Annual Report • Apr 12, 2015
Annual Report
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Annual Report 2014
| Our business model | 2 |
|---|---|
| Performance 2014 | 4 |
| Forecast 2015 | 5 |
| Chief Executive Officer's review – C. Ashley Heppenstall | 6 |
| Chairman's statement – Ian H. Lundin | 8 |
| Sustainable growth | 10 |
| Oil market | 12 |
| Share and shareholders | 14 |
| Finding and developing resources | 16 |
| Reserves, resources and production | 18 |
| Developing resources | 24 |
|---|---|
| Norway | 26 |
| South East Asia | 34 |
| Continental Europe | 38 |
| Risk management | 40 |
|---|---|
| Overview | 44 |
|---|---|
| People | 46 |
| Health and safety | 48 |
| Environment | 50 |
| Stakeholder engagement | 52 |
| Corporate governance report 2014 | 54 |
|---|---|
| ---------------------------------- | ---- |
| Contents of financial report | 75 |
|---|---|
| Directors' report of the Group | 76 |
| Financial tables of the Group | 89 |
| Accounting policies | 94 |
| Notes to the financial statements of the Group | 100 |
| Annual accounts of the Parent Company | 121 |
| Financial tables of the Parent Company | 121 |
| Notes to the financial statements of the | |
| Parent Company | 124 |
| Board assurance | 126 |
| Auditor's report | 127 |
| Key financial data | 128 | ||
|---|---|---|---|
| Key ratio definitions | 129 | ||
| Five year financial data | 130 | ||
| Reserve quantity information | 131 | ||
| Definitions and abbreviations | 132 | ||
| HSE indicator data | 133 | ||
| Share data | 134 | ||
| Shareholder information | 135 | ||
| i | |||
Lundin Petroleum has a global portfolio of assets with two core areas located in Norway and South East Asia
and is active in all stages of the life cycle of an upstream oil and gas company
Russia
Norway
Continental Europe
South East Asia
with a focus on generating value for all our stakeholders
Lundin Petroleum's business model is to generate sustainable value throughout the value chain
Lundin Petroleum's strategy of organic growth involves identifying core areas of focus and then establishing a team of professionals with experience in those areas to use the latest technologies to explore for oil and gas. Discoveries will be appraised, and where they are deemed to be economic, progressed through the development phase and into the production stage. The cash flow generated from production will be reinvested in exploration and development and when appropriate, a portion will be returned to shareholders. 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 positive results in the future.
Our vision is to grow a profitable upstream exploration and production company, focused on core areas in a safe and environmentally responsible manner for the long-term benefit of our shareholders and society.
Lundin Petroleum is pursuing the following strategy:
Lundin Petroleum is responsible towards:
Lundin Petroleum focuses on building core exploration areas in specific countries with the clear objective to grow organically. The strategy is to improve the technical understanding and thereby to develop new play concepts. This is achieved by using the best available technology including acquiring and processing 3D seismic and by building multi-disciplined teams of talented and experienced people who are encouraged to think creatively and to challenge conventional theories in the search for new oil discoveries.
Lundin Petroleum focuses on organically increasing its reserves base. Following exploration and appraisal, sustainable value is created through the conversion of discoveries into reserves and production. The strategy is to continuously optimise reserves and production throughout the life cycle of the asset by utilising the latest technologies and, above all, the expertise of skilled people.
Throughout all stages of the business cycle, Lundin Petroleum seeks to deliver outstanding value to its shareholders. All elements of the asset portfolio are constantly reviewed to determine that their value is fully reflected in the Lundin Petroleum share price. If it is determined that the value of an asset is not being fully reflected within the share price, Lundin Petroleum will review all available options to determine how to realise the asset's full value.
· Average Brent oil price USD 99/boe · Cost of operations USD 10.9/boe · EBITDA MUSD 671.3 · Operating cash flow MUSD 1,138.5 · Net result MUSD -431.9
| · Fatalities |
0 |
|---|---|
| · Oil spills |
2 |
| · Lost time incidents (LTI) |
7 |
| · LTI rate |
0.25 1 |
1 per 200,000 hours
We are very excited with the potential in the southern Barents Sea following our Gohta and Alta discoveries
C. Ashley Heppenstall President and CEO
We saw oil prices fall further at the beginning of 2015 where spot Brent was trading around USD 50 per barrel. It has become very clear that OPEC or more particularly Saudi Arabia is pursuing a policy to maintain market share. They are attempting, and I believe will be successful, in forcing high cost producers, particularly North American shale oil producers, to curtail production growth. There is currently a lot of uncertainty as to how long a period of low oil prices it will take to balance supply with demand and indeed where oil prices will trade during this period. I personally believe we were close to the bottom at the beginning of 2015 but there is certainly a possibility that we may see oil prices go even lower.
Our current producing and development assets as well as Johan Sverdrup will all generate value to shareholders at current oil prices but I believe strongly that the majority of our industry does not have a sustainable future if oil prices remain for the long-term at these levels. I do believe that one of the positives that will come out of this down cycle will be an industry wide focus on cost levels and a serious attempt to introduce more standardisation and efficiency. However I think that will be insufficient to sustain a viable industry at today's prices. In terms of new greenfield oil development projects Johan Sverdrup is probably one of the few that will still go ahead based upon current prices. We should remember that this is one of the five largest discoveries ever made in Norway and it will be at the bottom of the cost curve because of its sheer size and favourable location.
Oil prices will recover as they have in previous cycles. Current oversupply which is estimated at up to two million barrels per day represents only about two percent of demand. This oversupply will be eroded and oil prices will recover in the medium to long-term.
Lundin Petroleum is well prepared to weather the storm and will come out of this cycle as a stronger and much more valuable company. We are generating positive cash flow even at low oil prices due to our low cash operating costs and negligible cash taxes. Our production growth will ensure that our operating cash flow grows despite lower commodity prices. Our balance sheet is strong. We continue to have access to third party bank funding supported particularly by our long reserve life Norwegian asset base. We have approved a 2015 budget which predominantly focuses on the completion of our
development projects in Norway and Malaysia as well as an appraisal and exploration drilling programme on our core Utsira High and southern Barents Sea areas. However we are not complacent and will constantly review our expenditure plans in light of how markets develop.
Our objective is to deliver sustainable financial returns to our shareholders. It is obviously disappointing that the impact of unsuccessful exploration, asset impairment and non-cash foreign exchange losses resulted in a financial loss in 2014. But I am encouraged that our business continues to be cash generative with EBITDA and operating cash flow of USD 670 million and USD 1.14 billion respectively despite the reduction in oil prices.
Our production for 2014 was 24,900 boepd as compared to our guidance of 24,000 to 29,000 boepd. We were in the lower half of the range due to delays to production start-up at the Brynhild field.
I am pleased that the Brynhild and Bøyla fields, offshore Norway have now commenced production. And with the Bertam and Edvard Grieg development projects due to come onstream in the second and fourth quarter of this year we are forecasting 2015 production of between 41,000 and 51,000 boepd with a 2015 exit rate of over 75,000 boepd. It is very encouraging to see our production rates starting to increase again and I remain confident in our target to triple production over the course of 2015.
We are making good progress with the Bertam and Edvard Grieg development projects which both remain on schedule. I recently travelled to South East Asia where Bertam is on track for first oil in the second quarter of 2015. The Bertam FPSO refurbishment is now complete and the vessel has sailed from Singapore to the Bertam field for final hook up and installation. The jacket and topsides have already been successfully installed and completed development wells are ready to commence production. Similarly we are on schedule to load out the completed Edvard Grieg topsides in the spring for offshore installation. Hook up and commissioning will be completed during the summer prior to first oil in the fourth quarter 2015. I believe both projects are today substantially de-risked: procurement and construction are substantially complete, operations teams are ready and development drilling is ongoing.
The plan of development for Johan Sverdrup was delivered to the Norwegian Government on 13 February 2015. This was a major milestone not only for Lundin Petroleum but for the
Norwegian offshore industry. We have always believed since our initial discovery of Johan Sverdrup back in 2010 that we had something very special. The size, quality and location of this asset are unique and will be the cornerstone of our Company's growth for many years to come.
In today's oil price environment there is little focus from the markets on exploration assets. Indeed many view them as a liability. We however continue to believe in higher medium term oil prices and as such the key to create long-term value will remain access to resources. We do believe the best way to do this is through an organic growth model driven by exploration drilling.
We are very excited with the potential in the southern Barents Sea following our Gohta and Alta discoveries. We will appraise the Alta discovery in 2015 and drill exploration wells to test nearby prospectivity. I believe that as the major licence holder in this area we will find significant additional oil resources and ultimately this will act as a catalyst for the development of this region. We are taking a long-term view which in the future will deliver value from this region for our shareholders. It is critical that exploration continues in the region despite current markets.
Our objectives for 2015 are very clear. We will deliver on our promise of project execution by bringing the Bertam and Edvard Grieg fields onstream to meet our year end production target. The Johan Sverdrup development project will be sanctioned and will secure a pipeline of further production growth for our Company of in excess of 150,000 boepd. The potential of the southern Barents Sea will be tested through our summer appraisal and exploration drilling programme. We will manage the liquidity constraints of whatever oil price the market throws at us to ensure the long-term value of our business is preserved.
Finally we will continue to do this in a way which takes account of preserving our environment, the health and safety of all our stakeholders and which fulfils our stated goal of being a responsible corporate citizen.
Yours Sincerely,
C. Ashley Heppenstall President and CEO
The Johan Sverdrup field will be the largest development project ever undertaken in the Norwegian North Sea and will represent some 40 percent of total oil production from the Norwegian Continental Shelf
Ian H. Lundin Chairman of the Board
The low oil price environment may be of great economic benefit to millions of people around the world. However, only in the short-term. We must not let this situation reduce the importance of developing accessible and affordable energy for generations to come. Without sufficient quantities of energy, the world would look quite different today.
It has been estimated that roughly ten times as much energy, mostly in the form of fossil fuels, is required to produce, process, transport and refrigerate food than there is energy in the food itself. A massive quantity of oil and other fossil fuels is also required for cars to run, planes to fly and trucks, trains and ships to deliver goods on a daily basis. Oil and gas are further prime raw materials for many everyday goods that we take for granted, from plastics to clothing. Even electronics depend on petroleum; a two gram computer chip requires approximately 32 litres of water and 1.6 kg of fossil fuel to be produced.
Energy consumption is directly related to population growth and standards of living. If the world's population grows to ten billion by the end of the century, as expected, and the global standard of living rises to half of the developed world's standard of living, the world's need for energy is estimated to have to increase by a factor of four compared to current levels.
The good news is that we are making rapid technological improvements in fuel efficiency and in renewable energy, mainly solar and wind power. However, for the foreseeable future, fossil fuels will continue to make up over 75 percent of the world's total energy consumption. Another five to ten percent of the total energy consumption will be made up of biofuels, mainly wood, which are the only cooking and heating fuels for millions of people living outside the power grid. Solar and wind power should reach these people before the grid does, nevertheless, their hunger for energy will grow faster than the world average as their living standards improve.
There will be a substitute for fossil fuels eventually, even if only by pure economic necessity. Nuclear energy is one area where technology is playing a major role in improving safety and lowering production costs. Fusion could be an answer for further energy needs. There is also the so called "green" atom, thorium, which may one day replace uranium as nuclear fuel without the same disposal issues. In the meantime, it is important to utilise our limited reserves of fossil fuels in the
most efficient and sustainable way possible. At Lundin Petroleum, we believe that conducting operations in an economically, socially and environmentally responsible manner simply constitutes good business practice that benefits the Company, its stakeholders and society at large.
On 13 February 2015, Lundin Petroleum, together with its partners Statoil (operator), Maersk Oil, Det norske oljeselskap and Petoro, submitted a plan for development and operation (PDO) for Phase 1 of the Johan Sverdrup field to the Norwegian Ministry of Petroleum and Energy. The Johan Sverdrup field will be the largest development project ever undertaken in the Norwegian North Sea and will represent some 40 percent of total oil production from the Norwegian Continental Shelf. The submission of the PDO was a major milestone for Lundin Petroleum and for the future of the Norwegian Continental Shelf.
I would also like to highlight the significant contribution that Torstein Sannes has made in successfully taking our business in Norway to where it stands today. Torstein has led Lundin Norway since inception in 2004 to its current position as the leading independent operator on the Norwegian Continental Shelf. Torstein has had an eminent career, from the US to Norway, in which he always inspired and motivated people working with him to do their best. I am very pleased that Torstein will continue to be of guidance to Lundin Norway as Kristin Færøvik will take over as Managing Director in April of this year. We are pleased to welcome back Kristin, who previously served on the Board of Lundin Petroleum and who has an excellent reputation in the industry as a strong leader for major projects. She has the right skill set to take Lundin Norway through its next phase of growth.
In Malaysia, the next milestone is first oil from the Bertam field, which we expect to occur within schedule and budget.
Finally I would like to thank all our employees for their hard work and dedication. Lundin Petroleum is now in a stronger position than it has ever been with a great future ahead.
Ian H. Lundin Chairman of the Board
World Energy Demand
World Oil Demand by Sector
Source: IEA WEO 2014
Oil and gas products are fundamental to modern societies and are present in many aspects of our daily life. Oil continues to be the fuel of choice for power and transportation as well as component for asphalt, pharmaceuticals, plastics and many synthetic products and consumer goods.
Oil remains the primary source of world energy consumption and is estimated to remain so for decades to come. The world's annual oil consumption currently amounts to roughly 32 billion barrels. Put into context, this corresponds to more than 12 Johan Sverdrup discoveries per year.
The current level of oil supply can only be maintained by increasing production from existing discoveries; by using new methods and technology to develop oil deposits or by making new oil discoveries.
Making new discoveries is Lundin Petroleum's core competence. The oil discoveries that the Company has made in Norway will not only prolong the country's oil production but will also supply the world with oil for the next 50 years.
An oil discovery is a great economic resource which creates wealth and jobs, benefiting not only Lundin Petroleum's employees, their families, and the Company's shareholders but also local communities and society as a whole.
Lundin Petroleum operates in the oil and gas industry which requires a long-term perspective. On one hand, the Company generates income when oil is produced. The exploration and development phases, on the other hand, require large investments. Drilling and construction of facilities and infrastructure are particularly costly. The investment budget for Lundin Petroleum in 2015 has been set at USD 1.75 billion.
One of Lundin Petroleum's main financial contributions to society comes through taxes, paid in the form of corporate and production tax on sales proceeds from oil and gas production. In Norway, for example, the petroleum production tax is set at 78 percent. The giant Johan Sverdrup discovery made by Lundin Petroleum is expected to generate more than USD 150 billion in tax revenues during the life of the field.
Lundin Petroleum not only adheres to applicable legislation, but is also committed to conduct its business in accordance with best industry practice and principles for corporate citizenship embodied in reliable and recognised international initiatives. The Company has integrated corporate responsibility commitments and strategies into its business through the adoption of relevant policies, guidelines and procedures and strives for continuous improvement.
Due to the nature of oil and gas operations, Lundin Petroleum has a strong focus on putting in place and developing a robust health, safety and environmental (HSE) framework. Policies on health, safety and the environment set out the Company's commitment in this area, and the HSE Management System (Green Book) ensures these policies translate into good practice.
Lundin Petroleum's staff worldwide are trained in the application of the Company's Code of Conduct, Corporate Responsibility policies, and the Green Book to ensure understanding and compliance.
In order to increase the scale and impact of Lundin Petroleum's sustainable investment projects, the Company entered into a partnership with the Lundin Foundation in 2013. The Lundin Foundation is a philanthropic organisation founded originally by the Lundin family.
more information on the Lundin Foundation i can be found on page 45
Lundin Petroleum creates job opportunities across the world through direct employment and also through the various contractors and suppliers that the Company is using.
The development of the Edvard Grieg field in Norway and the Bertam field in Malaysia have generated millions of man hours in Norway and South East Asia.
There have been a number of material developments over the last few months with the fall in world oil prices and an industry which has finally woken up to the fact that the levels of cost inflation witnessed in recent years is unsustainable. At the same time the geopolitical uncertainty in the world has remained with recent events in the Middle East and Russia dominating the headlines. All of these issues directly affect our industry and impact commodity prices.
Our industry is finally recognising the level of cost inflation over recent years was unsustainable. The conclusion was clearly correct and action was needed. The reaction has been that over recent months we have seen a major reduction on capital expenditure in our industry which has put pressure on the oil service sector with material reductions in activity. Projects are being deferred and exploration spending has been significantly reduced with many companies reducing drilling activity in 2015. Unfortunately I think that reductions in work programmes are not necessarily the answer and will only result in negative impact upon supply in years to come. Our industry should focus more on standardisation and efficiency such as that achieved in the aerospace and automotive industries. We need to continue to spend money but to do that more efficiently.
At Lundin Petroleum we will continue to invest particularly on exploration as we believe this is the best way to create shareholder value.
C. Ashley Heppenstall President and CEO
The 2014 oil market turned out to be one of the most volatile the oil industry has faced in recent years. A three and a half year wave of strong oil prices finally broke in the middle of June as price levels topped out above USD 115 per barrel. No longer could economic growth from the BRICS and a resurgent US economy absorb the increased supply from non-OPEC producers, particularly the boom in US shale oil production. Between June and November oil prices fell dramatically. The decision by OPEC in late November to refrain from cutting production quotas laid the ground for a battle over market share. Further price weakness followed and by the end of 2014 oil prices were approaching USD 50 per barrel, a level not seen since early 2009.
However, well before the fall in oil prices, the oil and gas industry had begun to review investment plans, focusing on improving capital efficiency in response to cost pressures that had reached unsustainable levels.
Unsurprisingly, with the oil price drop, the industry's reaction intensified, resulting in major reductions in capital expenditure. Budget cuts of between 20 to 35 percent for 2015 compared with 2014 were common. This in turn has put pressure on the oil service sector as material reductions in activity levels follow. Projects are being deferred and exploration spending has been significantly reduced, impacting drilling and development activity levels into 2015.
Reductions in work programmes today will have a negative impact upon supply in years to come. What is less certain is how quickly supply will react to these changing dynamics, particularly US shale oil supply. We have seen significant reductions in the US rig count with a drop of around 45 percent compared with peak levels seen in 2014. Moreover, the ability of the US shale oil business to service the mountain of high yield debt that has been accumulated to fund its growth will be critical in determining how quickly capital returns when oil prices recover. This will influence price formation in the short to medium term.
However, we believe that the fundamentals remain for strong oil prices in the long run, with a growing global population and expanding economies in developing nations set to continue to provide strong support to oil demand growth.
At Lundin Petroleum we are prepared for all eventualities recognising that our low cost world class projects such as Johan Sverdrup will supply the world with oil for the next 50 years and as such will remain extremely valuable.
Like all oil and gas companies, Lundin Petroleum is impacted by commodity prices and cost levels in the industry. We have taken firm action to reduce our investment levels on discretionary projects and focus on those projects that create the most value for our shareholders. Our 2015 capital expenditure budget of USD 1.75 billion is 14 percent lower than our 2014 capital expenditure and is focused on execution of the Company's growth projects and highest impact exploration areas.
In addition Lundin Petroleum has a strong balance sheet with access to multiple sources of liquidity and can as a result withstand lower oil prices for long periods of time.
However, our business model and continued success is primarily driven by the ability to increase the Company's resource base. Operating in the oil and gas industry requires a long-term perspective and that is why we will continue to invest in developing the Company's discoveries as well as maintaining our exploration focus while managing our balance sheet prudently during times of uncertainty and lower oil prices.
Pursuing an exploration led organic growth strategy that minimises the cost of adding new resources to our portfolio allow us to create long-term shareholder value. Our focus on Norway, with a stable political environment, targeting conventional resources, in relatively shallow waters allows us to minimise our after tax cost of finding new resources. Our track record also demonstrates our success. Lundin Petroleum has been the most successful exploration company in Norway in the past ten years with average after tax finding costs of USD 0,59 and world class discoveries made such as Johan Sverdrup (1.7 to 3.0 billion boe) and Edvard Grieg (~200 MMboe).
With this combination of an exploration driven strategy, in large focused core areas, targeting conventional resource plays, we are strategically very well positioned to minimise the full cycle cost of developing new resources that ultimately creates value for our shareholders.
Second largest acreage holder in Malaysia
Peer Group Comparison
The Lundin Petroleum share is listed on the Large Cap list of Nasdaq Stockholm and is part of the OMX 30 index. Notwithstanding the lower oil price environment in 2014, the Lundin Petroleum share decreased by only 11 percent compared to a decrease of 18 percent for the S&P Global Oil Index.
Lundin Petroleum's market capitalisation as at 31 December 2014 was MSEK 34,964.
During the year a total of 354 million shares were traded on Nasdaq Stockholm to a value of approximately SEK 42 billion, representing a daily average of 1.4 million shares. As a result of minimal trading activity the Lundin Petroleum share was voluntarily delisted from the Toronto Stock Exchange in November 2014, where it had been listed since 2011.
The registered share capital as at 31 December 2014 amounted to SEK 3,179,106 represented by 311,070,330 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 15 May 2014 resolved to authorise the Board of Directors to decide on the repurchase and sale of Lundin Petroleum shares during the period until the next AGM. During the year Lundin Petroleum purchased a further 500,000 of its own shares at an average price of SEK 124.07. Following a 2014 AGM resolution, the Company also reduced its share capital with an amount of SEK 68,402.50 through the cancellation of 6,840,250 shares held in treasury. The reduction of the share capital was followed by a bonus issue of the same amount and in consequence the cancellation of shares did not impact the Company's share
capital. This resulted in a minor change in the quota value of each share as no new shares were issued. At 31 December 2014 the Company holds 2,000,000 of its own shares.
The maximum number of shares that can be repurchased and held in treasury from time to time cannot exceed five 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 its long-term incentive programmes.
During the 2014 AGM 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 effect 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 profitable operations and growth. This will be achieved by increased hydrocarbon reserves, developing discoveries and thereby increasing production and ultimately cash flow 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 financial position and the possibilities for growth through profitable investments. Dividends will be paid when Lundin Petroleum generates sufficient cash flow and operating income from operations to maintain long-term financial strength and flexibility. Over time the total return to shareholders is expected to transfer from an increase in share price to dividends received.
of the Lundin Petroleum share
5 Year Share Price 2010–2014
Lundin Petroleum had 45,668 shareholders as at 31 December 2014. The proportion of shares held by Swedish retail investors amounted to 13 percent. Foreign investors held 68 percent of the shares. The top 10 shareholder list excludes shareholdings through nominee accounts.
| The 10 largest shareholders as at 31 December 2014 |
Number of shares |
% |
|---|---|---|
| Lorito Holdings (Guernsey) Ltd.1 | 76,342,895 | 24.5 |
| Swedbank Robur fonder | 13,786,661 | 4.4 |
| Blackrock | 11,640,470 | 3.7 |
| Landor Participations Inc.2 | 11,538,956 | 3.7 |
| Zebra Holdings and Investment (Guernsey) Ltd.1 |
10,844,643 | 3.5 |
| Handelsbanken fonder | 5,402,255 | 1.7 |
| Danske Invest Sverige | 4,380,449 | 1.4 |
| Fjärde AP fonden | 3,358,713 | 1.1 |
| Norges Bank | 2,972,550 | 1.0 |
| Andra AP fonden | 2,875,013 | 0.9 |
| Other shareholders | 167,927,725 | 54.0 |
| Total | 311,070,330 | 100.00 |
1 An investment company wholly owned by a Lundin family trust.
2 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.
| Size categories | Numbers of shareholders |
Percentage of shares,% |
|---|---|---|
| 1–500 | 32,036 | 1.65 |
| 501–1,000 | 6,046 | 1.64 |
| 1,001–10,000 | 6,499 | 6.25 |
| 10,001–50,000 | 731 | 5.16 |
| 50,001–100,000 | 115 | 2.64 |
| 100,001–500,000 | 166 | 12.1 |
| 500,001– | 75 | 70.56 |
| Total | 45,668 | 100.00 |
| 31 Dec 2014 | 31 Dec 2013 | |
|---|---|---|
| Number of shares issued | 311,070,330 | 317,910,580 |
| Number of shares owned by Lundin Petroleum |
2,000,000 | 8,340,250 |
| Number of shares in circulation | 309,070,330 | 309,570,330 |
Shareholder Structure – Sector
Shareholder Structure – Geographical
Source: IPREO, November 2014
Lundin Petroleum has exploration and production assets focused upon two core areas, Norway and South East Asia, as well as assets in France, the Netherlands and Russia. Lundin Petroleum maintains an exploration focus seeking to generate sustainable value through exploration success and also has the resources to take exploration successes through to the production phase.
Lundin Petroleum has a proven track record in finding new oil and gas resources.
The Company's strategy of building core exploration areas in specific countries and assembling integrated teams of geologists, geophysicists and technical experts to develop new play concepts has proved very successful. The teams are encouraged to have a creative way of analysing information and thereby adapting a visionary approach to oil and gas exploration. This approach has been successful, for example, in the opening of a new play concept on the Utsira High, offshore Norway, which resulted in the discovery of the Edvard Grieg and the giant Johan Sverdrup fields. This new play concept had been overlooked by previous operators in the area since the 1960s.
The technical teams develop exploration prospects using the best available technology including acquiring and processing 3D seismic. The prospects are risked and ranked in terms of chance of geological success and size potential.
The best prospects are matured to form part of the drilling sequence. Lundin Petroleum drilled 16 exploration and appraisal wells in 2014, finding new resources in the southern Barents Sea with the Alta discovery. The Company has plans to drill 14 exploration and appraisal wells in 2015.
32 production 8 exploration
1 exploration licence
Based on the results from its exploration and appraisal drilling, Lundin Petroleum creates a 3D simulation model of the reservoir as accurately as possible. Thereafter the Company establishes a conceptual development plan.
The plan sets out how to best manage the reservoir for production. It includes a programme for how to extract hydrocarbons as efficiently as possible from the reservoir, a plan for the engineering and design of all surface and subsurface facilities as well as infrastructure to deliver the resources. The development plan also details all safety procedures and ensures that the environmental impact will be minimal.
Lundin Petroleum uses the best available technologies throughout this process in order to minimise all risks. Once a conceptual development plan has been approved by partners and it is demonstrated that resources can be recovered commercially, the resources in the field may be reclassified as reserves. Contracts can then be awarded for drilling, construction and installation of all facilities. During the construction phase Lundin Petroleum works closely with its partners and contractors with the common objective to deliver the components on schedule and within budget.
The installation phase involves transporting the facilities that have been constructed to a chosen location and assembling them on site. Thereafter, wells and infrastructure are connected to the facilities and production can begin.
Lundin Petroleum is currently constructing oil and gas production facilities in Norway and Malaysia.
After exploration, appraisal and development, Lundin Petroleum enters into the production phase. The production phase is defined as everything from extraction and processing to delivering the oil or gas for sale.
Lundin Petroleum uses the income from its production assets to finance its core activity, the exploration of new oil and gas resources. However, as the Edvard Grieg and Johan Sverdrup discoveries are developed and put into production, the focus on production operations will become more prominent. The Brynhild field and the Bøyla field, offshore Norway have recently been brought onstream. With first oil from the Bertam and Edvard Grieg projects planned in 2015, Lundin Petroleum's oil and gas production is expected to reach over 75,000 boepd by the end of the year.
Whereas Lundin Petroleum's exploration model is based on creativity and innovative analysis of geological information, its production operations rely upon proven methods in the industry with the use of best available technology and best practice. Lundin Petroleum aims to efficiently produce from each field and maximise the total quantity of oil or gas produced from the field. This requires thorough analysis during the development and production phase and can involve enhanced recovery methods, for example injecting water to sweep the oil towards selected production points.
The Company places great emphasis on safety. Operations are carried out with human, technical and organisational barriers in place, so that a breach of a single barrier cannot alone lead to any harm to people, the environment or the Company's assets.
Lundin Petroleum has a substantial portfolio of certified reserves in addition to a number of discovered oil and gas resources
Reserves
i
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".
Contingent Resources Unless otherwise stated, all contingent resource estimates in this Annual Report are unrisked best estimate.
End 2014 Reserves (MMboe)
| Reserves Summary | MMboe |
|---|---|
| Reserves end 2013 | 201.5 |
| 2014 Production | -9.1 |
| Sale of Russian onshore assets | -5.6 |
| Reserves additions (excluding sales/acquisitions) | 8.2 |
| Reserves end 2014 | 187.5 |
Oil price (Brent) USD 70/bbl in 2015, thereafter USD 90/bbl + 2% escalation on oil price and costs
Lundin Petroleum had 187.5 million barrels of oil equivalent (MMboe) of reserves at the end of 2014, excluding the Johan Sverdrup discovery. This is net of the Russian onshore assets that were sold in July 2014. From 2002 to 2014 Lundin Petroleum increased its reserves base four fold (see Reserves History graph).
In 2014, 8.2 MMboe of new reserves were identified, resulting in a five percent increase in reserves compared to 2013. This excludes production of 9.1 MMboe in 2014.
The Reserves Changes graph shows reserves additions related to the inclusion of the Viper/Kobra accumulations within the Alvheim field and the inclusion of one infill well on the Volund field, both located offshore Norway. The reserves have been further positively impacted by the inclusion of a unitised interest in the Ivar Aasen field which will ultimately be produced via the Edvard Grieg platform. The increase in reserves resulted in a reserves replacement ratio of 90 percent at the end of 2014 when compared to the total production of 9.1 MMboe in 2014.
92 percent of the 187.5 MMboe of reserves is related to oil and natural gas liquids (NGL). 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 are classified as contingent resources. Contingent resources are known oil and gas resources not yet classified as reserves due to one or more contingencies. Work is continuously ongoing to remove these contingencies and to mature contingent resources into reserves and ultimately production.
With the Alta discovery in the southern Barents Sea, Lundin Petroleum has materially increased its contingent resource base in the Loppa High. When combined with the Gohta discovery from 2013, located only 20 km from Alta, Lundin Petroleum's net contingent resources in this core area are 140 MMboe, which is predominantly oil.
There was an 18 percent year on year increase in the contingent resource base, driven by the Alta discovery. Other revisions relate to resource re-assessments following appraisal drilling on Luno II and Gohta in Norway, and on Tembakau in Malaysia. Lundin Petroleum also acquired an additional 10 percent in PL359 which contains the Luno II field.
1 excluding Johan Sverdrup
Matured Johan Sverdrup contingent resources will increase Lundin Petroleum reserves nearly four fold
The field will represent some 40 percent of total oil production from the NCS
1 based on WI 22.12% subject to governmental approval
Phase 1 development work can provide some 51,000 man-years of work in Norway; 2,700 man-years in the production phase
One of the biggest ever oil discoveries on the NCS
Lundin Petroleum's business model is to grow organically through exploration. This means to identify and mature exploration targets, drill exploration wells, appraise discoveries, develop and finally produce. To be successful with this strategy, access to world class exploration acreage and first class people is essential. Lundin Petroleum has focused upon two core exploration areas, Norway and South East Asia.
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 identified from the large exploration licence portfolio and are being matured to be drilled in future years.
In Norway, Lundin Petroleum has grown to become one of the largest operated acreage holders and has been the most successful explorer in the last 10 years. By the end of 2014, Lundin Petroleum has drilled a total of 41 exploration wells, resulting in 16 commercial discoveries at a cumulative finding cost of USD 0.59 per boe. Lundin Petroleum was awarded another eight new licences in the 2014 APA licensing round, increasing its total licence acreage to approximately 23,000 km2 . In 2015, Lundin Petroleum is planning to drill seven exploration wells in Norway, two of which are located in the southern Barents Sea.
Since South East Asia was established as a core area in 2008, Lundin Petroleum has a total of 13 Production Sharing Contracts (PSC) in Malaysia and Indonesia. In Malaysia, Lundin Petroleum has grown to become the second largest acreage holder after Petronas, with a total gross licence acreage of approximately 40,000 km2 . In 2015, two exploration wells are planned to be drilled in Malaysia.
2014 Exploration Drilling Performance net prospective resources 1 0 100 200 300 400 500 600 MMboe Pre drill unrisked total Pre drill risked total Post drill resources found
1 excludes Rengas (moved to 2015) and Maligan (not drilled)
2 Costs include cumulative exploration and appraisal costs since inception up to 31 December 2014. Discovered resources assume year end 2014 remaining 2P reserves for Edvard Grieg, Volund, Gaupe, Bøyla and Brynhild. For Gaupe and Volund cumulative production up to 31 December 2014 is also included in reserves. Brynhild 2P reserves have been adjusted for 50% ownership at the time of making the discovery. Johan Sverdrup contingent resources have been estimated by Lundin Petroleum. Gohta, Alta and Luno II contingent resources included as per third party certification.
During 2014, Lundin Petroleum produced 9.1 MMboe at an average rate of 24,900 boepd. In early 2014, production for the full year was forecast to be between 30,000 and 35,000 boepd. So for the first time in six years the production performance was below guidance, which was driven by the delay of the Brynhild project, offshore Norway, coming onstream and to a lesser extent by the sale of the onshore Russian assets in mid-2014. Excluding the impact of Brynhild and Russia, the remaining assets produced within guidance. This was a net result of the strong performance from the Alvheim field, in particular from the Kneler and Boa accumulations, which was offset by the lower than expected performance from the Volund field where water cut build was faster than foreseen. The water cut trends at Volund have since stabilised and the reserves assessment at year end 2014 showed that the ultimate recoverable volume estimates were not materially impacted by the under performance during 2014.
Lundin Petroleum's production forecast for 2015 is in the range of 41,000 to 51,000 boepd. The growth compared to 2014 is a direct result of the start-up of four new development projects, two of which are already onstream. Production from the Brynhild field started in late December 2014 from two production wells, with the remaining production well and injector to be completed in 2015.
Production from the Bøyla field started in early January 2015 from one production well supported by one water injector. The second and final production well is expected to come onstream by mid-2015. The Bertam field development is progressing well with production expected to start in the second quarter of 2015. Combined with the Edvard Grieg development, which is forecast to come onstream in the fourth quarter of 2015, these projects are expected to increase Lundin Petroleum's total production levels to in excess of 75,000 boepd by year end 2015.
The giant Johan Sverdrup oil field is planned to start production in late 2019 and is expected to increase 2014 production levels more than fivefold, when reaching plateau production. This excludes any contribution from the significant contingent resource base, or any contribution from the exploration wells that Lundin Petroleum is planning to drill.
2014 Production Performance
2014 adjusted forecast low excluding Brynhild and Russia
Through Lundin Petroleum's close to 15 year history, the Company has weathered several oil price cycles, during which it has continued to invest in its assets. Lundin Petroleum's exploration success has resulted in four fields moving into the development phase over the last three years and by the end of 2015 all four fields will have commenced production
Svalbard
· Production start in Q4 2015
· Johan Sverdrup discovered in 2010 in PL501 and in 2011 in PL265
| Greater Alvheim Area | |||
|---|---|---|---|
| Alvheim Field (WI 15%) |
Volund Field (WI 35%) |
Bøyla Field (WI 15%) |
|
| · Net reserves 19.1 MMboe | · Net reserves 8.2 MMboe | · Bøyla discovery in 2009 | |
| · Gross ultimate recovery 319 MMboe | · Gross ultimate recovery 76 MMboe | · Caterpillar discovery in 2011 | |
| · 2014 net production 9,670 boepd | · 2014 net production 7,360 boepd | · PDO approved in 2012 | |
| · 15 producing wells, 9 multilaterals | · Net reserves 3.4 MMboe | ||
| · 3 new infill wells to be drilled in 2015–2016 | · Production commenced January 2015 |
· Appraisal well drilled on Gohta – gross contingent resources 91–184 MMboe
· Alta gross contingent resources 125–400 MMboe · 2 Alta appraisal wells to be drilled in 2015
Gohta and Alta Discoveries
· Gohta discovery in 2013
· Alta discovery in 2014
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 potential new core areas. Lundin Petroleum holds close to 70 licences in Norway, with activities across exploration, appraisal, development and production, positioning the Company as one of the largest licence holders in the country and second most active explorer behind Statoil. Since Lundin Petroleum's entry into Norway in 2003, the Company has participated in 41 exploration wells and 29 appraisal wells leading to more than 3 billion barrels of gross discovered resources or 800 million barrels net to Lundin Petroleum. These wells have yielded 16 commercial or potentially commercial discoveries of which four have been put into production, excluding the Alvheim field which was acquired.
During 2014 Lundin Petroleum drilled a total of six exploration wells adding 89 MMboe of new resources through its exploration efforts with an after tax finding cost of USD 0.8 per boe, excluding appraisal costs. Lundin Petroleum's cumulative finding cost from inception to year end 2014 remains one of the best among its peer group with an after tax finding cost of USD 0.6 per boe including all exploration and appraisal costs.
The breakthrough discoveries of Edvard Grieg in 2007 in the Utsira High and Gohta and Alta in 2013 and 2014 in the Loppa High have established these respective licence positions offshore Norway as Lundin Petroleum's core exploration areas.
Lundin Petroleum is currently developing two fields, Edvard Grieg and the giant Johan Sverdrup, as well as evaluating the commerciality of numerous discoveries, most notably Alta, Gohta and Luno II. During 2015 Lundin Petroleum will continue its efforts to commercialise its discoveries by drilling three appraisal wells, two of which are located on the Alta discovery on the Loppa High with the remaining well being drilled on Edvard Grieg in the Utsira High. Furthermore, the Company continues its pursuit of organic growth in Norway by drilling seven exploration wells that will test 500 MMboe of net unrisked prospective resources in 2015. During 2014, the Norwegian assets produced at an average production rate of 17,600 boepd. Production in Norway for 2015 is set to increase significantly with the Brynhild field (WI 90%) that came onstream in December 2014, the Bøyla field (WI 15%) that came onstream in January 2015 and the Edvard Grieg field scheduled to come onstream during the fourth quarter of 2015.
| Norway Key Data | 2014 | 2013 |
|---|---|---|
| Reserves (MMboe) | 149 | 147 |
| Contingent Resources (MMboe) | 207 | 134 |
| Average production per day (Mboepd), net | 18 | 24 |
| Net Turnover (MUSD) | 619 | 946 |
| Sales price achieved (USD/boe) | 94 | 106 |
| Cost of operations (USD/boe) | 7 | 7 |
| Operational cash flow contribution (USD/boe) | 154 | 99 |
Since 2007 Lundin Petroleum unlocked the Utsira High area with the Johan Sverdrup, Edvard Grieg and Luno II discoveries delivering more than 2.5 billion barrels of new resources. It was Lundin Petroleum's innovative thinking that found the key to the geological setting on the Utsira High area in 2007 with the Edvard Grieg discovery. Subsequent drilling around the Utsira High area led to the Johan Sverdrup discovery in 2010 and the Luno II discovery in 2013. Expertise gained in the area continues to generate new prospects such as the four prospects to be drilled in 2015 with a combined gross unrisked resource potential in excess of 450 MMboe. During the first quarter of 2015 the Zulu well resulted in a new gas discovery. Two wells remain to be drilled in this area in 2015 targeting the Fosen and Luno II North prospects.
Following the successful discovery of the Luno II field in 2013, further appraisal activity in 2014 confirmed 51 MMboe of gross contingent resources. Further prospects have been mapped on trend with the Luno II discovery and during 2015 one exploration well, targeting the Luno II North prospect will be drilled. Clearly any new resources discovered within close proximity to the Edvard Grieg facilities could enhance the overall value proposition of the area.
Lundin Petroleum discovered the Johan Sverdrup field in 2010 and an extensive appraisal campaign for the field, comprising 22 appraisal wells, was drilled and completed during 2014. The first of the two appraisal wells drilled in 2014 encountered excellent reservoir quality amongst the best ever recorded in the North Sea. The well flowed at a rig constrained 4,900 bopd during the drill stem test. The second appraisal well in 2014 was drilled in PL265 in the Geitungen area in the northwestern part of the field. The well came in below pre-drill expectation.
On 13th February 2015, the plan of development and operations (PDO) for Phase 1 of the Johan Sverdrup development was submitted to the Norwegian Ministry of Petroleum and Energy following the completion of the Front End Engineering and Design studies (FEED). The development plan for Phase 1 involves installing four bridge-linked platforms on steel jackets. The field centre will comprise a processing platform, a riser platform, a drilling platform and a living quarter platform. A dedicated 274 km long oil pipeline to Mongstad and a 164 km long gas pipeline to Kårstø to existing terminals on the west coast of Norway will be installed. The PDO for Phase 1 also sets out alternative development concepts for the subsequent development phases of the field which will require separate PDO's to be submitted. A unitisation agreement covering the licences PL501, PL501B, PL265 and PL502 is expected to be finalised by mid-year 2015. The full field reserves are estimated at approximately 2.35 billion boe with Lundin Petroleum's proposed net share being approximately 520 MMboe, subject to the finalisation of the unitisation agreement. The capital investment for Phase 1 is estimated at NOK 117 billion and the full field capital investment, including Phase 1, is estimated at between NOK 170 to NOK 220 billion. The field's exceptional reservoir quality leads to a very quick ramp-up of production to a plateau production level of between 315,000 and 380,000 bopd for Phase 1, scheduled to commence in late 2019, and to between 550,000 to 650,000 boepd at full field plateau with Phase 2 production forecast to commence production in 2022.
Several major contracts have already been awarded to Norwegian and international contractors. Following Statoil's signing of a letter of intent in 2014 with Kværner for delivery of the riser platform jacket and drilling platform jacket, a contract for the riser platform jacket was awarded to Kværner in January 2015. A second contract was awarded to Aker Solutions for the engineering and procurement management for the riser and processing platform topsides for Phase 1, in addition to hook-up work and gangways for the entire field.
Aibel has been awarded a contract for the construction of the deck for the drilling platform and a contract has been signed with Allseas for the heavy lifts in relation to the installation of three of the topsides for Johan Sverdrup Phase 1 development.
The Edvard Grieg field (WI 50%) was discovered by Lundin Petroleum in 2007, and the Norwegian Parliament approved the Edvard Grieg PDO in June 2012.
The field is estimated to contain 187 MMboe of gross reserves with first production expected during the fourth quarter of 2015 and forecast gross peak production of approximately 100,000 boepd. The gross capital cost of the field development is estimated at approximately NOK 26 billion which includes the building of a production and processing platform, oil and gas pipelines and the drilling of 15 wells. During 2014 the construction of the steel jacket was completed by Kværner at the Verdal yard on the west coast of Norway and the jacket was successfully installed during the summer of 2014. Kværner completed the construction of the Edvard Grieg topsides at the Stord yard on the west coast of Norway during the first quarter of 2015 and the topside is scheduled to undergo offshore installation during the second quarter of 2015 with offshore commissioning to commence immediately thereafter. The
The development of Edvard Grieg consists of constructing a platform for production and processing of oil and gas and is the first stand-alone development project operated by Lundin Petroleum on the Norwegian Continental Shelf. As part of Lundin Petroleum's firm commitment to a strong health, safety and environment performance, the Edvard Grieg platform is being designed and constructed in order to minimise the impact on the environment.
A series of innovative technical solutions have been selected for the project that will see a reduction in emissions and discharges to sea. Examples include low-NOX emission technology, waste heat recovery, flare gas recovery and gas injection. The electrification of the platform from shore, meaning that electrical power will be supplied from land via cables out to sea, is an example of a measure that will significantly reduce the emissions levels from the offshore facility. Produced water re-injection, whereby produced water is being re-injected into the reservoir after passing through a redundant treatment system which will ensure low oil content in the water, is another example of how to minimise discharges to sea. Furthermore, both living quarters and helideck will be constructed entirely in aluminium, a material that has been chosen because of its low weight, easy maintenance and for its environmental friendliness.
A new Oil Spill Detection (OSD) radar system will also be installed on the Edvard Grieg platform. This new maritime radar will be able to detect even very small oil spills, as well as recognising other sea clutter, to produce clear and effective information that can be acted upon quickly. The installation of the radar system will be the first operational system that has the ability to detect oil spills at sea within a wide range of weather conditions, including quiet and coarse sea states.
Rowan Viking jack-up rig commenced the drilling of the development wells during the summer of 2014 and the rig will continue the drilling programme throughout 2015 with a short pause during the installation of the topsides during the second quarter of 2015. The installation of the 94 km gas pipeline to the Sage Beryl gas system was completed during the third quarter 2014. In addition, the Y-connection to the Grane oil pipeline was installed in 2014 with the installation of the Edvard Grieg oil pipeline having commenced during the first quarter of 2015. An appraisal well was drilled during 2014 on the southeastern segment of the Edvard Grieg field. An additional appraisal well is planned to be drilled in the southeastern part of the field in 2015 with the potential to add up to 50 MMboe of additional resources.
In 2014 the Ivar Aasen field (WI 1.385%), which is located immediately to the north of the Edvard Grieg field, was unitised across three licences PL001b/PL242, PL338BS (WI 50%) and PL457. PL338BS, a stratigraphic carve-out of PL338 (WI 50%) was assigned a 2.77 percent unitised interest in the Ivar Aasen development giving Lundin Petroleum a net ownership in Ivar Aasen of 1.385 percent. The unitised interest is not subject to any re-determination.
The field is estimated to contain gross reserves of 188 MMboe excluding the Hanz accumulation to the north of the field. It is being developed with a steel jacket with the topside facilities consisting of a living quarter and drilling facilities with oil, gas and water separation and onward export to the Edvard Grieg platform for final processing and pipeline export. The Ivar Aasen field is forecast to come onstream during the fourth quarter of 2016.
Lundin Petroleum has one of the largest acreage positions in the southern Barents Sea, most of which covers the highly prospective Loppa High. The licence position sits on trend with Statoil's Johan Castberg discovery to the west and Lundin Petroleum's own Gohta and Alta discoveries located in the southern part of the Loppa High. Lundin Petroleum was an early mover, starting to build an acreage position in the southern Barents Sea as far back as 2007. Since then the Company has drilled seven wells which all have encountered hydrocarbons, made two oil discoveries and two gas discoveries. In total, Lundin Petroleum has operated or participated in exploration wells which have discovered in excess of 400 MMboe of contingent resources with the net resources to Lundin Petroleum amounting to in excess of 150 MMboe.
Following the exploration success in the southern Barents Sea in 2013 with the Gohta discovery in PL492 (WI 40%) Lundin Petroleum capitalised on that in 2014, with the Alta discovery in PL609 (WI 40%) just 20 km to the northeast of Gohta. The Alta discovery is estimated to contain between 125 and 400 MMboe of gross contingent resources of which the majority is oil. In total, the Gotha and Alta discoveries alone have added additional resources of between 216 and 584 MMboe. Further northwest of the Alta and Gohta discoveries is the Johan Castberg discovery made by Statoil with its estimated 550 MMboe of contingent resources. Combined Gohta, Alta and Johan Castberg could hold in excess of 1 billion boe and thus providing a sound platform for studying potential development concepts as well as improving the economic viability of the whole area. Lundin Petroleum will drill two appraisal wells on the Alta discovery in 2015 as well as one exploration well on the Neiden prospect (200 MMboe) in PL609 which is located on-trend with Alta around 50 km further north and around 20 km east of Johan Castberg. Further prospects have been identified in the area on 3D seismic data.
During 2014 Lundin Petroleum successfully appraised the Gohta discovery and is currently analysing further appraisal drilling on this 50 km2 structure.
Lundin Petroleum was awarded four new licences in the APA 2013 licensing round and one additional licence was awarded in January 2015 through the APA 2014 licensing round. Lundin Petroleum is also planning to submit licence applications for the upcoming 23rd Licensing round with acreage in the southeastern Barents Sea being offered for the first time.
The net production from the Alvheim field (WI 15%) during 2014 was 9,600 boepd, a decrease of nine percent relative to 2013. Overall, the field has outperformed expectations and its 2014 performance is no exception with continued excellent performance during the year. In addition to continued reservoir outperformance the 2014 production was further helped with two wells coming back onstream in April 2014 following workover activity. The Alvheim partners have committed to five further infill wells to be drilled through 2015 and 2016. The first of these wells commenced drilling in the fourth quarter of 2014 and is expected to commence production during the second quarter of 2015. Two further wells are planned to be drilled later in 2015 with production start-up in late 2015 or early 2016. Two wells targeting the Viper/Kobra accumulations within the area will be drilled in 2016 with production start-up targeted for late 2016. The continued excellent reservoir performance from the existing wells and the additional infill opportunities identified has led to yet another reserves upgrade for the field with the gross ultimate recoverable reserves increasing from 306 MMboe at year end 2013 to 319 MMboe at year end 2014. At the point of submitting the Alvheim PDO, the ultimate recoverable reserves were estimated to 184 MMboe. The gross best estimate contingent resources associated with the field amounted to 32.9 MMboe as at year end 2014 and represent possible infill targets for future production wells. The base cost of operations for the Alvheim field for 2014 remained low at approximately USD 5 per barrel.
The Volund field (WI 35%) achieved average net production of 7,400 boepd during 2014. The production during 2014 was impacted by higher than expected water-cut which in turn led to lower oil production due to liquid throughput constraints. An additional well commenced production in early 2013. Since the field commenced production in 2010, the reservoir performance from the field has exceeded expectations and as a result the gross ultimate recoverable reserves have increased from 50 MMboe, at the time of submitting the PDO for the field, to 81 MMboe as at year end 2014. During 2015, certain longlead items will be ordered for one additional infill well which is planned to be drilled after 2016 and the contingent resources associated with this infill target have been recognised as reserves as at year end 2014. The cost of operations for the Volund field during 2014 remained at below USD 4 per barrel.
The Bøyla field commenced production in January 2015 and has been developed as a 28 km subsea tie-back to the Alvheim FPSO with two production wells and one water injection well. One production well and one water injection well have been completed and put onstream with a second production well commencing production later in 2015.
340 340BS Caterpillar 0 KM 10 Gas Oil Fields/discoveries
The Bøyla field contains gross reserves of 23 MMboe and is estimated to achieve a gross peak production rate of 20,000 boepd.
The Brynhild field (WI 90%) commenced production in December 2014. The Brynhild field, developed as a subsea tie-back to the Pierce field in the United Kingdom, contains gross reserves of 23.1 MMboe and is expected to produce at an estimated gross plateau production rate of 12,000 boepd. All subsea installation work was completed during 2013 as well as the first of four development wells. During 2014 the second development well, the topside modification and the life extension work on the Haewene Brim FPSO were completed. The third and fourth development wells are expected to be completed during 2015. The gross capital cost for the Brynhild development is estimated at approximately NOK 8.3 billion.
Lundin Petroleum Licences
Operated Non-operated
Lundin Petroleum's activities in the southern Barents Sea as well as in all our operations are based on a solid operational track record, a knowledge-based approach and are performed according to strict operational standards that protect the health and safety of our employees and the environment.
The Barents Sea lies off the northern coast of Norway. Contrary to common perception, the southern portion of the Barents Sea, where Lundin Petroleum's exploration licences are situated offers a relatively benign operating environment. Water depths are relatively shallow and the area is ice free due to the influence of the Gulf Stream. The Norwegian Petroleum Directorate (NPD) estimates the undiscovered resource potential of the Norwegian Barents Sea to be 7.6 billion boe. The Barents Sea has been under-explored relative to the Norwegian Sea and the North Sea with only just over 100 exploration wells drilled.
The first exploration wave in the Barents Sea came after the NPD conducted a strategic mapping exercise of the hydrocarbon potential on the Norwegian shelf. That exercise resulted in a gradual opening of the Norwegian Sea and the Barents Sea in the period between 1979 and 1982. Both areas were considered to contain a diversity of play types and petroleum systems. The NPD's assessment of the resource potential in the Norwegian Sea was predominantly oil prone with some gas. In contrast, the Barents Sea was considered predominantly gas prone by the NPD with some oil potential. The major oil companies held a different view. Their focus was on the Barents Sea, where they saw predominantly oil potential. Following an initial drilling campaign in both areas, a series of oil and gas discoveries were made in the Norwegian Sea and a major gas discovery, Snøhvit, was made in the southern Barents Sea.
A second wave of exploration came from the strategic concession licensing round in 1986/1987 where the focus was on a series of large structures identified in the Barents Sea. A number of dry wells with some minor oil shows resulted from this second wave of exploration. Following this, a consensus formed within the major oil companies who believed: "Too late, the oil has leaked out during the uplift and the ice age."
A third exploration wave came from within large concessions that were awarded with substantial follow up acreage in case of breakthroughs. Limited commercial success followed, with only minor discoveries made. The exception was the very positive Goliath oil discovery.
The fourth exploration wave started in 2004 with the inclusion of the southern Barents Sea in the APA licensing rounds, combined with the introduction of new players into Norway. The result so far has been a number of very promising discoveries including Johan Castberg, Wisting, Gohta and most recently the Alta field. These breakthroughs have arisen through the application of new 3D seismic data combined with the creative thinking of geoscience experts seeking to unlock new play concepts.
Lundin Petroleum has been active in the southern Barents Sea for many years with applications and awards starting with the APA 2006 licensing round. Within Lundin Petroleum, the southern Barents Sea is considered a very promising exploration area comparable in size with the North Sea. Following the same successful strategy applied on the Utsira High, with the discovery of the Edvard Grieg and Johan Sverdrup fields, Lundin Petroleum has established a core area around the southern part of the Loppa High. The reason for the focus on the Loppa High is a belief that this area has one of the highest chances for new oil and gas accumulations.
The recent oil discoveries Johan Castberg, Wisting, Gohta and Alta have confirmed this belief and consequently new opportunities are opening up. The Johan Castberg discovery was made in PL532 in 2011 by Statoil. A distinct direct hydrocarbon indicator was targeted and the well proved oil and gas in early to middle Jurassic sandstones. The Gohta discovery was drilled in 2013 by
Lundin Petroleum in PL492 and already appraised with one additional well in 2014. The discovery and appraisal wells have confirmed the presence of oil and gas in late Permian carbonate and siliciclastic rocks. The Wisting discovery was drilled in 2013 by OMV in PL537. That well found nonbiodegraded oil in Jurassic sandstones at only a few hundred metres below the sea floor. Following Lundin Petroleum's Gohta discovery in 2013, Lundin Petroleum made another significant oil discovery in 2014 with the Alta discovery in PL609, located just northeast of the Gotha field. The Alta discovery encountered a 46 metres gross oil column and an 11 metres gross gas column and achieved a flow test rate of 3,300 bopd. These recent oil discoveries have provoked a new wave of interest for exploration in the Barents Sea area. The Gohta and Alta discoveries open up a new oil play on the Loppa High – late Permian rocks exposed to weathering processes around 250 million years ago. This play is likely to be present along the Loppa High crest and Lundin Petroleum is drilling another prospect on this play-fairway in 2015 targeting the Neiden prospect in PL609. It may also be present in other places in the southern Barents Sea where late Permian rocks have been exposed and porosity and permeability developed due to weathering.
The "fresh" oil found in reservoirs at shallow depths in the Johan Castberg and Wisting discoveries suggest that oil charge has occurred relatively recently, perhaps even during the most recent episodes of glaciation. If this is confirmed, it will significantly reduce the risk of hydrocarbon leakage through time. In addition, shallow reservoirs may exhibit good reservoir properties as a result of limited burial and sandstone diagenesis. This play may extend along the western margin of the Loppa High and northwards into the Hoop fault complex area.
PL492 was awarded to Lundin Petroleum in 2008. The main prospect in the licence, Gohta, was a large Permian four way structural closure. An exploration well was drilled down flank on the structure by Shell in 1986. The well had oil shows, however, the Permian carbonate reservoir was too tight to flow any fluids. Later detailed evaluation of the structure by Lundin Petroleum with the use of modern 3D seismic revealed that up- dip from the well the Permian carbonates had been exposed to erosion and thereby rain water. Rain water was slightly acidic in the Permian era leading to partial dissolution of the carbonates, known as karstification. The result is that a tight carbonate rock can be transformed into a porous reservoir rock. The Gohta exploration well was drilled by Lundin Petroleum in 2013 to test this concept and it proved to be correct. A successful drill stem test (DST) was conducted, flowing more than 4,000 barrels of non-degraded oil per day. The Alta prospect was mapped on the same play type as the Gohta prospect. The Alta structure was drilled in 2014 and resulted in a discovery and is estimated to hold between 125 and 400 MMboe of recoverable resources with 74 percent being oil. Numerous prospects have been mapped further north in PL609 on the same play fairway and the first of these prospects, Neiden, will be drilled in 2015 in addition to two appraisal wells being drilled on the Alta discovery.
After a long-standing dispute, the Norwegian and Russian authorities agreed on the border line between Norway and Russia in 2010. The Norwegian government has announced that the acreage in the southeastern Barents Sea will be made available for exploration in the upcoming 23rd licensing round with licence awards expected in 2015. During 2014 a group of companies, including Lundin Petroleum, have shot advanced 3D seismic over the area to be offered for licensing in the 23rd Licensing round.
| Malaysia Key Data | 2014 | 2013 |
|---|---|---|
| Reserves (MMboe) | 14 | 14 |
| Contingent resources (MMboe) | 72 | 82 |
| · PM307 (WI 75%) Bertam field |
|---|
| – Net reserves 14 MMboe |
– Field development plan approved in 2013 – Facilities installation completed and
Peninsular Malaysia Area Sabah Area
· SB303 (WI 75%) 4 existing gas discoveries on Block – possible cluster development
| Indonesia Key Data | 2014 | 2013 | |
|---|---|---|---|
| Reserves (MMboe) | 1 | 2 | |
| Contingent Resources (MMboe) | 2 | 3 | the Sareba Block in 2014 |
| Average production per day (Mboepd), net | 1 | 2 | |
| Net Turnover (MUSD) | 22 | 17 | |
| Sales price achieved (USD/boe) | 48 | 33 | |
| Cost of operations (USD/boe) | 11 | 9 | |
| Operational cash flow contribution (USD/boe) | 33 | 24 |
· Lematang (WI 25.9%) Singa gas field – net reserves 1.4 MMboe – Improved gas sales price, USD 7.97/MMbtu, escalating 3% per annum · Cendrawasih VII (WI 100%) acquired offshore east Indonesia in a swap with
· Joint study area on Cendrawasih VIII (WI 100%) signed in 2014
Lundin Petroleum is pursuing an organic growth strategy in South East Asia and has over recent years been successful in Malaysia in making several gas discoveries and one commercial oil discovery through the drilling of 12 exploration and appraisal wells. Lundin Petroleum holds seven Production Sharing Contracts (PSC) in Malaysia and six PSCs in Indonesia. During 2014 the Tembakau gas discovery in Malaysia was appraised and the commercial viability of the discovery is being assessed. The Bertam oil field, offshore Peninsular Malaysia is being developed and the field is planned to commence production during the second quarter of 2015.
Lundin Petroleum is holding acreage in two core areas offshore Malaysia with five PSCs offshore Peninsular Malaysia and two PSCs offshore east Malaysia in the Sabah area. Oil fields are producing from both these areas and Lundin Petroleum holds oil reserves offshore Peninsular Malaysia and gas contingent resources in both areas.
In 2014, Lundin Petroleum has substantially completed the Bertam oil field development on Block PM307 (WI 75%). The Bertam field was successfully appraised by Lundin Petroleum in 2012 and the field's Plan for Development was submitted and approved during 2013. The Bertam development consists of a wellhead platform and 14 development wells producing to a spread moored FPSO. During 2014 the wellhead platform was successfully installed, and the development drilling campaign commenced in September 2014 and is expected to conclude in late 2015. An upgrade and life extension programme on the Bertam FPSO, which is owned 100 percent by Lundin Petroleum, commenced in late 2013 in the Keppel shipyard in Singapore. The refurbishment work was successfully completed in early 2015 and the vessel was successfully moored and hooked-up to the wellhead platform during the first quarter of 2015.
First oil from the Bertam field is scheduled to commence during the second quarter of 2015 with a gross plateau rate of 15,000 bopd and the field is estimated to contain gross reserves of 18.4 MMboe.
During 2014, Lundin Petroleum appraised the Tembakau gas discovery on PM307 (WI 75%). The appraisal well tested gas from two intervals at a combined rate of 31.7 million cubic feet per day (MMcfd) and the Tembakau discovery is estimated to contain gross contingent resources of 231 billion cubic feet (bcf). Commercialisation of the Tembakau discovery will require higher gas prices than those currently being realised offshore Peninsular Malaysia as a result of the link to oil prices.
Lundin Petroleum farmed into Block PM328 (WI 50%) during 2014 and has assumed operatorship. Block PM328 is located to the northeast of PM307 and spans 5,600 km2 . The initial PSC term is for three years where Lundin Petroleum has to acquire 600 km2 of 3D seismic within the first 18 months.
Two exploration wells are planned to be drilled on PM307 during 2015, targeting the Rengas and Mengkuang oil prospects.
Lundin Petroleum has made three gas discoveries offshore Sabah with the Tarap, Cempulut and Berangan gas discoveries on Block SB303 (WI 75%). Commercialisation will require access to higher gas prices. Collectively these discoveries contain gross contingent gas resources of 347 bcf.
During 2014, Lundin Petroleum drilled one exploration well offshore Sabah on Block SB307/SB308 (WI 42.5%) targeting the Kitabu prospect. The well, which was drilled four km to the north of the producing South Furious 30 oil field, failed to encounter any hydrocarbons. From 3D seismic Lundin Petroleum has mapped numerous additional prospects on SB307/SB308 and is currently in the process of high-grading the prospect inventory in this region to identify drillable prospects.
Lundin Petroleum has six PSCs in Indonesia and one joint study area. In total, Lundin Petroleum has gross acreage of approximately 23,000 km2 in Indonesia and also holds a non-operated interest in a producing gas field, onshore Sumatra.
Lundin Petroleum has a 25.88 percent, non-operated, working interest in the gas producing field Singa, onshore Sumatra. Production from the Singa field during 2014 was below expectation due to certain facility issues and a shut-in to re-route the gas pipeline to enhance gas export. In January 2014, a revised gas sales agreement was put in place, resulting in an increased gas sales price of 7.97 per million British Thermal Units. The gas price is escalating three percent per annum. The Singa field has net gas reserves of 1.4 MMboe based on a PSC expiring in 2017. The forecast production extending beyond 2017 has been classified as contingent resources, estimated to contain 2.1 MMboe, net.
Lundin Petroleum has four PSCs in the Natuna Sea area with 90 percent working interest in the Cakalang, Baronang and Gurita PSCs, and 60 percent operated working interest in the South Sokang PSC. Lundin Petroleum drilled three exploration wells in the Natuna Sea in 2014. Two wells were drilled on the Baronang PSC targeting the Balqis and Boni prospects and one well was drilled on the Gurita PSC targeting the Gobi prospect. None of the wells encountered any hydrocarbons and were plugged and abandoned as dry. The Baronang and Cakalang PSCs are in the process of being relinquished.
Lundin Petroleum holds one PSC offshore Papua, covering the Cendrawasih VII Block (WI 100%), and during 2014 entered into a joint study area for the Cendrawasih VIII Block (WI 100%) which is adjacent to the Cendrawasih VII Block. Lundin Petroleum is currently conducting technical studies on these two Blocks and further seismic acquisitions are planned during 2015.
In 2014, major projects such as Bertam in Malaysia required a strong HSE management in order to be successfully implemented. At the Keppel shipyard in Singapore where the Bertam FPSO vessel was refurbished with zero lost time incidents and only one recordable incident over a period of 17 months and with onsite personnel ranging from 100 to 1,200 daily. This exceptional performance was the result of a strong HSE stewardship, which included recruitment of new staff to strengthen existing HSE teams, selection of contractors with strong HSE credentials and a dedicated HSE officer that conducted on-site supervision during the entire duration of the work.
The excellent safety performance on the Bertam FPSO refurbishment demonstrates the importance of communicating the Company's HSE commitment and expectations to all contractors, and the value of exercising a close and constructive supervision of the work that is being conducted at all times.
Lundin Petroleum's fast-track development of the Bertam field in Malaysia was delivered on time and on budget
| 2011 | 2012 | 2013 | 2014 | 2015 | |
|---|---|---|---|---|---|
| Q1 Q2 |
Q3 Q4 |
Q1 Q2 Q3 Q4 |
Q1 Q2 Q3 Q4 |
Q1 Q2 Q3 Q4 |
Q1 Q2 Q3 Q4 |
| 3D Seismic PM307 signed |
Bertam well | PDO Approval | First steel cut | First Oil |
Lundin Petroleum farmed into PM307 and assumed operatorship in May 2011. Within a matter of weeks, an extensive 3D seismic survey of 2,100 km2 had been acquired and within six months of entering the Block, the Bertam field was successfully appraised. By early 2012, the field was declared commercial with concept selection studies being finalised by the end of 2012. The redeployment of the Ikdam FPSO (renamed Bertam FPSO), to serve as the host facility, allowed for an accelerated project execution schedule. Following PDO approval in the third quarter of 2013, work commenced on the wellhead platform and on the FPSO upgrade and life extension during the fourth quarter of 2013. With a project completion in less than 18 months from PDO approval, the Bertam project marks a pace setting performance in terms of project execution. None of this would have been possible without the strong support and guidance from Petronas and our partner Petronas Carigali, in addition to the efficient project execution by our major contractors TH Heavy Engineering (THHE) and Keppel Shipyard.
UNITED KINGDOM Mature assets in France and the Netherlands provide the Company with stable oil and gas production which commands a high sales price and low cash operating costs thus resulting in high operating cash flow generation
NETHERLANDS
North Sea
BELGIUM GERMANY
Onshore
Offshore
Lundin Petroleum continues to extend the life of its mature assets in France and the Netherlands that provide the Company with stable oil and gas production.
The French assets consist of mature onshore oil producing fields in the Paris Basin, operated by Lundin Petroleum, and mature onshore oil producing fields in the Aquitaine Basin, operated by Vermilion. The assets in the Netherlands consist of mature onshore and offshore gas producing fields operated by Vermilion, GDF Suez, Oranje-Nassau Energie and Total.
The assets in France and in the Netherlands were acquired through a corporate acquisition of Coparex in 2002. The combined net reserves at the time of acquisition was around 33 MMboe and the net cumulative production from the date of acquisition up to the end of 2014 was 25.6 MMboe. The
remaining net reserves at the end of 2014 were 23.6 MMboe, demonstrating that a significant portion of the produced volume has been replaced with additional reserves through a pro-active infill drilling and reservoir management strategy. The French assets also contain contingent resources of 13.1 MMboe net to Lundin Petroleum. During the course of 2014 the Grandville (WI 100%) redevelopment in the Paris Basin was completed with the incremental production from the new wells performing as expected. In late 2014 Lundin Petroleum commenced the redevelopment of the Vert la Gravelle field, also located in the Paris Basin.
The gas production in the Netherlands during 2014 was stable and the production performance was in line with forecast. During 2015, three development wells and two exploration wells are planned to be drilled.
| France Key Data | 2014 | 2013 |
|---|---|---|
| Reserves (MMboe) | 21 | 23 |
| Contingent Resources (MMboe) | 13 | 13 |
| Average production per day (Mboepd), net | 3 | 3 |
| Net Turnover (MUSD) | 98 | 112 |
| Sales price achieved (USD/boe) | 94 | 107 |
| Cost of operations (USD/boe) | 26 | 28 |
| Operational cash flow contribution (USD/boe) | 51 | 55 |
| Netherlands Key Data | 2014 | 2013 |
|---|---|---|
| Reserves (MMboe) | 3 | 3 |
| Average production per day (Mboepd), net | 2 | 2 |
| Net Turnover (MUSD) | 37 | 50 |
| Sales price achieved (USD/boe) | 51 | 64 |
| Cost of operations (USD/boe) | 20 | 16 |
| Operational cash flow contribution (USD/boe) | 26 | 18 |
· Langezwaag-2 exploration well on the Gorredijk licence (WI 7.75%) successfully completed in 2014 and put into production in early 2015 · K5-A5 development well successfully drilled and completed (Licence interest 2.03%)
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 the control mechanism and decision making within the Company. It is designed to ensure that all risks are identified, fully understood, controlled and communicated.
Lundin Petroleum's Board of Directors has the overall responsibility for establishing an effective internal control system, The Audit Committee assists the Board to retain oversight responsibility for management design, implementation, conduct and efficiency of the financial reporting, internal control and the reporting of financial risks. The CEO, assisted by Group management at varying levels, is responsible for maintaining in the daily operations an effective control environment and for operating the system of internal control and risk management in the Group.
All employees in the Group are accountable for compliance with the policies and procedures within their areas of control and risk management. The accountability is enforced through structures, authorities, and responsibilities.
The ability to manage, mitigate or transfer these risks represents a key component in ensuring that the business aim of the Company is achieved. Nevertheless oil and gas exploration, development and production involve high operational and financial risks, which even a combination of experience, knowledge and careful evaluation may not be able to fully eliminate or which are beyond the Company's control.
Lundin Petroleum has identified the following principal risks relative to the Group's performance. The impact of risks within any one of these segments can influence the reputation of the Company. In addition to these identified principal risks, Lundin Petroleum Group management reviews all its business risks, including project execution, operational, financial and HSE risks on a quarterly basis. Risk mitigation is discussed and if required additional measures are implemented
| Description of risk | Mitigation – Risk management |
|---|---|
| Strategic Risk | |
| Failure to create shareholder value and meet shareholder expectations A strategy that is ineffective and poorly communicated or executed may lead to a loss of investor confidence and a reduction in the share price. |
Lundin Petroleum's business model clearly defines 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 effective 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 Ineffective 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 reflected within the share price. |
| Ineffective 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, financing 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 and threats. Communication plans and management of stakeholder relations are designed to maintain good and effective relationships. (See also pages 44–53 Sustainable Development 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 benefit 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 sufficient 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 financial institutions as well as credit exposure to customers. |
Lundin Petroleum's policy is to limit credit risk by limiting the customers 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 financial reporting and failure to accurately report financial data could lead to regulatory action, legal liability and damage to the Company's reputation. |
The internal control system for financial reporting is in place to ensure the Group's objective for financial reporting is fulfilled. |
1 For more detailed information regarding financial risks see also Note 12 in notes to the financial statements pages 111–113. More information on the internal control is found in the Corporate Governance report pages 72–73.
| Description of risk | Mitigation – Risk management |
|---|---|
| Operational Risk | |
| Ensuring that development projects or exploration drilling remain on budget, on schedule and achieve operational objectives according to plan is essential in ensuring that shareholder value is maximised. There may be discrepancy due to inaccurate prognosis of conditions or weather delay or external factors. |
All development projects must pass through the Lundin Petroleum value process that requires technical, financial, Investment Committee and Board approval of material 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) and climate change 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 and climate change issues throughout the Group. Through developing knowledge and competence internally to face new developments, proactive risk management, HSE policies, an HSE management system and a Corporate Responsibility management system in compliance with statutory requirements are an integral part of operations. (See also pages 44–53 Sustainable Development for more information.) |
| Major operational incident Apart from the HSE impact of a major operational incident, there can be significant financial consequences for oil spill response, replacement of equipment and liability |
Lundin Petroleum's management systems are in place to avoid Major Operational Incidents. However oil and gas operations will never be completely risk free and the potential for incidents (although reduced to a minimum) will remain. Therefore all Operations are reviewed on a regular basis to assess the risk of incident and to ensure that adequate insurance coverage is in place. |
| Increase in production costs Production costs are affected by the normal economic drivers of supply and demand as well as by various field operating conditions. |
Effective procurement and cost control management processes are essential in ensuring that reasonable cost levels are achieved relative to business plans. Diligent operations management and effective maintenance planning help to ensure efficiency during operations. Production delays and declines from normal field operating conditions cannot be eliminated and may adversely affect revenue and cash flow 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 robust. 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 flows therefrom are based upon a number of variable factors and assumptions. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define 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. (See also pages 18–23 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 effective peer review for subsurface analysis and well site selection together with a well defined corporate strategy for recruitment and retention of talented personnel mitigates the risk. (See also pages 18–23 Reserves, Resources and Production for more information.) |
| Ineffective systems to prevent fraud, bribery and corruption Corruption can occur in any country of operation. Incidents of non-compliance with laws against fraud, bribery and corruption could be damaging to Lundin Petroleum, its reputation and shareholder value. |
A consistent application of Lundin Petroleum's Code of Conduct, together with Anti-Corruption policy, Anti-Fraud policy and procedures clearly define levels of authority. The internal control requirements help to mitigate this risk. Lundin Petroleum is a member of the UN Global Compact to further confirm the Company's commitment to ethical business practices. (See also pages 44–53 Sustainable Development for more information.) |
| Description of risk | Mitigation – Risk management | |||
|---|---|---|---|---|
| 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 modification of contract rights, and or increased taxation. |
The Company reviews its portfolio of assets in relation to its financial 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. |
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| Fluctuation in the price of oil and gas The price of oil and gas are affected by the normal economic drivers of supply and demand as well as the level of investment undertaken by partners, financial investors and market uncertainty. |
Lundin Petroleum's policy is to adopt a flexible approach towards oil price hedging based on an assessment of the benefits of the hedge contract in specific circumstances. |
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| 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. |
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| 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 benefits of interest rate hedging on borrowings. |
Responsible conduct is central to our business and creates value for all our stakeholders
Lundin Petroleum is committed to ensuring its worldwide operations are conducted in a responsible manner, which ultimately secures social, environmental as well as economic benefits for all our stakeholders.
The safety of our people and the protection of the environment are paramount in all of Lundin Petroleum's strategic decisions and operating activities. Our commitment to responsible conduct is set out in Lundin Petroleum's Code of Conduct and in specifically tailored Policies, Guidelines and Management Systems. These documents establish the requirement for all countries of operations to integrate Corporate Responsibility principles, systems and procedures into their activities for the protection of the health, safety and security of all stakeholders as well as the environment. Everyone within Lundin Petroleum is expected to contribute to continuously improve the way in which the Company conducts its operations.
As part of our continuous improvement efforts, Lundin Petroleum launched in 2013 a Corporate Responsibility Management System Review, covering compliance with our Code of Conduct as well as with the Company's policies and guidelines on anti-corruption, human rights, labour standards, environment and stakeholder engagement.
In 2014, Corporate Responsibility Management System Reviews were conducted in France, Indonesia, Malaysia and Norway. These process oriented reviews, will be carried out annually with the General Managers and heads of departments. They have become a valuable tool to assess the level of integration of Corporate Responsibility principles in the Group's operations. They also provide an opportunity to engage in discussions on corporate responsibility issues at different levels of the organisation; they stimulate reflections on issues of relevance given the operational contexts and contractual arrangements, and they provide an opportunity to share best practice across the Group.
more information on the Lundin Foundation can be found on their website www.lundinfoundation.org
i
The Lundin Foundation is a globally recognised leader in venture philanthropy that supports market-based solutions to sustainable and inclusive growth. The 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 risk 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.
In 2013, Lundin Petroleum entered into a Memorandum of Understanding with the Lundin Foundation through which 0.1 percent of the prior year's operating revenues are contributed to the Foundation. To date, the Company has contributed more than USD 2.7 million. A minimum of seventy percent of contributed funds are dedicated to supporting initiatives in designated areas where Lundin Petroleum has exploration, development, or production assets.
During the initial two years of the partnership, activities have been focused in South East Asia on three thematic areas with clearly identified needs; sustainable fisheries, access to energy, and biodiversity conservation.
In 2014 Lundin Norway ranked among the top ten most attractive employers for engineers in the country, according to a survey conducted among more than 8,000 people, asking which company they would prefer to work for.
Lundin Norway's position as an attractive employer has also been confirmed in the hiring process and in early 2014, a total of 2,500 applications were received for 12 job vacancies.
"We are pleased to see that so many people outside our company have noticed all the exciting projects we have going on at the moment. It is good to see that a company of our size is able to compete in a league where most of our competitors are considerably larger."
Jørn Kokvold Head of Human Resources in Norway
Lundin Petroleum values diversity and recruits employees representing a broad spectrum of experiences and backgrounds. At the end of 2014, a total of 593 people spread across seven countries were directly employed by the Group, along with a further 235 contractors. The largest number of employees was in Norway with 320 employees, followed by Malaysia with 98 employees. The workforce increased by 32 percent compared to 2013, due to the increased activity mainly on our growth projects in Norway and Malaysia.
Lundin Petroleum employs a large number of contractors spanning its exploration, development and operating activities. Lundin Petroleum takes its responsibility towards contractors seriously and applies the same high standards of professional conduct as it does towards its employees. This is reflected in the fact that Lundin Petroleum tracks Key Performance Indicators for health and safety not only for its employees but also for contractors over whom it has operational control.
Over the last thirteen years, Lundin Petroleum has been successful in attracting and retaining the best possible talent in the industry. This has been made possible through our good reputation as an employer driven by the opportunities and responsibilities that are given to Lundin Petroleum employees throughout our worldwide operations. Lundin Petroleum is known for keeping an open and attentive attitude towards its employees and for having short and direct channels of communication and fast decision-making, which allow for creative new ideas and propositions to be acted upon quickly generating value for our stakeholders. It is by fostering this culture of innovation and high-performance, where creativity is encouraged and rewarded, that Lundin Petroleum has confirmed its position as the employer of choice in the market place.
As the business continues to expand, Lundin Petroleum is convinced that it is this dynamic work environment that will allow the Company to retain and attract world class employees now and into the future. In order to maintain and foster this environment it continuously invests in its employees through training, skills development and by offering opportunities to move across the range of professional disciplines, which ensures that employees have the sufficient skills, knowledge and motivation to be successful in their work. The results of Lundin Petroleum's dedication to invest in its people are evident in the strong results that the Company has delivered and high levels of motivation and low levels of employee turnover at its sites around the world.
Lundin Petroleum values diversity and strives to maintain an inclusive work environment in all of its countries of operations. It recruits qualified individuals irrespective of gender, race, ethnicity, religion or disability.
Wherever the Company operates it strives to employ locally so that it can benefit from local knowledge and experience at the same time as contributing to capacity-building within the host country. During 2014, the total proportion of employed nationals in countries where Lundin Petroleum operated was 86 percent.
Lundin Petroleum rewards its employees according to their performance and their delivery on individual predetermined objectives. Its reward approach aims to encourage outstanding commitment and performance, thereby enhancing value creation across all parts of the group.
Lundin Petroleum invests in its future employee base by training and developing talent.
In parallel with investing in its current employees, Lundin Petroleum also actively contributes to secure tomorrow's talent pool. Throughout the countries of operations, traineeships are offered in fields of petroleum engineering, geology and Corporate Responsibility.
In Indonesia, Lundin Petroleum has maintained its longstanding partnership with the Bandung Institute of Technology. In 2014 three scholarships were granted to students from different academic departments: geology, petroleum engineering and environmental science.
Lundin Petroleum invests in its people and sees the wellbeing of its employees as a top priority. To maintain a rewarding work environment it strives to uphold a healthy work balance and lifestyle amongst its employees.
During 2014, Lundin Petroleum offered a wide range of sports activities and programmes to its employees, with varying content among the different countries of operations.
Lundin Petroleum supported the participation of Nathalie Pingret, operations assistant at Lundin France, in the Mont Blanc Ultra Trail race. Nathalie managed to run 168 km in 45 hours. The benefits of the race went towards supporting A Chacun son Everest, a charitable organisation which raises funds for children with cancer and leukaemia.
As an oil and gas company, Lundin Petroleum operates in an industry exposed to safety risks. Accidents can potentially occur anywhere and at any time, but it is Lundin Petroleum's responsibility to identify and mitigate any such potential risks and to provide its employees and contractors with safe working conditions. Dedicated policies, processes, procedures and work practices have been put in place to ensure that this responsibility is being met and that risks are being minimised.
The purpose of Lundin Petroleum's HSE management system (Green Book) is to prevent accidents or incidents from happening which can have an impact on people, the environment or on the Company's assets. The Company undertakes risk assessments and uses Key Performance Indicators (KPIs) as HSE management tools, focusing not only on areas where incidents have already occurred, but also where they could potentially occur in the future. Carrying out investigations after incidents have occurred enables us to ascertain the causes of the incidents and take corrective action to prevent them from happening again. Sharing experiences, lessons learned and best practice are also important HSE tools and take place informally within the Group on an ongoing basis and formally through quarterly Group HSE network meetings and management visits to the operations.
While policies provide a good framework, they are not enough to ensure safe operations. A strong safety culture is created when employees are sufficiently empowered to personally take responsibility for performing their work safely and when they have a sense of ownership regarding safe operations and a deep-rooted commitment to that goal. Constant vigilance is essential as well as identifying and openly reporting risks. Lundin Petroleum believes in the sound judgment and capability of its employees and, in addition to policies, procedures and personal protective equipment provides them with the necessary resources, trainings, advice and guidance to enable them to conduct their work in the safest possible manner. Since safety is a joint responsibility, the same level of commitment is expected from contractors, suppliers and partners, in order to ensure that the highest standards of safety are followed across all operations. In 2015, the Company plans to further strengthen its existing contractor management by expanding its current inclusion of the Code of Conduct and HSE requirements to contractors to also include additional corporate responsibility issues such as anti-corruption and human rights in contractual clauses and via a contractor declaration.
All incidents that occur at Lundin Petroleum's sites are reported and shared at different levels in the Company, with the purpose of increasing awareness and preventing future occurrences. "Near misses with high potential" are treated as importantly as serious incidents since they are deemed to have had potential to cause harm if circumstances had been slightly different. Since the Company was created, there have been no work-related fatalities in its operations. During 2014, the Lost Time Incident rate (LTI) for Lundin Petroleum's employees and contractors was 0.25 per 200,000 hours, which is the best performance to date. The majority of incidents were minor and occurred while performing daily routine work, and ranged from a broken finger to a strained ankle.
C. Ashley Heppenstall President and CEO
The emergency preparedness is tested on an ongoing basis together with contractors. This is done through regular emergency response drills conducted in each operation and at least one drill per operation and per year is conducted, with the corporate crisis management team. Throughout the year internal and third party HSE audits and HSE management systems reviews were conducted to identify potential safety issues and to ensure that a sound HSE management was in place.
Likewise the Company has systems and processes in place to prevent and, if need be, manage oil spills. These range from developing oil spill contingency plans based on impact studies, to training staff to prevent and remediate spills. In addition, as a precautionary step, Lundin Petroleum has a Group wide contract with an oil spill response organisation to ensure fast and efficient remedial actions in the event of a spill. In 2014, despite its best efforts, the Company recorded six chemical and two oil spills. Apart from the oil spill in France, none of the other incidents required mobilisation of oil or any chemical clean-up resources or any further measures to remedy the situation, since the oil diluted to harmless concentrations immediately after the incident and caused no measurable harm to the environment. As for France, while the incident required removal of soil where the spill occurred, there was no lasting impact on the environment.
Exposure Hours
Lost Time Incident Rate
Total Recordable Incident Rate
HSE indicator data can i be found on page 133
Working in the oil and gas industry requires us to minimise the impact of our activities on the surrounding natural environment. Every site, from onshore fields in the French mainland to offshore activities on the Norwegian Continental Shelf, has its own natural characteristics and sensitivities. Respect and dedication to preserving our common natural heritage is very important. Lundin Petroleum protects the environment in which it operates by performing extensive environmental impact and baseline studies prior to and during exploration or production activities. These requirements are set out in the Company's HSE Management System (the Green Book) and apply to all countries within the Group, which perform these environmental studies in addition to complying with national and local laws and regulations.
The life cycle of an operation, from licence application to site restoration, typically involves six important stages in which the Company has to carefully analyse all potential impacts on the environment.
For planned or newly acquired licences, data is gathered and analysed in order to gain an understanding of the particular environmental context for the area where operations are to be conducted. Environmental baseline studies are further conducted to identify if there are any environmental aspects that may be impacted by operational activities so that appropriate steps to minimise any impact can be taken.
In those new areas where seismic data acquisition is necessary, consultations with local stakeholders such as local officials, land owners, concerned communities and fisheries, are undertaken prior to starting any seismic campaigns. These consultations are guided by the outcome from the environmental impact studies and aim to reach an agreement as to when and how seismic campaigns can take place. When required, dialogues with the fishery industry are initiated in order to avoid seismic acquisitions being performed in particularly sensitive periods, and where appropriate, to establish compensation schemes.
Prior to starting exploration or appraisal drilling, extensive environmental baseline and impact studies of the planned activities are conducted, and an environmental permit is obtained from national authorities. The scope of the studies normally depends on the extent of existing knowledge of the area and may include literature studies, visual monitoring and sediment and water sampling. Following the outcome of these studies, measures may be taken to minimise the environmental impact of the operations, for example by drilling a deviated well, changing the anchor pattern of the rig or bringing drill cuttings to shore.
In addition to studies, other measures aimed at protecting the environment during drilling operations include risk assessments, emergency response and oil spill preparedness plans and substitution of chemicals to more environmentally friendly alternatives wherever possible.
Once the decision is taken to develop a field, full environmental impact assessments are carried out and environmental management plans are established which aim to minimise the environmental footprint. An example of this is the design of the Company's operating facilities, which are constructed to minimise emissions to air, discharges to sea and the impact on land. Other technical solutions include low NOX emission technology, waste heat recovery, produced water re-injection, flare gas recovery, gas injection or, in the case of Norway, using power from shore for offshore facilities. The Edvard Grieg platform in Norway is designed and constructed according to the examples listed above.
When reaching the production phase, the HSE Management System and Plan as well as a detailed monitoring programme are in place to measure levels of emissions to air and, for offshore activities, discharges to sea. Through such monitoring, the Company is able to identify areas of improvement in relation to energy optimisation and the efficient use of chemicals, and for setting improvement targets.
When operations come to an end, sites are decommissioned according to best practice and in compliance with applicable regulations regarding recovery of materials and site restoration. For onshore sites, all structures are removed and trees are planted. If an agreement is reached with the landowner, refurbished structures may however be left and for example, to be used for storage of agricultural equipment.
Lundin Petroleum recognises climate change as an important issue for the oil and gas sector and has, since 2007, committed to integrate the issue of energy efficiency and greenhouse gas emissions reduction in its strategic planning. Over the years it has developed systems and processes for operations to integrate climate related considerations in the selection of installation designs, products or equipment. As a result, in 2014 Lundin Petroleum received a score of 90B in its reporting to the Carbon Disclosure Project, which is the highest score obtained among Nordic oil and gas companies.
Lundin Petroleum's CDP Ranking 2011–2014
The preservation of biological diversity is implicit in Lundin Petroleum's Environmental Policy and the Green Book and operations continuously assess the potential effects of oil and gas activities on the biodiversity in their baseline and impact studies. In 2014, the Company decided to emphasise its commitment to preserve biodiversity in its areas of operations by consulting with two significant conservation organisations, the International Union for Conservation of Nature (IUCN) and Fauna & Flora International (FFI), and by issuing a Biodiversity Statement approved by the Board. In addition to integrating considerations of biodiversity in the operational plans, Lundin Petroleum funds projects which promote biodiversity. For example, it contributed over a number of years to artificial breeding of sturgeons in the Caspian Sea. In 2014, it funded the transport of Siberian cranes (an endangered species) from Siberia where they were bred, to Astrakhan from where they pursue their seasonal migration.
The UN Global Compact is an initiative to encourage businesses and other actors in society to adopt sustainable and socially responsible practices. This is achieved through endorsement of, and reporting on the implementation of Ten Principles covering Human Rights, Labour Standards, Environment and Anti-Corruption. Lundin Petroleum became a member of the UN Global Compact in 2010 and since then continues to implement the Principles in its operations. In 2014, Lundin Petroleum submitted its fourth Communication on Progress report; made a financial contribution to the UN Global Compact Foundation, joined the UN Global Compact Nordic Network and attended the bi-annual Nordic Network meetings to share best practice with other businesses committed to implement the Principles.
Lundin Petroleum continues to promote environmental protection and awareness throughout its operations. Country operations assess potential effects of their activities through baseline and environmental impact studies and contingency plans, and also support or take part in initiatives promoting environmental stewardship. Lundin Petroleum has in addition chosen to highlight two key issues which are particularly relevant to an oil and gas company, Climate Change and Biodiversity. The Company has committed to robust stewardship in these areas in dedicated Statements and in its operations. In 2014, Lundin Petroleum disclosed its strategy and greenhouse gas emissions to the Carbon Disclosure Project (CDP) for the sixth consecutive year and received the highest score among Nordic oil and gas companies. The Company also adopted a Biodiversity Statement, which was reviewed by two authoritative biodiversity organisations, the International Union for Conservation of Nature (IUCN) and Fauna and Flora International (FFI), to emphasise its commitment to preserve biological diversity in its areas of operations.
Lundin Petroleum's Board of Directors strengthened the Company's commitment towards human rights by formally endorsing the UN Guiding Principles on Business and Human Rights, building upon the Human Rights Policy that was adopted in 2012. Since then the Company has focused on further embedding the Human Rights Policy through the adoption of Human Rights Guidelines. Employees in France, Indonesia, Malaysia, Norway and Switzerland are continually trained on the Company's Human Rights Policy & Guidelines. In 2014, Lundin Petroleum participated in the third annual Forum on Business and Human Rights at the UN in Geneva in order to learn about the challenges of implementing the Guiding Principles, to exchange views and opinions on current best practices and to engage with human rights experts and stakeholders.
Lundin Petroleum has committed in its Code of Conduct to respect and protect employees' rights, including freedom of association and the right to collective bargaining. It ensures equal opportunity without discrimination on the basis of age, culture, disability, gender, race or religion by selecting candidates based on their competence and qualifications to perform the job. Every country of operations has a formal induction process in order to familiarise new employees with their rights and responsibilities and with Lundin Petroleum's Code of Conduct and Corporate Responsibility Policies.
Lundin Petroleum adopted its Anti-Corruption Policy and Guidelines in 2011 and since then monitors corruption trends through Transparency International's Corruption Index, the media and NGO reports, legislative developments and law enforcement. Lundin Petroleum tracks corruption potential within the Group through its Financial and Corporate Responsibility reports, reviews and audits. No cases of corruption occurred throughout the Group in 2014. In addition, Lundin Petroleum actively promotes anti-corruption within the Group and in the public domain, at conferences, with business partners, as well as engages with peers on the issue of the global fight against corruption. In 2013 Lundin Petroleum became a supporting company of the Extractive Industries Transparency Initiative (EITI), a voluntary initiative aimed at promoting anti-corruption and transparency through revenue disclosure. In 2014, the Company actively supported the EITI process in Indonesia, one of two EITI compliant countries within the Group, by meeting with the Indonesian EITI Secretariat and meeting with a key anti-corruption Commissioner. Lundin Petroleum also signed the UN Global Compact Call to Action on anti-corruption, which is an appeal by companies urging governments to enhance anti-corruption measures.
For the first time since Lundin Petroleum adopted its Whistleblowing Policy and Procedure in 2008, a contractor invoked it to lodge a complaint. A full and thorough investigation was conducted and the conclusion was that due process had been followed. A close-out meeting was held with the contractor who considered the matter had been dealt with in a fair and professional manner.
It is important for Lundin Petroleum to openly communicate with people and organisations which are impacted by or impact the Company. In its Code of Conduct, Lundin Petroleum identifies its shareholders, employees, host countries, local communities and society as its stakeholders; they remain the focus of the Company's attention. The type and frequency of engagement with each group differs according to the need and opportunity for engagement.
Shareholders are informed of Lundin Petroleum's strategy and ongoing activities through public disclosure in the form of financial reports, press releases, external presentations and through the corporate website. Other forums in which the Company engages with shareholders are in individual or joint meetings and at the Annual General Meeting.
Engagement with staff takes place on a daily basis throughout the Group. Corporate senior management visit country offices on a regular basis and hold individual meetings to discuss group strategy and to track progress on all issues impacting the Company. In addition, Corporate Responsibility training sessions and management system reviews or audits are also conducted. In 2015, Lundin Petroleum plans to introduce a new Corporate Responsibility induction and eLearning tool.
Contact with host governments take place prior to the acquisition of a licence and the engagement continues at national and local levels throughout the lifetime of the licence period.
Engagement with local communities takes place prior to and during operational stages, comprising informal discussions as well as formal meetings, together with local authorities.
Stakeholder Engagement by Group
Lundin Petroleum also engages with a variety of organisations such as NGOs, international initiatives and industry groups in different forums. In 2014 Lundin Petroleum formally joined the Nordic Network of the UN Global Compact and participated in events dedicated at promoting responsible business practice by organisations such as EITI, the UN Forum on Business & Human Rights, the French Industrial Petroleum Union and the Norwegian Oil and Gas Association.
Lundin Petroleum also seeks to contribute to the better understanding of the importance and impact of corporate responsibility in its operations and to the sector by participating as a speaker or panellist in various conferences and workshops. These forums offer an important opportunity to meet and exchange views and best practice with experts on corporate responsibility.
At Lundin Petroleum, we firmly believe that good corporate governance practices are key to any successful business and we are committed to applying a robust corporate governance framework suited to the Company's current operations, vision and strategy
Principles of good corporate governance, transparency and sustainability are all closely linked and are deeply rooted within Lundin Petroleum. I believe we have in many ways been frontrunners in this field applying a Code of Conduct, coupled with robust corporate policies, as a basis for our operations long before formal rules and reporting requirements were established. Over the years, we have also gradually increased our commitments to international initiatives and most recently, as a signatory of the UN Global Compact, we joined the "Call to Action" anti-corruption initiative to call on Governments to promote anti-corruption measures and implement policies that will establish systems of good corporate governance, as well as the Nordic Network, a forum to discuss the implementation of the Global Compact.
On the operational side, 2014 was a very busy year for Lundin Petroleum with an extensive exploration programme, four developments projects in Norway and Malaysia and progressing the giant Johan Sverdrup discovery in Norway towards development plan approval. A major focus for the Board has therefore been to ensure that adequate and appropriate control measures are in place to monitor the operations to ensure that the Company has access to sufficient liquidity to carry out the projects. The sharp decline in oil prices further emphasised the importance of effective governance routines and I am very pleased that Lundin Petroleum, despite challenging markets, remains today in a sound financial position with the required financial capacity to meet its obligations.
During the year, we further held extensive consultations with our stakeholders regarding the new LTIP 2014, mainly through the Compensation Committee and Group management. Several
meetings were held with institutional investors and their input and suggestions were taken into account for the final Board proposal to the 2014 AGM. I believe this process was beneficial to all parties involved and we will continue to engage with our stakeholders, as appropriate, as part of our corporate governance practices.
In 2015, we will experience some changes involving both current and former Board members of Lundin Petroleum. Subject to AGM approval, Grace Reksten Skaugen, a highly knowledgeable business professional with extensive international experience from a wide range of industries, will join the Board of Directors. At the same time, Asbjørn Larsen will step down after seven years on the Board. I would like to thank Asbjørn for his commitment and valuable input during these years, both as a Board member and as the Board CR/HSE representative, and would like to extend a warm welcome to Grace, who will undoubtedly make a great addition to the Board.
Finally, I would like to thank all Board members for their excellent work during the past year, Group management for their dedication and professional support to the Board as well as all our highly skilled staff for their professional efforts and devotion to Lundin Petroleum's corporate culture and commitment to operate in a responsible, transparent and sustainable manner. Last but not least, I would like to extend my thanks and appreciation to all fellow shareholders for your continued support and trust.
Ian H. Lundin Chairman of the Board
Mike Nicholson appointed Chief Financial Officer of the Company as per 1 January 2014.
Implementation of a new performance based long-term incentive plan LTIP 2014 for Group management and other key employees.
Joined the UN Global Compact "Call to Action" anti-corruption initiative.
Implementation of policies for share ownership for Board members as well as Group management and other key employees, the latter as part of LTIP 2014.
Lundin Petroleum is an independent Swedish oil and gas exploration and production company with a focus on two core areas, Norway and South East Asia, and with assets in France, the Netherlands and Russia as well. Lundin Petroleum maintains an efficient Group structure that currently consists of approximately 30 companies in eight jurisdictions. The ultimate parent company of the Group is the Swedish public limited liability company Lundin Petroleum AB (publ). Lundin Petroleum currently employs worldwide approximately 600 highly experienced oil and gas professionals representing 31 nationalities.
Lundin Petroleum maintains an exploration focus seeking to generate long-term value for all shareholders, as well as other stakeholders, and has, since its creation in 2001, 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 NASDAQ Stockholm, Lundin Petroleum is subject to the Swedish Companies Act and the Annual Accounts Act, as well as the Rule Book for Issuers of NASDAQ Stockholm, which can be found on www.nasdaqomxnordic.com. Lundin Petroleum was listed on the Toronto Stock Exchange until 14 November 2014 and was up until 20 February 2015 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 Code of Governance is based on the tradition of selfregulation and acts as a complement to the corporate governance rules contained in the Swedish 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 finds an alternative solution 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 2014, other than in one instance as mentioned in the schedule on page 58 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 the Company's website.
This Corporate Governance Report has been prepared in accordance with the Swedish Companies Act (SFS 2005:551), the Annual Accounts Act (SFS 1995:1554) and the Code of Corporate Governance (Code of Governance) and has been subject to a review by the Company's statutory auditor. Lundin Petroleum reports one deviation from the Code of Governance in 2014 in respect of the composition of the Nomination Committee as further described in the schedule on page 58.
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 benefit of all 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 oilfield 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 the Company's website.
While the Code of Conduct provides Lundin Petroleum's ethical framework, dedicated policies, guidelines and procedures have been developed to outline specific rules and controls applicable in the different 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, Stakeholder Engagement, Legal, Information Systems, Human Resources and Corporate Communications. The policies, guidelines and procedures are reviewed on a continuous basis
and are modified and updated as and when required. Some of these documents can be found on the Company's website, 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 field. A more detailed description of the Green Book is available on the Company's website.
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 Officer (CEO). The Rules of Procedure also include instructions to the CEO, instructions for the financial 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 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 benefit 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 financially.
The shares of Lundin Petroleum are listed on the Large Cap list of NASDAQ Stockholm. At the 2014 Annual General Meeting (AGM) of the Company, the shareholders approved a reduction of the Company's share capital with an amount of SEK 68,402.50 through cancellation of 6,840,250 shares held in treasury, without reimbursement to the shareholders. The total number of shares in the Company was reduced from 317,910,580 to 311,070,330 shares with a quota value of SEK 0.01 each (rounded-off). At the same time, the shareholders approved an increase of the Company's share capital through a bonus issue with an amount of SEK 68,402.50 to restore the Company's share capital. No new shares were issued in connection with the increase of share capital. After the reduction, the Company holds 2,000,000 own shares, representing 0.6 percent of the share capital. All shares of the Company 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 2014 a total of 45,668 shareholders listed with Euroclear Sweden, which represents an increase of 520 shareholders compared to 2013, i.e. an increase of approximately 1.2 percent. As at 31 December 2014, the major shareholders of the Company, which held more than ten percent of the shares and votes, were Lorito Holdings (Guernsey)
President and CEO
Group management
10
Lundin Petroleum – Governance Structure
Ltd. and Zebra Holdings and Investment (Guernsey) Ltd., two investment companies wholly owned by Lundin family trusts, which together held 28 percent of the shares. In addition, Landor Participations Inc., an investment company wholly owned by a trust whose settler is Ian H. Lundin, held 3.7 percent of the shares.
CR/HSE Board representative
9
The 2013 AGM authorised the Board to approve the repurchase and sale by the Company of 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 acquired 500,000 of its own shares in March 2014 and the average purchase price for these shares is SEK 124.07. The 2014 AGM held in May also authorised the Board to approve repurchases and sales, however no further own shares were acquired or sold by the Company. The average purchase price for all of the remaining 2,000,000 own shares held by the Company is SEK 65.16.
Lundin Petroleum AB (publ), company registration number 556610-8055, has its corporate head office at Hovslagargatan 5, 111 48 Stockholm, Sweden and the registered seat of the Board of Directors is Stockholm, Sweden.
The Company's website is www.lundin-petroleum.com.
Further information regarding the shares and shareholders of Lundin Petroleum in 2014, as well as the Company's dividend policy, can be found on pages 14–15.
Investment Committee
Investment Committee Charter
Policies, Guidelines, Procedures and Management System
Code of Conduct
2
4
5
11
The Nomination Committee is formed in accordance with the Company's Nomination Committee Process, which the shareholders approved at the 2014 AGM as applicable for all future AGMs, until a change is proposed by a Nomination Committee. According to the Process, the Company shall invite four of the larger shareholders of the Company based on shareholdings as per 1 August each year to form the Nomination Committee, however, the members are, regardless of how they are appointed, required to promote the interests of all shareholders of the Company.
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 statutory auditor and remuneration of the statutory auditor. Shareholders may also submit proposals to the Nomination Committee by e-mail to [email protected].
| Nomination Committee for the 2015 AGM | ||||||
|---|---|---|---|---|---|---|
| Member | Appointed by | Meeting attendance |
Shares represented as at 1 August 2014 |
Shares represented as at 31 December 2014 |
Independent of the Company and the Group management |
Independent of the Company's major shareholders |
| Åsa Nisell | Swedbank Robur fonder | 3/3 | 3.6 percent | 4.4 percent | Yes | Yes |
| Arne Lööw | Fjärde AP-fonden | 3/3 | 1.1 percent | 1.1 percent | Yes | Yes |
| Pehr-Olof Malmström |
Danske Capital AB | 2/3 | 1.5 percent | 1.4 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 |
3/3 | 31.7 percent | 31.7 percent | Yes | No1 |
| Magnus Unger | Non-executive Board member of Lundin Petroleum who acts as the Chairman of the Nomination Committee |
3/3 | – | – | Yes | Yes |
| Total 37.9 percent | Total 38.6 percent |
Members of the Nomination Committee, who are not members of the Company's Board, met with two current Board members, Peggy Bruzelius and Asbjørn Larsen, to discuss the work and functioning of the Board, and with the proposed new Board member Grace Reksten Skaugen.
The Nomination Committee fulfils 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,
1 For details, see schedule on pages 70–71.
The 2015 AGM will be held on 7 May 2015 at 1 p.m. in Vinterträdgården at Grand Hôtel, Södra Blaiseholmshamnen 8, in Stockholm. Shareholders who wish to attend the meeting must be recorded in the share register maintained by Euroclear Sweden on 30 April 2015 and must notify the Company of their intention to attend the AGM no later than 30 April 2015. Further information about registration to the AGM, as well as voting by proxy, can be found in the notice of the AGM, available on the Company's website.
In accordance with the Nomination Committee Process, the Nomination Committee for the 2015 AGM consists of members appointed by four of the larger shareholders of the Company based on shareholdings as per 1 August 2014. The names of the members were announced and posted on the Company's website on 30 October 2014, i.e. within the timeframe of six months before the AGM as prescribed by the Code of Governance. The Company's Vice President Legal, Jeffrey Fountain, acts as the secretary of the Nomination Committee.
The Nomination Committee has held three meetings during its mandate and informal contacts have taken place between such meetings. To prepare the Nomination Committee for its tasks and duties and to familiarise the members with the Company, the Chairman of the Board, Ian H. Lundin, who is also a member of the Nomination Committee, commented at the first meeting on the Company's business operations and future outlook, as well as on the oil and gas industry in general. He provided further updates on the Company's business, as well as the general economic environment in which the Company operates, at the subsequent meetings of the Nomination Committee.
The full Nomination Committee report, including the final proposals to the 2015 AGM, are published on the Company's website together with the notice of the 2015 AGM.
The Shareholders' Meeting is the highest decision-making body of Lundin Petroleum where the shareholders exercise their voting rights and influence the business of the Company. Shareholders may request that a specific 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 Swedish Gazette (Post- och Inrikes Tidningar) 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 statutory auditor, the remuneration of the Board, management and the statutory auditor, including approval of the Policy on Remuneration, discharge of the Board members and the CEO from liability and 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.
Resolutions at Shareholders' Meetings generally require a simple majority to pass, unless the Swedish Companies Act requires a higher proportion of shares represented and votes cast at the Meeting. The results of each Shareholders' Meeting are press released promptly after the Shareholders' Meeting and the approved minutes are published on the Company's website at the latest two weeks after the Shareholders' Meeting.
The 2014 AGM was held on 15 May 2014 at Grand Hôtel in Stockholm. The AGM was attended by 568 shareholders, personally or by proxy, representing 48.3 percent of the share capital. The Chairman of the Board, all of the 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 2014 AGM. The members of the Nomination Committee for the 2014 AGM were Åsa Nisell (Swedbank Robur fonder), Arne Lööw (Fjärde AP-fonden) and André Vatsgar (Danske Capital AB), 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 2014 AGM include:
An electronic system with voting devices was used for voting and the minutes of the 2014 AGM and all AGM materials, in Swedish and English, are available on the Company's website, together with the CEO's address to the AGM.
Lundin Petroleum's statutory auditor audits annually the Company's financial statements, the consolidated financial statements, the Board's and the CEO's administration of the Company's affairs and reports on the Corporate Governance Report. The auditor also performs a review of the Company's half year report and issues a statement regarding the Company's compliance with the Policy on Remuneration approved by the AGM. 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. Group entities outside of Sweden are audited in accordance with local rules and regulations.
At the 2014 AGM, the audit firm PricewaterhouseCoopers AB was elected as the auditor of the Company for a period of one year until the 2015 AGM. The auditor in charge is the authorised public accountant Klas Brand.
The auditor's fees are described in the notes to the financial statements – see Note 34 on page 119 and Note 7 on page 124. 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 and require prior approval of the Company's Investment Committee.
Lundin Petroleum's independent qualified reserves auditor audits annually the Company's oil and gas reserves and certain contingent resources, i.e. the Company's core assets, although such assets are not included in the Company's balance sheet. The auditor meets at least once a year with Group management to discuss the reserves reporting and the audit process, and provides a yearly report on reserves data. The current auditor is ERC-Equipoise Ltd. For further information regarding the Company's reserves and resources, see the Reserves, Resources and Production section on pages 18–23.
The Board of Directors of Lundin Petroleum is responsible for the organisation of the Company and management of the Company's operations. The Board is to manage the Company's affairs in the interests of the Company and all shareholders with the aim of creating long-term shareholder value. To achieve this, the Board should at all times have an appropriate composition considering the current and expected development of the operations, with Board members from a wide range of backgrounds that possess both individually and collectively the necessary experience and expertise. An even gender distribution should be pursued.
The Board of Lundin Petroleum 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 final number each year. The Board members are elected for a period of one year.
The Nomination Committee for the 2014 AGM considered that a Board size of eight members would be appropriate taking into account the nature, size, complexity and geographical scope of the Company's business. The 2014 AGM approved the proposal and re-elected Peggy Bruzelius, C. Ashley Heppenstall, also CEO of the Company, Asbjørn Larsen, Ian H. Lundin, also Chairman of the Board, Lukas H. Lundin, William A. Rand, Magnus Unger and Cecilia Vieweg as Board members for a period until the 2015 AGM. There are no deputy members and no members
In June 2010, the Swedish International Public Prosecution Office commenced an investigation into alleged violations of international humanitarian law in Sudan during 1997–2003. The Company has cooperated extensively and proactively with the Prosecution Office by providing 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 Office'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.
appointed by employee organisations. In addition, the Board is supported by a corporate secretary who is not a Board member. The appointed corporate secretary is Jeffrey Fountain, the Company's Vice President Legal.
In the opinion of the Nomination Committee, the Board as proposed and elected by the 2014 AGM is composed of multifaceted individuals who are well-suited for the job and whose expertise, experience and background is extensive. Such expertise and experience relates to the oil and gas industry generally and in particular in relation to Lundin Petroleum's current and prospective areas of operations, public company financial matters, Swedish practice and compliance matters, as well as Corporate Responsibility (CR)/HSE matters. At the 2013 AGM, two new members were elected to the Board, both women. The Nomination Committee nonetheless noted that it is important to continue to strive for a more equal gender distribution, and the Nomination Committee for the 2015 AGM has in-line therewith proposed Grace Reksten Skaugen, a Norwegian business woman with extensive international, financial and oil and gas experience, for election as a new Board member at the 2015 AGM.
Further, in preparation of the elections at the 2014 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 Group management and towards the Company's major shareholders. The independence of each Board member is presented in the schedule on pages 70–71.
In addition to applicable rules and regulations such as the Swedish Companies Act and the Code of Governance, the Board is guided by the Rules of Procedure, which set out how the Board is to conduct its work. The Chairman of the Board, Ian H. Lundin, is responsible for ensuring that the Board's work is well organised and conducted in an efficient 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 sufficiently informed of the Company's operations and financial 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.
In addition to the statutory meeting following the AGM, the Board normally holds at least six ordinary meetings per calendar year, as per a yearly work cycle, to ensure the Board duly addresses all areas of responsibility and that adequate focus is placed on strategic and important issues for the benefit of the Company's shareholders.
At the meetings, the CEO reports on the status of the business, prospects and the financial situation of the Company. The Board also receives management updates and presentations on
Chairman since 2002 Director since 2001 Member of the Nomination Committee
Director since 2013 Member of the Audit Committee
C. Ashley Heppenstall Director since 2001 President and Chief Executive Officer since 2002
Director since 2008 Member of the Audit Committee CR/HSE Board representative
Lukas H. Lundin Director since 2001
Director since 2001 Chairman of the Audit Committee Member of the Compensation Committee
Director since 2001 Member of the Compensation Committee Chairman of the Nomination Committee
Cecilia Vieweg Director since 2013 Chairman of the
more information on the Board members can be found on i pages 70–71 and on www.lundin-petroleum.com
the business and operations of the Company, financial status, CR and HSE matters, risk management, legal questions and investor relations matters, to enable the Board to duly monitor the Company's operations and financial position. Furthermore, the Board receives regular reports from the Company's Audit Committee, Compensation Committee and the CR/HSE Board representative on issues delegated to, or considered by, the Committees and the CR/HSE Board representative.
During 2014, ten board meetings were held, including the statutory meeting. One of the meetings took place over a two day period to give the Board ample time to review and discuss the Company's business and activities. To continue developing the Board's knowledge of the Company and its operations, at least one Board meeting per year is held in an operational location and is combined with visits to the operations, contractors and other business interests. In September 2014, the Board visited the Norwegian operations, including some of the Company's major contractors, and an executive session with Group management was held in connection with the Board meeting. At the executive session, an overview of the Company's general strategy and operations was given and the Company's current and future financing needs were discussed. In-depth operations reviews were given regarding the Group's exploration and development activities, with a continued focus on the Norwegian and South East Asian operations, as well as a reserves and production update, with a particular focus on the
planned inclusion of the Johan Sverdrup field in 2015 as well as the Company's ongoing development projects. In addition, a financial update, a CR/HSE report and an investor relations report were given. Group management also attended a number of Board meetings during the year to present and report on specific questions, as and when required.
A formal review of the work of the Board was conducted in November 2014 through a questionnaire submitted to all Board members, with the objective of ensuring that the Board functions in an efficient manner and 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 the Board members have relevant experience, which enables the Board to function as an effective governing body. The Board Committees' duties and decision-making powers within the Board are clear and the Committees report to the Board in an appropriate manner. The Board meetings are well planned and prepared, with high quality presentations, and enable the Board to effectively monitor the Company's activities and performance. Board meetings in connection with site visits to
In addition to the topics covered by the Board as per its yearly work cycle, the following significant matters were addressed by the Board during the year.
the operational areas were considered very helpful, as were the written monthly management reports received in-between Board meetings. Individual suggestions received included that one additional meeting in person per year would be beneficial, that Board materials could be circulated even further in advance of Board meetings and as in previous years, that more time should be given to discussions regarding the Company's overall strategy rather than to very detailed operational matters.
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. 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.
At the 2014 AGM, the Chairman was awarded an amount of SEK 1,050,000 and each other Board member, with the exception of the CEO, an amount of SEK 500,000. 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 900,000 for Committee work. No remuneration is due for any assignments in relation to the Reserves Committee. In addition, the 2014 AGM approved an amount of SEK 1,500,000 to be paid to the Chairman of the Board for special assignments outside the directorship.
The Board adopted in 2014 a new policy for share ownership for Board members, according to which each Board member is expected to own, directly or indirectly, at least 5,000 shares of the Company. The level shall be met within three years of appointment and during such period, Board members are expected to allocate at least 50 percent of their annual Board fees towards purchases of the Company's shares.
The remuneration of the Board of Directors is detailed further in the schedule on pages 70–71 and in the notes to the financial statements – see Note 32 on pages 117–118.
To maximise the efficiency of the Board's work and to ensure a thorough review of certain issues, the Board has established a Compensation Committee and an Audit 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. In addition, the Compensation Committee may request other advice and assistance of external reward consultants. For further information regarding Group remuneration matters, see the remuneration section of this report on pages 66–69.
The Audit Committee assists the Board in ensuring that the Company's financial 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 NASDAQ Stockholm and the Toronto Stock Exchange (until November 2014). The Audit Committee itself does not perform audit work, however, it supervises the Company's financial reporting and assesses the efficiency of the Company's financial 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 first and third quarter interim financial 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 the statutory auditor at the AGM.
As a result of the delisting of the Company's shares on the Toronto Stock Exchange in November 2014, and the approval of the Ontario Securities Commission for the Company to cease being a Reporting Issuer in Canada in February 2015, the Board as a whole decided to assume the tasks and responsibilities of the Reserves Committee and therefore dissolved the Reserves Committee.
During 2014, the Reserves Committee reviewed and reported 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 reported to the Board on the Company's procedures for disclosing oil and gas reserves and other related information, on the appointment of the independent qualified reserves auditor and on the Company's procedures for providing information to the independent qualified reserves auditor.
The Reserves Committee also met with Group management and the independent qualified 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 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
| Audit Committee 2014 | |||||||
|---|---|---|---|---|---|---|---|
| Members | Meeting attendance |
Audit Committee work during the year | Other requirements | ||||
| William A. Rand, Chairman Asbjørn Larsen Peggy Bruzelius |
6/6 6/6 6/6 |
– Assessment of the 2013 year end report and the 2014 half year report for completeness and accuracy and recommendation for approval to the Board. – Assessment and approval of the first and third quarter reports 2014 on behalf of the Board. – Evaluation of accounting issues in relation to the assessment of the financial reports. – Follow-up and evaluation of the results of the internal audit and risk management of the Group. – Three meetings with the statutory auditor to discuss the financial reporting, internal controls, risk management etc. The committee met with the statutory auditor without management present at these meetings. – Evaluation of the audit performance and the independence and impartiality of the statutory auditor. – Review and approval of statutory auditor's fees. – Assisting the Nomination Committee in its work to propose a |
– The composition of the Audit Committee fulfils the independence requirements of the Swedish Companies Act and the Code of Governance. – All Audit Committee members have extensive experience in financial, accounting and audit matters. William A. Rand has chaired the Audit Committee since its inception in 2002, Asbjørn Larsen's previous assignments include the position of CFO and CEO of a Norwegian listed upstream petroleum company and Peggy Bruzelius' current and previous assignments include high level management positions in financial institutions and companies and she has chaired the Audit Committees of other |
statutory auditor for election at the 2015 AGM.
| Compensation Committee 2014 | |||
|---|---|---|---|
| Members | Meeting attendance |
Compensation Committee work during the year | Other requirements |
| Cecilia Vieweg, Chairman Magnus Unger William A. Rand |
3/3 3/3 3/3 |
– Review of the performance of the CEO and Group management as per the Performance Management Process. – Preparing a report regarding the Board's evaluation of remuneration in 2013. – Continuous monitoring and evaluation of remuneration structures, levels, programmes and the Policy on Remuneration. – Preparing a proposal for the 2014 Policy on Remuneration for Board and AGM approval. – Consultation with Company stakeholders, including institutional investors, regarding the new proposed LTIP 2014. – Preparing a proposal for LTIP 2014 for Board and AGM approval, with the assistance of the HayGroup. – 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 2014 LTIP awards. |
– The composition of the Compensation Committee fulfils the independence requirements of the Code of Governance. – Cecilia Vieweg has previously held positions in listed companies' Compensation Committees and, considering the varied backgrounds and experience of the Committee members in general, including the position of William A. Rand as Chairman of the Committee for more than 10 years, the Compensation Committee has ample knowledge and experience of management remuneration issues. |
| – Undertaking a remuneration benchmark study and engaging the | ||
|---|---|---|
| HayGroup to assist with the study. |
companies.
| Reserves Committee 2014 | ||||||||
|---|---|---|---|---|---|---|---|---|
| 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 ERC-Equipoise Ltd., the independent qualified reserves auditor, to discuss the 2013 |
– The composition of the Reserves Committee fulfilled the independence requirements of Canadian securities regulation as per NI 51–101. |
|||||
| reserves reporting. – Review of reserves data. |
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 Sustainable Developments section on pages 44–53.
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 the only executive Board member. He in turn appoints the other members of Group management, who assist the CEO in his functions and duties, and in the implementation of decisions taken and instructions given by the Board, with the aim of ensuring that the Company meets its strategic objectives and continues to deliver responsible growth and long-term shareholder value.
Lundin Petroleum's Group and local management consists of highly experienced individuals with worldwide oil and gas experience and in addition to the CEO, comprises the following:
A management change occurred as per the end of January 2015 as the Company's former SVP Development, Chris Bruijnzeels, decided to step down following twelve years with the Company.
The tasks of the CEO and the division of duties between the Board and the CEO are defined 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 profit trends, financial position and liquidity, as well as information regarding important events such as significant 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 financial markets, business partners and public authorities. To fulfil his duties, the CEO works closely with the Chairman of the Board to discuss the Company's operations, financial status, upcoming Board meetings, implementation of decisions and other relevant matters.
Under the leadership of the CEO, Group management is responsible for ensuring that the operations are conducted in compliance with all Group policies, guidelines and procedures in a professional, efficient and responsible manner. Regular management meetings are held to discuss all commercial, technical, CR/HSE, financial, legal and other relevant issues within the Group to ensure the established short and long-term business objectives and goals will be met. A detailed weekly operations report is further circulated to Group management summarising the operational events, highlights and issues of the week in question. Group management also travels frequently to oversee the ongoing operations, seek new business opportunities and meet with various stakeholders, including business partners, suppliers and contractors, government representatives and financial institutions. In addition, Group management liaises continuously with the Board, and in particular the Board Committees and the CR/HSE Board representative, in respect of ongoing matters and issues that may arise, and meets with the Board at least once a year at the executive session held in connection with a Board meeting in one of the operational locations.
The Company's Investment Committee, which consists of the CEO, CFO and COO, is established by the Board 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 regularly scheduled meetings 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. These packages are designed to ensure that the Group can recruit, motivate and retain highly skilled individuals and reward performance that enhances shareholder value.
The Group's compensation packages consist of four elements, being (i) base salary; (ii) yearly variable salary; (iii) long-term incentive plan (LTIP); and (iv) other benefits. As part of the yearly assessment process, a Performance Management Process has been established 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 to the achievement of such stated and agreed performance measures.
C. Ashley Heppenstall President and Chief Executive Officer, Director
Christine Batruch Vice President Corporate Responsibility
Alexandre Schneiter Executive Vice President and Chief Operating Officer
Jeffrey Fountain Vice President Legal
Mike Nicholson Chief Financial Officer Teitur Poulsen Vice President Corporate Planning and Investor Relations
more information on the management can i be found on www.lundin-petroleum.com
To ensure compensation packages within the Group remain competitive and in line with market conditions, the Compensation Committee undertakes yearly benchmarking studies. For each study, a peer group of international oil and gas companies of similar size and operational reach is selected, against which the Group's remuneration practices are measured. The levels of base salary, yearly variable salary and long-term incentives are set at the median level, however, in the event of exceptional performance, deviations may be authorised. As the Group continuously competes with the peer group to retain and attract the very best talent in the market, both at operational and executive level, it is considered important that the Group's compensation packages are determined primarily by reference to the remuneration practices within this peer group.
The remuneration of Group management follows the principles that are applicable to all employees, however, these principles must be approved by the shareholders at the AGM. The Compensation Committee therefore prepares yearly for approval by the Board and for submission for final approval to the AGM, a Policy on Remuneration for Group 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. The CEO, in turn, proposes to the Compensation Committee, for approval by the Board, the remuneration and other terms of employment of the other members of Group management.
The 2014 AGM resolved to approve a new performance based LTIP 2014 for Group management and a number of key employees of Lundin Petroleum, which gives the participants the possibility to receive shares in Lundin Petroleum subject to the fulfilment of a performance condition under a three year performance period commencing on 1 July 2014 and expiring on 1 July 2017. The performance condition is based on the share price growth and dividends (Total Shareholder Return) of the Lundin Petroleum share compared to the Total Shareholder Return of a peer group of companies.
At the beginning of the performance period, the participants were granted awards which, provided that among other the performance condition is met, entitle the participant to be allotted shares in Lundin Petroleum at the end of the performance period. The number of performance shares that may be allotted to each participant is limited to a value of three times his/her annual gross base salary for 2014 and the total LTIP award made in respect of 2014 was 608,103.
The Board of Directors may reduce (including reduce to zero) the allotment of performance shares at its discretion, should it consider the underlying performance not to be reflected in the outcome of the performance condition, for example, in light of operating cash flow, reserves and HSE performance. The participants will not be entitled to transfer, pledge or dispose of the LTIP awards or any rights or obligations under LTIP 2014, or perform any shareholders' rights regarding the LTIP awards during the performance period.
The LTIP awards entitle participants to acquire already existing shares. Shares allotted under LTIP 2014 are further subject to certain disposition restrictions to ensure participants build
In this Policy on Remuneration, the term "Group management" refers to the President and Chief Executive Officer, the Executive Vice President and Chief Operating Officer, the Chief Financial Officer, the Senior Vice President Development and other Vice President level employees. Group management currently comprises seven executives.
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 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 Group 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 Group management. The Compensation Committee meets regularly and its tasks include monitoring and evaluating programmes for variable remuneration for Group management and the application of this Policy on Remuneration, as well as the current remuneration structures and levels in the Company.
The Compensation Committee may request the advice and assistance of external reward consultants, however, it shall ensure that there is no conflict of interest regarding other assignments that such consultants may have for the Company and Group management.
There are four key elements to the remuneration of the Group management: a) base salary; b) yearly variable salary; c) long-term incentive plan; and d) other benefits.
towards a meaningful shareholding in Lundin Petroleum. The level of shareholding expected of each participant is either 50 percent or 100 percent (200 percent for the CEO) of the participant's annual gross base salary based on the participant's position within the Group.
The Board is responsible for monitoring and reviewing on a continuous basis the work and performance of the CEO and shall carry out at least once a year a formal performance review. In 2014, the Compensation Committee undertook on behalf of the Board a review of the work and performance of Group
The executive's base 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 base 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 Compensation Committee undertakes yearly benchmarking studies in respect of the Company's remuneration policy and practices.
The Company considers that yearly variable salary is an important part of the executive's remuneration package where associated performance targets reflect 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.
The yearly variable salary shall, in the normal course of business, be based upon a predetermined limit, being within the range of one to twelve 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 cost of yearly variable salary for 2014 is estimated to range between no payout at minimum level and MSEK 25.6 (excluding social costs) at maximum level, based on the current composition of Group management.
The Company believes that it is appropriate to structure its long-term incentive plans (LTIP) to align Group management's incentives with shareholder interests. Remuneration which is linked to the share price results in a greater personal commitment to the Company. Therefore, the Board believes that the Company's LTIP for Group management should be related to the Company's share price.
Information on the principal conditions of the proposed 2014 LTIP for Group management is available as part of the documentation for the Annual General Meeting on www.lundin-petroleum.com.
The cost at grant of the proposed 2014 LTIP is estimated to range between no payout at minimum level and MSEK 95.0 (excluding
social costs) at maximum level, based on the current composition of Group management.
Other benefits shall be based on market terms and shall facilitate the discharge of each executive's duties. Such benefits include statutory pension benefits comprising a defined contribution scheme with premiums calculated on the full base salary. The pension contributions in relation to the base salary are dependent upon the age of the executive.
A mutual notice period of between one and twelve 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, up to two years' base salary, in the event of termination of employment due to a change of control of the Company. The Board of Directors is further authorised, in individual cases, to approve severance arrangements, in addition to the notice periods and the severance arrangements in respect of a change of control of the Company, where employment is terminated by the Company without cause, or otherwise in circumstances at the discretion of the Board. Such severance arrangements may provide for the payment of up to one year's base salary; no other benefits shall be included. Severance payments in aggregate (i.e. for notice periods and severance arrangements) shall be limited to a maximum of two years' base salary.
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 specific case.
Information regarding previously approved remunerations to Group management, which remain outstanding (if any), is available in Note 32 of the Company's Annual Report.
In 2013, the Board of Directors agreed on a deviation from the 2013 Policy on Remuneration and approved a severance arrangement for the Company's former Chief Financial Officer. The Board considered that special circumstances warranted such a deviation, in view of the former Chief Financial Officer's substantial contribution to the Company over his years of service. The details of the deviation are described in Note 31 of the Company's Annual Report (2013).
management, including the CEO. The results were presented to Board, together with 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.
The tasks of the Compensation Committee also include monitoring and evaluating the general application of the Policy on Remuneration, as approved by the AGM, and the Compensation Committee prepares in connection therewith a yearly report, for approval by the Board, on the application of the Policy on Remuneration and the evaluation of remuneration of Group management. As part of its review process, the statutory auditor of the Company also verifies on a yearly basis whether the Company has complied with the Policy on Remuneration. Both reports are available on the Company's website.
For information regarding the Board's proposal for remuneration to Group management to the 2015 AGM, including a similar LTIP as approved by the 2014 AGM, see the Directors' report, page 88.
| Board of Directors | ||||
|---|---|---|---|---|
| Name | Ian H. Lundin | Peggy Bruzelius | C. Ashley Heppenstall | Asbjørn Larsen |
| Function | Chairman (since 2002) | President and Chief Director Executive Officer, Director |
Director, CR/HSE representative |
|
| Elected | 2001 | 2013 | 2001 | 2008 |
| Born | 1960 | 1949 | 1962 | 1936 |
| Education | Bachelor of Science degree in Petroleum Engineering from the University of Tulsa. |
Master of Science (Econom ics and Business) from the Stockholm School of Economics. |
Bachelor of Science degree in Mathematics from the University of Durham. |
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. |
Peggy Bruzelius has worked as Managing Director of ABB Financial Services AB and has headed the asset management division of Skandinaviska Enskilda Banken AB. |
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. |
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 member of the board of Bukowski Auktioner AB. |
Chair of the board of Lancelot Asset Management AB, member of the board of Axfood AB, Diageo PLC, Akzo Nobel NV and Skandia Liv. |
Member of the board of Etrion Corporation, ShaMaran Petroleum Corp., Gateway Storage Company Limited and Africa Energy Corp. |
Member of the board of Selvaag Gruppen AS, The Montebello Cancer Rehabilitation Foundation and The Tom Wilhelmsen Foundation. |
| Shares in Lundin Petroleum (as at 31 December 2014) |
Nil1 | 8,000 | 1,391,283 | 12,000 |
| Board Attendance | 9/10 | 10/10 | 10/10 | 10/10 |
| Audit Committee Attendance |
– | 6/6 | – | 6/6 |
| Compensation Committee Attendance |
– | – | – | – |
| Reserves Committee Attendance |
1/1 | – | – | 1/1 |
| Remuneration for Board and Committee work |
SEK 1,025,000 | SEK 595,000 | Nil | SEK 595,000 |
| Remuneration for special assignments outside the directorship 6 |
SEK 1,590,000 | Nil | Nil | Nil |
| Independent of the Company and the Group management |
Yes2 | Yes | No3 | Yes |
| Independent of the Company's major shareholders |
No1 | Yes | No3 | 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 is a director of 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 | Cecilia Vieweg |
| Director | Director | Director | Director |
| 2001 | 2001 | 2001 | 2013 |
| 1958 | 1942 | 1942 | 1955 |
| 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. |
Master of Law from the University of Lund. |
| 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. |
Cecilia Vieweg is General Counsel and member of the Executive Management of AB Electrolux since 1999. She previously worked as legal advisor in senior positions within the AB Volvo Group and as a lawyer in private practice. |
| Chairman of the board of Lundin Mining Corp., Denison Mines Corp., Lucara Diamond Corp., NGEx Resources Inc., Lundin Gold Inc. and Lundin Foundation, member of the board of Bukowski Auktioner AB. |
Member of the board of Lundin Mining Corp., Denison Mines Corp., New West Energy Services Inc. and NGEx Resources Inc. |
– | Member of the board of the Association of Swedish Engineering Industries and the Swedish Securities Council. |
| 788,3314 | 118,441 | 250,000 | 3,500 |
| 9/10 | 10/10 | 10/10 | 9/10 |
| – | 6/6 | – | – |
| – | 3/3 | 3/3 | 3/3 |
| – | – | – | – |
| SEK 495,000 | SEK 745,000 | SEK 595,000 | SEK 645,000 |
| Nil | Nil | Nil | Nil |
| Yes | Yes | Yes | Yes |
| No4 | No5 | Yes | Yes |
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 2014 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 2013 and 2014 AGMs.
The responsibility of the Board of Directors for internal control over financial 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 financial reporting and describes how internal control over the financial reporting is organised, but does not comment on its effectiveness.
Lundin Petroleum's objective for financial 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 financial 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 financial reporting objectives.
The internal auditor of Lundin Petroleum provides an independent and objective appraisal function established as a service adding value to the organisation. The internal auditor is concerned with the adequacy and effectiveness of systems of control and whether they are managed, maintained, complied with and function effectively. To this end, the internal auditor will evaluate controls that promote efficient management reporting, compliance with procedures, protection of organisational assets and interests and effective control. The internal auditor reports to the Audit Committee.
Lundin Petroleum's Financial Reporting Internal Control System consists of five key components, as described below and is based upon the Committee of Sponsoring Organisations of the Treadway Commission (COSO) framework. The Group applies the updated version of the COSO framework with its 17 principles. The internal control of financial 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 effective internal control system. The Audit Committee assists the Board in relation to the financial reporting, internal control and the reporting of financial risks. The Audit Committee also supervises the efficiency of the internal auditing, internal control and financial reporting and reviews all interim and annual financial reports.
The CEO is responsible for maintaining in the daily operations an effective 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's internal auditor is further responsible for ensuring that the internal control framework is adhered to.
The development and implementation of a Groupwide 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.
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 identifies, sources and measures the risk of material error in the financial reporting and accounting systems of the Group. This process is the basis for designing control activities to mitigate identified risks.
Risks relating to financial 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 financial reporting process and structures its internal control systems around the risks identified. The risks are assessed, on a quarterly basis, through a standardised methodology based on likelihood and impact and are then documented in a Group-wide risk map. When risks are identified and evaluated, control activities are implemented to minimise the risks in the financial reporting process. Conclusions of the risk assessment are reported to management and the Board through the Audit Committee. Identified 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 different risks, see the Risks and Risk Management section on pages 70–71.
The finance department of each Group company is responsible for the regular analysis of the financial results and for reporting thereon to the finance department at Group level. Various other control activities are also incorporated into the financial reporting process to ensure that the financial reporting gives a true and fair view at any reporting date and that business is conducted efficiently.
The Investment Committee 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 regularly 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 financial 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 affected 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 defines how external information is to be issued, by whom and the way in which the information should be given.
In order to ensure the effectiveness of the internal control in respect of the financial reporting, monitoring activities are conducted by the Board, the Audit Committee and Group management, including the Company's CFO. The internal auditor and the Group finance 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.
Stockholm, 8 April 2015
The Board of Directors of Lundin Petroleum AB (publ)
To the annual meeting of the shareholders of Lundin Petroleum AB (publ), corporate identity number 556610-8055
It is the Board of Directors who is responsible for the Corporate Governance Statement for the year 2014 on pages 54–73 and that it has been prepared in accordance with the Annual Accounts Act.
We have read the corporate governance statement and based on that reading and our knowledge of the company and the group we believe that we have a sufficient basis for our opinions. This means that our statutory examination of the Corporate Governance Statement is different and substantially less in scope than an audit conducted in accordance with International Standards on Auditing and generally accepted auditing standards in Sweden.
In our opinion, the Corporate Governance Statement has been prepared and its statutory content is consistent with the annual accounts and the consolidated accounts.
Stockholm, 8 April 2015 PricewaterhouseCoopers AB
Klas Brand Johan Malmqvist Lead Partner Partner
Authorised Public Accountant Authorised Public Accountant
| Directors' report | 76 |
|---|---|
| Consolidated income statement | 89 |
| Consolidated statement of comprehensive income | 90 |
| Consolidated balance sheet | 91 |
| Consolidated statement of cash flow | 92 |
| Consolidated statement of changes in equity | 93 |
| Accounting policies | 94 |
| Notes to the financial statements of the Group | 100 |
| - Note 1 – Revenue | 100 |
| - Note 2 – Production costs | 100 |
| - Note 3 – Segment information | 100 |
| - Note 4 – Finance income | 102 |
| - Note 5 – Finance costs | 103 |
| - Note 6 – Share of net result of joint ventures | |
| accounted for using the equity method | 103 |
| - Note 7 – Income taxes | 104 |
| - Note 8 – Oil and gas properties | 106 |
| - Note 9 – Other tangible assets | 108 |
| - Note 10 – Other shares and participations | 108 |
| - Note 11 – Financial instruments | 109 |
| - Note 12 – Financial risks, sensitivity analysis | |
| and derivative instruments | 111 |
| - Note 13 – Other financial assets | 113 |
| - Note 14 – Inventories | 113 |
| - Note 15 – Trade receivables | 113 |
| - Note 16 – Prepaid expenses | 113 |
| - Note 17 – Other receivables | 114 |
| - Note 18 – Cash and cash equivalents | 114 |
| - Note 19 – Other reserves | 114 |
| - Note 20 – Provision for site restoration | 114 |
| - Note 22 – Other provisions | 114 |
|---|---|
| - Note 23 – Financial liabilities | 114 |
| - Note 24 – Other accrued expenses | 115 |
| - Note 25 – Other liabilities | 115 |
| - Note 26 – Pledged assets | 115 |
| - Note 27 – Contingent liabilities and assets | 115 |
| - Note 28 – Earnings per share | 115 |
| - Note 29 – Adjustment for non-cash related items | 115 |
| - Note 30 – Related party transactions | 116 |
| - Note 31 – Average number of employees | 116 |
| - Note 32 – Remuneration to the Board of directors, | |
| Group management and other employees | 117 |
| - Note 33 – Long-term incentive plans | 118 |
| - Note 34 – Remuneration to the Group's auditors | 120 |
| - Note 35 – Subsequent events | 120 |
| Annual accounts of the Parent Company | 121 |
| Parent Company income statement | 121 |
| Parent Company comprehensive income statement | 121 |
| Parent Company balance sheet | 122 |
| Parent Company statement of cash flow | 123 |
| Parent Company statement of changes in equity | 123 |
| Notes to the financial statements of the Parent Company 124 | |
| - Note 1 – Financial income | 124 |
| - Note 2 – Financial costs | 124 |
| - Note 3 – Income taxes | 124 |
| - Note 4 – Other receivables | 124 |
| - Note 5 – Accrued expenses and prepaid income | 124 |
| - Note 6 – Pledged assets, contingent liabilities and assets 124 | |
| - Note 7 – Remuneration to the auditor | 124 |
| - Note 8 – Shares in subsidiaries | 125 |
| Board assurance | 126 |
| Auditor's report | 127 |
The address of Lundin Petroleum AB's registered office 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 significant research and development. The Group maintains branches in some of its areas of operation. The Parent Company has no foreign branches.
In July 2014, Lundin Petroleum completed the sale of its interests in the Russian onshore producing assets in the Komi Region. These assets were proportionally consolidated until the end of 2013. Following the adoption of IFRS 11 Joint Arrangements from 1 January 2014 these jointly controlled entities have been accounted for using the equity method up to the date of the sale. The comparatives in the financial statements have been restated following the adoption of IFRS 11 Joint Arrangements, effective 1 January 2014. The impact of the restatement is described in Note 6.
Note: The Group structure shows significant subsidiaries only, see the Parent Company Financial Statements Note 8 for full legal names and all subsidiaries
(No) Norway
Lundin Petroleum has exploration and production assets focused upon three core areas, Norway, South East Asia and Continental Europe. Norway continues to represent the majority of Lundin Petroleum's operational activities with production for the financial year of 2014 accounting for 71 percent of total production and with 79 percent of Lundin Petroleum's total reserves as at the end of 2014.
Lundin Petroleum has 187.5 million barrels of oil equivalent (MMboe) of reserves as at 31 December 2014 as certified by an independent third party. Lundin Petroleum also has a number of discovered oil and gas resources which classify as contingent resources and are not yet classified as reserves. Excluding the major Johan Sverdrup field located in Norway, the best estimate contingent resources net to Lundin Petroleum amount to 404 MMboe as at 31 December 2014. The Johan Sverdrup field contains gross contingent resources of between 1.7 and 3.0 billion boe,1 with approximately 95 percent being oil. The Johan Sverdrup field is situated in licences PL501, PL502 and PL265 in Norway and Lundin Petroleum has a 22.12 percent unitised interest in the field, subject to approval by the Norwegian Ministry of Petroleum and Energy.
Production for the year amounted to 24.9 thousand barrels of oil equivalent per day (Mboepd) (compared to 32.7 Mboepd in 2013) and was comprised as follows:
| Production in Mboepd | 2014 | 2013 |
|---|---|---|
| Crude oil | ||
| Norway | 15.0 | 20.6 |
| France | 2.9 | 2.9 |
| Russia2 | 1.1 | 2.3 |
| Total crude oil production | 19.0 | 25.8 |
| Gas | ||
| Norway | 2.6 | 3.3 |
| Netherlands | 1.9 | 2.0 |
| Indonesia | 1.4 | 1.6 |
| Total gas production | 5.9 | 6.9 |
| Total production | ||
| Quantity in Mboe | 9,107.8 | 11,939.6 |
| Quantity in Mboepd | 24.9 | 32.7 |
1 Gross contingent resource range as disclosed by operator Statoil in February 2015
| Production in Mboepd | WI 1 | 2014 | 2013 |
|---|---|---|---|
| Alvheim | 15% | 9.6 | 10.5 |
| Volund | 35% | 7.4 | 12.2 |
| Brynhild | 90% | 0.1 | – |
| Gaupe | 40% | 0.5 | 1.2 |
| Quantity in Mboepd | 17.6 | 23.9 |
1 Lundin Petroleum's working interest (WI)
Production from the Alvheim field during the year has been better than forecast due to continued good reservoir performance, better FPSO uptime and better than expected production from two wells which came back onstream during April 2014 following work-over activity. The production outperformance was partially offset by two short weather related shut-ins of the Alvheim FPSO during the first quarter of 2014. Production on the Alvheim FPSO was shut-in for approximately two weeks during September 2014 for planned maintenance work and completion of the Bøyla (WI 15%) tie-in scope. One producing well on Alvheim has been shut-in since November 2013 and a work-over of this well is scheduled during 2015. The drilling of a new infill well on Alvheim commenced during the fourth quarter of 2014 and the well is expected to commence production during the second quarter of 2015. Two further infill wells are planned to be drilled in 2015 with production from these two wells expected to commence in late 2015 or early 2016. The development of the Viper/Kobra accumulations within the Alvheim field was sanctioned by the Alvheim partnership in December 2014 with expected production start-up in late 2016. The Viper/Kobra resources have consequently been moved into reserves as at 31 December 2014. The cost of operations for the Alvheim field, excluding well intervention work, was approximately USD 5 per barrel during the year.
The Volund field production during the year has been below forecast due to a combination of two short weather related shutins of the Alvheim FPSO, lower liquid throughput compared to the forecast and a higher water-cut than forecast. The under performance has been partly offset by better than forecast FPSO uptime. Further infill opportunities have been identified on the Volund field and it is the intention to drill at least one infill well during 2016. The contingent resources associated with the infill target have consequently been moved into reserves as at 31 December 2014. The cost of operations for the Volund field, during the year was below USD 4 per barrel.
Production from the Brynhild field commenced on 25 December 2014. Two production wells have been completed and are available for production whilst the drilling and completion of the third well is ongoing. The production capacity from the first well was confirmed as production initially reached plateau. However during the first month of production the production rate has been below plateau due to an unexpected combination of facilities and well optimisation as well as weather related issues. The field is expected to ramp-up to a sustainable plateau
2 Following the adoption of IFRS 11 Joint Arrangements, the financial results attributable to the onshore Russian assets are accounted for using the equity method from 1 January 2014. In July 2014, Lundin Petroleum sold its entire interest in the Sotchemyu-Talyu and North Irael fields in the Komi Republic to Arawak Energy Russia BV.
of 12,000 boepd during the next few weeks. The fourth and final development well on Brynhild will be drilled immediately after the third well has been completed.
The Gaupe field produced as per forecast. The field is currently shut-in with the potential to recommence limited production in 2015 subject to economic conditions. However no reserves have been booked for the Gaupe field.
The Bøyla field commenced production on 19 January 2015. The Bøyla field has been developed as a 28 km subsea tie-back to the Alvheim FPSO. One production well and one water injection well have been completed and put onstream with a second production well commencing production later in 2015.
The Edvard Grieg field development is well advanced and is progressing on schedule and on budget. The steel jacket was successfully installed offshore during the second quarter of 2014 and the installation of the 94 km gas pipeline to the Sage Beryl gas system was completed during the third quarter 2014. The construction work of the topsides by Kværner is substantially complete and onshore commissioning is ongoing. Installation of the oil export pipeline to the Grane field connection is ongoing. The installation of the topsides is planned during the second quarter of 2015. Development drilling commenced during the third quarter of 2014 with the Rowan Viking jack-up rig. First oil from the Edvard Grieg field is expected in the fourth quarter of 2015 following the completion of the offshore hook-up and commissioning.
The appraisal well 16/1-18 on the southeastern part of the Edvard Grieg field was successfully completed during the year. The well encountered 62 metres of moderate to good reservoir quality sandstone. A further appraisal well is planned in the southern part of Edvard Grieg during 2015 to better understand the distribution of this sandstone with the potential to increase reserves.
During the year the Ivar Aasen field, which is located immediately to the north of the Edvard Grieg field, has been unitised across three licences PL001b/PL242, PL338BS (WI 50%) and PL457. The PL338BS is a stratigraphic carve-out of PL338
Development
with the same ownership as in PL338 (WI 50%). PL338BS has been assigned a 2.77 percent unitised interest in the Ivar Aasen development which therefore gives Lundin Petroleum a net ownership in the Ivar Aasen unit of 1.385 percent. The unitised interest is not subject to any re-determination. The operator of Ivar Aasen, Det norske oljeselskap (Det norske), estimates the field to contain gross reserves of 192 MMboe excluding the Hanz discovery which is not a part of the Ivar Aasen unit. Ivar Aasen is being developed with a steel jacket platform with the topside facilities consisting of a living quarter and drilling facilities with oil, gas and water separation and onward export to the Edvard Grieg platform for final processing and pipeline export. Ivar Aasen is forecast to come onstream during the fourth quarter of 2016 and Lundin Petroleum has reported its 1.385 percent unitised interest as reserves as at 31 December 2014.
Lundin Petroleum discovered the Johan Sverdrup field in 2010 with the well 16/2-6 drilled in PL501 (WI 40%). A total of 22 wells and seven sidetracks have been drilled on the Johan Sverdrup field and the appraisal campaign is complete. In February 2015 the Johan Sverdrup partnership submitted a Plan for Development and Operations (PDO) for Phase 1 to the Ministry of Petroleum and Energy. The PDO for Phase 1 also outlines certain development concepts for the full field involving an expected full field gross plateau production level of between 550,000 and 650,000 boepd and gross contingent resources of between 1.7 to 3.0 billion boe with approximately 95 percent of the resources being oil. In parallel with the PDO submission the majority of the Johan Sverdrup partnership also submitted a Tract Participation agreement for the Johan Sverdrup field with a working interest of 22.12 percent to Lundin Petroleum. The Tract Participation agreement remains subject to approval by the Ministry of Petroleum and Energy. Statoil has been awarded the operatorship for the Johan Sverdrup field.
The FEED work for Phase 1 was completed by Aker Solutions in late 2014, culminating with the PDO for Phase 1 being submitted in February 2015. The PDO for Phase 1 involves a field centre, consisting of one processing platform, one riser platform, one wellhead platform with drilling facilities and one living quarter platform. The platforms will be installed on steel jackets in 120 metres of water and will be bridge-linked. In June 2014, Statoil announced that a letter of intent had been signed with Kværner in Norway for delivery of two of the steel
| Licence | Field | WI | PDO Approval | Estimated gross reserves |
First production expected |
Gross plateau production rate expected |
|---|---|---|---|---|---|---|
| PL340 | Bøyla | 15% | October 2012 | 23 MMboe | Commenced Jan 2015 | 20.0 Mboepd |
| PL338 | Edvard Grieg | 50% | June 2012 | 187 MMboe | Q4 2015 | 100.0 Mboepd |
| Various | Ivar Aasen | 1.385% | May 2013 | 192 MMboe | Q4 2016 | 65.0 Mboepd |
| Various | Johan Sverdrup | 22.12%1 | Expected mid-2015 | 1.7 – 3.0 billion boe2 | Q4 2019 | 550.0–650.0 Mboepd |
1 Subject to Government approval
2 Gross contingent resource range as disclosed by operator Statoil in February 2015
jackets for the Phase 1 development. The steel jacket for the riser platform is scheduled for delivery in 2017 and the steel jacket for the drilling platform is scheduled for delivery in 2018. A contract for the riser platform jacket was awarded to Kværner in January 2015 and a second contract was awarded to Aker Solution during January 2015 for the engineering and procurement management for the riser and processing platform topsides for Phase 1, in addition to hook-up work and gangways for the entire field.
The Phase 1 development is scheduled to start production in late 2019 and is forecast to have a gross production capacity of between 315,000 and 380,000 barrels of oil per day (bopd). It is anticipated that 35 production and injection wells will be drilled to support Phase 1 production, of which 14 wells will be drilled prior to first oil with a semi-submersible rig to facilitate Phase 1 plateau production.
The gross capital investment for Phase 1, which includes oil and gas export pipelines as well as a power supply from shore, is estimated to NOK 117 billion, including contingencies and certain market allowances for potential future increases in market rates. The Phase 1 field centre will also have spare capacity to facilitate future phases of development and potential enhanced recovery.
The Johan Sverdrup oil and gas production will be transported to shore via dedicated oil and gas pipelines. A 274 km 36" oil pipeline will be installed and connected to the Mongstad oil terminal on the west coast of Norway. A 165 km 18" gas pipeline will be installed and connected to the Kårstø gas terminal for processing and onward transportation.
The Johan Sverdrup resources not developed as part of Phase 1 will be developed through subsequent development phases. Whilst the development concept for the full field development has not yet been approved by the partnership, the current estimated full field development costs, including the Phase 1 costs, are in the range of NOK 170 to 220 billion.
Two appraisal wells have been completed on the Johan Sverdrup field during the year. Well 16/3-8S was successfully completed on PL501 on the Avaldsnes High between wells 16/2-6, 16/2-7 and 16/3-4 encountering 13 metres of oil filled reservoir of late Jurassic Draupne sandstones. The well achieved an excellent test flow rate and measured exceptionally high permeabilities. A sidetrack 16/3-8ST2 was also successfully completed. In April 2014, the appraisal well 16/2-19 and sidetrack well 16/2-19A in PL265 were completed. The results from the wells were below expectations with thinner than expected reservoir towards the basement high.
In addition to the Johan Sverdrup appraisal wells, a further two appraisal wells have been completed during the year.
In July 2014, the appraisal well on the Gohta discovery in the southern Barents Sea was completed. The Gohta appraisal well 7120/1-4S in PL492 (WI 40%) encountered 10 metres of gas and condensate in Upper Permian limestone conglomerate with good reservoir properties overlying fractured limestone of limited reservoir quality. A test produced over 26 million standard cubic feet of gas per day (MMscfd) and 880 barrels of condensate per day.
The 16/4-8S appraisal well in PL359 (WI 50%) on the Luno II discovery on the Utsira High was completed in August 2014 and encountered a 30 metres gross oil column underlying a thin gas cap. The well flow tested oil successfully however the reservoir quality failed to meet pre-drill expectations. The revised gross contingent resource range for Luno II is estimated at 27 to 71 MMboe.
Lundin Petroleum is planning to drill three to four appraisal wells offshore Norway during 2015. Two of these appraisal wells are planned on the Alta discovery in PL609 (WI 40%) in the southern Barents Sea. One appraisal well is planned to be drilled on the southeastern part of the Edvard Grieg field in PL338 (WI 50%). A further appraisal well may be drilled on the Gohta discovery in PL492 (WI 40%) in 2015.
| Licence | Operator | WI | Well | Spud Date | Status |
|---|---|---|---|---|---|
| PL501 | Lundin Petroleum | 40%1 | 16/3-8S & T2 | January 2014 | Completed March 2014 |
| PL265 | Statoil | 10%1 | 16/2-19 | February 2014 | Completed April 2014 |
| PL492 | Lundin Petroleum | 40% | 7120/1-4S | May 2014 | Completed July 2014 |
| PL359 | Lundin Petroleum | 50% | 16/4-8S | June 2014 | Completed August 2014 |
1 Unitised licence 22.12%, subject to governmental approval
| Licence | Well | Spud Date | Target | WI | Operator | Result |
|---|---|---|---|---|---|---|
| Utsira High | ||||||
| PL501 | 16/2-20A | January 2014 | Torvastad (sidetrack) | 40%1 | Lundin Petroleum | Oil shows – non-commercial |
| PL625 | 25/10-12S | October 2014 | Kopervik | 40% | Lundin Petroleum | Dry |
| Southern Barents Sea | ||||||
| PL659 | 7222/11-2 | January 2014 | Langlitinden | 20% | Det norske | Oil discovery – non-commercial |
| PL609 | 7220/11-1 | August 2014 | Alta | 40% | Lundin Petroleum | Oil and gas discovery – gross resources 125 – 400 MMboe |
| North Sea | ||||||
| PL631 | 33/12-10S | September 2014 | Vollgrav South | 60% | Lundin Petroleum | Dry |
| PL584 | 6405/12-1 | October 2014 | Lindarormen | 60% | Lundin Petroleum | Dry |
| PL555 | 33/2-1 | October 2014 | Storm | 60% | Lundin Petroleum | Oil shows – non-commercial |
1 Unitised licence 22.12%, subject to Government approval
Lundin Petroleum has completed seven exploration wells in Norway during the year. On the Utsira High the Torvastad side-track well 16/2-20A, targeting an Upper Jurassic reservoir sequence 770 metres west of the Torvastad exploration well 16/2-20, was completed in February 2014. The sidetrack encountered oil but found poorer than expected reservoir quality and was declared non-commercial.
In the southern Barents Sea, the Langlitinden well 7222/11-2 drilled on the southeast of the Loppa High was completed in February 2014. The well encountered oil in middle Triassic sandstone reservoir but the reservoir quality was poorer than expected and the well was consequently announced as noncommercial.
In October 2014, the Alta well 7220/11-1 in the southern Barents Sea was announced as an oil and gas discovery. The well was drilled on-trend with the Gohta discovery made in 2013 and encountered a 57 metre gross hydrocarbon column in carbonate rocks of good reservoir quality. The well flow tested approximately 3,300 bopd and 1.7 million cubic feet of gas per day and the discovery is estimated to contain resources of between 125 to 400 MMboe.
The Vollgrav South prospect drilled close to the Statfjord field with well 33/12-10S failed to encounter any hydrocarbons and was announced as a dry well in October 2014.
In December 2014, the Storm well 33/2-1 drilled 65 km northwest of the Snorre field was announced as having encountered hydrocarbons in Cretaceous and Jurassic reservoir sequences but in non-commercial quantities.
Also in December 2014, the Lindarormen well 6405/12-1 drilled 80 km northeast of the Ormen Lange field was announced as a dry well with no hydrocarbons encountered.
In December 2014, the Kopervik well 25/10-12S was completed as a dry well. The well was drilled 20 km northwest of the Johan Sverdrup field and encountered good quality Jurassic reservoir but failed to encounter any hydrocarbons.
During 2015, Lundin Petroleum is planning to drill seven operated exploration wells targeting net unrisked prospective resources of 475 MMboe.
| Exploration wells 2015 | |
|---|---|
| Licence | WI | Targeting prospect |
|---|---|---|
| Southern Barents Sea | ||
| PL609 | 40% | Neiden |
| PL708 | 40% | Ørnen |
| Utsira High | ||
| PL338C | 80% 1 | Gemini |
| PL359 | 50% | Luno II North |
| PL674 | 35% | Zulu |
| PL544 | 40% | Fosen |
| Northern North Sea | ||
| PL579 | 50% | Morkel |
1 Lundin Norway has farmed-out 30 percent of its 80 percent working interest to Lime Petroleum Norway, subject to governmental approval.
Lundin Petroleum, together with 32 other companies, has signed a contract during the year with Western Geco and PGS for an extended 3D seismic acquisition in the Norwegian southeastern Barents Sea ahead of the 23rd licensing round. The 3D acquisition was completed in the third quarter of 2014 and the processing is scheduled to be completed in the summer of 2015. In January 2015 the Norwegian Ministry of Petroleum and Energy announced that 57 blocks, or part of blocks, will be offered for licensing in the 23rd Licensing round with the majority of blocks being located in the Barents Sea. The deadline for submitting licence applications is in December 2015 with awards expected to be announced during the first half of 2016.
During the year, Lundin Petroleum was awarded nine licences through the APA 2013 licensing round including four new licences in the southern Barents Sea. In addition, Lundin Petroleum acquired from Premier Oil a 30 percent interest in PL359 where Lundin Petroleum already held a 40 percent interest and is operator. Lundin Petroleum subsequently entered into two separate transactions whereby a five percent interest in PL359 was sold to OMV Norge and a 15 percent interest in PL359 was sold to Wintershall Norge. Following these transactions, Lundin Petroleum has a 50 percent interest in PL359 and these transactions have also ensured full partner alignment between PL359 and PL338 where the Edvard Grieg field is located. In January 2014, Lundin Petroleum farmed out ten percent in PL546 (WI 50% after farm-out) to Petrolia Norway. In August 2014, Lundin Petroleum farmed-into PL674 acquiring a 35 percent working interest and into PL674BS acquiring a 15 percent working interest. During the year, PL409, PL570, PL495 and PL453S were relinquished. PL338 will be split into two licences where the original PL338 licence contains the Edvard Grieg field and the carved-out licence, PL338C contains the remaining exploration potential of the original licence including the Gemini and the Rolvsnes prospects. Lundin Petroleum has farmed-out 30 percent of its 80 percent working interest in PL338C to Lime Petroleum Norway, subject to governmental approval. OMV Norge holds the remaining 20 percent interest.
In January 2015, the Ministry of Petroleum and Energy announced the licence awards in the 2014 APA licensing round. Lundin Petroleum was awarded eight licences of which six were awarded to Lundin Petroleum as operator.
| Production in Mboepd | WI | 2014 | 2013 |
|---|---|---|---|
| France | |||
| – Paris Basin | 100%1 | 2.5 | 2.5 |
| – Aquitaine | 50% | 0.4 | 0.4 |
| Netherlands | Various | 1.9 | 2.0 |
| 4.8 | 4.9 |
1 Working interest in the Dommartin Lettree field 42.5 percent
Production levels from France are substantially in line with forecast and incremental production from the Grandville redevelopment in the Paris Basin has been offsetting the natural decline from the other fields. Development drilling on the Vert la Gravelle re-development project commenced in the fourth quarter of 2014 but following the current weak oil price environment the drilling of the remaining five development wells will be deferred.
The Hoplites exploration well on the Est Champagne concession (WI 100%) was completed during the fourth quarter with no hydrocarbons encountered.
Production from the Netherlands has been in line with the forecast during the year.
The K5-A5 (Licence Interest 2.03%) development well was successfully drilled during the year and is expected to be put on production by mid-2015. The drilling of the K5-A6 (Licence Interest 2.03%) development well completed in early January 2015. The encountered reservoir was pressure depleted and the well will be plugged and abandoned. The E17-A5 (WI 1.20%) development well is currently drilling ahead. Lundin Petroleum is expecting to participate in two further development wells and two exploration wells during 2015.
An exploration well on E17a/b (WI 1.20%) was drilled during the year and has encountered gas. Development options are currently being assessed.
The Hempens-1 exploration well on the Leeuwarden licence (WI 7.2325%) was completed during the year as a dry well. The LW102ST development well also drilled on the Leeuwarden licence in the first quarter of 2014 was declared unsuccessful following testing.
The drilling of the Lambertschaag-2 exploration well on the Slootdorp licence (WI 7.2325%) was completed during the year and whilst gas was found in a shallower interval, the well is non-commercial.
The Langezwaag-2 exploration well on the Gorredijk licence (WI 7.75%) has been completed and gas was found in two intervals. The well commenced production in January 2015.
The Bertam field development on PM307 (WI 75%) is progressing according to schedule. The steel jacket was successfully completed and installed offshore Peninsular Malaysia during the year. The construction of the topside of the wellhead platform at the TH Heavy Engineering yard was successfully installed on the steel jacket during October 2014. The Bertam FPSO (formerly the Ikdam FPSO) upgrade and life extension work is now mechanically complete at the Keppel shipyard in Singapore and the Bertam FPSO was moored and hooked-up to the wellhead platform in February 2015. During the third quarter of 2014, the jack-up drilling rig West Prospero commenced drilling the Bertam development wells and drilling is expected to continue until late 2015. The subsurface development concept consists of 13 horizontal wells completed with electrical submersible pumps.
The Bertam field is estimated to contain gross reserves of 18 MMboe and is being developed through an unmanned wellhead platform adjacent to the spread-moored Bertam FPSO with a total estimated development cost of MUSD 400, excluding any FPSO related costs. The Bertam field is expected to commence first oil in the second quarter of 2015 with a gross plateau rate of 15.0 Mbopd.
The Tembakau-2 appraisal well on PM307 (WI 75%) has been successfully completed with production test results from the I10 and I20 sands yielding 15.9 and 15.8 MMscfd respectively. Conceptual development studies are ongoing and any development decision will likely be dependent on achievable gas prices.
Two exploration wells are planned to be drilled on Block PM307 during the fourth quarter of 2015 following the completion of the Bertam development drilling campaign. The exploration wells are targeting the Mengkuang-1 oil prospect, estimated to contain gross unrisked prospective resources of 21 MMboe and the Rengas oil prospect which is targeting gross unrisked prospective resources of 22 MMboe.
During the third quarter of 2014, Lundin Petroleum entered into a farm-in agreement with Petronas Carigali whereby Lundin Petroleum has acquired a 50 percent working interest and operatorship in PM328. The PM328 Block is located northeast of PM307 and spans 5,600 km2 . The initial PSC term covers three years with a work programme commitment of acquiring 600 km2 of 3D seismic within the first 18 months.
The previously announced farm-out agreement with HiRex Petroleum in relation to PM308B will not complete and the agreement has been terminated.
Lundin Petroleum continues to evaluate the potential for commercialisation of the Berangan, Tarap, Cempulut and Titik Terang gas discoveries on Block SB303 (WI 75%), most likely through a cluster development. These four discoveries are estimated to contain gross best estimate contingent resources of 347 bcf.
The Kitabu prospect, on SB307/SB308 (WI 42.5%), was drilled during the fourth quarter 2014 however the well failed to encounter any hydrocarbons.
Lundin Petroleum's assets in Indonesia are located in the Natuna Sea and offshore northeastern Indonesia and onshore south Sumatra. The Indonesian assets consist of approximately 24,750 km² of exploration acreage and one producing field onshore Sumatra.
| Production in Mboepd | WI | 2014 | 2013 |
|---|---|---|---|
| Singa | 25.9% | 1.4 | 1.6 |
The production from the Singa field was below forecast during the year, primarily due to certain facility issues and a shut-in to re-route the gas pipeline. In early 2014, a revised gas sales agreement, with an effective date of 2 January 2014, was put in place for the Singa field resulting in an increased gas sales price of USD 7.97 per million British Thermal Units (MMbtu) compared to the previous price of USD 5.20 per MMbtu. The agreement provides for an annual price escalation.
Exploration drilling on the Balqis and Boni prospects in the Baronang Block (WI 90%) in the Natuna Sea, Indonesia, was completed during the year. Both wells encountered good quality reservoirs at the projected Oligocene level but neither well encountered any hydrocarbons and were declared as dry wells. Lundin Petroleum is in the process of relinquishing both the Baronang and the Cakalang Blocks.
In October 2014, Lundin Petroleum announced that the exploration well on the Gobi prospect in the Gurita Block (WI 90%) was unsuccessful and has been plugged and abandoned as a dry well.
A 3D seismic acquisition programme of 1,000 km² has been completed on the South Sokang Block (WI 60%) in 2013. The seismic processing and interpretation is substantially complete with both oil and gas prospectivity identified at Miocene and Oligocene levels.
Lundin Petroleum is undertaking geological and technical studies on the Cendrawasih VII Block (WI 100%), offshore eastern Indonesia.
In November 2014, Lundin Petroleum entered into a joint study agreement for 100 percent of the exploration Block Cendrawasih VIII which is contiguous to Cendrawasih VII Block.
| Production in Mboepd | WI | 2014 | 2013 |
|---|---|---|---|
| Komi Republic | 50% | 1.1 | 2.3 |
In July 2014, Lundin Petroleum sold its entire interest in the Sotchemyu-Talyu and North Irael fields in the Komi Republic to Arawak Energy Russia BV for a cash consideration.
In the Lagansky Block (WI 70%) in the northern Caspian, a major oil discovery, Morskaya, was made in 2008 and is estimated to contain gross best estimate contingent resources of 157 MMboe. In October 2013, Lundin Petroleum announced a Heads of Agreement with Rosneft whereby Rosneft will acquire a 51 percent shareholding in LLC PetroResurs which owns a 100 percent interest in the Lagansky Block. The completion of the deal with Rosneft is uncertain due to a number of factors.
During the year, Lundin Petroleum had seven low severity Lost Time Incidents (LTI) among its contractors, which resulted in a LTI frequency rate of 0.25 per 200,000 hours. The LTI frequency rate in 2014 was the lowest rate recorded to date. The total recordable incident rate (TRIR) was 0.42. A minor oil spill occurred in France during 2014, and while the incident required the removal of soil where the spill occurred, there was no lasting impact on the environment.
In September 2014, Lundin Petroleum signed the UN Global Compact's Call to Action, an appeal by companies to governments urging them to enhance measures to combat corruption. The Board of Directors approved of the decision to take this additional step in demonstrating Lundin Petroleum's commitment to anti-corruption.
In terms of disclosure regarding climate change, the Carbon Disclosure Project, CDP Nordic Report attributed a score of 90B to Lundin Petroleum. This is the highest score obtained among Nordic oil and gas companies. The highest score attributed to an energy company was 92A, while the average disclosure scores for the Nordic region was 80C and for Sweden 82B.
The net result for the financial year 2014 amounted to MUSD -431.9 (MUSD 72.9). The net result attributable to shareholders of the Parent Company for the year amounted to MUSD -427.2 (MUSD 77.6) representing earnings per share, before and after dilution of USD -1.38 (USD 0.25).
Earnings before interest, tax, depletion and amortisation (EBITDA) for the year amounted to MUSD 671.3 (MUSD 955.7) representing EBITDA per share of USD 2.14 (USD 3.08). Operating cash flow for the year amounted to MUSD 1,138.5 (MUSD 967.9) representing operating cash flow per share of USD 3.63 (USD 3.12).
Revenue for the year amounted to MUSD 785.2 (MUSD 1,132.0) and was comprised of net sales of oil and gas, change in under/ over lift position and other revenue as detailed in Note 1.
Net sales of oil and gas for the year amounted to MUSD 745.0 (MUSD 1,160.4). The average price achieved by Lundin Petroleum for a barrel of oil equivalent amounted to USD 88.28 (USD 100.19) and is detailed in the following table. The average Dated Brent price for the year amounted to USD 98.95 (USD 108.66) per barrel.
Net sales of oil and gas for the year are detailed in Note 3 and were comprised as follows:
| Sales | ||
|---|---|---|
| Average price per boe expressed in USD | 2014 | 2013 |
| Crude oil sales | ||
| Norway | ||
| – Quantity in Mboe | 5,183.3 | 7,925.4 |
| – Average price per boe | 102.35 | 111.87 |
| France | ||
| – Quantity in Mboe | 1,028.7 | 1,030.4 |
| – Average price per boe | 94.08 | 106.93 |
| Netherlands | ||
| – Quantity in Mboe | 1.1 | 1.8 |
| – Average price per boe | 91.64 | 96.24 |
| Total crude oil sales | ||
| – Quantity in Mboe | 6,213.1 | 8,957.6 |
| – Average price per boe | 100.98 | 111.30 |
| Sales | ||
| Average price per boe expressed in USD | 2014 | 2013 |
| Gas and NGL sales | ||
| Norway | ||
| – Quantity in Mboe | 1,080.8 | 1,389.4 |
| – Average price per boe | 56.02 | 72.33 |
| Netherlands | ||
| – Quantity in Mboe | 687.9 | 715.7 |
| – Average price per boe | 51.11 | 64.34 |
| Indonesia | ||
| – Quantity in Mboe | 457.2 | 520.1 |
| – Average price per boe | 47.87 | 32.54 |
| Total gas and NGL sales | ||
| – Quantity in Mboe | 2,225.9 | 2,625.2 |
| – Average price per boe | 52.83 | 62.27 |
| Total sales | ||
| – Quantity in Mboe | 8,439.0 | 11,582.8 |
| – Average price per boe | 88.28 | 100.19 |
Sales of oil and gas are recognised when the risk of ownership is transferred to the purchaser. Sales quantities in a period can differ from production quantities as a result of permanent and timing differences. Permanent differences arise as a result of paying royalties in kind as well as the effects from production sharing agreements. Timing differences can arise due to under/ over lift of entitlement, inventory, storage and pipeline balances effects.
The change in under/over lift position amounted to a net credit of MUSD 23.4 (charge of MUSD 45.2) in the year. There was an underlift of entitlement movement on the Alvheim and Volund fields during the year due to the timing of the cargo liftings compared to production.
Other revenue amounted to MUSD 16.8 (MUSD 16.8) for the year and included the quality differential compensation received from the Vilje field owners to the Alvheim and Volund field owners, 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 66.5 (MUSD 139.6) and are detailed in the table below.
| Production costs | 2014 | 2013 |
|---|---|---|
| Cost of operations | ||
| – In MUSD | 94.4 | 103.0 |
| – In USD per boe | 10.86 | 9.28 |
| Tariff and transportation expenses | ||
| – In MUSD | 18.4 | 21.6 |
| – In USD per boe | 2.12 | 1.95 |
| Royalty and direct production taxes | ||
| – In MUSD | 3.6 | 3.4 |
| – In USD per boe | 0.41 | 0.31 |
| Change in inventory position | ||
| – In MUSD | -0.8 | -2.0 |
| – In USD per boe | -0.09 | -0.18 |
| Other | ||
| – In MUSD | -49.1 | 13.6 |
| – In USD per boe | -5.65 | 1.21 |
| Total production costs | ||
| – In MUSD | 66.5 | 139.6 |
| – In USD per boe | 7.65 | 12.57 |
Note: USD per boe is calculated by dividing the cost by total production volume for the period (excluding Russia).
The total cost of operations for the year was MUSD 94.4 (MUSD 103.0) and included costs of MUSD 10.9 associated with well intervention work on two wells on the Alvheim field which was completed in the first quarter of 2014. There was well intervention work on the Alvheim and Volund fields, as well as radial drilling in the Paris Basin in the comparative period. The total cost of operations excluding operational projects amounted to MUSD 72.3 (MUSD 77.3) with most of the decrease versus the comparative period being attributable to the Gaupe field in Norway which was shut-in for most of the second half of 2014.
The cost of operations per barrel amounted to USD 10.86 (USD 9.28) for the year including the Alvheim well intervention work and other operational projects. The increase in the cost of operations per barrel compared to the same period last year is primarily due to the lower production volumes in the year. Excluding operational projects, the cost of operations amounted to USD 8.32 (USD 6.96) per barrel.
Other costs amounted to a credit of MUSD 49.1 (charge of MUSD 13.6) and substantially related to an operating cost share arrangement on the Brynhild field whereby the amount of operating cost varies with the oil price until mid-2017. This arrangement is being marked-to-market against the oil price curve and due to the low oil price at the end of 2014, an asset was recognised at 31 December 2014.
Depletion costs amounted to MUSD 131.6 (MUSD 156.0) and are detailed in Note 3. Norway's contribution to the total depletion cost for the year was 67 percent (75 percent) at an average rate of USD 13.75 (USD 13.40) per barrel. The lower depletion cost for the year compared to the same period last year is in line with the lower production volumes.
Decommissioning costs amounted to MUSD – (MUSD 13.3). The non-cash decommissioning costs charged to the income statement in the comparative period related to an increase in the site restoration estimate of the Gaupe field in Norway.
Exploration costs expensed in the income statement for the year amounted to MUSD 386.4 (MUSD 287.8) and are detailed in Note 3. During 2014, exploration costs relating to Norway of MUSD 272.1 (MUSD 285.4) were expensed and mainly related to unsuccessful wells that were drilled in PL501 (Torvastad), PL659 (Langlitinden), PL631 (Vollgrav South), PL555 (Storm), PL584 (Lindarormen) and PL625 (Kopervik). In addition, costs associated with the unsuccessful Kitabu-1 well on SB307/SB308, offshore Malaysia and the Balqis and Boni wells on the Baronang Block and the Gobi-1 well on the Gurita Block, offshore Indonesia, were expensed for an amount of MUSD 107.0.
Impairment costs expensed in the income statement for the year amounted to MUSD 400.7 (MUSD 123.4). The carrying value of oil and gas properties are continually assessed to ensure recoverability and due to the significantly lower oil price at the end of 2014, a non-cash pre-tax MUSD 400.7 impairment cost against the Brynhild field, Norway, was recognised. A deferred tax credit on the impairment of MUSD 309.7 was recognised in the deferred tax line of the income statement. The amount in the comparative period related to discoveries in Malaysia and Norway which were deemed uncommercial.
The general, administrative and depreciation expenses for the year amounted to MUSD 52.2 (MUSD 41.2) which included a charge of MUSD 8.9 (MUSD 4.7) in relation to the Group's long-term incentive plans (LTIP), see also Note 33. Fixed asset depreciation charges for the year amounted to MUSD 4.8 (MUSD 4.4).
Finance income for the year amounted to MUSD 1.8 (MUSD 3.4) and is detailed in Note 4.
Finance costs for the year amounted to MUSD 421.8 (MUSD 85.9) and are detailed in Note 5.
Interest expenses for the year amounted to MUSD 21.1 (MUSD 5.1) and represented the proportion of interest charged to the income statement. An additional amount of interest of MUSD 36.6 (MUSD 18.2) primarily associated with the funding of the Norwegian development projects was capitalised in the year.
Net foreign exchange losses for the year amounted to MUSD 356.3 (MUSD 46.5). Foreign exchange movements occur on the settlement of transactions denominated in foreign currencies and the revaluation of working capital and loan balances to the prevailing exchange rate at the balance sheet date where those monetary assets and liabilities are held in currencies other than the functional currencies of the Group's reporting entities. The US Dollar strengthened against the Euro during 2014 resulting in a foreign currency exchange loss on the US Dollar denominated external loan which is borrowed by a subsidiary using a functional currency of the Euro. In addition, the Norwegian Krone significantly weakened during 2014, generating a foreign currency exchange loss on an intercompany loan balance denominated in Norwegian Krone. A strengthening US Dollar currency has a positive overall value effect on the business as it increases the purchasing power of the US Dollar to purchase the currencies in which the Group incurs operational expenditure. Lundin Petroleum has hedged certain foreign currency operational expenditure amounts against the US Dollar as detailed in Note 12. During the year, the net realised exchange loss on settled foreign exchange hedges amounted to MUSD 22.8 (MUSD 5.5 gain). In addition, there were net foreign exchange losses recognised within other comprehensive income on foreign entities translated to the presentation currency of the Group of MUSD 196.3 (MUSD 31.7). In other comprehensive income there were also losses on the unsettled part of the cash flow hedges of MUSD 148.7 (MUSD 8.1) which mainly related to the unsettled foreign currency hedges.
The amortisation of the deferred financing fees amounted to MUSD 12.6 (MUSD 8.7) for the year and related to the expensing of the fees incurred in establishing the original USD 2.5 billion financing facility, and the subsequent increase to USD 4.0 billion in February 2014, over the period of usage of the facility.
Loan facility commitment fees for the year amounted to MUSD 21.4 (MUSD 17.1) with the increase over the comparative period being attributable to the increased facility size.
Share of result of joint ventures accounted for using the equity method for the year amounted to a loss of MUSD 12.9 (MUSD 0.2) and included a MUSD 12.6 (MUSD –) non-cash expense relating to the carrying value of the onshore Russian assets following the agreement to sell the assets. The onshore Russian assets were sold in July 2014.
The overall tax credit for the year amounted to MUSD 253.2 (charge of MUSD 215.1).
The current tax credit for the year amounted to MUSD 419.7 (charge of MUSD 24.7) of which MUSD 431.7 (MUSD 2.9) related to Norway due to the significant level of development and exploration and appraisal expenditure in Norway in the year and the tax depreciation on development expenditure incurred in prior years. The current tax credit in Norway for the year is partly offset by the current tax charge relating to operations in France and the Netherlands.
The deferred tax charge for the year amounted to MUSD 166.5 (MUSD 190.4) which predominantly related to Norway. The deferred tax charge arises primarily where there is a difference in depletion for tax and accounting purposes. During the fourth quarter of 2014, a deferred tax credit was recognised in the income statement on the impairment of the Brynhild field which amounted to MUSD 309.7.
The Group operates in various countries and fiscal regimes where corporate income tax rates are different from the regulations in Sweden. Corporate income tax rates for the Group vary between 20 percent and 78 percent. The effective tax rate calculated from the face of the income statement is 37 percent and does not reflect the effective rate of tax paid within each country of operation. The effective tax rate is also affected by items which do not receive a full tax credit such as the expensed exploration costs in Indonesia, net foreign exchange losses and the expense relating to the sale of the onshore Russian assets.
The net result attributable to non-controlling interest for the year amounted to MUSD -4.7 (MUSD -4.7) and related mainly to the non-controlling interest's share in a Russian subsidiary which is fully consolidated.
Oil and gas properties amounted to MUSD 4,182.6 (MUSD 3,820.8) and are detailed in Note 8.
Development and exploration and appraisal expenditure incurred in the financial year 2014 was as follows:
| Development expenditure in MUSD | 2014 | 2013 |
|---|---|---|
| Norway | 1,068.2 | 1,105.9 |
| France | 29.3 | 7.0 |
| Netherlands | 3.9 | 4.8 |
| Indonesia | -0.8 | -1.9 |
| Malaysia | 130.6 | 12.7 |
| 1,231.2 | 1,128.5 |
An amount of MUSD 1,068.2 (MUSD 1,105.9) of development expenditure was incurred in Norway during the year, of which MUSD 1,035.3 (MUSD 1,091.7) was invested in the Edvard Grieg, Brynhild and Bøyla field developments. In Malaysia, MUSD 130.6 (MUSD 12.7) was incurred during the year on the Bertam field development.
An amount of MUSD 118.8 (MUSD 29.8) was incurred during the year on upgrading the Bertam FPSO for use on the Bertam field, Malaysia. This amount is not shown in the table above and has been capitalised as part of other tangible fixed assets.
| Exploration and appraisal expenditure in MUSD |
2014 | 2013 |
|---|---|---|
| Norway | 572.8 | 506.4 |
| France | 5.9 | 2.4 |
| Indonesia | 47.5 | 18.5 |
| Malaysia | 42.7 | 36.1 |
| Russia | 4.0 | 6.0 |
| Other | 1.6 | 0.5 |
| 674.5 | 569.9 |
Exploration and appraisal expenditure of MUSD 572.8 (MUSD 506.4) was incurred in Norway during the year, primarily on the appraisal drilling of the Johan Sverdrup field and the Edvard Grieg southeastern extension, Gohta, and Luno II appraisal wells, as well as seven exploration wells. During the year MUSD 47.5 (MUSD 18.5) was spent in Indonesia mainly on drilling of the Balqis and Boni wells on the Baronang Block and the Gobi-1 well on the Gurita Block. In Malaysia, MUSD 42.7 (MUSD 36.1) was incurred in the year mainly on the appraisal drilling of Tembakau (PM307) and the Kitabu-1 well (SB307/ SB308).
Other tangible fixed assets amounted to MUSD 200.3 (MUSD 85.0) and included amounts relating to the Bertam FPSO.
Investments accounted for using the equity method amounted to MUSD – (MUSD 24.6) following the sale of the onshore Russian assets in July 2014.
Other shares and participations amounted to MUSD 4.7 (MUSD 22.0) and related to the shares held in ShaMaran Petroleum which are reported at market value with any change in value being recorded in other comprehensive income.
Long-term receivables amounted to MUSD – (MUSD 9.7) and the comparative amount related to the loan due from the sub-group which contained the onshore Russian assets that was accounted for using the equity method until the sale of the assets in July 2014.
Deferred tax assets amounted to MUSD 12.9 (MUSD 22.4) and are mainly related to the part of the tax loss carry forwards in the Netherlands that are expected to be utilised against future tax liabilities. The reduction in the deferred tax asset balance compared to the previous year was primarily due to a reclassification of a deferred tax liability.
Derivative instruments amounted to MUSD – (MUSD 3.0) and related to the mark-to-market gain on outstanding hedges due to be settled after twelve months, see also Note 12.
Other financial assets amounted to MUSD 32.3 (MUSD 11.9) and included MUSD 31.0 (MUSD –) relating to the long-term portion of the mark-to-market valuation of the Brynhild operating cost share arrangement where the share of the operating cost varies with the oil price. The comparative amount included the Etrion Corporation bonds that were sold during the first quarter of 2014.
Inventories amounted to MUSD 41.6 (MUSD 21.2) and included both well supplies and hydrocarbon inventories. The increase compared to the previous year is mainly due to drilling and other inventory bought for the Bertam project in Malaysia.
Trade receivables, which are all current, amounted to MUSD 40.3 (MUSD 125.8).
Prepaid expenses and accrued income amounted to MUSD 41.5 (MUSD 61.7) and represented prepaid operational and insurance expenditure.
Tax receivables amounted to MUSD 373.6 (MUSD 6.5) and related mainly to the Norwegian corporate tax refund in respect of 2014 which is due to be received in December 2015.
Joint operations debtors amounted to MUSD 49.1 (MUSD 25.2) and included a significant amount that was settled in January 2015.
Other receivables amounted to MUSD 32.6 (MUSD 36.0) and included an amount of MUSD 21.6 (MUSD –) relating to the Brynhild operating cost share agreement which related to the short-term portion of the mark-to-market valuation of the arrangement where the share of the operating cost varies with the oil price.
Underlift, amounting to MUSD 3.6 (MUSD 9.4) represented small underlift positions in Norway, France and the Netherlands, is also included, as well as VAT and other miscellaneous balances. The comparative amount included amounts receivable on farmout deals in Norway and Indonesia.
Cash and cash equivalents amounted to MUSD 80.5 (MUSD 82.4). Cash balances are held to meet ongoing operational funding requirements.
The provision for site restoration amounted to MUSD 274.1 (MUSD 241.6) and related to future decommissioning obligations. The provision has increased during the year due to the additions of infrastructure that have been put in place for the Norwegian and Malaysian development projects.
The provision for deferred taxes amounted to MUSD 973.3 (MUSD 1,066.0) of which MUSD 844.8 (MUSD 924.6) related to Norway. The provision mainly arises 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.
Derivative instruments amounted to MUSD 33.9 (MUSD 1.6) and related to the mark-to-market loss on outstanding foreign currency and interest rate hedges due to be settled after twelve months.
Other provisions amounted to MUSD 12.7 (MUSD 34.4) and included the non-current portion of the provision for Lundin Petroleum's LTIP scheme amounting to MUSD 1.8 (MUSD 30.8). Lundin Petroleum's LTIP scheme is outlined in this report in Note 33. The phantom option plan vested in May 2014 and 50 percent of the vested amount was paid during the second quarter of 2014. The second tranche of the phantom scheme
payable within twelve months was reclassified to current liabilities in the second quarter of 2014. The remaining entitlement under the phantom option plan for the former VP Finance and CFO was settled during the third quarter of 2014 in accordance with the rules of the plan. A farm-in payment is also included of MUSD 7.5 (MUSD –) and related to a provision for payments towards historic costs on Block PM307, Malaysia, see also Other Current Liabilities section.
Financial liabilities amounted to MUSD 2,654.0 (MUSD 1,239.1) and included Bank loans of MUSD 2,690.0 (MUSD 1,275.0) relating to the outstanding loan under the Group's increased USD 4.0 billion revolving borrowing base facility. Capitalised financing fees relating to the establishment costs of the financing facility amounted to MUSD 36.0 (MUSD 35.9) and are being amortised over the expected life of the financing facility.
Other non-current liabilities amounted to MUSD 29.1 (MUSD 25.0) and mainly arose from the full consolidation of a subsidiary in which the non-controlling interest entity has made funding advances in relation to LLC PetroResurs, Russia.
Derivative instruments amounted to MUSD 101.4 (MUSD 4.0) and related to the mark-to-market loss on outstanding foreign currency and interest rate hedge contracts due to be settled within twelve months.
Other accrued expenses amounted to MUSD 46.1 (MUSD 39.4) and included an amount of MUSD 19.4 (MUSD 4.8) relating to the work performed on the Bertam FPSO.
Joint operations creditors and accrued expenses amounted to MUSD 383.5 (MUSD 334.5) and related mainly to the increased development and drilling activity in Norway and on the Bertam development project in Malaysia.
Other liabilities amounted to MUSD 37.9 (MUSD 40.7) and included a liability for the phantom option plan amounted to MUSD 28.2 (MUSD –) representing the second tranche of the phantom option plan including social costs due within twelve months. The phantom option plan is now fully vested and the liability has been reclassified from provisions to current liabilities. Overlift is also included and amounted to MUSD – (MUSD 29.2) with the overlift position at the start of the year being reversed into a small underlift position at the end of 2014.
Short-term provisions amounted to MUSD 53.4 (MUSD 46.2) and included an amount of MUSD 48.5 (MUSD –) relating to a payment for historic costs on Block PM307, Malaysia, which is payable on first oil from the Bertam project. Also included in short-term provisions is an amount of MUSD 4.9 (MUSD 46.2) relating to the current portion of the provision for Lundin Petroleum's Unit Bonus Plan.
The Annual General Meeting will be held in Stockholm on 7 May 2015.
The intention of the Board of Directors is to propose to the 2015 AGM the adoption of a Policy on Remuneration for 2015 that follows in essence the same principles as applied in 2014 and that contains similar elements of remuneration for Group management as the 2014 Policy on Remuneration being base salary, yearly variable salary, Long-term Incentive Plan (LTIP) and other benefits.
The Board will propose that the AGM also resolve on a longterm, performance-based incentive plan in respect of Group management and a number of key employees of Lundin Petroleum, which follows the same principles as LTIP 2014 approved by the 2014 AGM. LTIP 2015 gives the participants the possibility to receive shares in Lundin Petroleum subject to the fulfilment of a performance condition under a three year performance period commencing on 1 July 2015 and expiring on 1 July 2018. The performance condition is based on the share price growth and dividends (Total Shareholder Return) of the Lundin Petroleum share compared to the Total Shareholder Return of a peer group of companies. At the beginning of the performance period, the participants will be granted awards free of charge which, provided that the performance condition is met, entitle the participant to be allotted free of charge shares in Lundin Petroleum at the end of the performance period.
The number of performance shares that may be allotted to each participant is limited to a value of three times his/her annual gross base salary for 2015. The total number of performance shares that may be allotted under LTIP 2015 is 900,000, corresponding to approximately 0.3 percent of the total number of outstanding shares in Lundin Petroleum. The Board of Directors may reduce (including reduce to zero) allotment of performance shares at its discretion, should it consider the underlying performance not to be reflected in the outcome of the performance condition, for example, in light of operating cash flow, reserves, and health and safety performance.
The participants will not be entitled to transfer, pledge or dispose of the LTIP awards or any rights or obligations under LTIP 2015, or perform any shareholders' rights regarding the LTIP awards during the performance period.
The LTIP awards entitle participants to acquire already existing shares. To ensure delivery of the required number of shares under LTIP 2015, the Board of Directors will consider means to secure the Company's commitment. One method would be to enter into an equity swap agreement with a third party on terms in accordance with market practice, whereby the third party in its own name shall be entitled to acquire and transfer shares in Lundin Petroleum to the participants.
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 specific case.
For a detailed description of the Policy on Remuneration applied in 2014, see the Corporate Governance report on pages 68–69. The remuneration to Board and Group management is detailed in Notes 32 and 33.
For the AGM resolution on the authorisation to issue new shares, see pages 14–15, Share and Shareholders.
The Board of Directors propose that no dividend be paid for the year. For details of the dividend policy see page 14, Share and Shareholders.
The Board of Directors propose that the unrestricted equity of the Parent Company of MSEK 6,996.0, including the net result for the year of MSEK 108.7 be brought forward.
At the 2015 AGM, all the current members of the Board of Directors will be proposed for re-election, except Asbjørn Larsen who has declined to stand for re-election. Grace Reksten Skaugen will be proposed for election as a new member of the Board of Directors.
The result of the Group's operations and financial position at the end of the financial year are shown in the following income statement, statement of comprehensive income, balance sheet, statement of cash flow, 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 flow, statement of changes in equity and related notes presented in Swedish Kroner can be found on pages 121–125.
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 pages 54–73.
for the Financial Year Ended 31 December
| Expressed in MUSD | Note | 2014 | 2013 1 |
|---|---|---|---|
| Revenue | 1 | 785.2 | 1,132.0 |
| Cost of sales | |||
| Production costs | 2 | -66.5 | -139.6 |
| Depletion and decommissioning costs | 3 | -131.6 | -169.3 |
| Exploration costs | 3 | -386.4 | -287.8 |
| Impairment costs of oil and gas properties | 3 | -400.7 | -123.4 |
| Gross profit/loss | -200.0 | 411.9 | |
| General, administration and depreciation expenses | -52.2 | -41.2 | |
| Operating profit/loss | -252.2 | 370.7 | |
| Result from financial investments | |||
| Finance income | 4 | 1.8 | 3.4 |
| Finance costs | 5 | -421.8 | -85.9 |
| -420.0 | -82.5 | ||
| Share of the result of joint ventures accounted for using the equity method |
6 | -12.9 | -0.2 |
| Profit/loss before tax | -685.1 | 288.0 | |
| Income tax | 7 | 253.2 | -215.1 |
| Net result | -431.9 | 72.9 | |
| Attributable to: | |||
| Shareholders of the Parent Company | -427.2 | 77.6 | |
| Non-controlling interest | -4.7 | -4.7 | |
| -431.9 | 72.9 | ||
| Earnings per share, before and after dilution – USD 2 | 28 | -1.38 | 0.25 |
1 The comparatives in the financial statements have been restated following the adoption of IFRS 11 Joint Arrangements, effective 1 January 2014, see Note 6.
2 Based on net result attributable to shareholders of the Parent Company, see Note 28.
for the Financial Year Ended 31 December
| Expressed in MUSD | Note | 2014 | 2013 |
|---|---|---|---|
| Net result | -431.9 | 72.9 | |
| Items that may be subsequently reclassified to profit or loss | |||
| Exchange differences foreign operations | -196.3 | -31.7 | |
| Cash flow hedges | -148.7 | -8.1 | |
| Available-for-sale financial assets | -15.3 | 1.9 | |
| Income tax relating to other comprehensive income | 7 | – | 1.9 |
| Other comprehensive income, net of tax | -360.3 | -36.0 | |
| Total comprehensive income | -792.2 | 36.9 | |
| Attributable to: | |||
| Shareholders of the Parent Company | -766.7 | 44.7 | |
| Non-controlling interest | -25.5 | -7.8 | |
| -792.2 | 36.9 |
for the Financial Year Ended 31 December
| Expressed in MUSD | Note | 2014 | 2013 1 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 8 | 4,182.6 | 3,820.8 |
| Other tangible assets | 9 | 200.3 | 85.0 |
| Investments accounted for using the equity method | 6 | – | 24.6 |
| Other shares and participations | 10 | 4.7 | 22.0 |
| Long-term receivables | – | 9.7 | |
| Deferred tax | 7 | 12.9 | 22.4 |
| Derivative instruments | 11 | – | 3.0 |
| Other financial assets | 13 | 32.3 | 11.9 |
| Total non-current assets | 4,432.8 | 3,999.4 | |
| Current assets | |||
| Inventories | 14 | 41.6 | 21.2 |
| Trade receivables | 15 | 40.3 | 125.8 |
| Prepaid expenses and accrued income | 16 | 41.5 | 61.7 |
| Derivative instruments | 11 | – | 3.2 |
| Tax receivables | 7 | 373.6 | 6.5 |
| Joint operations debtors | 49.1 | 25.2 | |
| Other receivables | 17 | 32.6 | 36.0 |
| Cash and cash equivalents | 18 | 80.5 | 82.4 |
| Total current assets | 659.2 | 362.0 | |
| TOTAL ASSETS | 5,092.0 | 4,361.4 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Share capital | 0.5 | 0.5 | |
| Additional paid in capital | 445.0 | 454.8 | |
| Other reserves | 19 | -436.2 | -96.7 |
| Retained earnings | 849.4 | 770.8 | |
| Net result | -427.2 | 77.6 | |
| Shareholders' equity | 431.5 | 1,207.0 | |
| Non-controlling interest | 34.2 | 59.8 | |
| Total equity | 465.7 | 1,266.8 | |
| Non-current liabilities | |||
| Provision for site restoration | 20 | 274.1 | 241.6 |
| Pension provision | 21 | 1.2 | 1.5 |
| Provision for deferred tax | 7 | 973.3 | 1,066.0 |
| Derivative instruments | 11 | 33.9 | 1.6 |
| Other provisions | 22 | 12.7 | 34.4 |
| Financial liabilities | 23 | 2,654.0 | 1,239.1 |
| Other non-current liabilities | 29.1 | 25.0 | |
| Total non-current liabilities | 3,978.3 | 2,609.2 | |
| Current liabilities | |||
| Trade payables | 23.9 | 16.3 | |
| Tax liabilities | 7 | 1.8 | 4.3 |
| Derivative instruments | 11 | 101.4 | 4.0 |
| Joint operations creditors and accrued expenses | 383.5 | 334.5 | |
| Other accrued expenses | 24 | 46.1 | 39.4 |
| Other liabilities | 25 | 37.9 | 40.7 |
| Provisions Total current liabilities |
22 | 53.4 648.0 |
46.2 485.4 |
| TOTAL EQUITY AND LIABILITIES | 5,092.0 | 4,361.4 1,870.3 |
|
| Pledged assets | 26 | 1,126.8 | |
| Contingent liabilities and assets | 27 | – | – |
1 The comparatives in the financial statements have been restated following the adoption of IFRS 11 Joint Arrangements, effective 1 January 2014, see Note 6.
for the Financial Year Ended 31 December
| Expressed in MUSD | Note | 2014 | 2013 1 |
|---|---|---|---|
| Cash flow from operations | |||
| Net result | -431.9 | 72.9 | |
| Adjustments for non-cash related items | 30 | 1,033.7 | 880.1 |
| Interest received | 0.9 | 0.9 | |
| Interest paid | -56.5 | -21.8 | |
| Income taxes paid | -13.8 | -188.2 | |
| Changes in working capital: | |||
| Change in inventories | -20.4 | -4.6 | |
| Change in underlift position | 5.8 | 17.1 | |
| Change in receivables | 41.0 | -41.8 | |
| Change in overlift position | -29.2 | 28.8 | |
| Change in liabilities | 111.9 | 163.2 | |
| Total cash flow from operations | 641.4 | 906.6 | |
| Cash flow from investments | |||
| Investment in oil and gas properties | -1,957.8 | -1,698.4 | |
| Investment in office equipment and other assets | -124.9 | -36.2 | |
| Disposal of bonds | 10.5 | – | |
| Investment in subsidiaries | – | -3.5 | |
| Share in result in joint venture | 11.7 | – | |
| Decommissioning costs paid | -1.2 | -1.5 | |
| Other payments | -0.1 | -0.4 | |
| Total cash flow from investments | -2,061.8 | -1,740.0 | |
| Cash flow from financing | |||
| Changes in long-term receivables | 9.8 | 3.5 | |
| Proceeds from borrowings | 1,669.7 | 915.1 | |
| Repayments of borrowings | -250.5 | -70.0 | |
| Paid financing fees | -20.7 | – | |
| Purchase of own shares | -9.8 | -20.1 | |
| Dividend paid to non-controlling interest | -0.1 | -0.1 | |
| Total cash flow from financing | 1,398.4 | 828.4 | |
| Change in cash and cash equivalents | -22.0 | -5.0 | |
| Cash and cash equivalents at the beginning of the year | 82.4 | 87.6 | |
| Currency exchange difference in cash and cash equivalents | 20.1 | -0.2 | |
| Cash and cash equivalents at the end of the year | 80.5 | 82.4 |
1 The comparatives in the financial statements have been restated following the adoption of IFRS 11 Joint Arrangements, effective 1 January 2014, see Note 6.
The effects of acquisitions and divestments of subsidiary companies have been excluded from the changes in the balance sheet items. The effects of currency exchange differences due to the translation of foreign group companies have also been excluded as these effects do not affect the cash flow. Cash and cash equivalents comprise cash and short-term deposits maturing within less than three months.
for the Financial Year Ended 31 December
| Attributable to owners of the Parent company | |||||||
|---|---|---|---|---|---|---|---|
| Total Equity comprises: Expressed in MUSD |
Share capital 1 |
Additional paid-in capital |
Other reserves 3 |
Retained earnings |
Total | Non controlling interest |
Total equity |
| 1 January 2013 | 0.5 | 474.9 | -63.8 | 770.8 | 1,182.4 | 67.7 | 1,250.1 |
| Comprehensive income | |||||||
| Net result | – | – | – | 77.6 | 77.6 | -4.7 | 72.9 |
| Currency translation difference | – | – | -28.6 | – | -28.6 | -3.1 | -31.7 |
| Cash flow hedges | – | – | -8.1 | – | -8.1 | – | -8.1 |
| Available for sale financial assets | – | – | 1.9 | – | 1.9 | – | 1.9 |
| Income tax relating to other comprehensive income |
– | – | 1.9 | – | 1.9 | – | 1.9 |
| Total comprehensive income | – | – | -32.9 | 77.6 | 44.7 | -7.8 | 36.9 |
| Transactions with owners | |||||||
| Distributions | – | – | – | – | – | -0.1 | -0.1 |
| Purchase of own shares | – | -20.1 | – | – | -20.1 | – | -20.1 |
| Total transactions with owners | – | -20.1 | – | – | -20.1 | -0.1 | -20.2 |
| 31 December 2013 | 0.5 | 454.8 | -96.7 | 848.4 | 1,207.0 | 59.8 | 1,266.8 |
| Comprehensive income | |||||||
| Net result | – | – | – | -427.2 | -427.2 | -4.7 | -431.9 |
| Currency translation difference | – | – | -175.5 | – | -175.5 | -20.8 | -196.3 |
| Cash flow hedges | – | – | -148.7 | – | -148.7 | – | -148.7 |
| Available for sale financial assets | – | – | -15.3 | – | -15.3 | – | -15.3 |
| Total comprehensive income | – | – | -339.5 | -427.2 | -766.7 | -25.5 | -792.2 |
| Transactions with owners 2 | |||||||
| Distributions | – | – | – | – | – | -0.1 | -0.1 |
| Purchase of own shares | – | -9.8 | – | – | -9.8 | – | -9.8 |
| Value of employee services | – | – | – | 1.0 | 1.0 | – | 1.0 |
| Total transactions with owners | – | -9.8 | – | 1.0 | -8.8 | -0.1 | -8.9 |
| 31 December 2014 | 0.5 | 445.0 | -436.2 | 422.2 | 431.5 | 34.2 | 465.7 |
1 Lundin Petroleum AB's issued share capital at 31 December 2014 amounted to SEK 3,179,106 represented by 311,070,330 shares. The USD equivalent of the issued share capital is MUSD 0.5. Included in the number of shares issued at 31 December 2014 are 2,000,000 shares which Lundin Petroleum holds in its own name.
2 During the year the Parent Company reduced its share capital by an amount of SEK 68,402.50 through the cancellation of 6,840,250 shares held in treasury. The reduction of the share capital was followed by a bonus issue of the same amount. The amounts were recognised against other reserves. In consequence the cancellation of shares did not impact the Company's share capital.
3 Other reserves are described in detail in Note 19.
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 (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 specified in the Parent Company accounting policies on page 121.
The preparation of financial 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 significant to the consolidated financial statements are disclosed under the headline "Critical accounting estimates and judgements".
The consolidated financial statements have been prepared under the historical cost convention, as modified by the revaluation of available for sale financial assets and financial assets and liabilities (including derivative instruments) at fair value through other comprehensive income.
As from 1 January 2014, Lundin Petroleum has applied the following new accounting standards:
IFRS 10, "Consolidated financial 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 financial statements.
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.
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 significant 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.
Other amendments applicable from 1 January 2014 did not have any impact on the consolidated financial statements of the Group.
The Group has not adopted the following standards and interpretations that are not yet mandatory.
IFRS 9 "Financial instruments" The standard addresses the classification, measurement and recognition of financial assets and financial liabilities. Effective from 1 January 2018.
IFRS 15 "Revenue from contract with customers" The standard addresses revenue recognition and establishes principles for reporting useful information to users of financial statements. Effective from 1 January 2017.
The Group is yet to assess the full impact of these standards.
Subsidiaries are all entities (including structured entities) over which the Group has control. The Group controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. The existence and effect 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. Identifiable 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 acquisitionby- acquisition basis, either at fair value or at the non-controlling interest's proportionate share of the recognised amounts of the acquiree's identifiable 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 remeasurement are recognised in income statement.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred and the fair value of noncontrolling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net assets of the subsidiary acquired, the difference is recognised in the income statement.
Inter-company transactions, balances, income and expenses on transactions between group companies are eliminated. Profits 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.
Oil and gas operations are conducted by the Group as colicencees in unincorporated joint operations with other companies, These joint operations are a type of joint arrangement whereby the parties have joint control. The Group's financial statements reflect the relevant proportions of production, capital costs, operating costs and current assets and liabilities of the joint operations applicable to the Group's interests.
An investment in an associated company is an investment in an undertaking where the Group exercises significant influence 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 financial 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 financial assets. If the value of these assets has declined significantly 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 are recognised in the income statement as part of net financial items.
Items included in the financial 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 financial 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 differences are recognised in the income statement. Transactions in foreign currencies are translated at exchange rates prevailing at the transaction date. Exchange differences are included in financial income/costs in the income statement except deferred exchange differences on qualifying cash flow 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 differences which arise are recorded directly in the foreign currency translation reserve within other comprehensive income. Upon disposal of a foreign operation the translation differences relating to that operation will be transferred from equity to the income statement and included in the result on sale. Translation differences arising from net investments in subsidiaries, used for financing exploration activities, are recorded directly in other comprehensive income.
For the preparation of the annual financial statements, the following currency exchange rates have been used.
| 2014 Average |
2014 Period end |
2013 Average |
2013 Period end |
|
|---|---|---|---|---|
| 1 USD equals NOK | 6.3011 | 7.4332 | 5.8753 | 6.0837 |
| 1 USD equals EUR | 0.7526 | 0.8236 | 0.7529 | 0.7251 |
| 1 USD equals RUR | 38.3878 | 59.5808 | 31.8675 | 32.8653 |
| 1 USD equals SEK | 6.8457 | 7.7366 | 6.5132 | 6.4238 |
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 operations 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 field area cost centre basis.
Costs directly associated with an exploration well are capitalised. 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 field 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 as production costs 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 field area is charged to the income statement through cost of sales 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 confidence 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 indicate are less likely to be recovered than Proved reserves but more certain to be recovered than Possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.
Proceeds from the sale or farm-out of oil and gas concessions in the exploration stage are offset against the related capitalised costs of each cost centre with any excess of net proceeds over the costs capitalised included in the income statement. In the event of a sale in the exploration stage, any deficit is included in the income statement.
Impairment tests are performed annually or when there are facts and circumstances that suggest that the carrying value of an asset capitalised costs within each field area less any provision for site restoration costs, royalties and deferred production or revenue related taxes is higher than the anticipated future net cash flow from oil and gas reserves attributable to the Group's interest in the related field areas. Capitalised costs cannot be carried unless those costs can be supported by future cash flows 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 flows using prices and cost levels used by Group management in their internal forecasting. If there is no decision to continue with a field specific exploration programme, the costs will be expensed at the time the decision is made.
Other tangible 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 three to five years for office equipment and other assets. The Bertam FPSO will be depreciated over its useful life once the upgrade of the vessel has been completed and it is on location on the Bertam field.
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 benefits associated with the item will flow 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.
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 flows to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific 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 flows 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 financial assets and liabilities:
participations do not have a quoted market price in an active market and whose fair value cannot be measured reliably, they are accounted for at cost less impairment if applicable. A gain or a loss on available for sale financial assets shall be recognised in other comprehensive income, except for impairment losses and foreign exchange gains and losses until the financial asset is derecognised.
· Derivative instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently remeasured at their fair value. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument. The Group also documents its assessment, both at hedge inception and on an ongoing basis, of whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. When derivatives do not qualify for hedge accounting, changes in fair value are recognised immediately in the income statement.
The Group has only cash flow hedges which qualify for hedge accounting. The effective portion of changes in the fair value of derivatives that qualify as cash flow hedges are recognised in other comprehensive income. The gain or loss relating to the ineffective 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 affect 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 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 field 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 field is included in the current liabilities and valued at the reporting date spot price or prevailing contract price.
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 effects, 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 available for sale 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 hedged item will be transferred to the income statement. The currency translation reserve contains unrealised translation differences 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 outflow 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 reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to passage of time is recognised as financial costs.
On fields 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 field 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 field and is charged to financial 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 effective interest method, with interest expense recognised on an effective yield basis.
The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial 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 offset 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 operations, is recognised as other income. The fiscal regime in the area of operations defines 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 specific 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 finance fields under development which is capitalised within oil and gas properties until production commences. All other borrowing costs are recognised in the income statement in the period in which they occur. Interest on borrowings to finance the acquisition of producing oil and gas properties is charged to the income statement as incurred
Short-term employee benefits such as salaries, social premiums and holiday pay, are expensed when incurred.
Pensions are the most common long-term employee benefits. The pension schemes are funded through payments to insurance companies. The Group's pension obligations consist mainly of defined contribution plans. A defined contribution plan is a pension plan under which the Group pays fixed 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 defined benefit plan. The relating liability recognised in the balance sheet is valued at the discounted estimated future cash outflows as calculated by an external actuarial expert. Actuarial gains and losses are recognised in other comprehensive income. The Group does not have any designated plan assets.
Cash-settled share-based payments are recognised 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. Equity-settled share-based payments are recognised in the income statement as expenses during the vesting period and as equity in the Balance Sheet. The option is measured at fair value at the date of grant using an options pricing model and is charged to the income statement over the vesting period without revaluation of the value of the option.
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 differences arising between the tax bases of assets and liabilities and their carrying values. Temporary differences 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 financial 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 affects neither accounting nor taxable profit nor loss. Deferred income tax is provided on temporary differences arising on investments in subsidiaries and associates, except where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the temporary difference 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 profit will be available against which the temporary differences can be utilised.
Deferred tax assets are offset 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 Group management, which, due to the unique nature of each country's operations, commercial terms or fiscal environment, is at a country level. Information for segments is only disclosed when applicable. Segmental information is presented in Notes; Note 3, Note 7 and Note 8.
The management of Lundin Petroleum has to make estimates and judgements when preparing the financial 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 reserves auditor reviews these estimates. See page 131 Reserve Quantity Information. Changes in estimates of oil and gas reserves, resulting in different future production profiles, will affect the discounted cash flows 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 inflation 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 8.
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 flows 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 affect the rate used to discount future cash flow 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 Note 3 and Note 8.
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 plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to the site decommissioning and restoration can be different. To reflect the effects 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 effects of changes in estimates do not give rise to prior year adjustments and are treated prospectively over the estimated remaining commercial reserves of each field. While the Group uses its best estimates and judgement, actual results could differ from these estimates.
Information about the carrying amounts of the Provision for site restoration is presented in Note 20.
All events up to the date when the financial statements were authorised for issue and which have a material effect in the financial statements have been disclosed.
of the Group
| MUSD | 2014 | 2013 |
|---|---|---|
| Crude Oil | 627.4 | 997.0 |
| Condensate | 3.0 | 3.4 |
| Gas | 114.6 | 160.0 |
| Net sales of oil and gas | 745.0 | 1,160.4 |
| Change in under/over lift position | 23.4 | -45.2 |
| Other operating income | 16.8 | 16.8 |
| 785.2 | 1,132.0 |
For further information on revenue, see the Directors' Report on page 83.
| MUSD | 2014 | 2013 |
|---|---|---|
| Cost of operations | 94.4 | 103.0 |
| Tariff and transportation expenses | 18.4 | 21.6 |
| Direct production taxes | 3.6 | 3.4 |
| Change in inventory position | -0.8 | -2.0 |
| Other | -49.1 | 13.6 |
| 66.5 | 139.6 |
For further information on production costs, see the Directors' Report on page 84.
The Group operates within several geographical areas. Operating segments are reported at country level which is consistent with the internal reporting provided to Group management.
The following tables present segment information regarding; revenue, production costs, exploration costs, impairment costs of oil and gas properties, gross profit and certain asset and liability information regarding the Group's business segments. In addition segment information is reported in Note 7 and Note 8.
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. Within each segment, revenues from transactions with a single external customer amount to ten percent or more of revenue for that segment. Approximately 70 percent of the total revenue is contracted with one customer. The Parent Company is included in Other in the table below.
| MUSD | 2014 | 2013 |
|---|---|---|
| Norway | ||
| Crude oil | 530.5 | 886.6 |
| Condensate | 1.7 | 2.0 |
| Gas | 58.8 | 98.5 |
| Net sales of oil and gas | 591.0 | 987.1 |
| Change in under/over lift position | 24.4 | -47.0 |
| Other revenue | 3.8 | 5.6 |
| Revenue | 619.2 | 945.7 |
| Production costs | -11.3 | -85.1 |
| Depletion and decommissioning costs | -88.5 | -130.2 |
| Exploration costs | -272.1 | -285.4 |
| Impairment costs of oil and gas properties | -400.7 | -81.7 |
| Gross profit/loss | -153.4 | 363.3 |
| MUSD | 2014 | 2013 |
|---|---|---|
| France | ||
| Crude oil | 96.8 | 110.2 |
| Net sales of oil and gas | 96.8 | 110.2 |
| Change in under/over lift position | -0.5 | -0.4 |
| Other revenue | 1.7 | 2.2 |
| Revenue | 98.0 | 112.0 |
| Production costs | -33.1 | -34.3 |
| Depletion and decommissioning costs | -16.9 | -12.5 |
| Exploration costs | -4.6 | -0.2 |
| Gross profit/loss | 43.4 | 65.0 |
| Netherlands | ||
| Crude oil | 0.1 | 0.2 |
| Condensate | 1.3 | 1.4 |
| Gas | 33.8 | 44.6 |
| Net sales of oil and gas | 35.2 | 46.2 |
| Change in under/over lift position | -0.5 | 2.2 |
| Other revenue | 2.2 | 1.7 |
| Revenue | 36.9 | 50.1 |
| Production costs | -16.8 | -14.7 |
| Depletion and decommissioning costs | -15.9 | -15.0 |
| Exploration costs | -1.4 | -1.3 |
| Gross profit/loss | 2.8 | 19.1 |
| Malaysia | ||
| Exploration costs | -14.4 | -0.5 |
| Impairment costs of oil and gas properties Gross profit/loss |
– -14.4 |
-41.7 -42.2 |
| Indonesia | ||
| Gas | 22.0 | 16.9 |
| Net sales of oil and gas | 22.0 | 16.9 |
| Other revenue | – | – |
| Revenue | 22.0 | 16.9 |
| Production costs | -5.4 | -5.0 |
| Depletion and decommissioning costs | -10.3 | -11.4 |
| Exploration costs | -94.2 | -0.4 |
| Gross profit/loss | -87.9 | 0.1 |
| Other | ||
| Other revenue | 9.1 | 7.3 |
| Revenue | 9.1 | 7.3 |
| Production costs | 0.1 | -0.5 |
| Depletion and decommissioning costs | – | -0.2 |
| Exploration costs | 0.3 | – |
| Gross profit/loss | 9.5 | 6.6 |
| MUSD | 2014 | 2013 |
|---|---|---|
| Total | ||
| Crude oil | 627.4 | 997.0 |
| Condensate | 3.0 | 3.4 |
| Gas | 114.6 | 160.0 |
| Net sales of oil and gas | 745.0 | 1,160.4 |
| Change in under/over lift position | 23.4 | -45.2 |
| Other revenue | 16.8 | 16.8 |
| Revenue | 785.2 | 1,132.0 |
| Production costs | -66.5 | -139.6 |
| Depletion and decommissioning costs | -131.6 | -169.3 |
| Exploration costs | -386.4 | -287.8 |
| Impairment costs of oil and gas properties | -400.7 | -123.4 |
| Gross profit/loss | -200.0 | 411.9 |
| Assets | Equity and Liabilities | |||
|---|---|---|---|---|
| MUSD | 2014 | 2013 | 2014 | 2013 |
| Norway | 3,549.3 | 2,975.9 | 3,188.1 | 2,545.2 |
| France | 237.4 | 258.9 | 128.6 | 120.6 |
| Netherlands | 2,819.8 | 2,067.9 | 3,019.2 | 1,689.3 |
| Malaysia | 683.8 | 267.7 | 447.1 | 60.1 |
| Indonesia | 63.4 | 123.3 | 229.1 | 248.1 |
| Russia | 501.8 | 594.8 | 422.4 | 421.1 |
| Sweden | 2.4 | 3.1 | 3.9 | 12.1 |
| Other | 113.9 | 124.2 | 67.7 | 52.5 |
| Intercompany balance elimination | -2,879.8 | -2,054.4 | -2,879.8 | -2,054.4 |
| Assets/Liabilities | 5,092.0 | 4,361.4 | 4,626.3 | 3,094.6 |
| Shareholders' equity | N/A | N/A | 431.5 | 1,207.2 |
| Non-controlling interest | N/A | N/A | 34.2 | 59.6 |
| Total equity for the Group | N/A | N/A | 465.7 | 1,266.8 |
| Total consolidated | 5,092.0 | 4,361.4 | 5,092.0 | 4,361.4 |
See Note 8 for detailed information of the oil and gas properties per country.
For further information on revenue, production costs, depletion and decommissioning costs, exploration costs, impairment costs of oil and gas properties see the Directors' Report on pages 83–85.
| MUSD | 2014 | 2013 |
|---|---|---|
| Interest income | 1.2 | 2.4 |
| Guarantee fees | 0.5 | 0.5 |
| Other | 0.1 | 0.5 |
| 1.8 | 3.4 |
| MUSD | 2014 | 2013 |
|---|---|---|
| Interest expense | 21.1 | 5.1 |
| Foreign currency exchange loss, net | 356.3 | 46.5 |
| Result on interest rate hedge settlement | 2.4 | 1.5 |
| Unwinding of site restoration discount | 7.0 | 5.9 |
| Amortisation of deferred financing fees | 12.6 | 8.7 |
| Loan facility commitment fees | 21.4 | 17.1 |
| Other | 1.0 | 1.1 |
| 421.8 | 85.9 |
During 2014, MUSD 36.6 (MUSD 18.2) of interest was capitalised relating to development projects.
Exchange rate variations result primarily from fluctuations in the value of the USD currency against a pool of currencies which includes, amongst others, EUR, NOK and the Russian Rouble (RUR). Lundin Petroleum has USD denominated debt recorded in subsidiaries using a functional currency other than USD. For further information on the foreign exchange loss see the Directors' Report on page 85.
In July 2014, Lundin Petroleum completed the sale of its interests in the Russian onshore producing assets in the Komi Region. These assets were proportionally consolidated until the end of 2013. Following the adoption of IFRS 11 Joint Arrangements from 1 January 2014, these jointly controlled entities have been accounted for using the equity method up to the date of the sale.
| Number of shares | |||
|---|---|---|---|
| MUSD | 31 December 2014 | 31 December 2013 | Share % |
| RF Energy Investments Ltd. | – | 11,540 | 50 |
| - CJSC Pechoraneftegas | – | 20,000 | Direct 100, indirect 50 |
| - LLC Zapolyarneftegas | – | 1 | Direct 100, indirect 50 |
| - LLC NK Recher-Komi | – | 1 | Direct 100, indirect 50 |
| - Geotundra BV | – | 20,000 | Direct 100, indirect 50 |
"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.
| 2014 | ||
|---|---|---|
| RF Energy consolidated | Sold July | 2013 |
| MUSD | 2014 | 12 months |
| Income statement | ||
| Revenue | 60.2 | 127.7 |
| Operating and other net costs | -60.8 | -128.0 |
| Net result | -0.6 | -0.3 |
| Balance Sheet | ||
| Non-current assets | – | 62.1 |
| Current assets | – | 32.8 |
| Total assets | – | 94.9 |
| Equity | – | 49.2 |
| Non-current liabilities | – | 31.6 |
| Current liabilities | – | 14.1 |
| Total equity and liabilities | – | 94.9 |
In addition to its 50 percent share of the above loss, the Group also recognised a net loss of MUSD 12.6 relating to the carrying value of the assets in 2014.
Following the adoption of IFRS 11 joint arrangement from 1 January 2014, the income statement and balance sheet at 31 December 2013 has been restated. The effect of the change of accounting policy is shown in the table below.
| MUSD | 2013 Reported | Effect of IFRS 11 | 2013 Restated |
|---|---|---|---|
| Income statement | |||
| Revenue | 1,195.8 | -63.8 | 1,132.0 |
| Operating costs | -824.8 | 63.5 | -761.3 |
| Operating result | 371.0 | -0.3 | 370.7 |
| Financial items | -83.0 | 0.5 | -82.5 |
| Result from investment in associated company | – | -0.2 | -0.2 |
| Profit before tax | 288.0 | – | 288.0 |
| Tax | -215.1 | – | -215.1 |
| Net result | 72.9 | – | 72.9 |
| Balance sheet | |||
| Long-term receivable | – | 9.7 | 9.7 |
| Non-current assets | 3,996.1 | -31.0 | 3,965.1 |
| Investment in associated company | – | 24.6 | 24.6 |
| Current assets | 378.4 | -16.4 | 362.0 |
| Total assets | 4,374.5 | -13.1 | 4,361.4 |
| Equity | 1,266.8 | – | 1,266.8 |
| Non-current liabilities | 2,615.3 | -6.1 | 2,609.2 |
| Current liabilities | 492.4 | -7.0 | 485.4 |
| Total equity and liabilities | 4,374.5 | -13.1 | 4,361.4 |
| Tax charge MUSD |
2014 | 2013 |
|---|---|---|
| Current tax | ||
| Norway | -431.7 | 2.9 |
| France | 8.9 | 19.2 |
| Netherlands | 2.4 | 3.5 |
| Indonesia | – | -1.7 |
| Russia | 0.1 | – |
| Other | 0.6 | 0.8 |
| -419.7 | 24.7 | |
| Deferred tax | ||
| Norway | 172.2 | 196.2 |
| France | 5.9 | 4.7 |
| Netherlands | 8.1 | -9.8 |
| Indonesia | -10.3 | 1.6 |
| Russia | -0.2 | -0.1 |
| Malaysia | -9.2 | -2.2 |
| 166.5 | 190.4 | |
| Total tax | -253.2 | 215.1 |
For further information on income taxes, see the Directors' Report on page 85.
The tax on the Group's profit before tax differs from the theoretical amount that would arise using the tax rate of Sweden as follows:
| MUSD | 2014 | 2013 |
|---|---|---|
| Profit/loss before tax | -685.1 | 288.0 |
| Tax calculated at the corporate tax rate in Sweden 22% (22%) | 150.7 | -63.4 |
| Effect of foreign tax rates | 138.8 | -179.9 |
| Tax effect of expenses non-deductible for tax purposes | -116.1 | -33.9 |
| Tax effect of deduction for petroleum tax | 101.0 | 55.8 |
| Tax effect of utilisation of unrecorded tax losses | 6.0 | 13.2 |
| Tax effect of creation of unrecorded tax losses | -30.5 | -7.4 |
| Adjustments to prior year tax assessments | 3.3 | 0.5 |
| Tax credit/charge | 253.2 | -215.1 |
The tax rate in Norway is 78 percent and is the primary reason for the significant effect of foreign tax rates in the table above.
The tax charge/credit relating to components of other comprehensive income is as follows:
| 2014 | 2013 | ||||
|---|---|---|---|---|---|
| Before tax | credit | After tax | Before tax | credit | After tax |
| -196.3 | – | -196.3 | -31.7 | – | -31.7 |
| -148.7 | – | -148.7 | -8.1 | 1.9 | -6.2 |
| -15.3 | – | -15.3 | 1.9 | – | 1.9 |
| -360.3 | – | -360.3 | -37.9 | 1.9 | -36.0 |
| – | – | ||||
| Tax charge/ – – |
Tax charge/ 1.9 1.9 |
The deferred tax amounting to MUSD – (MUSD 1.9 income) has been recorded directly in other comprehensive income.
| Current | Deferred | |||
|---|---|---|---|---|
| Corporation tax liability - current and deferred MUSD |
2014 | 2013 | 2014 | 2013 |
| Norway | – | 3.6 | 844.8 | 924.6 |
| France | – | – | 43.9 | 43.1 |
| Netherlands | 1.3 | 0.2 | 0.9 | 5.2 |
| Indonesia | – | – | – | 7.1 |
| Russia | 0.3 | 0.3 | 83.7 | 76.7 |
| Malaysia | – | – | – | 9.2 |
| Other | 0.2 | 0.2 | – | 0.1 |
| Total tax liability | 1.8 | 4.3 | 973.3 | 1,066.0 |
There is also a tax receivable of MUSD 373.6 (MUSD 6.5) mainly relating to Norway reported in tax receivable as at 31 December 2014.
| Specification of deferred tax assets and tax liabilities 1 | ||
|---|---|---|
| MUSD | 2014 | 2013 |
| Deferred tax assets | ||
| Unused tax loss carry forwards | 253.5 | 102.3 |
| Overlift position | – | 18.8 |
| Other deductible temporary differences | 18.0 | 19.9 |
| 271.5 | 141.0 | |
| Deferred tax liabilities | ||
| Accelerated allowances | 1,064.8 | 1,093.8 |
| Brynhild operating cost share | 38.7 | – |
| Exchange gains and losses | 19.1 | – |
| Deferred tax on excess values | 109.1 | 90.6 |
| Other taxable temporary differences | 0.2 | 0.2 |
| 1,231.9 | 1,184.6 |
1 The specification 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 asset is primarily relating to tax loss carried forwards in Norway and the Netherlands for an amount of MUSD 105.2 (MUSD 30.9) and unused uplift carry forward in Norway of MUSD 134.7 (MUSD 59.4). 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 liability arises mainly on accelerated allowances, being the difference 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 liability 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 271 (MUSD 181). The Dutch tax losses can be carried forward and utilised for up to nine years. A deferred tax asset relating to MUSD 59 (MUSD 57) of the tax loss carry forwards has not been recognised as at 31 December 2014 due to the uncertainty as to the timing and the extent of the tax loss carry forward utilisation. This treatment is consistent with the comparative year's accounts.
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Production cost pools | 1,054.9 | 684.8 |
| Non-production cost pools | 3,127.7 | 3,136.0 |
| 4,182.6 | 3,820.8 |
| MUSD | Norway | France | Netherlands | Indonesia | Total |
|---|---|---|---|---|---|
| Cost | |||||
| 1 January | 1,146.2 | 347.4 | 150.7 | 66.4 | 1,710.7 |
| Additions | 27.8 | 29.3 | 3.9 | -0.9 | 60.1 |
| Change in estimates | 11.5 | -0.1 | -3.8 | – | 7.6 |
| Reclassifications | 926.2 | 0.2 | – | – | 926.4 |
| Currency translation difference | -215.1 | -43.9 | -17.8 | – | -276.8 |
| 31 December | 1,896.6 | 332.9 | 133.0 | 65.5 | 2,428.0 |
| Depletion | |||||
| 1 January | -771.1 | -130.8 | -96.6 | -27.4 | -1,025.9 |
| Depletion charge for the year | -88.5 | -16.8 | -15.9 | -10.2 | -131.5 |
| Impairment | -400.7 | – | -0.5 | – | -401.2 |
| Currency translation difference | 156.2 | 16.9 | 12.4 | – | 185.5 |
| 31 December | -1,104.1 | -130.7 | -100.6 | -37.7 | -1,373.1 |
| Net book value | 792.5 | 202.2 | 32.4 | 27.8 | 1,054.9 |
| 2013 production cost pools, MUSD | Norway | France | Netherlands | Indonesia | Total | ||
|---|---|---|---|---|---|---|---|
| Cost | |||||||
| 1 January | 1,221.0 | 317.7 | 137.0 | 68.3 | 1,744.0 | ||
| Additions | 14.3 | 7.0 | 4.8 | -1.9 | 24.2 | ||
| Change in estimates | 14.7 | 1.0 | 2.7 | – | 18.4 | ||
| Reclassifications | – | 6.8 | – | – | 6.8 | ||
| Currency translation difference | -103.8 | 14.9 | 6.2 | – | -82.7 | ||
| 31 December | 1,146.2 | 347.4 | 150.7 | 66.4 | 1,710.7 | ||
| Depletion | |||||||
| 1 January | -718.5 | -113.0 | -76.3 | -16.0 | -923.8 | ||
| Depletion charge for the year | -117.2 | -12.5 | -15.0 | -11.4 | -156.1 | ||
| Impairment | – | – | -1.3 | – | -1.3 | ||
| Currency translation difference | 64.6 | -5.3 | -4.0 | – | 55.3 | ||
| 31 December | -771.1 | -130.8 | -96.6 | -27.4 | -1,025.9 | ||
| Net book value | 375.1 | 216.6 | 54.1 | 39.0 | 684.8 | ||
| 2014 non-production cost pools, MUSD | Norway | France | Netherlands | Indonesia | Russia | Malaysia | Total |
| 1 January | 2,310.5 | 7.9 | 6.0 | 62.7 | 559.0 | 189.9 | 3,136.0 |
|---|---|---|---|---|---|---|---|
| Additions | 1,663.8 | 5.9 | 1.9 | 47.5 | 4.0 | 230.8 | 1,953.9 |
| Expensed Exploration costs | -272.1 | -4.6 | -0.9 | -94.2 | – | -14.4 | -386.2 |
| Change in estimates | 36.4 | – | – | – | – | 21.7 | 58.1 |
| Reclassifications | -926.2 | -0.2 | – | – | – | – | -926.4 |
| Currency translation difference | -644.4 | -1.0 | -0.8 | 0.1 | -62.1 | 0.5 | -707.7 |
| 31 December | 2,168.0 | 8.0 | 6.2 | 16.1 | 500.9 | 428.5 | 3,127.7 |
| 2013 non-production cost pools, MUSD | Norway | France | Netherlands | Indonesia | Russia | Malaysia | Total |
| 1 January | 1,199.7 | 12.2 | 5.1 | 44.6 | 563.0 | 183.4 | 2,008.0 |
| Additions | 1,598.1 | 2.4 | 0.6 | 18.5 | 6.0 | 48.7 | 1,674.3 |
| Expensed Exploration costs | -285.4 | -0.2 | – | -0.4 | – | -0.5 | -286.5 |
| Impairment | -81.7 | – | – | – | – | -41.7 | -123.4 |
| Change in estimates | 25.1 | – | – | – | – | – | 25.1 |
| Reclassifications | – | -6.8 | – | – | – | – | -6.8 |
| Currency translation difference | -145.3 | 0.3 | 0.3 | – | -10.0 | – | -154.7 |
| 31 December | 2,310.5 | 7.9 | 6.0 | 62.7 | 559.0 | 189.9 | 3,136.0 |
In 2014, the reclassification from Non-production cost pools to Production cost pools related to the Brynhild field, Norway, which commenced production in December 2014.
Lundin Petroleum carried out its impairment testing for each producing and development asset at 31 December 2014 in conjunction with the annual reserves audit process. Lundin Petroleum used an oil price curve based on year end price forecasts, a future cost inflation factor of 2% (2%) per annum and a discount rate of 8% (8%) to calculate the future post-tax cash flows. As a result of the impairment testing performed, the carrying value of the Brynhild asset, Norway, was impaired by a pre-tax amount of MUSD 400.7. For further information on impairment, see the Directors' Report on page 84.
During 2014, MUSD 36.6 (MUSD 18.2) of capitalised interest costs were added to oil and gas properties and relate to Norwegian and Malaysian development projects. The interest rate for capitalised borrowing costs is calculated at the external facility borrowing rate of LIBOR plus the margin of 2.75% per annum.
The Group participates in joint operations 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 2014 are estimated to be MUSD 501.5 (MUSD 490.7) of which third parties who are joint operations partners will contribute approximately MUSD 252.2 (MUSD 224.4).
| 2014 | 2013 | |||||||
|---|---|---|---|---|---|---|---|---|
| Real | Real | |||||||
| MUSD | FPSO | estate | Other | Total | FPSO | estate | Other | Total |
| Cost | ||||||||
| 1 January | 63.4 | 11.3 | 40.1 | 114.8 | 32.5 | 11.3 | 22.2 | 66.0 |
| Acquired on consolidation | – | – | – | – | – | – | 12.7 | 12.7 |
| Additions | 118.8 | – | 6.1 | 124.9 | 29.8 | – | 6.4 | 36.2 |
| Disposals | – | – | -0.1 | -0.1 | – | – | -0.1 | -0.1 |
| Currency translation difference | -3.3 | -0.1 | -5.3 | -8.7 | 1.1 | – | -1.1 | – |
| 31 December | 178.9 | 11.2 | 40.8 | 230.9 | 63.4 | 11.3 | 40.1 | 114.8 |
| Depreciation | ||||||||
| 1 January | – | -1.6 | -28.2 | -29.8 | – | -1.6 | -15.0 | -16.6 |
| Disposals | – | – | 0.1 | 0.1 | – | – | – | – |
| Acquired on consolidation | – | – | – | – | – | – | -9.6 | -9.6 |
| Depreciation charge for the year | – | -0.1 | -4.6 | -4.7 | – | -0.1 | -4.3 | -4.4 |
| Currency translation difference | – | 0.1 | 3.7 | 3.8 | – | 0.1 | 0.7 | 0.8 |
| 31 December | – | -1.6 | -29.0 | -30.6 | – | -1.6 | -28.2 | -29.8 |
| Net book value | 178.9 | 9.6 | 11.8 | 200.3 | 63.4 | 9.7 | 11.9 | 85.0 |
The depreciation charge for the year is based on cost and an estimated useful life of three to five years for office equipment and other assets. Real estate is depreciated using an estimated useful life of 20 years and taking into account its residual value. Depreciation is included within the general, administration and depreciation line in the income statement.
The Bertam FPSO will be depreciated over its useful life once the upgrade of the vessel has been completed and it is on location on the Bertam field.
| 31 December 2014 | ||||||
|---|---|---|---|---|---|---|
| Other shares and participations comprise: | Number of shares | Share % | Book amount MUSD |
Book amount MUSD |
||
| ShaMaran Petroleum Corp. | 50,000,000 | 6.2 % | 4.7 | 21.6 | ||
| Cofraland BV 1 | – | – | – | 0.4 | ||
| 4.7 | 22.0 |
1 Cofraland BV was liquidated in 2014.
The investment in ShaMaran Petroleum Corp. (ShaMaran) was booked at the fair value of the shares at the date of acquisition in 2009 and under accounting rules, subsequent movements in the fair value of the shares is being recorded in other comprehensive income. See also Note 35.
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.
| MUSD | 2014 | 2013 |
|---|---|---|
| 1 January | 21.6 | 19.6 |
| Fair value movement | -15.3 | 1.5 |
| Currency translation difference | -1.6 | 0.5 |
| 31 December | 4.7 | 21.6 |
The accounting policies for financial instruments have been applied to the line items below:
| 31 December 2014 | Loan receivables and other |
Available | Fair value recognised in |
Derivatives used | |
|---|---|---|---|---|---|
| MUSD | Total | receivables | for sale | profit or loss | for hedging |
| Assets | |||||
| Other shares and participations | 4.7 | – | 4.7 | – | – |
| Other non current financial assets | 32.3 | 32.3 | – | – | – |
| Joint operations debtors | 49.1 | 49.1 | – | – | – |
| Other current receivables | 446.5 | 446.5 | – | – | – |
| Cash and cash equivalents | 80.5 | – | – | 80.5 | – |
| 613.1 | 527.9 | 4.7 | 80.5 | – | |
| Financial | |||||
| liabilities valued at amortised |
Fair value recognised in |
Derivatives used | |||
| Total | Other liabilities | cost | profit or loss | for hedging | |
| Liabilities | |||||
| Financial liabilities | 2,654.0 | – | 2,654.0 | – | – |
| Other non-current liabilities | 29.1 | 29.1 | – | – | – |
| Derivative instruments | 135.3 | – | – | – | 135.3 |
| Joint operations creditors | 383.5 | 383.5 | – | – | – |
| Other current liabilities | 63.6 | 63.6 | – | – | – |
| 3,265.5 | 476.2 | 2,654.0 | – | 135.3 |
| 31 December 2013 MUSD |
Total | Loan receivables and other receivables |
Available for sale |
Fair value recognised in profit or loss |
Derivatives used for hedging |
|---|---|---|---|---|---|
| Assets | |||||
| Other shares and participations | 22.0 | – | 22.0 | – | – |
| Other non current financial assets | 11.9 | 1.5 | 10.4 | – | – |
| Other non current receivables | 9.7 | 9.7 | – | – | – |
| Derivative instruments | 6.2 | – | – | – | 6.2 |
| Joint operations debtors | 25.2 | 25.2 | – | – | – |
| Other current receivables | 168.3 | 168.3 | – | – | – |
| Cash and cash equivalents | 82.4 | – | – | 82.4 | – |
| 325.7 | 204.7 | 32.4 | 82.4 | 6.2 |
| Total | Other liabilities | Financial liabilities valued at amortised cost |
Fair value recognised in profit or loss |
Derivatives used for hedging |
|
|---|---|---|---|---|---|
| Liabilities | |||||
| Financial liabilities | 1,239.1 | – | 1,239.1 | – | – |
| Other non-current liabilities | 25.0 | 25.0 | – | – | – |
| Derivative instruments | 5.6 | – | – | – | 5.6 |
| Joint operations creditors | 334.5 | 334.5 | – | – | – |
| Other current liabilities | 61.3 | 61.3 | – | – | – |
| 1,665.5 | 420.8 | 1,239.1 | – | 5.6 |
The fair value of loan receivables and other receivables equal the book value.
For financial 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, financial instruments measured at fair value can be detailed as follows:
| 31 December 2014 | |||
|---|---|---|---|
| MUSD | Level 1 | Level 2 | Level 3 |
| Assets | |||
| Cash and cash equivalents | 80.5 | – | – |
| Other shares and participations | 4.7 | – | – |
| Other financial assets | 32.3 | – | – |
| 117.5 | – | – | |
| Liabilities | |||
| Derivative instruments | – | 135.3 | – |
| – | 135.3 | – | |
| 31 December 2013 | |||
|---|---|---|---|
| MUSD | Level 1 | Level 2 | Level 3 |
| Assets | |||
| Cash and cash equivalents | 82.4 | – | – |
| Other shares and participations | 21.6 | – | 0.4 |
| Bonds | 10.4 | – | – |
| Long-term receivables | 9.7 | – | – |
| Derivative instruments | – | 6.2 | – |
| 124.1 | 6.2 | 0.4 | |
| Liabilities | |||
| Derivative instruments | – | 5.6 | – |
| – | 5.6 | – |
| Other shares and participations Level 3 MUSD |
2014 | 2013 |
|---|---|---|
| 1 January | 0.4 | 0.4 |
| Disposal/liquidation | -0.4 | – |
| 31 December | – | 0.4 |
The outstanding derivative instruments can be specified as follows:
| Fair value of outstanding derivative | 31 December 2014 | 31 December 2013 | ||
|---|---|---|---|---|
| instruments (MUSD) | Assets | Liabilities | Assets | Liabilities |
| Interest rate swaps | – | 22.3 | – | 1.0 |
| Currency hedge | – | 113.0 | 6.2 | 4.6 |
| Total | – | 135.3 | 6.2 | 5.6 |
| Non-current | – | 33.9 | 3.0 | 1.6 |
| Current | – | 101.4 | 3.2 | 4.0 |
| Total | – | 135.3 | 6.2 | 5.6 |
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 effective portion of the interest rate swap as at 31 December 2014 amounted to a net liability of MUSD 22.3 (MUSD 1.0).
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 effective portion of the currency hedge as at 31 December 2014 amounted to a net liability of MUSD 113.0 (MUSD 1.6 net asset).
As an international oil and gas exploration and production company operating globally, Lundin Petroleum is exposed to financial risks such as currency risk, interest rate risk, credit risks, liquidity risks as well as the risk related to the fluctuation in the oil price. The Group seeks to control these risks through sound management practice and the use of internationally accepted financial instruments, such as oil price, interest rate and foreign exchange hedges. Lundin Petroleum uses financial instruments solely for the purpose of minimising risks in the Group's business.
For further information on risks in the financial reporting see the section Internal control and risk management for the financial reporting in the Corporate Governance report on pages 72–73 and risks and risk management on pages 40–43.
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 flexibility. Lundin Petroleum is not subject to any externally-imposed capital requirements.
No significant changes were made in the objectives, policies or processes during the year ended 31 December 2014.
Lundin Petroleum monitors capital on the basis of net debt. Net debt is calculated as bank loans as shown in the balance sheet less cash and cash equivalents.
| MUSD | 31 December 2014 | 31 December 2013 |
|---|---|---|
| Bank loans | 2,690.0 | 1,275.0 |
| Less cash and cash equivalents | -80.5 | -82.4 |
| Net debt | 2,609.5 | 1,192.6 |
The increase in net debt compared to 2013 is mainly due to the funding of the Group's development activities.
Lundin Petroleum is exposed to interest rate risk through the credit facility (see also Liquidity risk below). Lundin Petroleum will assess the benefits 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 rate hedge.
The total interest expense for 2014 amounted to MUSD 60.1 which includes MUSD 36.6 of capitalised interest related to borrowings for the Group's development activities and the result on the interest rate hedge setting. A 150 basis point shift in the interest rate would have resulted in a change in the total interest expense for the year of MUSD 6.3, taking into account the Group's interest rate hedges for 2014.
During March 2013, Lundin Petroleum entered into a three year fixed interest rate swap, starting 1 April 2013 in respect of MUSD 500 of borrowings, fixing the floating LIBOR rate at approximately 0.57 percent per annum for the duration of the hedge. In March 2014, Lundin Petroleum entered into further interest rate hedge swaps starting 1 July 2014 and ending in December 2018 as follows:
| Borrowings expressed in MUSD |
Fixing of floating LIBOR Rate per annum |
Settlement period |
|---|---|---|
| 1,000 | 0.21% | 1 Jul 2014 – 31 Dec 2014 |
| 1,500 | 0.52% | 1 Jan 2015 – 31 Dec 2015 |
| 1,500 | 1.50% | 1 Jan 2016 – 31 Mar 2016 |
| 2,000 | 1.50% | 1 Apr 2016 – 31 Dec 2016 |
| 1,500 | 2.32% | 1 Jan 2017 – 31 Dec 2017 |
| 1,000 | 3.06% | 1 Jan 2018 – 31 Dec 2018 |
Lundin Petroleum is a Swedish company which is operating globally and therefore attracts substantial foreign exchange exposure, both on transactions as well as on the translation from functional currency for entities to the Group's presentational currency of the US Dollar. The main functional currencies of Lundin Petroleum's subsidiaries are Norwegian Kroner (NOK), Euro (EUR) and Russian Rouble (RUR), as well as US Dollar, making Lundin Petroleum sensitive to fluctuations of these currencies against the US Dollar.
Lundin Petroleum's policy on the 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.
The Group entered into currency hedging contracts fixing the rate of exchange from USD into NOK to meet NOK operational requirements as summarised in the table below.
| Buy | Sell | Average contractual exchange rate |
Settlement period |
|---|---|---|---|
| MNOK 5,547.1 | MUSD 897.4 | NOK 6.18: USD 1 | Jan 2014 – Dec 2014 |
| MNOK 4,424.5 | MUSD 690.8 | NOK 6.40: USD 1 | Jan 2015 – Dec 2015 |
| MNOK 1,251.8 | MUSD 182.5 | NOK 6.86: USD 1 | Jan 2016 – Jun 2016 |
Under IAS 39, subject to hedge effectiveness testing, all of the hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. At 31 December 2014, a current liability of MUSD 101.4 (MUSD 4.0) and a non-current liability of MUSD 33.9 (MUSD 1.6) have been recognised representing the fair value of the outstanding currency and interest rate hedges. In addition, the comparative period's current and non-current asset related to currency hedge contracts amounted to MUSD 3.2 and MUSD 3.0 respectively.
The following table summarises the effect that a change in these currencies against the US Dollar would have on operating profit 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 31 December 2014.
| Operating profit in the financial statements (MUSD) | -252.2 | -252.2 | |
|---|---|---|---|
| Shift of currency exchange rates |
Average rate 2014 | 10% USD weakening | 10% USD strengthening |
| EUR/USD | 0.7526 | 0.6841 | 0.8278 |
| NOK/USD | 6.3011 | 5.7283 | 6.9312 |
| RUR/USD | 38.3878 | 34.8980 | 42.2266 |
| CHF/USD | 0.9140 | 0.8309 | 1.0054 |
| Total effect on operating result (MUSD) | -12.4 | 12.4 |
The foreign currency risk to the Group's income and equity from conversion exposure is not hedged.
Price of oil and gas are affected by the normal economic drivers of supply and demand as well as the financial investors and market uncertainty. Factors that influence these include operational decisions, natural disasters, economic conditions, political instability or conflicts or actions by major oil exporting countries. Price fluctuations can affect Lundin Petroleum's financial position.
The table below summarises the effect that a change in the oil price would have had on the net result and equity at 31 December 2014:
| Net result in the financial statements (MUSD) | -431.9 | -431.9 |
|---|---|---|
| Possible shift | -10% | 10% |
| Total effect on net result (MUSD) | -24.7 | 24.7 |
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 flexible approach towards oil price hedging, based on an assessment of the benefits of the hedge contract in specific circumstances. Based on analysis of the circumstances, Lundin Petroleum will assess the benefits of forward hedging monthly sales contracts for the purpose of establishing cash flow. If it believes that the hedging contract will provide an enhanced cash flow then it may choose to enter into an oil price hedge.
For the year ended 31 December 2014, the Group did not enter into oil price hedging contracts and there are no oil price hedging contracts outstanding as at 31 December 2014.
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 operations parties is to rely on the provisions of the underlying joint operating agreements to take possession of the licence or the joint operations partner's share of production for non-payment of cash calls or other amounts due.
As at 31 December 2014, the Group's trade receivables amounted to MUSD 40.3 (MUSD 125.8). There is no recent history of default. Other longterm and short-term receivables are considered recoverable and no provision for bad debt was accounted for as at 31 December 2014. Cash and cash equivalents are maintained with banks having strong long-term credit ratings.
Liquidity risk is defined 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 seven year senior 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. The facility is secured against certain cash flows generated by the Group and was increased to USD 4.0 billion in February 2014. It is expected that the Group's ongoing development and exploration expenditure requirements will be funded by the Group's operating cash flow and the loan facility. The amount available under the facility is recalculated every six months based upon the calculated cash flow generated by certain producing fields at an oil price and economic assumptions agreed with the banking syndicate providing the facility. The maturity date of the bank facility is June 2019 and there is a loan reduction schedule which commences in 2016 and reduces to zero by the final 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 flows. Based on the reduction schedule and the current availability calculation, part of the current outstanding bank loan balance falls due within five years. No loan repayments are required for the credit facility in 2015.
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 specified in the agreement, as are customary in financing 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 specified actions to enforce their security, including accelerating the repayment of outstanding amounts under the credit facility. The Group is not in breach of its financing facility agreement.
The table below analyses the Group's financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet date to the contractual maturity date. Loan repayments are made based upon a net present value calculation of the assets' future cash flows. No loan repayments are currently forecast under this calculation.
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Non-current | ||
| Repayment within 1–2 years: | ||
| - Derivatives | 20.3 | 1.5 |
| Repayment within 2–5 years: | ||
| - Bank loans | 2,690.0 | 704.0 |
| - Derivatives | 13.6 | 0.1 |
| Repayment after 5 years: | ||
| - Bank loans | – | 571.0 |
| - Other non-current liabilities | 29.1 | 25.0 |
| 2,753.0 | 1,301.6 |
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Current | ||
| Repayment within 6 months: | ||
| - Trade payables | 23.9 | 16.3 |
| - Tax liabilities | 1.8 | 4.3 |
| - Joint operations creditors | 383.5 | 334.5 |
| - Other current liabilities | 37.9 | 40.7 |
| - Derivatives | 35.0 | 1.5 |
| Repayment after 6 months: | ||
| - Derivatives | 66.4 | 2.5 |
| 548.5 | 399.8 |
Lundin Petroleum has, through its subsidiary Lundin Malaysia BV, entered into Production Sharing Contracts (PSC) with Petroliam Nasional Berhad, the oil and gas company of the Government of Malaysia (Petronas). Bank guarantees have been issued in support of the work commitments and other related costs in relation to certain of these PSCs and the outstanding amount of the bank guarantees at 31 December 2014 was MUSD 40.4 of which MUSD 7.7 is guaranteed until the end of 2015 with the remaining MUSD 32.7 guaranteed until 2017. An additional bank guarantee in support of work commitments in Indonesia was put in place in December 2014 for an amount of MUSD 1.0 which is guaranteed until the end of 2015.
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Bonds | – | 10.4 |
| Brynhild operating cost share | 31.0 | – |
| Other | 1.3 | 1.5 |
| 32.3 | 11.9 |
At 31 December 2013, the Group held 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. The bonds were sold during 2014.
The Brynhild operating cost share relates to the long-term portion of the mark-to-market valuation of the Brynhild operating cost share arrangement where the share of the operating cost varies with the oil price. The short-term portion is described in Note 17.
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Hydrocarbon stocks Drilling equipment and |
3.5 | 3.1 |
| consumable materials | 38.1 | 18.1 |
| 41.6 | 21.2 |
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.
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Prepaid rent | 0.9 | 0.7 |
| Prepaid operational payments | 36.5 | 52.2 |
| Prepaid insurance | 1.5 | 3.7 |
| Accrued income | – | 0.5 |
| Other | 2.6 | 4.6 |
| 41.5 | 61.7 |
Prepaid operational payments included MUSD 21.7 (MUSD 35.7) in relation to the mobilisation costs of a Norwegian rig that will be allocated to future wells.
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Underlift | 3.6 | 9.4 |
| Brynhild operating cost share | 21.6 | – |
| Short-term VAT receivable | 5.6 | 4.1 |
| Receivable on farm-out | 0.4 | 10.9 |
| Other | 1.4 | 11.6 |
| 32.6 | 36.0 |
The Brynhild operating cost share relates to the short-term portion of the mark-to-market valuation of the Brynhild operating cost share arrangement where the share of the operating cost varies with the oil price. The long-term portion is described in Note 13.
Cash and cash equivalents include only cash at hand or on bank. No short-term deposits are held as at 31 December 2014.
| MUSD | Available for sale reserve |
Hedge reserve |
Currency translation reserve |
Total other reserves |
|---|---|---|---|---|
| 1 January 2013 | 6.9 | 7.0 | -77.7 | -63.8 |
| Total comprehensive |
||||
| income | 1.9 | -6.2 | -28.6 | -32.9 |
| 31 December 2013 | 8.8 | 0.8 | -106.3 | -96.7 |
| Total comprehensive |
||||
| income | -15.3 | -148.7 | -175.5 | -339.5 |
| 31 December 2014 | -6.5 | -147.9 | -281.8 | -436.2 |
| MUSD | 2014 | 2013 |
|---|---|---|
| 1 January | 241.6 | 186.1 |
| Unwinding of site restoration discount | 7.0 | 5.9 |
| Decommissioning costs | 0.1 | 13.2 |
| Payments | -1.2 | -1.5 |
| Changes in estimates | 65.7 | 43.5 |
| Currency translation difference | -39.1 | -5.6 |
| 31 December | 274.1 | 241.6 |
In calculating the present value of the site restoration provision, a pre-tax discount rate of 3.5% (3.5%) was used which is based on longterm risk-free interest rate projections. Based on the estimates used in calculating the site restoration provision as at 31 December 2014, approximately 75% of the total amount is expected to be settled after more than 15 years.
| MUSD | 2014 | 2013 |
|---|---|---|
| 1 January | 1.5 | 1.5 |
| Actuarial gains | – | 0.2 |
| Instalments paid | -0.2 | -0.2 |
| Currency translation difference | -0.1 | – |
| 31 December | 1.2 | 1.5 |
In May 2002, the Compensation Committee recommended to the Board of Directors, and the Board of Directors approved, a pension to be paid to 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 Adolf H. Lundin, the monthly payments would be paid to his wife, Eva Lundin, for the duration of her life.
Pension payments totalling an annual amount of TCHF 138 (TUSD 151) are payable to Eva Lundin. The Company may, at its option, buy out the obligation to make the pension payments through a lump sum payment in the amount of TCHF 1,800 (TUSD 1,817).
| Farm in | ||||
|---|---|---|---|---|
| MUSD | LTIP | payment | Other | Total |
| 1 January 2014 | 77.0 | – | 3.6 | 80.6 |
| Additions | 13.1 | 56.0 | 0.2 | 69.3 |
| Payment | -44.8 | – | -0.2 | -45.0 |
| Reclassifications | -38.3 | – | – | -38.3 |
| Currency translation | ||||
| difference | -0.3 | – | -0.2 | -0.5 |
| 31 December 2014 | 6.7 | 56.0 | 3.4 | 66.1 |
| Non-current | 1.8 | 7.5 | 3.4 | 12.7 |
| Current | 4.9 | 48.5 | – | 53.4 |
| Total | 6.7 | 56.0 | 3.4 | 66.1 |
See Note 33 for more information on the Group's LTIP.
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Bank loans | 2,690.0 | 1,275.0 |
| Capitalised financing fees | -36.0 | -35.9 |
| 2,654.0 | 1,239.1 |
The upfront fees associated with the credit facility have been capitalised and are being amortised over the expected life of the financing facility. The interest rate on Lundin Petroleum's credit facility is floating and is currently LIBOR + 2.75% (2.75%) per annum.
For further information, see Note 12.
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Holiday pay | 7.3 | 11.0 |
| Operating costs | 33.2 | 20.1 |
| Social security charges | 3.5 | 3.4 |
| Salaries and wages | – | 0.1 |
| Other | 2.1 | 4.8 |
| 46.1 | 39.4 |
| MUSD | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Long-term incentive plan | 28.2 | – |
| Overlift | – | 29.2 |
| Withholding tax on salaries | 6.8 | 7.2 |
| VAT payable | 0.1 | 0.1 |
| Social charges payable | 0.6 | 0.7 |
| Mineral resource extraction tax | – | 0.6 |
| Other | 2.2 | 2.9 |
| 37.9 | 40.7 |
In February 2014, Lundin Petroleum increased its seven year senior secured revolving borrowing base facility to USD 4.0 billion as described in Note 12. 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. The pledged amount at 31 December 2014 is MUSD 1,126.8 (MUSD 1,870.3) equivalent and represents the accounting value of net assets of the Group companies whose shares are pledged as described in the parent company section below.
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 (Gunvor) 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 and timing of the contingent asset and liability related to the Lagansky Block are dependent on the outcome of future exploration, development and production activities. Due to the uncertainties related to these activities, estimates of the cash inflow and outflow cannot be calculated with certainty.
In connection with the sale by Lundin Petroleum of its Salawati (Indonesia) interests 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 field developments within the Salawati Island Block.
Earnings per share are calculated by dividing the net result attributable to shareholders of the Parent Company by the weighted average number of shares for the year.
| 2014 | 2013 | |
|---|---|---|
| Net result attributable to shareholders of the Parent Company (in USD) |
-427,209,353 | 77,553,799 |
| Weighted average number of shares for the year |
309,170,986 | 310,017,074 |
| Earnings per share (in USD) | -1.38 | 0.25 |
Diluted earnings per share is equal to earnings per share as the dilution effect of the Groups' 608,103 awards under the equity-settled long-term incentive plan is not significant.
| MUSD | Note | 2014 | 2013 |
|---|---|---|---|
| Exploration costs | 3 | 386.4 | 287.8 |
| Impairment of oil and gas properties | 3 | 400.7 | 123.4 |
| Depletion, depreciation and | |||
| amortisation | 8/9 | 136.2 | 160.5 |
| Amortisation of deferred financing fees | 5 | 12.6 | 8.7 |
| Unwinding of site restoration discount | 5/20 | 7.0 | 5.9 |
| Decommissioning costs | 3/20 | 0.1 | 13.2 |
| Long-term incentive plan | 14.5 | 9.9 | |
| Interest income | 4 | -1.2 | -2.4 |
| Current tax | 7 | -419.7 | 24.7 |
| Deferred tax | 7 | 166.5 | 190.4 |
| Interest expense | 5 | 21.1 | 5.1 |
| Exchange gains/losses | 4/5 | 333.5 | 52.1 |
| Brynhild operating cost share | 13/17 | -36.7 | – |
| Share of the result of joint ventures | |||
| accounted for using the equity method | 6 | 12.9 | – |
| Other provisions | 0.2 | 0.6 | |
| Other non-cash items | -0.4 | 0.3 | |
| Adjustment to cash flow from operations |
1,033.7 | 880.1 |
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 significant influence over the entity.
During 2014, the Group has entered into transactions with related parties on a commercial basis as shown below:
| MUSD | 2014 | 2013 |
|---|---|---|
| Purchase of services | -0.6 | -0.4 |
| Sale of services | 0.7 | 0.4 |
The related party transactions concern other parties that are controlled by key management personnel. Key management personnel include directors and Group management. The remuneration to the Board of directors and Group management is disclosed in Note 32. There are no balances related to key management personnel as at 31 December 2014.
| 2014 | 2013 | ||||
|---|---|---|---|---|---|
| Average number of employees per country | Total employees | of which men | Total employees |
of which men | |
| Parent Company in Sweden | 3 | 1 | 3 | 1 | |
| Subsidiaries abroad | |||||
| Norway | 320 | 240 | 218 | 163 | |
| France | 54 | 41 | 50 | 38 | |
| Netherlands | 7 | 4 | 8 | 4 | |
| Indonesia | 24 | 14 | 23 | 12 | |
| Russia | 43 | 24 | 44 | 26 | |
| Tunisia | – | – | 6 | 4 | |
| Malaysia | 98 | 68 | 60 | 35 | |
| Switzerland | 44 | 27 | 38 | 22 | |
| Total subsidiaries abroad | 590 | 418 | 447 | 304 | |
| Total Group | 593 | 419 | 450 | 305 |
| 2014 | 2013 | |||
|---|---|---|---|---|
| Board members and Group management | Total at year end |
of which men | Total at year end |
of which men |
| Parent Company in Sweden | ||||
| Board members 1 | 7 | 5 | 7 | 5 |
| Subsidiaries abroad | ||||
| Group management 1 | 7 | 6 | 7 | 6 |
| Total Group | 14 | 11 | 14 | 11 |
1 C. Ashley Heppenstall, CEO and Board member is only included in Group management.
| Note 32 – Remuneration to the Board of Directors, Group Management and Other Employees | |||||
|---|---|---|---|---|---|
| 2014 | 2013 | ||||
|---|---|---|---|---|---|
| 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 | 686 | 147 | 646 | 131 | |
| Employees | 454 | 236 | 214 | 114 | |
| Subsidiaries abroad | |||||
| Group management | 13,696 | 960 | 10,456 | 730 | |
| Other employees | 101,629 | 23,957 | 90,391 | 21,518 | |
| Total Group | 116,465 | 25,300 | 101,707 | 22,493 | |
| of which pension costs | 9,821 | 8,670 |
The table above shows the cost that has been recognised through the income statement during the year and does not equal the actual payments made. The Phantom option plan that vested in 2014 has mainly been recognised in previous years as it has been accrued for over the vesting period of the plan. The table below shows the actual payments made to Group management during 2014.
| Salaries and other remuneration for the Board members and Group management TUSD |
Fixed Board remuneration/ base salary and other benefits1 |
Short-term variable salary 2 |
Unit bonus plan |
Phantom option plan |
Remuneration for committee work |
Remuneration for work outside of directorship 3 |
Pension | Total 2014 |
Total 2013 |
|---|---|---|---|---|---|---|---|---|---|
| Parent Company in Sweden |
|||||||||
| Board members | |||||||||
| Ian H. Lundin | 150 | – | – | – | – | 232 | – | 382 | 389 |
| Peggy Bruzelius | 72 | – | – | – | 15 | – | – | 87 | 46 |
| Kristin Færøvik | – | – | – | – | – | – | – | – | 43 |
| Asbjørn Larsen | 72 | – | – | – | 15 | – | – | 87 | 87 |
| Lukas H. Lundin | 72 | – | – | – | – | – | – | 72 | 72 |
| William A. Rand | 72 | – | – | – | 37 | – | – | 109 | 114 |
| Magnus Unger | 72 | – | – | – | 15 | – | – | 87 | 141 |
| Cecilia Vieweg | 72 | – | – | – | 22 | – | – | 94 | 49 |
| Total Board members | 582 | – | – | – | 104 | 232 | – | 918 | 941 |
| Subsidiaries abroad | |||||||||
| Group management | |||||||||
| C. Ashley Heppenstall | 1,149 | 708 | – | 12,841 | – | – | 95 | 14,793 | 1,929 |
| Other 4 | 3,596 | 2,469 | 443 | 27,396 | – | – | 480 | 34,384 | 5,674 |
1 Other benefits include school fees and health insurance.
2 The bonus awarded and paid in 2014 relates to the assessment made by the Compensation Committee in January 2014, considering the employees' contributions to the results of the Group in 2013.
3 Other remuneration paid during 2014 relates to fees paid for work outside of the normal board duties undertaken by Board members on behalf of the Group. The payment of such fees was in accordance with fees approved by the 2013 and 2014 AGM.
Total Group management 4,745 3,177 443 40,237 – – 575 49,177 7,603
4 Comprises seven persons (Chief Operating Officer, Chief Financial Officer, Vice President Corporate Responsibility, Vice President Legal, Vice President Corporate Planning and Investor Relations, former Senior Vice President Development and former CFO). The comparative amounts in 2013 have been restated.
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 15% and 18% of the qualifying income for pension purposes. The Company provides for 60% of the pension contribution and the employee for the remaining 40%. Qualifying income is defined as annual base salary and short-term variable salary and is capped at approximately TCHF 842 (TUSD 842). The normal retirement age for the CEO is 65 years.
A mutual termination period of between one month and twelve months applies between the Company and Group management, 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' base salary, in the event of termination of employment due to a change of control of the Company. The Board of Directors is further authorised, in individual cases, to approve severance arrangements, in addition to the notice periods and the severance arrangements in respect of a change of control of the Company, where employment is terminated by the Company without cause, or otherwise in circumstances at the discretion of the Board. Such severance arrangements may provide for the payment of up to one year's base salary; no other benefits shall be included. Severance payments in aggregate (i.e. for notice periods and severance arrangements) shall be limited to a maximum of two years' base salary.
The former VP Finance and CFO left the Company in mid-2014. Under agreed severance terms he received a payment equal to one years´ base salary on his departure, which the Board authorised as a permitted deviation from the Policy on Remuneration for Group management, taking into account the special circumstances of his substantial contributions to the Company over his years of service. In addition he received payment of his full entitlement to the Phantom Option Plan in 2014.
See page 66–69 of the Corporate Governance report for further information on the Group's principles of remuneration and the Policy on Remuneration for the Group management for 2014.
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 final third after three years. The cash payment is conditional upon the holder of the units remaining an employee of the Group at the time of payment. The share price for determining the cash payment at the end of each vesting period will be the average of the Lundin Petroleum closing share price for the period five trading days prior to and following the actual vesting date. The exercise price at vesting date 31 May 2014 was SEK 131.30.
LTIPs that follow the same principles as the 2008 LTIP have subsequently been implemented each year.
The following table shows the number of units issued under the LTIPs, the amount outstanding as at 31 December 2014 and the year in which the units will vest.
| Plan | |||||
|---|---|---|---|---|---|
| Unit Bonus Plan | 2011 | 2012 | 2013 | 2014 | Total |
| Outstanding at the beginning of the period | 123,992 | 238,496 | 422,730 | – | 785,218 |
| Awarded during the period | – | – | – | 372,897 | 372,897 |
| Forfeited during the period | -4,251 | -8,004 | -14,359 | -1,383 | -27,997 |
| Exercised during the period | -119,741 | -116,392 | -138,055 | – | -374,188 |
| Outstanding at the end of the period | – | 114,100 | 270,316 | 371,514 | 755,930 |
| Vesting date | |||||
| 31 May 2015 | 114,100 | 135,158 | 123,838 | 373,096 | |
| 31 May 2016 | – | 135,158 | 123,838 | 258,996 | |
| 31 May 2017 | – | – | 123,838 | 123,838 | |
| Outstanding at the end of the period | 114,100 | 270,316 | 371,514 | 755,930 |
The costs associated with the unit bonus plans are as given in the following table.
| Unit Bonus Plan MUSD | 2014 | 2013 |
|---|---|---|
| 2010 | – | 0.5 |
| 2011 | 1.8 | 0.7 |
| 2012 | 1.1 | 2.2 |
| 2013 | 2.0 | 3.9 |
| 2014 | 1.4 | – |
| 6.3 | 7.3 |
LTIP awards are recognised in the financial statements pro rata over their vesting period. The total carrying amount for the provision for the Unit Bonus Plan including social costs at 31 December 2014 amounted to MUSD 6.7 (MUSD 8.8). The provision is calculated based on Lundin Petroleum's share price at the balance sheet date. The closing share price at 31 December 2014 was SEK 112.40.
At the AGM on 13 May 2009, the shareholders of Lundin Petroleum approved the implementation of an LTIP for Group management (being the President and Chief Executive Officer, the Chief Operating Officer, the former Chief Financial Officer and the former Senior Vice President Development) consisting of a grant of phantom options exercisable after five years from the date of grant. The exercise of these options entitled 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 is made in two equal instalments: (i) first on the date immediately following the fifth anniversary of the date of grant and (ii) second on the date which is one year following the date of the first payment. The grant amounted to 5,500,928 phantom options with an exercise price of SEK 52.91.
| Group management | Phantom options |
|---|---|
| C. Ashley Heppenstall | 2,062,848 |
| Alexandre Schneiter | 1,512,756 |
| Chris Bruijnzeels (Former SVP Development) | 962,662 |
| Geoffrey Turbott (Former VP Finance and CFO) | 962,662 |
| Group management | 5,500,928 |
The phantom options vested in May 2014 being the fifth anniversary of the date of grant. The recipients received 50 percent of the entitlement as a cash payment equal to the average closing price of the Company's shares during the fifth year following grant, less the exercise price, multiplied by the number of phantom options. The remaining entitlement under the phantom option plan for the former VP Finance and CFO was settled during the third quarter of 2014 in accordance with the rules of the plan. 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 however they have the right to receive new awards under the new performance based plan described below.
LTIP awards are recognised in the financial statements pro rata over their vesting period. The total carrying amount for the provision for the Phantom Option Plan including social costs at 31 December 2014 amounted to MUSD 28.2 (MUSD 68.2). 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 Phantom Option Plan for Group management amounted to MUSD 6.1 (MUSD 3.3), including social costs for the financial year ended 31 December 2014.
The AGM 2014 has resolved a performance based LTIP in respect of Group management and a number of key employees. The plan is effective from 1 July 2014. The total number of awards made in respect of 2014 was 608,103 and the related cost is recognised on a straight line basis over the three year performance period commencing 1 July 2014. Each award was fair valued at the date of award at SEK 81.40 using an option pricing model and as at 31 December 2014 an amount of MUSD 1.0 was accounted for. The allotment of shares at the end of the performance period is subject to certain performance conditions being met.
| Performance Based Incentive Plan | Awards |
|---|---|
| C. Ashley Heppenstall | 144,307 |
| Other 1 | 193,299 |
| Total Group management | 337,606 |
| Other employees | 270,497 |
| Total | 608,103 |
1 Comprises six persons (Chief Operating Officer, Chief Financial Officer, Vice President Corporate Responsibility, Vice President Legal, Vice President Corporate Planning and Investor Relations and former Senior Vice President Development).
| Performance Based Incentive Plan | 2014 |
|---|---|
| Outstanding at the beginning of the period | – |
| Awarded during the period | 608,103 |
| Forfeited during the period | – |
| Exercised during the period | – |
| Outstanding at the end of the period | 608,103 |
| TUSD | 2014 | 2013 |
|---|---|---|
| PwC | ||
| Audit fees | 1,136 | 1,104 |
| Audit related | 123 | 64 |
| Tax advisory services | 48 | 26 |
| Other fees | 12 | 344 |
| Total PwC | 1,320 | 1,538 |
| Remuneration to other auditors than PwC | 207 | 235 |
| Total | 1,527 | 1,773 |
Audit fees include the review of the 2014 half year report. Audit related costs include special assignments such as licence audits and PSC audits. Other fees in 2013 related to advice on business development activities.
In January 2015, Lundin Petroleum announced that it had been awarded eight licences in the Norwegian 2014 APA licensing round, six as operator.
The Bøyla field, Norway, commenced production on 19 January 2015.
In October 2014, Lundin Petroleum signed a standby purchase agreement in relation to a rights offering by ShaMaran Petroleum. Under this agreement, Lundin Petroleum and other major shareholders of ShaMaran agreed to exercise their pro rata number of rights to acquire ShaMaran shares, and to purchase any ShaMaran shares not subscribed for by other shareholders, in consideration for receiving a fee from ShaMaran, such fee to be payable in ShaMaran shares. The offering was completed by ShaMaran in February 2015. Under the standby purchase agreement, Lundin Petroleum exercised its pro rata number of rights to acquire 46.5 million ShaMaran shares for total consideration of CAD 4.65 million, and Lundin Petroleum purchased a further 20.4 million ShaMaran shares for total consideration of CAD 2.0 million. Lundin Petroleum received 7.3 million ShaMaran shares as a fee. Subsequent to the completion of the offering, Lundin Petroleum sold 20.4 million ShaMaran shares. As at 31 December 2014, prior to completion of the offering, Lundin Petroleum held 50.0 million ShaMaran shares representing 6.2 percent of the total outstanding ShaMaran shares at that date. As at 31 March 2015, Lundin Petroleum held 103.8 million ShaMaran shares, representing 6.6 percent of the total outstanding ShaMaran shares at that date.
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 108.7 (MSEK 76.1) for the year.
The result included general and administrative expenses of MSEK 144.9 (MSEK 105.7) and finance income of MSEK 209.9 (MSEK 181.4), including a dividend of MSEK 205.7 (MSEK 178.2) and guarantee fees of MSEK 3.5 (MSEK 3.1).
The tax credit amounting to MSEK 36.4 (MSEK –) reported as income tax represents the reversal of a historic tax provision.
Pledged assets of MSEK 8,717.8 (MSEK 12,014.5) relate to the accounting value of the pledge of the shares in respect of the financing facility entered into by its fully-owned subsidiary Lundin Petroleum BV.
In June 2010, the Swedish International Public Prosecution Office commenced an investigation into alleged violations of international humanitarian law in Sudan during 1997–2003. The Company is cooperating with the Prosecution Office by providing information regarding its operations in Block 5A in Sudan during the relevant time period and has in relation to the ongoing investigation incurred costs in the form of advisory fees and related expenses. Lundin Petroleum categorically refutes all allegations of wrongdoing and will continue to cooperate with the Prosecution Office's investigation.
The financial 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 (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 94–99.
for the Financial Year Ended 31 December
| Expressed in MSEK | Note | 2014 | 2013 |
|---|---|---|---|
| Revenue | 9.2 | 3.1 | |
| Gross profit | 9.2 | 3.1 | |
| General, administration and depreciation expenses | 7 | -144.9 | -105.7 |
| Operating loss | -135.7 | -102.6 | |
| Result from financial investments | |||
| Financial income | 1 | 209.9 | 181.4 |
| Financial costs | 2 | -1.9 | -2.7 |
| 208.0 | 178.7 | ||
| Profit before tax | 72.3 | 76.1 | |
| Income tax | 3 | 36.4 | – |
| Net result | 108.7 | 76.1 |
for the Financial Year Ended 31 December
| Expressed in MSEK | 2014 | 2013 |
|---|---|---|
| Net result | 108.7 | 76.1 |
| Other comprehensive income | – | – |
| Total comprehensive income | 108.7 | 76.1 |
| Attributable to: | ||
| Shareholders of the Parent Company | 108.7 | 76.1 |
| 108.7 | 76.1 |
for the Financial Year Ended 31 December
| ASSETS Non-current assets Shares in subsidiaries 8 7,871.8 7,871.8 Other financial fixed assets 0.2 0.2 Total non-current assets 7,872.0 7,872.0 Current assets Prepaid expenses and accrued income 3.4 5.7 Other receivables 4 13.3 11.6 Cash and cash equivalents 1.8 2.6 Total current assets 18.5 19.9 TOTAL ASSETS 7,890.5 7,891.9 EQUITY AND LIABILITIES Restricted equity Share capital 3.2 3.2 Statutory reserve 861.3 861.3 Total restricted equity 864.5 864.5 Unrestricted equity Other reserves 2,295.3 2,357.5 Retained earnings 4,592.0 4,515.9 Net profit 108.7 76.1 Total unrestricted equity 6,996.0 6,949.5 Total equity 7,860.5 7,814.0 Non-current liabilities Provisions 0.3 36.6 Payables to Group companies – 21.6 Total non-current liabilities 0.3 58.2 Current liabilities Trade payables 5.2 0.5 Payables to Group companies 13.5 – Accrued expenses and prepaid income 5 9.8 19.2 Other liabilities 1.2 – Total current liabilities 29.7 19.7 TOTAL EQUITY AND LIABILITIES 7,890.5 7,891.9 Pledged assets 6 8,717.8 12,014.5 Contingent liabilities 6 – – |
Expressed in MSEK | Note | 2014 | 2013 |
|---|---|---|---|---|
for the Financial Year Ended 31 December
| Expressed in MSEK | 2014 | 2013 |
|---|---|---|
| Cash flow from operations | ||
| Net result | 108.7 | 76.1 |
| Non-cash settled dividend | -205.7 | -178.2 |
| Other non-cash items | 168.2 | 159.6 |
| Unrealised exchange losses | 0.7 | -0.4 |
| Changes in working capital: | ||
| Change in current assets | 0.6 | 3.4 |
| Change in current liabilities | 10.5 | 10.9 |
| Total cash flow from operations | 83.0 | 71.4 |
| Cash flow from investments | ||
| Change in long-term financial fixed assets | -0.1 | -0.2 |
| Total cash flow from investments | -0.1 | -0.2 |
| Cash flow from financing | ||
| Change in long-term liabilities | -21.7 | 62.2 |
| Purchase of own shares | -62.2 | -131.9 |
| Total cash flow from financing | -83.9 | -69.7 |
| Change in cash and cash equivalents | -1.0 | 1.5 |
| Cash and cash equivalents at the beginning of the year | 2.6 | 1.1 |
| Currency exchange difference in cash and cash equivalents | 0.2 | – |
| Cash and cash equivalents at the end of the year | 1.8 | 2.6 |
for the Financial Year Ended 31 December
| Restricted Equity | Unrestricted Equity | |||||
|---|---|---|---|---|---|---|
| Expressed in MSEK | Share capital 1 |
Statutory reserve |
Other reserves |
Retained earnings |
Total | Total equity |
| Balance at 1 January 2013 | 3.2 | 861.3 | 2,489.4 | 4,515.9 | 7,005.3 | 7,869.8 |
| Total comprehensive income | – | – | – | 76.1 | 76.1 | 76.1 |
| Transactions with owners | ||||||
| Purchase of own shares | – | – | -131.9 | – | -131.9 | -131.9 |
| Total transactions with owners | – | – | -131.9 | – | -131.9 | -131.9 |
| Balance at 31 December 2013 | 3.2 | 861.3 | 2,357.5 | 4,592.0 | 6,949.5 | 7,814.0 |
| Total comprehensive income | – | – | – | 108.7 | 108.7 | 108.7 |
| Transactions with owners | ||||||
| Purchase of own shares | – | – | -62.2 | – | -62.2 | -62.2 |
| Total transactions with owners | – | – | -62.2 | – | -62.2 | -62.2 |
| Balance at 31 December 2014 | 3.2 | 861.3 | 2,295.3 | 4,700.7 | 6,996.0 | 7,860.5 |
1 During the year the Company reduced its share capital with an amount of SEK 68,402.50 through the cancellation of 6,840,250 shares held in treasury. The reduction of the share capital was followed by a bonus issue of the same amount. The amounts were recognised against other reserves. In consequence the cancellation of shares did not impact the Company's share capital.
of the Parent Company
| MSEK | 2014 | 2013 |
|---|---|---|
| Dividend | 205.7 | 178.2 |
| Guarantee fees | 3.5 | 3.1 |
| Foreign exchange gain | 0.7 | – |
| Other | – | 0.1 |
| 209.9 | 181.4 | |
| MSEK | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Social security charges | 1.1 | 0.7 |
| Directors fees | 0.5 | 0.3 |
| Lundin Foundation | – | 2.2 |
| Audit | 1.1 | 1.1 |
| Outside services | 7.1 | 14.9 |
| 9.8 | 19.2 |
| MSEK | 2014 | 2013 |
|---|---|---|
| Interest expenses Group | 1.9 | 2.3 |
| Foreign exchange losses, net | – | 0.4 |
| 1.9 | 2.7 |
Pledged assets relate to the accounting value of the pledge of the shares in respect of the new financing facility entered into by its fully-owned subsidiary Lundin Petroleum BV. See Note 26 in the notes to the financial statements of the Group.
| MSEK | 2014 | 2013 |
|---|---|---|
| Net result before tax | 72.3 | 76.1 |
| Tax calculated at the corporate tax rate in Sweden 22% (22%) |
-15.9 | -16.7 |
| Tax effect of dividend not taxable | 45.3 | 39.2 |
| Tax effect of expenses non-deductible for tax purposes |
-3.0 | -4.5 |
| Increase unrecorded tax losses | -26.4 | -18.0 |
| Reversal of tax provision | -36.4 | – |
| -36.4 | – |
| MSEK | 2014 | 2013 |
|---|---|---|
| PwC | ||
| Audit fees | 1.7 | 1.4 |
| Audit related | 0.1 | – |
| 1.8 | 1.4 |
There has been no remuneration to any auditors other than PwC.
| MSEK | 31 December 2014 |
31 December 2013 |
|---|---|---|
| Due from Group companies | 10.0 | 8.3 |
| VAT receivable | 1.2 | 2.9 |
| Other | 2.1 | 0.4 |
| 13.3 | 11.6 |
| Total number |
Nominal | Book amount |
Book amount |
||||
|---|---|---|---|---|---|---|---|
| MSEK | Registration number |
Registered office | of shares issued |
Percentage owned |
value per share |
31 Dec 2014 |
31 Dec 2013 |
| Directly owned | |||||||
| Lundin Petroleum BV | 27254196 | The Hague, Netherlands | 181 | 100 | EUR 100.00 | 7,871.8 | 7,871.8 |
| Lundin Services Ltd | LL09860 | Labuan, Malaysia | 100 | 100 | USD 0.01 | – | – |
| 7,871.8 | 7,871.8 | ||||||
| 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 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 Cendrawasih VII 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 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 | ||
| Jet Arrow SA | 660.2.774.006-9 | Collonge-Bellerive, Switzerland |
11,000 | 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 |
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 2014. Lundin Exploration BV and Lundin Komi BV were liquidated during 2014.
FINANCIAL REPORT Board Assurance
As at 8 April 2015, the Board of Directors and the President of Lundin Petroleum AB have adopted this annual report for the financial year ended 31 December 2014.
The Board of Directors and the President & CEO certify that the annual financial 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 financial position and profit 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, 8 April 2015
Lundin Petroleum AB (publ) Reg. Nr. 556610-8055
Ian H. Lundin Chairman
C. Ashley Heppenstall President & CEO
Peggy Bruzelius Board Member
Asbjørn Larsen Board Member
Lukas H. Lundin Board Member
William A. Rand Board Member
Magnus Unger Board Member
Cecilia Vieweg Board Member
Our audit report was issued on April 8, 2015.
PricewaterhouseCoopers AB
Klas Brand Authorised Public Accountant Lead Partner
Johan Malmqvist Authorised Public Accountant Partner
To the annual meeting of the shareholders of Lundin Petroleum AB (publ), corporate identity number 556610-8055
We have audited the annual accounts and consolidated accounts of Lundin Petroleum AB (publ) for the year 2014. The annual accounts and consolidated accounts of the company are included in the printed version of this document on pages 75–126.
The Board of Directors and the President are responsible for the preparation and fair presentation of these annual accounts in accordance with the Annual Accounts Act and of the consolidated accounts in accordance with International Financial Reporting Standards , as adopted by the EU, and the Annual Accounts Act, and for such internal control as the Board of Directors and the President determine is necessary to enable the preparation of annual accounts and consolidated accounts that are free from material misstatement, whether due to fraud or error.
Our responsibility is to express an opinion on these annual accounts and consolidated accounts based on our audit. We conducted our audit in accordance with International Standards on Auditing and generally accepted auditing standards in Sweden. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the annual accounts and consolidated accounts are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the annual accounts and consolidated accounts. The procedures selected depend on the auditor's judgement, including the assessment of the risks of material misstatement of the annual accounts and consolidated accounts, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company's preparation and fair presentation of the annual accounts and consolidated accounts in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by the Board of Directors and the President, as well as evaluating the overall presentation of the annual accounts and consolidated accounts.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinions.
In our opinion, the annual accounts have been prepared in accordance with the Annual Accounts Act and present fairly, in all material respects, the financial position of the parent company as of 31 December 2014 and of its financial performance and its cash flows for the year then ended in accordance with the Annual Accounts Act. The consolidated accounts have been prepared in accordance with the Annual Accounts Act and present fairly, in all material respects, the financial position of the group as of 31 December 2014 and of their financial performance and cash flows for the year then ended in accordance with International Financial Reporting
Standards, as adopted by the EU, and the Annual Accounts Act. The statutory administration report is consistent with the other parts of the annual accounts and consolidated accounts. We therefore recommend that the annual meeting of shareholders adopt the income statement and balance sheet for the parent company and the group.
In addition to our audit of the annual accounts and consolidated accounts, we have also audited the proposed appropriations of the company's profit or loss and the administration of the Board of Directors and the President of Lundin Petroleum AB (publ) for the year 2014. We have also conducted a statutory examination of the corporate governance statement.
The Board of Directors is responsible for the proposal for appropriations of the company's profit or loss, and the Board of Directors and the President are responsible for administration under the Companies Act and that the corporate governance statement has been prepared in accordance with the Annual Accounts Act.
Our responsibility is to express an opinion with reasonable assurance on the proposed appropriations of the company's profit or loss and on the administration based on our audit. We conducted the audit in accordance with generally accepted auditing standards in Sweden.
As a basis for our opinion on the Board of Directors' proposed appropriations of the company's profit or loss, we examined whether the proposal is in accordance with the Companies Act. As a basis for our opinion concerning discharge from liability, in addition to our audit of the annual accounts and consolidated accounts, we examined significant decisions, actions taken and circumstances of the company in order to determine whether any member of the Board of Directors or the President is liable to the company. We also examined whether any member of the Board of Directors or the President has, in any other way, acted in contravention of the Companies Act, the Annual Accounts Act or the Articles of Association.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinions. Furthermore, we have read the corporate governance statement and based on that reading and our knowledge of the company and the group we believe that we have a sufficient basis for our opinions. This means that our statutory examination of the corporate governance statement is different and substantially less in scope than an audit conducted in accordance with International Standards on Auditing and generally accepted auditing standards in Sweden.
We recommend to the annual meeting of shareholders that the profit be appropriated in accordance with the proposal in the statutory administration report and that the members of the Board of Directors and the President be discharged from liability for the financial year.
Stockholm, 8 April 2015
PricewaterhouseCoopers AB
Klas Brand Johan Malmqvist Authorised Public Accountant Authorised Public Accountant Lead Partner Partner
Key financial data is based on continuing operations.
| Financial data (MUSD) | 2014 | 2013 | 2012 | 2011 | 2010 |
|---|---|---|---|---|---|
| Revenue1 | 785.2 | 1,132.0 | 1,375.8 | 1,251.1 | 805.3 |
| EBITDA | 671.3 | 955.7 | 1,144.1 | 1,012.1 | 603.5 |
| Net result | -431.9 | 72.9 | 103.9 | 155.2 | 129.5 |
| Operating cash flow | 1,138.5 | 967.9 | 831.4 | 676.2 | 573.4 |
| Data per share (USD) | |||||
| Shareholders' equity per share | 1.40 | 3.90 | 3.81 | 3.22 | 2.96 |
| Operating cash flow per share | 3.68 | 3.12 | 2.68 | 2.17 | 1.84 |
| Cash flow from operations per share | 2.07 | 2.92 | 2.64 | 2.88 | 1.79 |
| Earnings per share | -1.38 | 0.25 | 0.35 | 0.51 | 0.46 |
| Earnings per share fully diluted | -1.38 | 0.25 | 0.35 | 0.51 | 0.46 |
| EBITDA per share | 2.17 | 3.08 | 3.68 | 3.25 | 1.93 |
| Dividend per share | – | – | – | – | 2.30 |
| Number of shares issued at period end | 311,070,330 | 317,910,580 | 317,910,580 | 317,910,580 | 317,910,580 |
| Number of shares in circulation at period end | 309,070,330 | 309,570,330 | 310,542,295 | 311,027,942 | 311,027,942 |
| Weighted average number of shares for the period | 309,170,986 | 310,017,074 | 310,735,227 | 311,027,942 | 312,096,990 |
| Share price | |||||
| Share price (SEK) | 112.40 | 125.40 | 149.50 | 169.20 | 83.65 |
| Share price (CAD) 2 | N/A | 19.73 | 22.87 | 24.54 | N/A |
| Key ratios (%) | |||||
| Return on equity | -50 | 6 | 9 | 15 | 12 |
| Return on capital employed | -11 | 16 | 35 | 53 | 24 |
| Net debt/equity ratio | 605 | 99 | 28 | 13 | 45 |
| Equity ratio | 9 | 29 | 38 | 40 | 41 |
| Share of risk capital | 28 | 53 | 66 | 69 | 67 |
| Interest coverage ratio | -13 | 52 | 75 | 59 | 19 |
| Operating cash flow/interest ratio | 49 | 149 | 119 | 55 | 27 |
| Yield | – | – | – | – | 18 |
1 Following the reclassification of the change in under/over lift from production cost to revenue from 1 January 2013, the comparatives have been restated.
2 The shares were listed on the Toronto Stock Exchange from March 2011 until November 2014 when the shares were voluntarily delisted.
In 2014, Lundin Petroleum adopted IFRS 11 Joint Arrangements. The reported numbers for year 2013 have also been restated for the effect of the adoption of the new standard.
Operating EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortisation): Operating profit before depletion of oil and gas properties, exploration costs, impairment costs, depreciation of other tangible assets and gain on sale of assets.
Revenue less production costs and less current taxes.
Shareholders' equity divided by the number of shares in circulation at period end.
Operating cash flow divided by the weighted average number of shares for the period.
Cash flow from operations in accordance with the consolidated statement of cash flow divided by the weighted average number of shares for the period.
Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period.
Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the period after considering any dilution effect.
EBITDA divided by the 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.
Net result divided by average total equity.
Income before tax plus interest expenses plus/less exchange differences on financial loans divided by the average capital employed (the average balance sheet total less non-interest bearing liabilities).
Bank loan less cash and cash equivalents divided by shareholders' equity.
Total equity divided by the balance sheet total.
The sum of the total equity and the deferred tax provision divided by the balance sheet total.
Result after financial items plus interest expenses plus/less exchange differences on financial loans divided by interest expenses.
Revenue less production costs and less current taxes divided by the interest charge for the period.
Dividend per share in relation to quoted share price at the end of the financial period.
| Income Statement Summary (MUSD) | 2014 | 2013 1 | 2012 | 2011 | 2010 |
|---|---|---|---|---|---|
| Continuing operations | |||||
| Revenue | 785.2 | 1,132.0 | 1,375.8 | 1,251.1 | 805.3 |
| Production costs | -66.5 | -139.6 | -203.2 | -174.7 | -163.8 |
| Depletion | -131.6 | -169.3 | -191.4 | -165.1 | -145.3 |
| Exploration costs | -386.4 | -287.8 | -168.4 | -140.0 | -127.5 |
| Impairment costs of oil and gas properties | -400.7 | -123.4 | -237.5 | – | – |
| Gross profit/loss | -200.0 | 411.9 | 575.3 | 771.2 | 368.7 |
| Gain on sale of assets | – | – | – | – | 66.1 |
| General, administration and depreciation expenses | -52.2 | -41.2 | -31.8 | -67.0 | -41.0 |
| Operating profit/loss | -252.2 | 370.7 | 543.5 | 704.2 | 393.9 |
| Result from financial investments | -420.0 | -82.5 | -21.2 | 25.4 | -12.5 |
| Share of result of joint ventures accounted for | |||||
| using the equity method | -12.9 | -0.2 | – | – | – |
| Profit/loss before tax | -685.1 | 288.0 | 522.3 | 729.7 | 381.3 |
| Tax | 253.2 | -215.1 | -418.4 | -574.4 | -251.9 |
| Net result from continuing operations | -431.9 | 72.9 | 103.9 | 155.2 | 129.5 |
| Discontinued operations | |||||
| Net result from discontinued operations | – | – | – | – | 369.0 |
| Net result | -431.9 | 72.9 | 103.9 | 155.2 | 498.5 |
| Net result attributable to the shareholders of the Parent Company: |
-427.2 | 77.6 | 108.2 | 160.1 | 511.9 |
| Net result attributable to non-controlling interest: | -4.7 | -4.7 | -4.3 | -4.9 | -13.4 |
| Net result | -431.9 | 72.9 | 103.9 | 155.2 | 498.5 |
| Balance Sheet Summary (MUSD) | 2014 | 2013 | 2012 | 2011 | 2010 |
| Tangible fixed assets | 4,382.9 | 3,905.8 | 2,913.8 | 2,345.4 | 2,014.3 |
| Other non-current assets | 49.9 | 93.6 | 44.1 | 44.0 | 129.9 |
| Current assets | 659.2 | 362.0 | 335.8 | 298.0 | 284.9 |
| Total assets | 5,092.0 | 4,361.4 | 3,293.7 | 2,687.4 | 2,429.1 |
| Shareholders' equity | 431.5 | 1,207.0 | 1,182.4 | 1,000.9 | 920.4 |
| Non-controlling interest | 34.2 | 59.8 | 67.7 | 69.4 | 77.4 |
| Total equity | 465.7 | 1,266.8 | 1,250.1 | 1,070.3 | 997.8 |
| Provisions | 1,295.2 | 1,345.1 | 1,204.6 | 988.0 | 769.7 |
| Non-current liabilities | 2,683.1 | 1,264.1 | 406.8 | 226.3 | 476.6 |
| Current liabilities | 648.0 | 485.4 | 432.2 | 402.8 | 185.0 |
| Total equity and liabilities | 5,092.0 | 4,361.4 | 3,293.7 | 2,687.4 | 2,429.1 |
1 The comparatives for 2013 have been restated following the adoption of IFRS 11 Joint Arrangements, effective 1 January 2014. No restatement has been made for the years 2010–2012.
| Proved and probable oil reserves | Total MMbbl |
Norway MMbbl |
France MMbbl |
Netherlands MMbbl |
Malaysia MMbbl |
Russia MMbbl |
|---|---|---|---|---|---|---|
| 1 January 2013 | 183.5 | 139.9 | 23.9 | 0.1 | 12.7 | 6.9 |
| Changes during the year | ||||||
| – acquisitions | – | – | – | – | – | – |
| – sales | – | – | – | – | – | – |
| – revisions | 4.8 | 4.2 | -0.3 | – | 0.9 | – |
| – extensions and discoveries | – | – | – | – | – | – |
| – production | -9.4 | -7.5 | -1.1 | – | – | -0.8 |
| 31 December 2013 1 | 178.9 | 136.6 | 22.5 | 0.1 | 13.6 | 6.1 |
| 2014 | ||||||
| Changes during the year | ||||||
| – acquisitions | – | – | – | – | – | – |
| – sales | -5.6 | – | – | – | – | -5.6 |
| – revisions | 3.1 | 3.2 | -0.2 | -0.1 | 0.2 | – |
| – extensions and discoveries | 3.4 | 3.4 | – | – | – | – |
| – production | -7.1 | -5.5 | -1.1 | – | – | -0.5 |
| 31 December 2014 1 | 172.7 | 137.7 | 21.2 | – | 13.8 | – |
| Proved and probable gas reserves | Total Bn scf 2 |
Norway Bn scf |
Netherlands Bn scf |
Indonesia Bn scf |
|---|---|---|---|---|
| 1 January 2013 | 108.4 | 70.8 | 21.7 | 15.9 |
| Changes during the year | ||||
| – acquisitions | – | – | – | – |
| – sales | – | – | – | – |
| – revisions | -1.9 | -3.2 | 2.4 | -1.1 |
| – extensions and discoveries | – | – | – | – |
| – production | -15.1 | -7.3 | -4.4 | -3.4 |
| 31 December 2013 | 91.4 | 60.3 | 19.7 | 11.4 |
| 2014 | ||||
| Changes during the year | ||||
| – acquisitions | – | – | – | – |
| – sales | – | – | – | – |
| – revisions | 6.8 | 7.7 | -0.7 | -0.2 |
| – extensions and discoveries | 3.1 | 3.1 | ||
| – production | -12.8 | -5.6 | -4.2 | -2.9 |
| 31 December 2014 | 88.5 | 65.5 | 14.8 | 8.3 |
1 The oil reserves include 4.2 MMbbl of NGL's relating to Norway.
2 The Company has used a factor of 6,000 to convert one scf to one boe.
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.
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.
| bbl | Barrel (1 barrel = 159 litres) |
|---|---|
| bcf | Billion cubic feet (1 cubic foot = 0.028 m3 ) |
| Bn | Billion |
| boe | Barrels of oil equivalents |
| boepd | Barrels of oil equivalents per day |
| bopd | Barrels of oil per day |
| Bn boe | Billion barrels of oil equivalents |
| Mbbl | Thousand barrels |
| Mbo | Thousand barrels of oil |
| Mboe | Thousand barrels of oil equivalents |
| Mboepd | Thousand barrels of oil equivalents per day |
| MMbo | Million barrels of oil |
| MMboe | Million barrels of oil equivalents |
| MMbpd | Million barrels per day |
| MMbopd | Million barrels of oil per day |
| Mcf | Thousand cubic feet |
| Mcfpd | Thousand cubic feet per day |
| MMscf | Million standard cubic feet |
| MMscfd | Million standard cubic feet per day |
| MMstb | Million stock tank barrels |
| MMbtu | Million British thermal units |
| CHF | Swiss Franc |
|---|---|
| CAD | Canadian Dollar |
| EUR | Euro |
| GBP | British Pound |
| NOK | Norwegian Kroner |
| RUR | Russian Rouble |
| SEK | Swedish Kroner |
| USD | US Dollar |
| TCHF | Thousand CHF |
| TSEK | Thousand SEK |
| TUSD | Thousand USD |
| MSEK | Million SEK |
| MUSD | Million USD |
For further definitions of oil and gas terms and i measurements visit www.lundin-petroleum.com
| HSE Indicator Data | 2014 | 2013 | 2012 | 2011 | 2010 | |
|---|---|---|---|---|---|---|
| Employees | 1,219,744 | 960,508 | 909,196 | 1,036,831 | 731,793 | |
| Exposure Hours | Contractors | 4,466,854 | 2,074,824 | 1,561,482 | 2,354,452 | 2,336,409 |
| Employees | 0 | 0 | 0 | 0 | 0 | |
| Fatalities | Contractors | 0 | 0 | 0 | 0 | 0 |
| Employees | 0 | 2 | 2 | 3 | 2 | |
| Lost Time Incidents 1 | Contractors | 7 | 4 | 5 | 3 | 2 |
| Employees | 0 | 0 | 0 | 0 | 0 | |
| Restricted Work Incidents 2 | Contractors | 1 | 0 | 0 | 3 | 7 |
| Employees | 0 | 0 | 1 | 1 | 0 | |
| Medical Treatment Incidents 3 | Contractors | 4 | 2 | 0 | 4 | 17 |
| Employees | 0.00 | 0.42 | 0.44 | 0.58 | 0.55 | |
| Lost Time Incident Rate 4 | Contractors | 0.31 | 0.39 | 0.64 | 0.25 | 0.17 |
| Employees | 0.00 | 0.42 | 0.66 | 0.77 | 0.55 | |
| Total Recordable Incident Rate 4 | Contractors | 0.54 | 0.58 | 0.64 | 0.85 | 2.23 |
| No. | 2 | 0 | 2 | 7 | 1 | |
| Oil Spills | Vol. (m3 ) |
5.2 | 0 | 4 | 33 | 10 |
| No. | 6 | 7 | 1 | 2 | 1 | |
| Chemical Spills | Vol. (m3 ) |
45.9 | 59.37 | 1.75 | 3.50 | 7.70 |
| No. | 0 | 0 | 0 | 0 | 0 | |
| Hydrocarbon Leaks | Mass (kg) | 0 | 0 | 0 | 0 | 0 |
| Near Misses with High Potential | No. | 7 | 2 | 5 | 3 | 3 |
| Non-compliance with Permits/Consents |
No. | 0 | 0 | 0 | 0 | 6 |
1 Lost Time Incident (LTI) is an incident which results in a person having at least one day away from work.
2 Restricted Work Incident (RWI) is an incident which results in keeping a person from performing one or more routine functions.
3 Medical Treatment Incident (MTI) is a work related injury or illness that does not result in a job restriction or days away from work.
4 Lost Time Incident Rate and Total Recordable Incident Rate are calculated on the basis of 200,000 hours.
Since Lundin Petroleum was incorporated in May 2001 and up to 31 December 2014 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 |
| Cancellation of shares/Bonus issue | 2014 | 0.01 | -6,840,250 | 311,070,330 | 3,179,106 |
| Total | 311,070,330 | 311,070,330 | 3,179,106 |
Lundin Petroleum will publish the following interim reports:
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' register 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 Thursday 7 May 2015 at 13.00 (Swedish time). Location: Vinterträdgården, Grand Hôtel, Södra Blasieholmshamnen 8 in Stockholm.
Shareholders wishing to attend the meeting shall:
· be recorded in the share register maintained by Euroclear Sweden AB on Thursday 30 April 2015; and notify Lundin Petroleum of their intention to attend the meeting no later than Thursday 30 April 2015.
· in writing to Lundin Petroleum AB, c/o Computershare AB, P.O. Box 610, SE 182 16 Danderyd, Sweden
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 name in the shareholders' register to be able to attend the meeting and exercise their voting rights. Such registration must be effected by Thursday 30 April 2015.
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 reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations and assumptions will prove to be correct and such forward-looking statements should not be relied upon. These statements speak only as on the date of the information and the Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, operational risks (including exploration and development risks), productions costs, availability of drilling equipment, reliance on key personnel, reserve estimates, health, safety and environmental issues, legal risks and regulatory changes, competition, geopolitical risk, and financial risks. These risks and uncertainties are described in more detail under the heading "Risks and Risk Management" and elsewhere in the Company's annual report. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. Actual results may differ materially from those expressed or implied by such forward-looking statements. Forwardlooking statements are expressly qualified by this cautionary statement.
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.
In February 2015, the majority of the Johan Sverdrup partnership agreed the following allocation of resources in the Johan Sverdrup unitised field: Statoil 40.0267 percent, Lundin Petroleum 22.12 percent, Petoro 17.84 percent, Det norske oljeselskap 11.8933 percent and Maersk Oil 8.12 percent. This allocation remains subject to approval of the Ministry of Petroleum and Energy. Lundin Petroleum's estimates of Contingent Resources assume this working interest split.
South East Asia
Shareholder information 135 for further information on Lundin Petroleum i visit www.lundin-petroleum.com
Printed in Sweden 2015 Landsten Reklam – Sjuhäradsbygdens Tryckeri Corporate Head Office Lundin Petroleum AB (publ) Hovslagargatan 5 SE-111 48 Stockholm, Sweden T +46-8-440 54 50 F +46-8-440 54 59 E [email protected]
W lundin-petroleum.com
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