement. Amounts accumulated in other comprehensive income are transferred to the income statement in the period when the hedged item will aff ect the income statement. When a hedging instrument no longer meets the requirements for hedge accounting, expires or is sold, any accumulated gain or loss recognised in other comprehensive income remains in shareholders' equity until the forecast transaction no longer is expected to occur, at which point it is being transferred to the income statement.
Inventories of consumable well supplies are stated at the lower of cost and net realisable value, cost being determined on a weighted average cost basis. Net realisable value is the estimated selling price in the
ordinary course of business, less applicable variable selling expenses. Inventories of hydrocarbons are stated at the lower of cost and net realisable value. Under or overlifted positions of hydrocarbons are valued at market prices prevailing at the balance sheet date. An underlift of production from a fi eld is included in the current receivables and valued at the reporting date spot price or prevailing contract price and an overlift of production from a fi eld is included in the current liabilities and valued at the reporting date spot price or prevailing contract price. A change in the over or underlift position is refl ected in the income statement as production costs.
Cash and cash equivalents include cash at bank, cash in hand and interest bearing securities with original maturities of three months or less.
Share capital consists of the registered share capital for the Parent Company. Share issue costs associated with the issuance of new equity are treated as a direct reduction of proceeds. Excess contribution in relation to the issuance of shares is accounted for in the item additional paid-in-capital.
Where any Group company purchases the Company's equity share capital (treasury shares), the consideration paid, including any directly attributable incremental costs (net of income taxes) is deducted from equity attributable to the Company's equity holders until these shares are cancelled or sold. Where these shares are subsequently sold, any consideration received, net of any directly attributable incremental transaction costs and related income tax eff ects, is included in equity attributable to the Company's equity holders.
The change in fair value of other shares and participations is accounted for in the fair value reserve. Upon the realisation of a change in value, the change in fair value recorded will be transferred to the income statement. The change in fair value of hedging instruments which qualify for hedge accounting is accounted for in the hedge reserve. Upon settlement of the hedge instrument, the change in fair value remains in other comprehensive income until the hedged item eff ects the income statement. The currency translation reserve contains unrealised translation diff erences due to the conversion of the functional currencies into the presentation currency.
Retained earnings contain the accumulated results attributable to the shareholders of the Parent Company.
A provision is reported when the Company has a legal or constructive obligation as a consequence of an event and when it is more likely than not that an outfl ow of resources is required to settle the obligation and a reliable estimate can be made of the amount.
Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a discount rate that refl ects current market assessments of the time value of money and the risks specifi c to the obligation. The increase in the provision due to passage of time is recognised as fi nancial expense.
On fi elds where the Group is required to contribute to site restoration costs, a provision is recorded to recognise the future commitment. An asset is created, as part of the oil and gas property, to represent the discounted value of the anticipated site restoration liability and depleted over the life of the fi eld on a unit of production basis. The corresponding accounting entry to the creation of the asset recognises the discounted value of the future liability. The discount applied to the anticipated site restoration liability is subsequently released over the life of the fi eld and is charged to fi nancial expenses. Changes in site restoration costs and reserves are treated prospectively and consistent with the treatment applied upon initial recognition.
Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortised costs using the eff ective interest method, with interest expense recognised on an eff ective yield basis.
The eff ective interest method is a method of calculating the amortised cost of a fi nancial liability and of allocating interest expense over the relevant period. The eff ective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the fi nancial liability, or a shorter period where appropriate.
Revenues from the sale of oil and gas are recognised in the income statement net of royalties taken in kind. Sales of oil and gas are recognised upon delivery of products and customer acceptance or on performance of services. Incidental revenues from the production of oil and gas are off set against capitalised costs of the related cost centre until quantities of proven and probable reserves are determined and commercial production has commenced.
Service income, generated by providing technical and management services to joint ventures, is recognised as other income.
Production and sales taxes directly attributable to fi elds, including royalties and export duties, are expensed in the income statement and classifi ed as direct production taxes included within production costs. The fi scal regime in the area of operations defi nes whether royalties are payable in cash or in kind. Royalties payable in cash are accrued in the accounting period in which the liability arises. Royalties taken in kind are subtracted from production for the period to which they relate.
Borrowing costs attributable to the acquisition, construction or production of qualifying assets are added to the cost of those assets. Qualifying assets are assets that take a substantial period of time to complete for their intended use or sale. Investment income earned on the temporary investment of specifi c borrowings pending to be used for the qualifying asset is deducted from the borrowing costs eligible for capitalisation. This applies on the interest on borrowings to fi nance fi elds under development which is capitalised within oil and gas properties until production commences. All other borrowing costs are recognised in profi t or loss in the period in which they occur. Interest on borrowings to fi nance the acquisition of producing oil and gas properties is charged to income as incurred.
Short-term employee benefi ts such as salaries, social premiums and holiday pay, are expensed when incurred.
Pensions are the most common long-term employee benefi ts. The pension schemes are funded through payments to insurance companies. The Group's pension obligations consist mainly of defi ned contribution plans. A defi ned contribution plan is a pension plan under which the Group pays fi xed contributions. The Group has no further payment obligations once the contributions have been paid. The contributions are recognised as an expense when they are due.
The Group has one obligation under a defi ned benefi t plan. The relating liability recognised in the balance sheet is valued at the discounted estimated future cash outfl ows as calculated by an external actuarial expert. Actuarial gains and losses are charged to the income statement. The Group does not have any designated plan assets.
Lundin Petroleum recognises cash-settled share-based payments in the income statement as expenses during the vesting period and as a liability in relation to the long-term incentive plan. The liability is measured at fair value and revalued using the Black & Scholes pricing model at each balance sheet date and at the date of settlement, with any change in fair value recognised in the income statement for the period.
The components of tax are current and deferred. Tax is recognised in the income statement, except to the extent that it relates to items recognised in other comprehensive income or directly in equity, in which case it is matched.
Current tax is tax that is to be paid or received for the year in question and also includes adjustments of current tax attributable to previous periods.
Deferred income tax is a non-cash charge provided, using the liability method, on temporary diff erences arising between the tax bases of assets and liabilities and their carrying values. Temporary diff erences can occur for example where investment expenditure is capitalised for accounting purposes but the tax deduction is accelerated or where site restoration costs are provided for in the fi nancial statements but not deductible for tax purposes until they are actually incurred. However, the deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction aff ects neither accounting nor taxable profi t nor loss. Deferred income tax is provided on temporary diff erences arising on investments in subsidiaries and associates, except where the timing of the reversal of the temporary diff erence is controlled by the Group and it is probable that the temporary diff erence will not reverse in the foreseeable future. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantively enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled. Deferred income tax assets are recognised to the extent that it is probable that future taxable profi t will be available against which the temporary diff erences can be utilised.
Deferred tax assets are off set against deferred tax liabilities in the balance sheet where they relate to the same jurisdiction.
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker being Executive Management, which, due to the unique nature of each country's operations, commercial terms or fi scal environment, is at a country level. Information for segments is only disclosed when applicable. Segmental information is presented in Notes; Note 1 segment information, Note 3 depletion costs, Note 4 exploration costs, Note 5 impairment of oil and gas properties, Note 8 taxes and Note 9 oil and gas properties.
The management of Lundin Petroleum has to make estimates and judgements when preparing the fi nancial statements of the Group. Uncertainties in the estimates and judgements could have an impact on the carrying amount of assets and liabilities and the Group's result. The most important estimates and judgements in relation thereto are:
Estimates of oil and gas reserves are used in the calculations for impairment tests and accounting for depletion and site restoration. Standard recognised evaluation techniques are used to estimate the proved and probable reserves. These techniques take into account the future level of development required to produce the reserves. An independent qualifi ed reserves auditor reviews these estimates. See page 115 Reserve quantity Information. Changes in estimates in oil and gas reserves, resulting in diff erent future production profi les, will aff ect the discounted cash fl ows used in impairment testing, the anticipated date of site decommissioning and restoration and the depletion charges in accordance with the unit of production method. Changes in estimates in oil and gas reserves could for example result from additional drilling, observation of long-term reservoir performance or changes in economic factors such as oil price and infl ation rates.
Information about the carrying amounts of the oil and gas properties and the amounts charged to income, including depletion, exploration costs, and impairment costs is presented in Note 9.
Key assumptions in the impairment models relate to prices and costs that are based on forward curves and the long-term corporate assumptions. Lundin Petroleum carried out its annual impairment tests in conjunction with the annual reserves audit process. The calculation of the impairment requires the use of estimates. For the purpose of determining an eventual impairment the assumptions that management uses to estimate the future cash fl ows for value-in-use are future oil and gas prices and expected production volumes. These assumptions and judgements of management that are based on them are subject to change as new information becomes available. Changes in economic conditions can also aff ect the rate used to discount future cash fl ow estimates and the discount rate applied is reviewed throughout the year.
Information about the carrying amounts of the oil and gas properties and impairment of oil and gas properties is presented in Notes 5 and 9.
Amounts used in recording a provision for site restoration are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and decommissioning. Due to changes in relation to these items, the future actual cash outfl ows in relation to the site decommissioning and restoration can be diff erent. To refl ect the eff ects due to changes in legislation, requirements and technology and price levels, the carrying amounts of site restoration provisions are reviewed on a regular basis.
The eff ects of changes in estimates do not give rise to prior year adjustments and are treated prospectively over the estimated remaining commercial reserves of each fi eld. While the Group uses its best estimates and judgement, actual results could diff er from these estimates.
Information about the carrying amounts of the Provision for site restoration is presented in Note 21.
All events up to the date when the fi nancial statements were authorised for issue and which have a material eff ect in the fi nancial statements have been disclosed.
OF THE GROUP
The Group operates within several geographical areas. Operating segments are reported at country level that is consistent with the internal reporting provided to Executive Management.
The following tables present segment information regarding; operating income, operating profi t contribution and certain asset and liability information regarding the Group's business segments. In addition segment information is reported in the following notes; Note 3 depletion costs, Note 4 exploration costs, Note 5 impairment of oil and gas properties, Note 8 income taxes and Note 9 oil and gas properties.
| TUSD | 2012 | 2011 |
|---|---|---|
| Operating income | ||
| Net sales of: | ||
| Oil | ||
| Norway | 953,432 | 911,072 |
| France | 114,974 | 127,789 |
| Netherlands | 170 | 228 |
| Russia | 75,806 | 79,515 |
| Tunisia | 24,597 | 24,798 |
| 1,168,979 | 1,143,402 | |
| Condensate | ||
| Norway | 2,312 | 1,314 |
| Netherlands | 999 | – |
| 3,311 | 1,314 | |
| Gas | ||
| Norway | 94,851 | 57,909 |
| Netherlands | 41,385 | 42,496 |
| Indonesia | 10,964 | 12,570 |
| 147,200 | 112,975 | |
| Total net sales | 1,319,490 | 1,257,691 |
| Other income: | ||
| Norway | 6,487 | 5,848 |
| France | 2,641 | 1,566 |
| Netherlands | 12,213 | 1,397 |
| Other | 4,311 | 3,013 |
| Total other income | 25,652 | 11,824 |
| Total operating income | 1,345,142 | 1,269,515 |
Revenues are derived from various external customers. There were no intercompany sales or purchases in the year or in the previous year, and therefore there are no reconciling items towards the amounts stated in the income statement.
| TUSD | 2012 | 2011 |
|---|---|---|
| Operating profi t contribution | ||
| Norway | 558,646 | 703,711 |
| France | 70,429 | 85,334 |
| Netherlands | 29,908 | 18,868 |
| Indonesia | -7,511 | 168 |
| Russia | -26,304 | 7,715 |
| Tunisia | -4,297 | 13,476 |
| Malaysia | -47,554 | -11,010 |
| Congo (Brazzaville) | -1,309 | -51,273 |
| Other | -28,476 | -62,765 |
| Total operating profi t contribution | 543,532 | 704,224 |
| Assets | Equity and Liabilities | |||
|---|---|---|---|---|
| TUSD | 2012 | 2011 | 2012 | 2011 |
| Norway | 1,942,797 | 1,445,439 | 1,221,134 | 1,035,145 |
| France | 279,587 | 207,894 | 87,194 | 70,581 |
| Netherlands | 112,801 | 96,643 | 555,397 | 300,139 |
| Indonesia | 108,243 | 106,123 | 16,299 | 16,400 |
| Russia | 619,029 | 652,168 | 112,463 | 114,179 |
| Tunisia | 12,663 | 21,703 | 9,421 | 21,416 |
| Malaysia | 197,757 | 138,697 | 33,148 | 39,987 |
| Congo (Brazzaville) | 30 | 7,677 | 768 | 9,012 |
| Other | 20,819 | 11,094 | 7,849 | 10,273 |
| Assets/Liabilities | ||||
| per country | 3,293,726 | 2,687,438 | 2,043,673 | 1,617,132 |
| Shareholders' equity | N/A | N/A | 1,182,405 | 1,000,882 |
| Non-controlling interest | N/A | N/A | 67,648 | 69,424 |
| Total equity for | ||||
| the Group | N/A | N/A | 1,250,053 | 1,070,306 |
| Total consolidated | 3,293,726 | 2,687,438 | 3,293,726 | 2,687,438 |
See also Note 9 for detailed information of the oil and gas properties including depletion per country. There are no reconciling items towards the balance sheet totals.
| TUSD | 2012 | 2011 |
|---|---|---|
| Cost of operations | 105,612 | 102,476 |
| Tariff and transportation expenses | 29,684 | 22,863 |
| Direct production taxes | 51,328 | 52,390 |
| Change in lifting position | -30,700 | 18,419 |
| Inventory movement | 14,782 | -5,290 |
| Other | 1,768 | 2,246 |
| Total production costs | 172,474 | 193,104 |
For further information on production costs, see the Directors' Report on page 78.
| TUSD | 2012 | 2011 |
|---|---|---|
| Norway | 154,140 | 130,011 |
| France | 11,668 | 12,174 |
| Netherlands | 10,437 | 11,939 |
| Indonesia | 5,612 | 6,250 |
| Russia | 4,320 | 4,764 |
| Total depletion costs | 186,177 | 165,138 |
| Tunisia | 5,267 | – |
| Total decommissioning costs | 5,267 | – |
| Total depletion and decommissioning costs | 191,444 | 165,138 |
| 2012 | 2011 | |
|---|---|---|
| Average depletion cost, USD per boe | ||
| Norway | 15.54 | 15.34 |
| France | 11.21 | 10.88 |
| Netherlands | 15.03 | 16.47 |
| Indonesia | 15.20 | 14.76 |
| Russia | 4.39 | 4.18 |
| Total | 14.27 | 13.59 |
For further information on depletion and decommissioning costs, see the Directors' Report on page 78.
| TUSD | 2012 | 2011 |
|---|---|---|
| Norway | 103,052 | 74,060 |
| France | 5,012 | 1,486 |
| Indonesia | 7,432 | 967 |
| Malaysia | 46,683 | 11,015 |
| Congo (Brazzaville) | 1,298 | 51,263 |
| Other | 5,003 | 1,236 |
| Total exploration costs | 168,480 | 140,027 |
For further information on exploration costs, see the Directors' Report on page 78.
| TUSD | 2012 | 2011 |
|---|---|---|
| Norway | 205,835 | – |
| Russia | 31,655 | – |
| Total impairment costs of oil and gas properties | 237,490 | – |
For further information on impairment costs of oil and gas properties, see the Directors' Report on pages 78–79 and Note 9 oil and gas properties.
| TUSD | 2012 | 2011 |
|---|---|---|
| Interest income | 5,050 | 4,138 |
| Foreign currency exchange gain, net | 6,154 | 8,945 |
| Gain on consolidation of a subsidiary | 13,409 | – |
| Gain on sale of shares | – | 29,974 |
| Guarantee fees | 233 | 998 |
| Other fi nancial income | 2,395 | 2,400 |
| Total fi nancial income | 27,241 | 46,455 |
Exchange rate variations result primarily from fl uctuations in the value of the USD currency against a pool of currencies which includes, amongst others, EUR, NOK and RUR. Lundin Petroleum has USD denominated debt recorded in subsidiaries using a functional currency other than USD. The foreign currency exchange gain, net includes a realised exchange gain of MUSD 11.7 (MUSD -) on settled foreign exchange hedges.
For further information on fi nancial income, see the Directors' Report on page 79.
| TUSD | 2012 | 2011 |
|---|---|---|
| Loan interest expenses | 6,819 | 5,390 |
| Result on interest rate hedge settlement | 198 | 6,995 |
| Unwinding of site restoration discount | 5,073 | 4,494 |
| Amortisation of deferred fi nancing fees | 6,634 | 2,181 |
| Loan facility commitment fees | 10,315 | 1,005 |
| Impairment of other shares | 18,631 | – |
| Other fi nancial expenses | 852 | 957 |
| Total fi nancial expenses | 48,522 | 21,022 |
For further information on fi nancial expenses, see the Directors' Report on page 79.
| Tax charge TUSD |
2012 | 2011 |
|---|---|---|
| Current tax | ||
| Norway | 311,760 | 365,615 |
| France | 21,721 | 27,149 |
| Netherlands | 5,898 | 3,014 |
| Indonesia | 663 | 760 |
| Russia | 794 | 1,360 |
| Tunisia | 61 | 1,634 |
| Other | 405 | 678 |
| Total current tax | 341,302 | 400,210 |
| Deferred tax | ||
| Norway | 80,413 | 166,190 |
| France | 2,366 | 2,149 |
| Netherlands | 2,180 | -981 |
| Indonesia | -1,913 | 3,177 |
| Russia | -2,949 | 1,604 |
| Tunisia | 1,507 | -1,937 |
| Malaysia | -4,473 | 5,149 |
| Other | -32 | -1,148 |
| Total deferred tax | 77,099 | 174,203 |
| Total tax | 418,401 | 574,413 |
For further information on taxes, see the Directors' Report on page 79.
The tax on the Group's profi t before tax diff ers from the theoretical amount that would arise using the tax rate of Sweden as follows:
| TUSD | 2012 | 2011 |
|---|---|---|
| Profit before tax | 522,251 | 729,657 |
| Tax calculated at the corporate tax rate in Sweden (26.3%) | -137,352 | -191,900 |
| Eff ect of foreign tax rates | -282,571 | -371,884 |
| Tax eff ect of expenses non-deductible for tax purposes | -25,942 | -21,002 |
| Tax eff ect of deduction for petroleum tax | 22,517 | 15,770 |
| Tax eff ect of income not subject to tax | 4,414 | 8,751 |
| Tax eff ect of utilisation of unrecorded tax losses | 8,348 | 6,669 |
| Tax eff ect of creation of unrecorded tax losses | -7,787 | -23,155 |
| Adjustments to prior year tax assessments | -28 | 2,338 |
| Tax charge | -418,401 | -574,413 |
The tax rate in Norway is 78 percent and the large contribution of the results from Norway are the primary reasons for the signifi cant eff ect of foreign tax rates in the table above.
OF THE GROUP
The tax charge relating to components of other comprehensive income is as follows:
| 2012 | 2011 | |||||
|---|---|---|---|---|---|---|
| TUSD | Before tax | Tax charge/credit | After tax | Before tax | Tax charge/credit | After tax |
| Exchange diff erences on foreign operations | -61,661 | – | -61,661 | -37,525 | – | -37,525 |
| Cash fl ow hedges | 9,222 | -2,306 | 6,916 | 6,971 | -1,743 | 5,228 |
| Available for sale fi nancial assets | 16,053 | – | 16,053 | -50,210 | – | -50,210 |
| Other comprehensive income | 86,936 | -2,306 | 84,630 | -80,764 | -1,743 | -82,507 |
| Current tax | – | – | ||||
| Deferred tax | -2,306 | -1,743 | ||||
| -2,306 | -1,743 |
The deferred tax charge amounting to TUSD 2,306 (TUSD 1,743) has been recorded directly in other comprehensive income.
| Corporation tax liability - current and deferred | Current | Deferred | ||
|---|---|---|---|---|
| TUSD | 2012 | 2011 | 2012 | 2011 |
| Corporation tax | ||||
| Norway | 163,648 | 222,971 | 802,770 | 660,643 |
| France | – | 6,656 | 36,701 | 33,691 |
| Netherlands | 2,500 | 7,733 | 7,975 | 3,326 |
| Indonesia | 1,684 | 1,021 | 6,148 | 7,688 |
| Russia | 648 | 152 | 77,158 | 80,334 |
| Tunisia | 1,527 | 1,519 | – | 1,823 |
| Malaysia | – | – | 11,384 | 15,857 |
| Other | – | – | 99 | 131 |
| Total tax liability | 170,007 | 240,052 | 942,235 | 803,493 |
There is also a tax receivable of TUSD 3,986 (TUSD -) relating to France reported in other receivables at the end of the year, as reported in Note 18.
| Specifi cation of deferred tax assets and tax liabilities 1 | ||
|---|---|---|
| TUSD | 2012 | 2011 |
| Deferred tax assets | ||
| Unused tax loss carry forwards | 13,758 | 12,714 |
| Overlift position | – | 3,842 |
| Fair value of fi nancial instruments | – | 42 |
| Other deductible temporary diff erences | 8,720 | 6,524 |
| 22,478 | 23,122 | |
| Deferred tax liabilities | ||
| Accelerated allowances | 867,392 | 736,834 |
| Fair value on derivative instruments | 2,264 | – |
| Capitalised acquisition cost | 158 | 155 |
| Deferred tax on excess values | 81,629 | 74,281 |
| 951,443 | 811,270 |
1 The specifi cation of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the balance sheet when they relate to the same jurisdiction.
The deferred tax assets primarily relate to tax loss carried forwards in the Netherlands for an amount of TUSD 12,572 (TUSD 12,329). Deferred tax assets in relation to tax loss carried forwards are only recognised in so far that there is a reasonable certainty as to the timing and the extent of their realisation.
The deferred tax liabilities arise mainly on accelerated allowances, being the diff erence between the book and the tax value of oil and gas properties primarily in Norway, and tax on the excess value of the acquired assets in Russia. The deferred tax liabilities will be released over the life of the assets as the book value is depleted for accounting purposes.
The Group has Dutch tax loss carry forwards of approximately MUSD 161 (MUSD 134). Dutch tax losses can be carried forward and utilised for up to nine years. A deferred tax asset relating to the tax loss carry forwards of MUSD 110 (MUSD 87) has not been recognised as at 31 December 2012 due to the uncertainty as to the timing and the extent of the tax loss carry forward utilisation.
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Production cost pools | 857,009 | 792,446 |
| Non-production cost pools | 2,007,386 | 1,536,824 |
| 2,864,395 | 2,329,270 |
| 2012 production cost pools TUSD |
Norway | France | Netherlands | Indonesia | Russia | Tunisia | Total |
|---|---|---|---|---|---|---|---|
| Cost | |||||||
| 1 January | 791,950 | 265,721 | 105,085 | 68,696 | 98,229 | 105,876 | 1,435,557 |
| Additions | 112,311 | 29,224 | 8,515 | -430 | 7,458 | – | 157,078 |
| Disposals | – | -1,406 | – | – | – | -105,876 | -107,282 |
| Change in estimates | 21,262 | 18,140 | 21,210 | – | 1,196 | – | 61,808 |
| Reclassifi cations | 229,389 | 43 | 9 | 12 | – | – | 229,453 |
| Currency translation diff erence | 66,113 | 5,930 | 2,203 | – | 1,649 | – | 75,895 |
| 31 December | 1,221,025 | 317,652 | 137,022 | 68,278 | 108,532 | – | 1,852,509 |
| Depletion | |||||||
| 1 January | -326,283 | -100,376 | -64,469 | -10,391 | -35,716 | -105,876 | -643,111 |
| Depletion charge for the year | -154,140 | -11,668 | -10,437 | -5,612 | -4,320 | – | -186,177 |
| Impairment | -205,835 | – | – | – | -31,655 | – | -237,490 |
| Disposals | – | 1,302 | – | – | – | 105,876 | 107,178 |
| Reclassifi cations | – | -43 | – | – | – | – | -43 |
| Currency translation diff erence | -32,192 | -2,212 | -1,453 | – | – | – | -35,857 |
| 31 December | -718,450 | -112,997 | -76,359 | -16,003 | -71,691 | – | -995,500 |
| 2011 production cost pools TUSD |
Norway | France | Netherlands | Indonesia | Russia | Tunisia | Total |
|---|---|---|---|---|---|---|---|
| Cost | |||||||
| 1 January | 767,187 | 243,961 | 102,780 | 62,292 | 95,565 | 105,876 | 1,377,661 |
| Additions | 38,832 | 30,945 | 4,146 | 6,404 | 4,194 | – | 84,521 |
| Disposals | – | – | – | – | – | – | – |
| Change in estimates | 7,158 | 650 | 1,556 | – | 54 | – | 9,418 |
| Currency translation diff erence | -21,227 | -9,835 | -3,397 | – | -1,584 | – | -36,043 |
| 31 December | 791,950 | 265,721 | 105,085 | 68,696 | 98,229 | 105,876 | 1,435,557 |
| Depletion | |||||||
| 1 January | -209,907 | -91,903 | -54,961 | -4,141 | -30,952 | -105,876 | -497,740 |
| Depletion charge for the year | -130,011 | -12,174 | -11,939 | -6,250 | -4,764 | – | -165,138 |
| Currency translation diff erence | 13,635 | 3,701 | 2,431 | – | – | – | 19,767 |
| 31 December | -326,283 | -100,376 | -64,469 | -10,391 | -35,716 | -105,876 | -643,111 |
| Net book value | 465,667 | 165,345 | 40,616 | 58,305 | 62,513 | – | 792,446 |
Net book value 502,575 204,655 60,663 52,275 36,841 – 857,009
| 2012 non production cost pools TUSD |
Norway | France | Netherlands | Indonesia | Russia | Malaysia | Congo (Brazzaville) |
Other | Total |
|---|---|---|---|---|---|---|---|---|---|
| 1 January | 804,075 | 7,124 | 3,122 | 35,829 | 552,504 | 129,831 | – | 4,339 | 1,536,824 |
| Additions | 630,532 | 9,781 | 2,464 | 16,385 | 3,595 | 100,455 | 1,298 | – | 764,510 |
| Disposals | – | – | – | – | -1,010 | – | – | – | -1,010 |
| Expensed Exploration costs | -103,052 | -5,012 | -565 | -7,559 | – | -46,683 | -1,298 | -4,311 | -168,480 |
| Change in estimates | 11,763 | – | – | – | – | – | – | – | 11,763 |
| Reclassifi cations | -229,389 | – | – | -12 | – | – | – | – | -229,401 |
| Currency translation diff erence | 85,811 | 266 | 111 | -40 | 7,293 | -233 | – | -28 | 93,180 |
| 31 December | 1,199,740 | 12,159 | 5,132 | 44,603 | 562,382 | 183,370 | – | – | 2,007,386 |
OF THE GROUP
| 2011 non production cost pools TUSD |
Norway | France | Netherlands | Indonesia | Russia | Tunisia | Malaysia | Congo (Brazzaville) |
Other | Total |
|---|---|---|---|---|---|---|---|---|---|---|
| 1 January | 461,249 | 7,113 | 1,902 | 20,255 | 550,119 | – | 42,057 | 32,256 | 4,099 | 1,119,050 |
| Additions | 436,534 | 1,740 | 1,632 | 17,711 | 10,048 | 13 | 98,657 | 19,007 | 169 | 585,511 |
| Expensed Exploration costs | -74,060 | -1,486 | -255 | -2,163 | – | -13 | -11,015 | -51,263 | 228 | -140,027 |
| Change in estimates | 15,353 | – | – | – | – | – | – | – | – | 15,353 |
| Currency translation diff erence | -35,001 | -243 | -157 | 26 | -7,663 | – | 132 | – | -157 | -43,063 |
| 31 December | 804,075 | 7,124 | 3,122 | 35,829 | 552,504 | – | 129,831 | – | 4,339 | 1,536,824 |
In 2012, the reclassifi cation from Non-Production cost pools to Production cost pools related to the production start-up on the Gaupe fi eld, Norway.
Lundin Petroleum carried out its impairment testing at 31 December 2012 in conjunction with the annual reserves audit process. Lundin Petroleum used an oil price deck of USD 100 per bbl infl ating at 2 percent per annum, a future cost infl ation factor of 2 percent per annum and a discount rate of 10 percent to calculate the future pre-tax cash fl ows. As a result of the impairment testing performed, the Gaupe fi eld, Norway and the onshore producing assets in Russia were impaired and a pre-tax cost of MUSD 237.5 was charged to the income statement. For further information on impairment, see the Directors' Report on pages 78–79.
During 2012, MUSD 3.4 (MUSD 1.4) of capitalised interest costs were added to oil and gas properties and relate to oil and gas assets in Norway. The interest rate for capitalised borrowing costs is calculated at the external facility borrowing rate of LIBOR plus the margin of 2.75 percent per annum.
The Group participates in joint ventures with third parties in oil and gas exploration activities. The Group is contractually committed under various concession agreements to complete certain exploration programmes. The commitments as at 31 December 2012 are estimated to be MUSD 935.7 (MUSD 629.8) of which third parties who are joint venture partners will contribute approximately MUSD 491.5 (MUSD 279.8).
| 2012 | 2011 | |||||||
|---|---|---|---|---|---|---|---|---|
| TUSD | FPSO | Real estate | Offi ce equipment and other assets |
Total | FPSO | Real estate | Offi ce equipment and other assets |
Total |
| Cost | ||||||||
| 1 January | – | 11,129 | 17,936 | 29,065 | – | 11,182 | 15,174 | 26,356 |
| Acquired on consolidation | 25,222 | – | – | 25,222 | – | – | – | – |
| Additions | 6,037 | 86 | 3,579 | 9,702 | – | – | 3,786 | 3,786 |
| Disposals | – | – | -175 | -175 | – | – | -655 | -655 |
| Reclassifi cation | – | – | – | – | – | -53 | – | -53 |
| Currency translation diff erence | 1,253 | 52 | 837 | 2,142 | – | – | -369 | -369 |
| 31 December | 32,512 | 11,267 | 22,177 | 65,956 | – | 11,129 | 17,936 | 29,065 |
| Depreciation | ||||||||
| 1 January | – | -1,375 | -11,605 | -12,980 | – | -1,337 | -9,748 | -11,085 |
| Disposals | – | – | 162 | 162 | – | – | 530 | 530 |
| Depreciation charge for the year | – | -117 | -2,999 | -3,116 | – | -95 | -2,579 | -2,674 |
| Currency translation diff erence | – | -53 | -551 | -604 | – | 57 | 191 | 248 |
| 31 December | – | -1,545 | -14,993 | -16,538 | – | -1,375 | -11,606 | -12,981 |
| Net book value | 32,512 | 9,722 | 7,184 | 49,418 | – | 9,754 | 6,330 | 16,084 |
The depreciation charge for the year is based on cost and an estimated useful life of 3 to 5 years for offi ce equipment and other assets. Real estate is depreciated using an estimated useful life of 20 years. Depreciation is included within the general, administration and depreciation line in the income statement.
The FPSO will be depreciated over its remaining useful life once the upgrade of the vessel has been completed. The FPSO was consolidated from the end of August 2012, see section Changes in the Group in the Directors' Report on page 73.
| Number of | ||
|---|---|---|
| As at 31 December 2012 | shares | Share % |
| RF Energy Investments Ltd. 1 | 11,540 | 50.00 |
| – CJSC Pechoraneftegas 1 | 20,000 | Direct 100.00, indirect 50.00 |
| – LLC Zapolyarneftegas 1 | 1 | Direct 100.00, indirect 50.00 |
| – LLC NK Recher-Komi 1 | 1 | Direct 100.00, indirect 50.00 |
| – Geotundra BV 1 | 20,000 | Direct 100.00, indirect 50.00 |
1 Through the proportional consolidation of RF Energy Investments Ltd. (RF Energy), the subsidiaries of RF Energy are also proportionally consolidated in the Lundin Petroleum accounts.
"Direct" refers to RF Energy's ownership percentage, "indirect" refers to the Group's ultimate ownership percentage.
The amounts included below for the jointly controlled entity RF Energy represent 100 percent of the reported accounts.
| RF Energy consolidated | ||
|---|---|---|
| TUSD | 2012 | 2011 |
| Income statement | ||
| Revenue | 152,044 | 159,481 |
| Operating cost | -198,337 | -149,348 |
| Net result | -46,293 | 10,133 |
| Balance Sheet | ||
| Non-current assets | 109,892 | 122,381 |
| Current assets | 43,469 | 39,428 |
| Total assets | 153,361 | 161,809 |
| Equity | 56,655 | 97,015 |
| Non-current liabilities | 72,692 | 47,220 |
| Current liabilities | 24,014 | 17,574 |
| Total liabilities | 153,361 | 161,809 |
The fi nancial results of Ikdam Production SA are fully consolidated following the increase in the shareholding from 40 percent to 100 percent in August 2012 and the company is in consequence no longer an associated company.
| Ikdam Production SA TUSD |
2011 |
|---|---|
| Income statement | |
| Revenue | 2,610 |
| Operating cost | -4,946 |
| Net result | -2,336 |
| Balance Sheet | |
| Non-current assets | – |
| Current assets | 775 |
| Total assets | 775 |
| Equity | -13,934 |
| Non-current liabilities | 14,213 |
| Current liabilities | 496 |
| Total liabilities | 775 |
| Other shares and | 31 December 2012 | 31 December 2011 |
||
|---|---|---|---|---|
| participation comprise: TUSD |
Number of shares |
Share % | Book amount |
Book amount |
| ShaMaran Petroleum Corp. | 50,000,000 | 8.02 | 19,584 | 17,380 |
| Cofraland B.V. | 31 | 7.75 | 399 | 391 |
| Maison de la géologie | – | – | – | 4 |
| 19,983 | 17,775 |
In October 2009, Lundin Petroleum received 50 million shares of ShaMaran Petroleum Corporation (ShaMaran) in consideration for the sale of Lundin International BV, a 100 percent owned subsidiary, which had commenced negotiations for Production Sharing Contracts (PSCs) for three separate exploration and development blocks in Kurdistan. The investment was booked at the fair value of the shares at the date of acquisition and under accounting rules, any subsequent movement in the fair value of the shares is being recorded in the consolidated statement of comprehensive income.
The fair value of ShaMaran is calculated using the quoted share price at the Toronto Stock Exchange at the balance sheet date and is detailed below.
| ShaMaran TUSD |
2012 | 2011 |
|---|---|---|
| 1 January | 17,380 | 68,205 |
| Fair value movement | 16,303 | -49,964 |
| Currency translation diff erence | 4,532 | -861 |
| Impairment | -18,631 | – |
| 31 December | 19,584 | 17,380 |
During 2012, the fair value of the ShaMaran shares was impaired by MUSD 18.6, see section fi nancial expenses in the Directors' Report, page 79.
As at 31 December 2012, the other shares and participations include TUSD 399.0 (TUSD 395.0) recognised at cost because their fair value cannot be measured reliably since there is no quoted share price and due to the uncertainty of the timing of the future cash fl ows from these companies.
For further information on other shares and participations, see the section non-current assets in the Directors' Report on page 80.
As an international oil and gas exploration and production company operating globally, Lundin Petroleum is exposed to fi nancial risks such as currency risk, interest rate risk, credit risks, liquidity risks as well as the risk related to the fl uctuation in the oil price. The Group seeks to control these risks through sound management practice and the use of internationally accepted fi nancial instruments, such as oil price, interest rate and foreign exchange hedges. Lundin Petroleum uses fi nancial instruments solely for the purpose of minimising risks in the Group's business.
| Financial liabilities TUSD |
31 December 2012 | 31 December 2011 |
|---|---|---|
| Current | ||
| Trade payables | 15,718 | 16,546 |
| Derivative instruments | 9,056 | – |
| Joint venture creditors | 209,594 | 88,417 |
| Acquisition liabilities | – | 10,979 |
| Non-current | ||
| Bank loans | 432,000 | 207,000 |
| Other non-current liabilities | 22,556 | 21,830 |
The Group's objectives when managing capital are to safeguard the Group's ability to continue as a going concern and to meet its committed work programme requirements in order to create shareholder value. The Group may put in place new credit facilities, repay debt, or other such restructuring activities as appropriate. Group management continuously monitors and manages the Group's net debt position in order to assess the requirement for changes to the capital structure to meet the objectives and to maintain fl exibility. Lundin Petroleum is not subject to any externally-imposed capital requirements.
No signifi cant changes were made in the objectives, policies or procedures during the year ended 31 December 2012.
Lundin Petroleum monitors capital on the basis of net debt. Net debt is calculated as bank loans less cash and cash equivalents.
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Bank loans | 432,000 | 207,000 |
| Less cash and cash equivalents | -97,425 | -73,597 |
| Net debt | 334,575 | 133,403 |
The increase compared to 2011 is due to the new revolving credit facility, signed in June 2012.
OF THE GROUP
Interest rate risk is the risk to the earnings due to uncertain future interest rates.
Lundin Petroleum is exposed to interest rate risk through the credit facility (see also liquidity risk below). Lundin Petroleum will assess the benefi ts of interest rate hedging on borrowings on a continuous basis. If the hedging contract provides a reduction in the interest rate risk at a price that is deemed acceptable to the Group, then Lundin Petroleum may choose to enter into an interest hedge.
The table below summarises the eff ect that a change in the interest rate for the credit facility would have had on the net result and equity for the year ended 31 December 2012:
| Net result in the fi nancial statements (MUSD) | 103.9 | 103.9 |
|---|---|---|
| Possible shift (%) | -10% | 10% |
| Total eff ect on net result (MUSD) | 0.4 | -0.4 |
In the fi rst quarter of 2013, Lundin Petroleum entered into a three year fi xed interest rate swap, starting 31 March 2013, in respect of MUSD 500 of borrowings, fi xing the LIBOR rate at approximately 0.57 percent per annum. This hedge reduces the interest rate risk.
Lundin Petroleum is a Swedish company which is operating globally and therefore attracts substantial foreign exchange exposure, both transactional as well as conversion from functional currency to presentation currency. The functional currency of Lundin Petroleum's subsidiaries are Norwegian Kroner (NOK), Euro (EUR) and Russian Rouble (RUR), as well as US Dollar (USD), making Lundin Petroleum sensitive to fl uctuations of these currencies against the US Dollar, the presentation currency.
Lundin Petroleum's policy on currency rate hedging is, in case of currency exposure, to consider setting the rate of exchange for known costs in non-US Dollar currencies to US Dollars in advance so that future US Dollar cost levels can be forecasted with a reasonable degree of certainty. The Group will take into account the current rates of exchange and market expectations in comparison to historic trends and volatility in making the decision to hedge.
During the year, the Group entered into currency hedging contracts fi xing the rate of exchange from USD into NOK to meet NOK operational and tax requirements as summarised in the table below. Under IAS 39, subject to hedge eff ectiveness testing, these cash fl ow hedges are treated as eff ective and changes to the fair value are refl ected in other comprehensive income. At 31 December 2012, a current asset has been recognised amounting to MUSD 9.1 (MUSD -) representing the short-term portion of the fair value of the outstanding currency hedging contracts.
| Buy | Sell | Average contractual exchange rate |
Settlement period |
|---|---|---|---|
| MNOK 1,580.7 | MUSD 261.6 | NOK 6.04: 1 USD | 1 Jun 2012 – 20 Dec 2012 |
| MNOK 670.7 | MUSD 110.4 | NOK 6.07: 1 USD | 2 Jan 2013 – 20 Dec 2013 |
The following table summarises the eff ect that a change in these currencies against the US Dollar would have on operating result and equity through the conversion of the income statements of the Group's subsidiaries from functional currency to the presentation currency US Dollar for the year ended at 31 December 2012.
| Operating profi t in the fi nancial | |||
|---|---|---|---|
| statements (MUSD) | 543.5 | 543.5 | |
| Shift of currency exchange rates | Average rate | 10% USD | 10% USD |
| 2012 | weakening | strengthening | |
| EUR/USD | 0.7778 | 0.7071 | 0.8556 |
| NOK/USD | 5.8148 | 5.2862 | 6.3963 |
| RUR/USD | 31.0546 | 28.2315 | 34.1601 |
| Total eff ect on operating result | |||
| (MUSD) | 53.9 | -53.9 |
The foreign currency risk to the Group's income and equity from conversion exposure is not hedged.
Price of oil and gas are aff ected by the normal economic drivers of supply and demand as well as the fi nancial investors and market uncertainty. Factors that infl uence these include operational decisions, natural disasters, economic conditions, political instability or confl icts or actions by major oil exporting countries. Price fl uctuations can aff ect Lundin Petroleum's fi nancial position.
The table below summarises the eff ect that a change in the oil price would have had on
the net result and equity at 31 December 2012:
| Net result in the fi nancial statements (MUSD) | 103.9 | 103.9 |
|---|---|---|
| Possible shift (%) | -10% | 10% |
| Total eff ect on net result (MUSD) | -37.5 | 37.5 |
The impact on the net result from a change in oil price is reduced due to the 78 percent tax rate in Norway.
Lundin Petroleum's policy is to adopt a fl exible approach towards oil price hedging, based on an assessment of the benefi ts of the hedge contract in specifi c circumstances. Based on analysis of the circumstances, Lundin Petroleum will assess the benefi ts of forward hedging monthly sales contracts for the purpose of establishing cash fl ow. If it believes that the hedging contract will provide an enhanced cash fl ow then it may choose to enter into an oil price hedge.
For the year ended 31 December 2012, the Group did not enter into oil price hedging contracts. There are no oil price hedging contracts outstanding as at 31 December 2012.
Lundin Petroleum's policy is to limit credit risk by limiting the counter-parties to major banks and oil companies. Where it is determined that there is a credit risk for oil and gas sales, the policy is to require an irrevocable letter of credit for the full value of the sale. The policy on joint venture parties is to rely on the provisions of the underlying joint operating agreements to take possession of the licence or the joint venture partner's share of production for non-payment of cash calls or other amounts due.
As at 31 December 2012, the Group's trade receivables amounted to MUSD 126.0 (MUSD 145.0). There is no recent history of default. Other long-term and short-term receivables are considered recoverable. The provision for bad debt as at 31 December 2012 amounted to MUSD – (MUSD –). Cash and cash equivalents are maintained with banks having strong long-term credit ratings.
Liquidity risk is defi ned as the risk that the Group could not be able to settle or meet its obligations on time or at a reasonable price. Group treasury is responsible for liquidity, funding as well as settlement management. In addition, liquidity and funding risks and related processes and policies are overseen by management.
On 25 June 2012, Lundin Petroleum entered into a new seven year secured revolving borrowing base facility of USD 2.5 billion to provide funding for Lundin Petroleum's ongoing exploration expenditure and development costs, particularly in Norway. It is expected that the Group's ongoing development and exploration expenditure requirements will be funded by the Group's operating cash fl ow and the loan facility. No loan repayments are required for the credit facility in 2013. See Note 24 for more information regarding the Group's credit facility.
Lundin Petroleum has, through its subsidiary Lundin Malaysia BV, entered into fi ve 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. Bank guarantees have been issued in support of the work commitments in relation to these PSCs amounting to MUSD 75.4. In addition, bank guarantees have been issued to cover work commitments in Indonesia amounting to MUSD 2.4 and in Tunisia for MUSD 1.5 relating to a tax dispute.
The accounting policies for fi nancial instruments have been applied to the line items below:
| 31 December 2012 TUSD |
Loan receivables and other receivables |
Available for sale |
Derivatives used for hedging |
Financial liabilities valued at amortised cost |
|---|---|---|---|---|
| Assets | ||||
| Other shares and participations |
– | 19,983 | – | – |
| Bonds | 9,526 | – | – | – |
| Derivative instruments | – | – | 9,056 | – |
| Trade receivables | 125,905 | – | – | – |
| Joint venture debtors | 11,539 | – | – | – |
| Cash and cash equivalents | 97,425 | – | – | – |
| 244,395 | 19,983 | 9,056 | – | |
| Liabilities | ||||
| Trade payables | – | – | – | 15,718 |
| Joint venture creditors | – | – | – | 209,594 |
| Bank loans | – | – | – | 432,000 |
| Other non-current liabilities | – | – | – | 22,556 |
| – | – | – | 679,868 |
| 31 December 2011 TUSD |
Loan receivables and other receivables |
Available for sale |
Derivatives used for hedging |
Financial liabilities valued at amortised cost |
|---|---|---|---|---|
| Assets | ||||
| Other shares and participations |
– | 17,775 | – | – |
| Bonds | 9,588 | – | – | – |
| Trade receivables | 144,954 | – | – | – |
| Joint venture debtors | 20,252 | – | – | – |
| Other receivables | 11,176 | – | – | – |
| Cash and cash equivalents | 73,597 | – | – | – |
| 259,567 | 17,775 | – | – | |
| Liabilities | ||||
| Trade payables | – | – | – | 16,546 |
| Bank loans | – | – | – | 207,000 |
| – | – | 168 | 470,299 | |
|---|---|---|---|---|
| Acquisition liabilities | – | – | – | 10,979 |
| Joint venture creditors | – | – | – | 213,944 |
| Derivative instruments | – | – | 168 | – |
| Other non-current liabilities | – | – | – | 21,830 |
| Bank loans | – | – | – | 207,000 |
For fi nancial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:
– Level 1: based on quoted prices in active markets;
– Level 2: based on inputs other than quoted prices as within level 1, that are either
directly or indirectly observable; – Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, fi nancial instruments measured at fair value can be detailed as follows:
| 31 December 2012 TUSD |
Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Available for sale fi nancial assets | |||
| - Equity securities | 19,584 | – | 399 |
| - Derivative instruments | – | 9,056 | – |
| 19,584 | 9,056 | 399 | |
| Liabilities | |||
| - Derivative instruments | – | – | – |
| – | – | – |
| 31 December 2011 TUSD |
Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Available for sale fi nancial assets | |||
| - Equity securities | 17,380 | – | 395 |
| 17,380 | – | 395 | |
| Liabilities | |||
| - Derivative instruments | – | 168 | – |
| – | 168 | – |
| Equity securities Level 3 TUSD |
31 December 2012 | 31 December 2011 |
|---|---|---|
| 1 January | 395 | 408 |
| Disposal | -4 | – |
| Currency translation diff erence | 8 | -13 |
| 31 December | 399 | 395 |
| Fair value of outstanding derivative instruments in the |
31 December 2012 | 31 December 2011 | ||
|---|---|---|---|---|
| balance sheet (TUSD) | Assets Liabilities | Assets | Liabilities | |
| Interest rate swaps | – | – | – | 168 |
| Currency hedge | 9,056 | – | – | – |
| Non-current | – | – | – | – |
| Current | 9,056 | – | – | 168 |
| Total | 9,056 | – | – | 168 |
The fair value of the currency hedge is calculated using the forward exchange rate curve applied to the outstanding portion of the outstanding currency hedging contracts. The eff ective portion of the currency hedge as at 31 December 2012 amounted to TUSD 9,056 (TUSD –).
The fair value of the interest rate swap is calculated using the forward interest rate curve applied to the outstanding portion of the swap transaction. The eff ective portion of the interest rate swap as at 31 December 2012 amounted to TUSD – (TUSD 168).
For risks in the fi nancial reporting see the section Internal control and risk management for the fi nancial reporting in the Corporate Governance report on pages 62–63 and risks and risk management on pages 70–71 for more information.
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Bonds | 9,526 | 9,588 |
| Other | 1,326 | 1,372 |
| 10,852 | 10,960 |
The Group holds 7.6 million Euro denominated bonds in Etrion Corporation with a coupon rate of 9 percent per year and a maturity date in April 2015.
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Hydrocarbon stocks | 1,576 | 16,307 |
| Drilling equipment and consumable materials |
17,124 | 15,282 |
| 18,700 | 31,589 |
The trade receivables relate mainly to hydrocarbon sales to a limited number of independent customers from whom there is no recent history of default. The trade receivables balance is current and the provision for bad debt is nil.
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Prepaid rent | 605 | 521 |
| Prepaid area fees | 16,660 | – |
| Prepaid insurance | 12,210 | 1,675 |
| Accrued income | 1,083 | 885 |
| Other | 2,348 | 1,441 |
| 32,906 | 4,522 |
Prepaid insurance included an amount of TUSD 10,082 relating to the construction insurance on the Edvard Grieg project, Norway.
OF THE GROUP
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Underlift | 26,439 | 1,851 |
| Corporation tax | 3,986 | – |
| Short-term VAT receivable | 2,963 | 5,699 |
| Other | 6,889 | 15,540 |
| 40,277 | 23,090 |
Cash and cash equivalents include only cash at hand or on bank. No short term deposits are held as at 31 December 2012.
| TUSD | Available for sale reserve |
Hedge reserve |
Currency translation reserve |
Total Other reserves |
|---|---|---|---|---|
| 1 January 2011 | 41,023 | -5,149 | -102,009 | -66,135 |
| Total comprehensive income | -50,210 | 5,228 | -34,689 | -79,671 |
| 31 December 2011 | -9,187 | 79 | -136,698 | -145,806 |
| Total comprehensive income | 16,053 | 6,916 | 59,103 | 82,072 |
| 31 December 2012 | 6,866 | 6,995 | -77,595 | -63,734 |
| TUSD | 2012 | 2011 |
|---|---|---|
| 1 January | 119,341 | 93,766 |
| Unwinding of site restoration discount | 10,340 | 4,494 |
| Payments | -18,550 | -1,168 |
| Changes in estimates | 73,571 | 24,771 |
| Currency translation diff erence | 5,768 | -2,522 |
| 31 December | 190,470 | 119,341 |
In calculating the present value of the site restoration provision, a pre-tax discount rate of 3.5 percent (5.5 percent) was used which is based on long-term risk-free interest rate projections. The estimated costs of the fi nal decommissioning liabilities for the assets have been updated during the year and the eff ect of the updated estimates and the change in the discount rate used is refl ected in change in estimates in the table above. Based on the estimates used in calculating the site restoration provision as at 31 December 2012, approximately 60 percent of the total amount is expected to settle after more than 15 years.
| TUSD | 2012 | 2011 |
|---|---|---|
| 1 January | 1,460 | 1,421 |
| Fair value adjustment | 161 | 192 |
| Instalments paid | -147 | -155 |
| Currency translation diff erence | 36 | 2 |
| 31 December | 1,510 | 1,460 |
In May 2002, the Compensation Committee recommended to the Board of Directors, and the Board of Directors approved that a pension be paid to Mr Adolf H. Lundin upon his resignation as Chairman of the Board of Directors and his appointment as Honorary Chairman. It was further agreed that upon the death of Mr Adolf H. Lundin, the monthly payments would be paid to his wife, Mrs Eva Lundin for the duration of her life.
Pension payments totalling an annual amount of TCHF 138 (TUSD 147) are payable to Mrs Eva Lundin. The Company may, at its option, buy out the obligation to make the pension payments through a lump sum payment of TCHF 1,800 (TUSD 1,967).
| TUSD | LTIP | Termination indemnity provision |
Other | Total |
|---|---|---|---|---|
| 1 January 2012 | 70,294 | 3,517 | 2,103 | 75,914 |
| Additions | 13,873 | 718 | 96 | 14,687 |
| Payment | -10,774 | -3,188 | – | -13,962 |
| Currency translation diff erence | 2,567 | – | 29 | 2,596 |
| 31 December 2012 | 75,960 | 1,047 | 2,228 | 79,235 |
| Non-current | 67,135 | 1,047 | 2,228 | 70,410 |
| Current | 8,825 | – | – | 8,825 |
| Total | 75,960 | 1,047 | 2,228 | 79,235 |
The termination indemnity provision represents Lundin Petroleum's share of the provision for employment termination costs for the Oudna joint venture in Tunisia.
For details of the LTIP see Note 34.
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Bank loans | 432,000 | 207,000 |
| Capitalised fi nancing fees | -47,812 | -2,506 |
| 384,188 | 204,494 |
Lundin Petroleum had a secured revolving borrowing base facility of MUSD 850 with a seven year term expiring in 2014. On 25 June 2012, Lundin Petroleum entered into a new seven year secured revolving borrowing base facility of USD 2.5 billion. The facility is with a group of 25 banks including many of the banks providing the USD 850 million facility. The USD 2.5 billion fi nancing facility is a revolving borrowing base facility secured against certain cash fl ows generated by the Group. The amount available under the facility is recalculated every six months based upon the calculated cash fl ow generated by certain producing fi elds at an oil price and economic assumptions agreed with the banking syndicate providing the facility. The new facility has been completed to provide funding for Lundin Petroleum's ongoing exploration expenditure and development costs, particularly in Norway. The upfront fees associated with the new credit facility have been capitalised and are being amortised over the expected life of the fi nancing facility. The interest rate on Lundin Petroleum's credit facility is fl oating and is currently LIBOR + 2.75 percent per annum.
In relation to fi nancial liabilities, the following amounts were outstanding:
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Non-current | ||
| Repayment within 2–5 years: | ||
| Bank loans | – | 207,000 |
| Repayment after 5 years: | ||
| Bank loans | 432,000 | – |
| Other non-current liabilities | 22,556 | 21,830 |
| Current | ||
| Repayment within 6 months: | ||
| Trade payables | 15,718 | 16,546 |
| Joint venture creditors | 209,594 | 213,944 |
| Acquisition liabilities | – | 10,979 |
| Repayment between 6–12 months: | ||
| Other current liabilities | – | – |
| 679,868 | 470,299 |
The table above analyses the Group's fi nancial liabilities into relevant maturity groupings based on the remaining period at the balance sheet date to the contractual maturity date. The maturity date of the new bank facility is June 2019 and there is a loan reduction schedule which commences in 2016 and reduces to zero by the fi nal maturity date. In addition, the amount available to borrow under the facility is based upon a net present value calculation of the assets' future cash fl ows. Based on the reduction schedule and the current availability calculation, no repayments of the current outstanding bank loan balance falls due within fi ve years.
The Group's credit facility agreement provides that an "event of default" occurs where the Group does not comply with certain material covenants or where certain events occur as specifi ed in the agreement, as are customary in fi nancing agreements of this size and nature. If such an event of default occurs and subject to any applicable cure periods, the external lenders may take certain specifi ed actions to enforce their security, including accelerating the repayment of outstanding amounts under the credit facility. The Group is not in breach of the debt covenants.
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Holiday pay | 4,557 | 3,909 |
| Operating costs | 3,133 | 6,456 |
| Social security charges | 2,641 | 2,316 |
| Salaries and wages | 109 | 91 |
| Other | 2,247 | 3,455 |
| 12,687 | 16,227 |
| TUSD | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Overlift | 490 | 7,670 |
| Acquisition liabilities | – | 10,979 |
| Withholding tax on salaries | 5,430 | 4,770 |
| VAT payable | 263 | 1,899 |
| Social charges payable | 677 | 633 |
| Mineral resource extraction tax | 2,158 | 2,849 |
| Other liabilities | 6,455 | 390 |
| 15,473 | 29,190 |
Acquisition liabilities at 31 December 2011 represent the amount 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 fi rst quarter of 2012. Other liabilities include an operational liability relating to the Gaupe fi eld, Norway, an audit claim and other supplier payables.
In June 2012, Lundin Petroleum entered into a new seven year secured revolving borrowing base facility of USD 2.5 billion as described in Note 24 Financial liabilities. The facility is secured by a pledge over the shares of certain Group companies and a charge over some of the bank accounts of the pledged companies.
For accounting purposes, the pledged amount at 31 December 2012 is MUSD 1,831.3 (MUSD 1,791.0) and is the accounting value of net assets of the Group companies whose shares are pledged.
In connection with the acquisition by Lundin Petroleum of the additional 30 percent interest in the Lagansky Block in 2009, Lundin Petroleum has agreed to pay to the former owner of the Lagansky Block a fee to be based on USD 0.30 per barrel of oil in respect of 30 percent of the proven and probable reserves in the Lagansky Block as at the date a decision is made to proceed to a development.
In connection with the acquisition of a 30 percent interest in the Lagansky Block by a subsidiary of Gunvor International BV in 2009, Gunvor has agreed to pay to Lundin Petroleum a fee to be based on USD 0.15 per barrel of oil (up to gross 150 MMbbls) and USD 0.30 per barrel of oil (over gross 150 MMbbls) of the proven and probable reserves in the Lagansky Block as at the date a decision is made to proceed to a development.
The amounts of the contingent asset and liability related to the Lagansky Block are dependent on the outcome of future exploration and production activities. Due to the uncertainties related to these activities, estimates of the cash infl ow and outfl ow can not be calculated with certainty.
In connection with the sale by Lundin Petroleum of its Salawati interests in Indonesia to RH Petrogas in 2010, RH Petrogas has agreed to pay to Lundin Petroleum up to MUSD 3.9 as deferred consideration. The amount and timing of such payment will be determined based on certain future fi eld developments within the Salawati Island Block.
Earnings per share is calculated by dividing the net result attributable to shareholders of the Parent Company by the weighted average number of shares for the year.
| 2012 | 2011 | |
|---|---|---|
| Net result attributable to shareholders of the Parent | ||
| Company (in USD) | 108,160,717 | 160,136,792 |
| Weighted average number of shares for the year | 310,735,227 | 311,027,942 |
| Earnings per share (in USD) | 0.35 | 0.51 |
There was no dilution for the years 2012 and 2011.
| TUSD | Note | 2012 | 2011 |
|---|---|---|---|
| Exploration costs | 4 | 168,480 | 140,027 |
| Impairment of oil and gas properties | 5 | 237,490 | – |
| Depletion, depreciation and amortisation | 9/10 | 189,293 | 167,812 |
| Impairment of other shares | 12 | 18,631 | – |
| Amortisation of deferred fi nancing fees | 7 | 6,634 | 2,181 |
| Unwinding of site restoration discount | 7/21 | 5,073 | 4,494 |
| Decommissioning costs | 3/21 | 5,267 | – |
| Long-term incentive plan | 12,988 | 63,443 | |
| Interest income | 6 | -5,050 | -4,138 |
| Current tax | 8 | 341,302 | 400,210 |
| Deferred tax | 8 | 77,099 | 174,203 |
| Interest expense | 7 | 6,819 | 5,390 |
| Exchange gains/losses | 6 | 5,562 | -8,945 |
| Gain on sale of shares | 6 | – | -29,974 |
| Gain on consolidation of subsidiary | 6 | -13,409 | – |
| Other provisions | 857 | 638 | |
| Other non-cash items | -138 | -167 | |
| Adjustment to cash fl ow from operations | 1,056,898 | 915,174 |
Lundin Petroleum recognises the following related parties: associated companies, jointly controlled entities, key management personnel and members of their close family or other parties that are partly, directly or indirectly, controlled by key management personnel or of its family or of any individual that controls, or has joint control or signifi cant infl uence over the entity.
During the year, the Group has entered into transactions with related parties on commercial basis as described below:
| TUSD | 2012 | 2011 |
|---|---|---|
| Purchase and sale of services: | ||
| Purchase of services | -1,012 | -735 |
| Sale of services | 396 | 391 |
| Sale of fi nancial services | – | 915 |
The related party transactions concern other parties where key management personnel has joint control or signifi cant infl uence over the entity. Key management personnel include directors and the Executive Management as defi ned in the Corporate Governance report page 59. The remuneration to the board of directors and Executive Management is disclosed in Note 33. There are no year end balances related to key management personnel.
OF THE GROUP
| 2012 | 2011 | |||
|---|---|---|---|---|
| Average number of employees per country | Total employees | of which men | Total employees | of which men |
| Parent Company in Sweden | – | – | – | – |
| Subsidiaries abroad | ||||
| Norway | 144 | 104 | 100 | 72 |
| France | 56 | 45 | 57 | 46 |
| Netherlands | 7 | 3 | 7 | 3 |
| Indonesia | 26 | 15 | 22 | 12 |
| Russia | 43 | 27 | 46 | 28 |
| Tunisia | 7 | 5 | 10 | 6 |
| Malaysia | 50 | 32 | 32 | 21 |
| Switzerland | 39 | 23 | 39 | 24 |
| Other | – | – | 3 | 2 |
| Total subsidiaries abroad | 372 | 254 | 316 | 214 |
| Total Group | 372 | 254 | 316 | 214 |
| 2012 | 2011 | |||
|---|---|---|---|---|
| Board members and Executive Management | Total at year end | of which men | Total at year end | of which men |
| Parent Company in Sweden | ||||
| Board members 1 | 6 | 5 | 7 | 5 |
| Subsidiaries abroad | ||||
| Executive Management 1 | 4 | 4 | 4 | 4 |
| Total Group | 10 | 9 | 11 | 9 |
1 Ashley Heppenstall, CEO and Board member is included in Executive Management.
| 2012 | 2011 | |||
|---|---|---|---|---|
| Salaries, other remuneration and social security costs TUSD |
Salaries and other remuneration |
Social security costs |
Salaries and other remuneration |
Social security costs |
| Parent Company in Sweden | ||||
| Board members | 580 | 117 | 570 | 116 |
| Subsidiaries abroad | ||||
| Executive Management | 5,095 | 336 | 5,105 | 337 |
| Other employees | 70,499 | 16,095 | 62,312 | 13,436 |
| Total Group | 76,174 | 16,548 | 67,987 | 13,889 |
| of which pension costs | 5,740 | 4,344 |
| Salaries and other remuneration for the Board members and Executive Management1 TUSD |
Fixed Board remuneration/ basic salary and other benefi ts 2 |
Short-term variable salary 3 |
Remuneration for Committee work |
Board remuneration for special assignments 4 |
Pension | Total 2012 | Total 2011 |
|---|---|---|---|---|---|---|---|
| Parent Company in Sweden | |||||||
| Board members | |||||||
| Ian H. Lundin | 134 | – | – | 284 | – | 418 | 303 |
| Magnus Unger | 63 | – | 30 | 14 | – | 107 | 108 |
| Lukas H. Lundin | 63 | – | – | – | – | 63 | 70 |
| William A. Rand | 63 | – | 36 | – | – | 99 | 93 |
| Asbjørn Larsen | 63 | – | 15 | – | – | 78 | 77 |
| Dambisa F. Moyo | 29 | – | 6 | – | – | 35 | 77 |
| Kristin Færøvik | 63 | – | 15 | – | – | 78 | 39 |
| Total Board members | 478 | – | 102 | 298 | – | 878 | 767 |
| Subsidiaries abroad | |||||||
| Executive Management | |||||||
| C. Ashley Heppenstall | 1,005 | 1,133 | – | – | 96 | 2,234 | 2,049 |
| Alexandre Schneiter | 645 | 640 | – | – | 64 | 1,349 | 1,345 |
| Chris Bruijnzeels | 537 | 373 | – | – | 54 | 964 | 1,048 |
| Geoff rey Turbott | 587 | 373 | – | – | 58 | 1,018 | 1,132 |
Salaries and other remuneration have been expensed during the year.
2 Other benefi ts include school fees and health insurance.
3 In December 2012, the Compensation Committee awarded a bonus for 2012 of one month's salary to Executive Management (included in the bonus expense for 2012). In January 2013, the Compensation Committee reassessed the bonus payments made for 2012 considering the employees' contributions to the results of the Group and the achievement of personal targets and awarded additional bonuses payable in January 2013. The same reassessment was made in January 2012 for 2011 and the amounts are included in the cost of 2012.
Total Executive Management 2,774 2,519 – – 272 5,565 5,574
4 Other remuneration paid during 2012 relates to fees paid for special assignments undertaken by Board members on behalf of the Group. The payment of such fees was in accordance with fees approved by the AGM.
There are no severance pay agreements in place for any non-executive directors and such directors are not eligible to participate in any of the Group's incentive programmes.
The pension contribution is between 19 percent and 21 percent of the qualifying income for pension purposes, 40 percent of which is funded by the employee. Qualifying income is defi ned as annual basic salary and bonus. The normal retirement age for the CEO is 65 years. .
The Executive Management has no outstanding incentive warrants. The third and last tranche under the 2008 Unit Bonus Plan was paid in 2011.
A mutual termination period of between one month and six months applies between the Company and Executive Management, depending on the duration of the employment with the Company, where the maximum applies as of the tenth year of employment. In addition, severance terms are incorporated into the employment contracts for Executives that give rise to compensation, equal to two years' basic salary, in the event of termination of employment due to a change of control of the Company.
See pages 59–61 of the Corporate Governance report for further information on the Company's principles of remuneration and the Policy on Remuneration for the Executive Management for 2012.
OF THE GROUP
The Company maintains the long-term incentive plans (LTIP) described below.
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 fi nal 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 fi ve trading day average closing Lundin Petroleum share price prior to and following the actual vesting date. The exercise price at vesting date 31st of May 2012 was SEK 127.90.
The LTIPs that follow the same principles as the 2008 LTIP have subsequently been implemented for employees other than Executive Management each year and are summarised in the table below.
| Plan | |||||
|---|---|---|---|---|---|
| Unit Bonus Plan | 2009 | 2010 | 2011 | 2012 | Total |
| Outstanding at the beginning of the period | 219,984 | 470,169 | 418,400 | – | 1,108,553 |
| Awarded during the period | – | – | – | 361,158 | 361,158 |
| Forfeited during the period | -10,544 | -35,989 | -34,169 | – | -80,702 |
| Exercised during the period | -209,440 | -225,018 | -133,606 | – | -568,064 |
| Outstanding at the end of the period | – | 209,162 | 250,625 | 361,158 | 820,945 |
| Vesting date | |||||
| 31 May 2013 | 209,162 | 125,315 | 120,386 | 454,863 | |
| 31 May 2014 | – | 125,310 | 120,386 | 245,696 | |
| 31 May 2015 | – | – | 120,386 | 120,386 | |
| Outstanding at the end of the period | 209,162 | 250,625 | 361,158 | 820,945 |
The costs associated with the unit bonus plans are as given in the following table.
| Unit Bonus Plan TUSD |
2012 | 2011 |
|---|---|---|
| 2008 | – | 786 |
| 2009 | -754 | 3,851 |
| 2010 | 760 | 7,379 |
| 2011 | 2,116 | 4,350 |
| 2012 | 3,083 | – |
| 5,205 | 16,366 |
LTIP awards are recognised in the fi nancial statements prorata over their vesting period. The total carrying amount for the provision for the Unit Bonus Plan including social costs as at 31 December 2012 amounted to TUSD 11,972 (TUSD 17,343). The provision is calculated based on Lundin Petroleum's share price at the balance sheet date. The closing share price at 31 December 2012 was SEK 149.50.
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 Offi cer, the Chief Operating Offi cer, the Chief Financial Offi cer and the Senior Vice President Operations) consisting of a grant of phantom options exercisable after fi ve 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 instalments: (i) fi rst on the date immediately following the fi fth anniversary of the date of grant and (ii) second on the date which is one year following the date of the fi rst 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 fi fth 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 fi fth 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 purchased 6,882,638 of its own shares up to 31 December 2010 at an average cost of SEK 46.51 per share to mitigate against the exposure of the LTIP. The Lundin Petroleum share price at 31 December 2012 was SEK 149.50. The provision for LTIP amounted to MUSD 64.0 including social charges as at 31 December 2012 and the market value of these shares held at 31 December 2012 was MUSD 158.2. The gain in the value of the own shares held cannot be off set against the cost for the LTIP in the fi nancial statements in accordance with accounting rules.
LTIP awards are recognised in the fi nancial statements prorata over their vesting period. The total carrying amount for the provision for the Phantom Option Plan including social costs as at 31 December 2012 amounted to TUSD 63,988 (TUSD 52,951). The provision is calculated based on Lundin Petroleum's share price at the balance sheet date using the Black and Scholes method applied to the portion of the awards recognised at the balance sheet date.
The non-cash charge in relation to the LTIP for Executive Management amounted to TUSD 9,058 (TUSD 44,900), including social costs for the fi nancial year ended 31 December 2012.
For further details regarding the Phantom Option Plan, please see the pages 60-61 of the Corporate Governance report.
| TUSD | 2012 | 2011 |
|---|---|---|
| PwC | ||
| Audit fees | 952 | 1,065 |
| Audit related | – | 75 |
| Tax advisory services | 227 | 179 |
| Other fees | 10 | 26 |
| Total PwC | 1,189 | 1,345 |
| Remuneration to other auditors than PwC | 278 | 305 |
| Total | 1,467 | 1,650 |
Audit fees include the review of the 2012 half year report. Audit related costs include special assignments such as licence audits, PSC audits and internal control audits.
In the fi rst quarter of 2013, Lundin Petroleum entered into a three year fi xed interest rate swap, starting 31 March 2013, in respect of MUSD 500 of borrowings, fi xing the LIBOR rate at approximately 0.57 percent per annum.
OF THE PARENT COMPANY
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 762.2 (MSEK -182.4) for the fi nancial year 2012.
The operating income includes service income received from Group companies. The net result includes general and administrative expenses of MSEK 84.5 (MSEK 206.1), intra-group interest expense of MSEK 31.3 (MSEK 25.5) and a dividend received from the subsidiary Lundin Petroleum BV of MSEK 804.7 (MSEK -). The general and administrative expenses in the year are impacted by the variation in the provision for the Group's LTIP. The high cost in 2011 was a result of a signifi cant increase in the Lundin Petroleum share price. The comparative period includes fi nancial income of MSEK 6.5 for supporting certain fi nancial obligations for ShaMaran Petroleum.
The fi nancial statements of the Parent Company are prepared in accordance with accounting policies generally accepted in Sweden, applying RFR 2 issued by the Swedish Financial Reporting Board and the Annual Accounts Act (SFS 1995:1554). RFR 2 requires the Parent Company to use similar accounting policies as for the Group, i.e. IFRS to the extent allowed by RFR 2. The Parent Company's accounting policies do not in any material respect deviate from the Group policies, see pages 87–91.
FOR THE FINANCIAL YEAR ENDED 31 DECEMBER
| Expressed in TSEK | Note | 2012 | 2011 |
|---|---|---|---|
| Operating income | |||
| Other operating income | 1 | 70,956 | 42,644 |
| Gross profi t | 70,956 | 42,644 | |
| General, administration and depreciation expenses | -84,533 | -206,108 | |
| Operating loss | -13,577 | -163,464 | |
| Result from fi nancial investments | |||
| Financial income | 2 | 807,074 | 6,560 |
| Financial expenses | 3 | -31,266 | -25,495 |
| 775,808 | -18,935 | ||
| Profi t before tax | 762,231 | -182,399 | |
| Income tax expense | 4 | – | – |
| Net result | 762,231 | -182,399 |
| Expressed in TSEK | Note | 2012 | 2011 |
|---|---|---|---|
| Net result | 762,231 | -182,399 | |
| Other comprehensive income | – | – | |
| Total comprehensive income | 762,231 | -182,399 | |
| Total comprehensive income attributable to: | |||
| Shareholders of the Parent Company | 762,231 | -182,399 | |
| 762,231 | -182,399 |
| Expressed in TSEK | Note | 2012 | 2011 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Shares in subsidiaries | 11 | 7,871,847 | 7,871,947 |
| Receivables from group companies | 21,370 | – | |
| Total non-current assets | 7,893,217 | 7,871,947 | |
| Current assets | |||
| Prepaid expenses and accrued income | 2,675 | 1,144 | |
| Other receivables | 5 | 18,023 | 7,810 |
| Cash and cash equivalents | 1,080 | 3,849 | |
| Total current assets | 21,778 | 12,803 | |
| TOTAL ASSETS | 7,914,995 | 7,884,750 | |
| EQUITY AND LIABILITIES | |||
| Restricted equity | |||
| Share capital | 3,179 | 3,179 | |
| Statutory reserve | 861,306 | 861,306 | |
| Total restricted equity | 864,485 | 864,485 | |
| Unrestricted equity | |||
| Other reserves | 2,489,380 | 2,551,805 | |
| Retained earnings | 3,753,687 | 3,936,086 | |
| Net profi t | 762,231 | -182,399 | |
| Total unrestricted equity | 7,005,298 | 6,305,492 | |
| Total equity | 7,869,783 | 7,169,977 | |
| Non-current liabilities | |||
| Provisions | 6 | 36,403 | 36,403 |
| Payables to Group companies | – | 673,988 | |
| Total non-current liabilities | 36,403 | 710,391 | |
| Current liabilities | |||
| Trade payables | 1,035 | 1,171 | |
| Accrued expenses and prepaid income | 7 | 7,356 | 2,742 |
| Other liabilities | 418 | 469 | |
| Total current liabilities | 8,809 | 4,382 | |
| TOTAL EQUITY AND LIABILITIES | 7,914,995 | 7,884,750 | |
| Pledged assets | 9 | 11,911,649 | 12,333,233 |
| Contingent liabilities | 9 | – | – |
| Expressed in TSEK | 2012 | 2011 |
|---|---|---|
| Cash fl ow from operations | ||
| Net result | 762,231 | -182,399 |
| Dividend | -804,746 | – |
| Other non-cash items | 78,793 | 207,410 |
| Interest expenses paid | – | -332 |
| Unrealised exchange losses | 716 | 138 |
| Changes in working capital: | ||
| Change in current assets | -10,844 | -1,779 |
| Change in current liabilities | 4,461 | -10,118 |
| Total cash fl ow from operations | 30,611 | 12,920 |
| Cash fl ow from investments | ||
| Change in long-term fi nancial fi xed assets | 100 | – |
| Total cash fl ow from investments | 100 | – |
| Cash fl ow from fi nancing | ||
| Change in long-term liabilities | 29,129 | -15,702 |
| Purchase of own shares | -62,425 | – |
| Total cash fl ow from fi nancing | -33,296 | -15,702 |
| Change in cash and cash equivalents | -2,585 | -2,782 |
| Cash and cash equivalents at the beginning of the year | 3,849 | 6,735 |
| Currency exchange diff erence in cash and cash equivalents | -184 | -104 |
| Cash and cash equivalents at the end of the year | 1,080 | 3,849 |
FOR THE FINANCIAL YEAR ENDED 31 DECEMBER
| Restricted Equity | Unrestricted equity | |||||
|---|---|---|---|---|---|---|
| Expressed in TSEK | Share capital 1 |
Statutory reserve |
Other reserves 2 |
Retained earnings |
Net result |
Total 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 | – | – | – | – | -182,399 | -182,399 |
| 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 | – | – | – | – | 762,231 | 762,231 |
| Transactions with owners | ||||||
| Purchase of own shares | – | – | -62,425 | – | – | -62,425 |
| Total transactions with owners | – | – | -62,425 | – | – | -62,425 |
| Balance at 31 December 2012 | 3,179 | 861,306 | 2,489,380 | 3,753,687 | 762,231 | 7,869,783 |
Lundin Petroleum AB's issued share capital at 31 December 2012 amounted to SEK 3,179,106 represented by 317,910,580 shares with a quota value of SEK 0.01 each. Included in the number of shares issued at 31 December 2012 are 7,368,285 shares which Lundin Petroleum holds in its own name.
2 From 1 January 2006, the additional paid in capital has been included in other reserves as well as currency diff erences on loans to subsidiaries.
OF THE PARENT COMPANY
| TSEK | 2012 | 2011 |
|---|---|---|
| Norway | 42,181 | 19,401 |
| Indonesia | 320 | 2,270 |
| Tunisia | 8,214 | 4,827 |
| Malaysia | 18,538 | 15,601 |
| Other | 1,704 | 545 |
| 70,956 | 42,644 |
| TSEK | 2012 | 2011 |
|---|---|---|
| Dividend | 804,746 | – |
| Guarantee fees | 1,577 | 6,472 |
| Foreign exchange gain | 716 | – |
| Other | 35 | 88 |
| 807,074 | 6,560 |
| TSEK | 2012 | 2011 |
|---|---|---|
| Interest expenses Group | 31,218 | 24,979 |
| Interest expense non-Group | – | 332 |
| Foreign exchange losses, net | – | 138 |
| Other | 48 | 46 |
| 31,266 | 25,495 |
| TSEK | 2012 | 2011 |
|---|---|---|
| Net result before tax | 762,231 | -182,399 |
| Tax calculated at the corporate tax rate in Sweden (26.3%) |
-200,467 | 47,971 |
| Tax eff ect of dividend not taxable | 211,648 | – |
| Tax eff ect of expenses non-deductible for tax purposes |
-8,917 | -35,674 |
| Increase unrecorded tax losses | -2,264 | -12,297 |
| Tax credit/charge | – | – |
| TSEK | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Due from Group companies | 17,238 | 7,291 |
| VAT receivable | 784 | 267 |
| Others | – | 252 |
| 18,023 | 7,810 |
Provisions as at 31 December 2012 amounted to TSEK 36,403 (TSEK 36,403) and related to corporate income tax.
| TSEK | 31 December 2012 | 31 December 2011 |
|---|---|---|
| Social security charges | – | 349 |
| Directors fees | 424 | 194 |
| Audit | 184 | 942 |
| Travel | 1,020 | 575 |
| Other | 5,728 | 682 |
| 7,356 | 2,742 |
The accounting policies for fi nancial instruments have been applied to the line items below:
| TSEK | Loan receivables and other receivables |
Financial liabilities valued at amortised cost |
|---|---|---|
| Assets | ||
| Receivables from Group companies – Non-current |
21,370 | – |
| Other receivables due from Group companies - Current |
17,238 | – |
| Cash and cash equivalents | 1,080 | – |
| 39,688 | – | |
| Liabilities | ||
| Trade Payables | – | 1,035 |
| – | 1,035 |
Pledged assets relate to the accounting value of the pledge of the shares in respect of the new fi nancing facility entered into by its fully-owned subsidiary Lundin Petroleum BV. Please see Group Note 27 and 28 for details.
| TSEK | 2012 | 2011 |
|---|---|---|
| PwC | ||
| Audit fees | 1,416 | 1,424 |
| Audit related | – | – |
| 1,416 | 1,424 |
There has been no remuneration to other auditors than PwC.
OF THE PARENT COMPANY
| Total number | Book amount | Book amount | |||||
|---|---|---|---|---|---|---|---|
| TSEK | Registration number | Registered offi ce | of shares issued |
Percentage owned |
Nominal value per share |
31 December 2012 |
31 December 2011 |
| Directly owned | |||||||
| Lundin Petroleum BV | 27254196 | The Hague, Netherlands | 181 | 100 | EUR 100.00 | 7,871,847 | 7,871,847 |
| Lundin Energy AB | 556619-2299 | Stockholm, Sweden | 10,000,000 | 100 | SEK 0.01 | – | 100 |
| 7,871,847 | 7,871,947 | ||||||
| Indirectly owned | |||||||
| Lundin Norway AS | 986 209 409 | Lysaker, Norway | 4,930,000 | 100 | NOK 100.00 | ||
| Lundin Netherlands BV | 24106565 | The Hague, Netherlands | 6,000 | 100 | EUR 450.00 | ||
| Lundin Netherlands Facilities BV | 27324007 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Holdings SA | 442423448 | Montmirail, France | 1,853,700 | 100 | EUR 10.00 | ||
| - Lundin International SA | 572199164 | Montmirail, France | 1,721,855 | 99.86 | EUR 15.00 | ||
| - Lundin Gascogne SNC | 419619077 | Montmirail, France | 100 | 100 | EUR 152.45 | ||
| Ikdam Production SA | 433912920 | Montmirail, France | 4,000 | 100 | EUR 10.00 | ||
| Lundin Exploration BV | 27273727 | The Hague, Netherlands | 180 | 100 | EUR 100.00 | ||
| Lundin SEA Holding BV | 27290568 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Malaysia BV | 27306815 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Indonesia Holding BV | 27290577 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Baronang BV | 27314235 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Cakalang BV | 27314288 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Gurita BV | 27296469 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Lematang BV | 24262562 | The Hague, Netherlands | 40 | 100 | EUR 450.00 | ||
| - Lundin Oil & Gas BV | 24262561 | The Hague, Netherlands | 40 | 100 | EUR 450.00 | ||
| - Lundin Rangkas BV (under liquidation) | 27314247 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Sareba BV | 24278356 | The Hague, Netherlands | 40 | 100 | EUR 450.00 | ||
| - Lundin South Sokang BV | 27324012 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin South East Asia BV (under liquidation) |
27290262 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Cambodia BV (under liquidation) | 27292990 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Russia BV | 27290574 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Russia Services BV | 27292018 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Russia Ltd. | 656565-4 | Vancouver, Canada | 55,855,414 | 100 | CAD 1.00 | ||
| - Culmore Holding Ltd | 162316 | Nicosia, Cyprus | 1,002 | 100 | CYP 1.00 | ||
| - Lundin Lagansky BV | 27292984 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Mintley Caspian Ltd | 160901 | Nicosia, Cyprus | 5,000 | 70 | CYP 1.00 | ||
| - LLC PetroResurs | 1047796031733 | Moscow, Russia | 1 | 100 | RUR 10,000 | ||
| - Lundin Komi BV | 53732561 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Tunisia BV | 27284355 | The Hague, Netherlands | 180 | 100 | EUR 100.00 | ||
| Lundin Marine BV (under liquidation) | 27275508 | The Hague, Netherlands | 180 | 100 | EUR 100.00 | ||
| - Lundin Marine SARL (under liquidation) | 06B090 | Pointe Noire, Congo | 200 | 100 | FCFA 5,000 | ||
| Lundin Petroleum SA | 660.0.330.999-0 | Collonge-Bellerive, Switzerland |
1,000 | 100 | CHF 100.00 | ||
| Lundin Services BV | 27260264 | The Hague, Netherlands | 180 | 100 | EUR 100.00 | ||
| Lundin Ventures XVII BV | 53732855 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Ventures XVIII BV | 55709532 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Ventures XIX BV | 55709362 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 |
During 2012 the 100 percent investments in Lundin Energy AB and Lundin Vietnam BV were liquidated.
Lundin Marine BV, Lundin Marine SARL, Lundin South East Asia BV, Lundin Rangkas BV and Lundin Cambodia BV were under liquidation as at 31 December 2012.
At 9 April 2013, the Board of Directors and the President of Lundin Petroleum AB have adopted this annual report for the fi nancial year ended 31 December 2012.
The Board of Directors and the President & CEO certify that the annual fi nancial report for the Parent Company has been prepared in accordance with generally accepted accounting principles in Sweden and that the consolidated accounts have been prepared in accordance with IFRS as adopted by the EU and give a true and fair view of the fi nancial position and profi t of the Company and the Group and provides a fair review of the performance of the Group's and Parent Company's business, and describes the principal risks and uncertainties that the Company and the companies in the Group face.
Stockholm, 9 April 2013
Lundin Petroleum AB (publ) Org. Nr. 556610-8055
Ian H. Lundin Chairman
C. Ashley Heppenstall President & CEO
Lukas H. Lundin Board Member
William A. Rand Board Member
Magnus Unger Board Member
Asbjørn Larsen Board Member
Kristin Færøvik Board Member
| Income Statement Summary (TUSD) | 2012 | 2011 | 2010 | 2009 | 2008 |
|---|---|---|---|---|---|
| Continuing operations | |||||
| Operating income | 1,345,142 | 1,269,515 | 798,599 | 571,835 | 628,939 |
| Production costs | -172,474 | -193,104 | -157,065 | -155,311 | -198,269 |
| Depletion | -191,444 | -165,138 | -145,316 | -118,128 | -95,046 |
| Exploration costs | -168,480 | -140,027 | -127,534 | -134,792 | -110,023 |
| Impairment costs of oil and gas properties | -237,490 | – | – | -644,766 | -78,572 |
| Gross profi t | 575,254 | 771,246 | 368,684 | -481,162 | 147,029 |
| Gain on sale of assets | – | – | 66,126 | 4,589 | 20,481 |
| General, administration and depreciation expenses | -31,722 | –67,022 | -40,960 | -27,619 | -19,684 |
| Operating profi t/(loss) | 543,532 | 704,224 | 393,850 | -504,192 | 147,826 |
| Result from fi nancial investments | -21,281 | 25,433 | -12,507 | 29,559 | -110,121 |
| Result from share in associated company | – | – | – | -25,504 | 4,480 |
| Profi t/(loss) before tax | 522,251 | 729,657 | 381,343 | -500,137 | 42,185 |
| Tax | -418,401 | -574,413 | -251,865 | -45,669 | -40,824 |
| Net result from continuing operations | 103,850 | 155,244 | 129,478 | -545,806 | 1,361 |
| Discontinued operations | |||||
| Net result from discontinued operations | – | – | 368,992 | 8,737 | 59,042 |
| Net result | 103,850 | 155,244 | 498,470 | -537,069 | 60,403 |
| Net result attributable to the shareholders of the Parent Company |
108,161 | 160,137 | 511,875 | -411,268 | 93,958 |
| Net result attributable to non-controlling interest | -4,311 | -4,893 | -13,405 | -125,801 | -33,555 |
| NET RESULT | 103,850 | 155,244 | 498,470 | -537,069 | 60,403 |
| Balance Sheet Summary (TUSD) | 2012 | 2011 | 2010 | 2009 | 2008 |
|---|---|---|---|---|---|
| Tangible fi xed assets | 2,913,813 | 2,345,354 | 2,014,242 | 2,556,275 | 2,704,556 |
| Other non-current assets | 44,105 | 44,080 | 129,944 | 119,093 | 259,515 |
| Current assets | 335,808 | 298,004 | 284,950 | 275,290 | 272,619 |
| TOTAL ASSETS | 3,293,726 | 2,687,438 | 2,429,136 | 2,950,658 | 3,236,690 |
| Shareholders' equity | 1,182,405 | 1,000,882 | 920,416 | 1,141,658 | 1,462,442 |
| Non-controlling interest | 67,648 | 69,424 | 77,365 | 95,555 | 179,793 |
| Total equity | 1,250,053 | 1,070,306 | 997,781 | 1,237,213 | 1,642,235 |
| Provisions | 1,204,625 | 987,993 | 769,687 | 897,622 | 779,370 |
| Non-current liabilities | 406,744 | 226,324 | 476,671 | 558,327 | 555,626 |
| Current liabilities | 432,304 | 402,815 | 184,997 | 257,496 | 259,459 |
| TOTAL SHAREHOLDERS' EQUITY & LIABILITIES | 3,293,726 | 2,687,438 | 2,429,136 | 2,950,658 | 3,236,690 |
Key fi nancial data is based on continuing operations.
| Financial data (TUSD) | 2012 | 2011 | 2010 | 2009 | 2008 |
|---|---|---|---|---|---|
| Operating income | 1,345,142 | 1,269,515 | 798,599 | 571,835 | 628,939 |
| EBITDA | 1,144,061 | 1,012,063 | 603,450 | 392,324 | 414,794 |
| Net result | 103,850 | 155,244 | 129,478 | -545,806 | 1,361 |
| Operating cash fl ow | 831,366 | 676,201 | 573,380 | 384,511 | 444,923 |
| Data per share (USD) | |||||
| Shareholders' equity per share | 3.81 | 3.22 | 2.96 | 3.64 | 4.67 |
| Operating cash fl ow per share | 2.68 | 2.17 | 1.84 | 1.23 | 1.41 |
| Cash fl ow from operations per share | 2.64 | 2.88 | 1.79 | 1.56 | 1.92 |
| Earnings per share | 0.35 | 0.51 | 0.46 | -1.34 | 0.11 |
| Earnings per share fully diluted | 0.35 | 0.51 | 0.46 | -1.34 | 0.11 |
| EBITDA per share | 3.68 | 3.25 | 1.93 | 1.25 | 1.31 |
| Dividend per share | – | – | 2.30 | – | – |
| 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 | 310,542,295 | 311,027,942 | 311,027,942 | 313,420,280 | 313,420,280 |
| Weighted average number of shares for the period | 310,735,227 | 311,027,942 | 312,096,990 | 313,420,280 | 315,682,981 |
| Share price |
| Quoted price at period end (SEK) | 149.50 | 169.20 | 83.65 | 56.60 | 28.07 |
|---|---|---|---|---|---|
| Quoted price at period end (CAD) | 22.87 | 24.54 | N/A1 | N/A1 | N/A1 |
| Key ratios (%) | |||||
|---|---|---|---|---|---|
| Return on equity | 9 | 15 | 12 | -38 | – |
| Return on capital employed | 35 | 53 | 24 | -28 | 9 |
| Net debt/equity ratio | 30 | 15 | 36 | 40 | 35 |
| Equity ratio | 38 | 40 | 41 | 42 | 51 |
| Share of risk capital | 66 | 69 | 67 | 66 | 71 |
| Interest coverage ratio | 75 | 59 | 19 | -37 | 7 |
| Operating cash fl ow/interest ratio | 119 | 55 | 27 | 26 | 51 |
| Yield | – | – | 18 | – | – |
The share is listed on the Toronto Stock Exchange from 24 March 2011.
EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortisation): Operating profi t before depletion of oil and gas properties, exploration costs, impairment costs, depreciation of other tangible assets and gain on sale of assets.
Operating cash fl ow: Operating income less production costs and less current taxes.
Shareholders' equity per share: Shareholders' equity divided by the number of shares in circulation at period end.
Operating cash fl ow per share: Operating cash fl ow divided by the weighted average number of shares for the period.
Cash fl ow from operations per share: Cash fl ow from operations in accordance with the consolidated statement of cash fl ow 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 any dilution eff ect.
EBITDA per share: EBITDA divided by the weighted average number of shares for 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: Profi t before tax plus interest expenses plus/less exchange diff erences on fi nancial 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 fi nancial items plus interest expenses plus/less exchange diff erences on fi nancial loans divided by interest expenses.
Operating cash fl ow/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 period.
| Proved and probable | Total | Norway | France | Netherlands | Malaysia | Tunisia | Russia |
|---|---|---|---|---|---|---|---|
| oil reserves | Mbbl | Mbbl | Mbbl | Mbbl | Mbbl | Mbbl | Mbbl |
| 1 January 2011 | 157,081 | 117,478 | 22,310 | 86 | – | 514 | 16,693 |
| Changes during the year | |||||||
| – acquisitions | 4,037 | 4,037 | – | – | – | – | – |
| – sales | – | – | – | – | – | – | – |
| – revisions | 19,206 | 16,585 | 2,252 | -9 | – | -116 | 494 |
| – extensions and discoveries | 12,934 | 11,500 | 1,314 | – | – | 120 | – |
| – production | -10,250 | -7,720 | -1,118 | – | – | -268 | -1,144 |
| 31 December 2011 | 183,008 | 141,880 | 24,758 | 77 | – | 250 | 16,043 |
| 2012 | |||||||
| Changes during the year | |||||||
| – acquisitions | 4,073 | 4,073 | – | – | – | – | – |
| – sales | – | – | – | – | – | – | – |
| – revisions | -5,756 | 2,460 | 143 | 18 | – | -209 | -8,168 |
| – extensions and discoveries | 12,713 | – | – | – | 12,713 | – | – |
| – production | -10,568 | -8,501 | -1,040 | -2 | – | -41 | -984 |
| 31 December 2012 | 183,470 | 139,912 | 23,861 | 93 | 12,713 | – | 6,891 |
| Proved and probable | Total | Norway | Netherlands | Indonesia | |||
| gas reserves | MMscf1 | MMscf | MMscf | MMscf | |||
| 1 January 2011 | 177,433 | 130,298 | 21,226 | 25,909 | |||
| Changes during the year | |||||||
| – acquisitions | – | – | – | – | |||
| – sales | – | – | – | – | |||
| – revisions | -10,013 | -11,182 | 1,067 | 102 | |||
| – extensions and discoveries | 10,230 | 7,100 | 3,130 | – | |||
| – production | -11,421 | -4,587 | -4,275 | -2,559 | |||
| 31 December 2011 | 166,229 | 121,629 | 21,148 | 23,452 | |||
| 2012 | |||||||
| Changes during the year | |||||||
| – acquisitions | 893 | – | 893 | – | |||
| – sales | – | – | – | – | |||
| – revisions | -43,807 | -42,317 | 3,782 | -5,272 | |||
| – extensions and discoveries | – | – | – | – | |||
| – production 31 December 2012 |
-14,893 108,422 |
-8,522 70,790 |
-4,156 21,667 |
-2,215 15,965 |
The Company has used a factor of 6,000 to convert one scf to one boe.
Of the total proved and probable oil and gas reserves as at 31 December 2012, 36 Mbbl (37 Mbbl) are attributable to non-controlling shareholders of other subsidiaries of the Group.
The reserves as at 31 December 2012 have been certifi ed by the independent qualifi ed reserves auditor, ERC-Equipoise Ltd. (ERCE).
Lundin Petroleum will publish the following interim reports:
» 6 November 2013 Nine month report (January – September 2013)
The reports are available on www.lundin-petroleum.com in Swedish and English directly after public announcement.
The Annual General Meeting (AGM) is held within six months from the close of the financial year. All shareholders who are registered in the shareholders' registry and who have duly notified their intention to attend the AGM may do so and vote in accordance with their level of shareholding. Shareholders may also attend the AGM through a proxy and a shareholder shall in such a case issue a written and dated proxy. A proxy form is available on www.lundin-petroleum.com.
Lundin Petroleum's AGM is to be held on Wednesday, 8 May 2013 at 13.00 (Swedish time). Location: Vinterträdgården, Grand Hotel, Södra Blasieholmshamnen 8 in Stockholm.
Shareholders wishing to attend the meeting shall:
When registering please indicate your name, social security number/ company registration number, registered shareholding, address and day time telephone number.
Shareholders whose shares are registered in the name of a nominee must temporarily register the shares in their own names in the shareholders' register to be able to attend the meeting and exercise their voting rights. Such registration must be effected by Thursday 2 May 2013.
For more information regarding the Company's business, visit www. lundin-petroleum.com where you can fi nd corporate, investor, press and media information as well as details on Lundin Petroleum's global operations, corporate governance and corporate responsibility.
MMbtu Million British thermal units
| Barrel (1 barrel = 159 litres) | CHF | Swiss Franc |
|---|---|---|
| Billion cubic feet (1 cubic foot = 0.028 m3 ) |
CAD | Canadian Dollar |
| Billion | EUR | Euro |
| Barrels of oil equivalents | GBP | British Pound |
| Barrels of oil equivalents per day | NOK | Norwegian Kroner |
| Barrels of oil per day | RUR | Russian Rouble |
| Billion barrels of oil equivalents | SEK | Swedish Kroner |
| Thousand barrels | USD | US Dollar |
| Thousand barrels of oil | TCHF | Thousand CHF |
| Thousand barrels of oil equivalents | TSEK | Thousand SEK |
| Thousand barrels of oil equivalents per day | TUSD | Thousand USD |
| Million barrels of oil | MSEK | Million SEK |
| Million barrels of oil equivalents | MUSD | Million USD |
| Million barrels per day | ||
| Million barrels of oil per day | ||
| Thousand cubic feet | ||
| Thousand cubic feet per day | ||
| Million standard cubic feet | ||
| Million standard cubic feet per day | ||
For further defi nitions of oil and gas terms and measurements vist www.lundin-petroleum.com
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 forward-looking statements and refl ect 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 diff er 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 this release 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 fi nancial 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 diff er materially from those expressed or implied by such forward-looking statements. Forward-looking statements included in this new release are expressly qualifi ed by this cautionary statement.
Unless otherwise stated, Lundin Petroleum's reserve and resource estimates are as at 31 December 2012, 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 in this Annual Report are the aggregate of "Proved Reserves" and "Probable Reserves", together also known as "2P Reserves". For further information on reserve and resource classifi cations, see "Reserves, Resources and Production" on pages 12 to 17.
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.
The Company is a reporting issuer in certain Canadian jurisdictions. However, the Company is a "designated foreign issuer" as defi ned in National Instrument 71-102 Continuous Disclosure and Other Exemptions Relating to Foreign Issuers, and is subject to foreign regulatory requirements, including those of the NASDAQ OMX Stockholm. As such, the Company is exempt from certain requirements otherwise imposed on reporting issuers in Canada.
Lundin Petroleum AB (publ) Hovslagargatan 5 SE-111 48 Stockholm Sweden Telephone: +46-8-440 54 50 Telefax: +46-8-440 54 59 E-mail: [email protected]
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