Annual Report • Mar 29, 2018
Annual Report
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Lundin Petroleum is one of the leading independent oil and gas companies in Europe. With a strategic focus on Norway, our aim is to develop oil and gas resources efficiently and responsibly for a sustainable and low carbon energy future.
| Our business model | 2 |
|---|---|
| 2017 at a glance | 4 |
| 2018 guidance | 5 |
| CEO review | 6 |
| Chairman's statement | 8 |
| Share and shareholders | 10 |
| Operations review | 12 |
| Responsibility | 20 |
| Risk management | 24 |
| Guiding principles | 28 |
|---|---|
| Board of Directors | 33 |
| Group management | 38 |
| Internal control over fi nancial reporting | 44 |
| Auditor's report | 45 |
| Financial summary | 46 |
|---|---|
| Directors' report | 48 |
| Financial statements of the Group | 59 |
| Accounting policies | 64 |
| Financial statements of the Parent Company | 94 |
| Board assurance | 100 |
| Auditor's report | 101 |
| Key fi nancial data | 106 |
|---|---|
| Key ratio defi nitions | 107 |
| Five year fi nancial data | 108 |
| Reserve quantity information | 109 |
| Defi nitions and abbreviations | 110 |
| Share data | 111 |
| Shareholder information | 112 |
First cash dividend payment in 2018 page 5
Operational delivery and a strong safety culture page 12
Johan Sverdrup a world class project page 16
Strong financial performance page 46
Lundin Petroleum Annual Report 2017 1
This report constitutes the Annual Report for Lundin Petroleum AB (publ), company registration number 556610-8055.
Lundin Petroleum AB ("Lundin Petroleum" or "the Company") is a Swedish public limited liability company listed on NASDAQ Stockholm with ticker "LUPE".
Lundin Petroleum generates sustainable long-term value in all stages of the upstream oil and gas value chain. We have developed the capacity and competence to take exploration success through to the production phase and we retain our standing in the industry as one of the strongest players to capitalise on further growth.
Lundin Petroleum was founded in 2001 and acquired the first assets on the Norwegian Continental Shelf in 2003. Since then it has become one of the largest operated acreage holders in Norway with a strong production growth trajectory.
Production Mboepd
1,300
Reserves
Capital Spend Cash Operating Costs
Net MUSD USD/boe MUSD
Contingent Resources
Net MMboe Net MMboe
Operating Cash Flow
2017
1,180
At the end of April 2017, Lundin Petroleum completed the spinoff of the assets in Malaysia, France and the Netherlands into the new independent company International Petroleum Corporation (IPC). The transaction resulted in a dividend distribution, through IPC shares, of USD 410 million to Lundin Petroleum's shareholders.
Following the spin-off, Lundin Petroleum has become fully focused on operations on the Norwegian continental shelf, where we see continued great opportunities for further organic growth and development projects.
After a record setting performance for Lundin Petroleum in 2017, the Board of Directors proposes that a fi rst cash dividend be paid after the 2018 AGM. The inaugural cash dividend distribution of SEK 4.00 per share represents an amount equal to approximately USD 165 million and is based on the current number of shares, excluding own shares held by the Company. The dividend is proposed to be paid after the AGM which will be held on 3 May 2018 in Stockholm.
Lundin Petroleum anticipates to be able to increase this amount and distribute an annual dividend of at least USD 350 million from next year and is optimistic about the capacity to grow annual dividends further when Johan Sverdrup comes onstream in late 2019.
Our responsible approach, in combination with maintaining a strong production growth at low cash operating costs that will deliver increased free cash flow, means that we will be able to fund sustainable dividends and at the same time be very active on the organic growth front, thereby continuing to create long-term sustainable value for our shareholders
Looking back on the results for 2017 it is pleasing to report a record setting performance for Lundin Petroleum. We delivered above expectations both in terms of high production and low cash operating costs which resulted in the highest operating cash fl ow and EBITDA for the Company to date, close to double the levels in 2016. Based on this successful year, it is very good news that the Board decided to propose our fi rst ever cash dividend to be paid out after the 2018 AGM.
These great results were driven by continued strong facilities and reservoir performance from our core producing assets, the Edvard Grieg fi eld and the Alvheim area, which generated a production for 2017 that exceeded guidance. The increase in reserves is another positive update, driven in particular by the success from the Edvard Grieg fi eld where the best estimate ultimate gross recovery of 274 MMboe at year end represents a remarkable increase of 47 percent compared to the PDO. Our belief that big fi elds tend to get bigger has certainly proven to be true for this key asset and we are hopeful that the reserves upgrade, in combination with further upside, will extend the fi eld's plateau production well beyond start-up of the Johan Sverdrup fi eld.
The Johan Sverdrup development project is progressing well with close to 70 percent of Phase 1 complete at the beginning of the year. We remain fi rmly on track to start production in late 2019 which will increase Lundin Petroleum's production to above 130 Mboepd and with Phase 2 coming onstream in 2022 our production will double current levels.
Further positive updates were recently made for the project, both in terms of an increased resource estimate to between 2.1 and 3.1 billion boe and a reduction in costs, which now means that Phase 1 costs have been reduced by 30 percent since the PDO. We look forward to the exciting installation milestones in 2018 with the installation of three additional jackets, two platform topsides and the export pipelines. We will also work with the operator to submit the PDO for Phase 2 of the project in the second half of the year.
While I would have liked to have seen more success with our exploration activities in 2017, it is important to remember that this is a long-term game and I remain confi dent in our strategy to grow organically.
Our exploration acreage in Norway increased by 50 percent during 2017 and we renewed our portfolio by adding two new exploration areas with the Mandal High in the North Sea and the Frøya High/Froan Basin in the Norwegian Sea. We now have an even more diversifi ed exploration position and I expect our active 2018 drilling programme, targeting net unrisked resources of more than 500 MMboe, to allow us to continue to fi nd new resources and create value within these core areas. In addition we have an active appraisal programme for 2018 with four wells targeting net resources of more than 200 MMboe.
With a focus on operational and execution excellence alongside safe and sustainable practices, we are committed to developing oil and gas in a responsible and carbon effi cient manner. Through our continued efforts to reduce emissions throughout our operations, we achieved a carbon intensity level for the Edvard Grieg platform in 2017 that is among the lowest in our industry. This performance is set to improve further in the coming years with the investment in power from shore for both the Edvard Grieg and Johan Sverdrup fi elds.
Our responsible approach, in combination with maintaining a strong production growth at low cash operating costs that will deliver increased free cash fl ow, means that we will be able to fund sustainable dividends and at the same time be very active on the organic growth front, thereby continuing to create longterm sustainable value for our shareholders.
To you, fellow shareholders and the Board, I thank you for your continued support. To my colleagues and management team, a big thank you for an outstanding performance.
Exciting times ahead!
Alex Schneiter President and CEO
It was another year of record performance with a production that increased by 45 percent, generating the strongest operating cash fl ow in Lundin Petroleum's history. I am pleased to say that it was these exceptional results, in combination with indications of an improving oil market, that gave the Board the confi dence to recommend that this success would be returned to the shareholders in the form of our fi rst ever cash dividend.
Our long held view was that a dividend would be possible after Johan Sverdrup comes onstream in late 2019 or potentially earlier if the oil price stayed at a sustainable level. This position was continuously reviewed by the Board with the aim of bringing back value to the shareholders sooner rather than later. With a production that is set to double current levels by 2022, industry leading low cash operating costs and a strong liquidity of USD 1.1 billion, means that all the fundamentals are in place and that the time is right to start paying dividends.
The Board will therefore recommend to the 2018 AGM that an inaugural cash dividend of SEK 4.00 per share, totalling approximately USD 165 million, be paid out after the AGM. We are also optimistic that with the current market conditions we will be able to distribute an annual cash dividend of at least USD 350 million as of next year.
The core driver behind Lundin Petroleum's record production is our Edvard Grieg asset, which represented a majority of total production in 2017 with an exceptionally strong operating performance, excellent safety record and one of the lowest carbon intensity levels in our industry. The signifi cant reserves upgrade for the fi eld also means that plateau production has been extended by many more years and I am very proud of our Norwegian team for this great achievement and their outstanding ability to continue to unlock value.
The Johan Sverdrup project also continues to exceed all expectations. It is breath taking to realise that all four jackets will be in place in the North Sea after this summer and that production will start towards the end of next year. Equally impressive is that development costs for the
full fi eld have been reduced by more than a third since the PDO – a saving that represents nearly one Edvard Grieg development alone. This progress, combined with the increased resource estimate, affi rms the world class quality of this fi eld and I am truly convinced we are still only witnessing the beginning of the Johan Sverdrup success story.
I am very conscious that exploration has been the key to our success and continues to be part of our core philosophy. Therefore, I am very pleased to see that our licence position on the Norwegian Continental Shelf increased by some 50 percent during the year and that we continue to bid actively for new acreage in all the licensing rounds. 2018 will be a very active year in terms of appraisal and exploration drilling, which I am confi dent will allow the Company to continue to grow organically for years to come.
While the outlook for Lundin Petroleum certainly looks promising we are also seeing a recovery in the oil market. World oil demand has now reached approximately 100 MMbopd and continues to grow. Meanwhile the effects of capital discipline in the industry over the past few years are starting to have an effect on the supply side. I expect that we are getting very close to tightened supply and even if there are signs that the industry is starting to react to the
imbalance it will probably be too little too late to avoid a constraint in supply.
Lundin Petroleums's production growth profi le for the coming years will generate strong free cash fl ow and means that we can pay out dividends and still be able to repay our debt and fund our organic growth activities. Quality assets, creative mind sets, innovative methods, cutting edge technology and most importantly a great team of people explains why Lundin Petroleum is one of the leading independent oil and gas companies in the world and why we will retain our standing in the industry as one of the strongest players to capitalise on further growth, continuing to create long-term sustainable shareholder value.
Lundin Petroleum's future success lies in the hands of the people that make up the Company and I want to thank you all for your great work in 2017 and you, fellow shareholders, for your continued support. I look forward to continue to share the Lundin Petroleum journey with you all.
Ian H. Lundin Chairman of the Board
2017 has been a consolidation year for the Lundin Petroleum share price, which saw an intraday peak of SEK 215 per share whilst overall growth was relatively fl at. Since the inception of the listing of Lundin Petroleum's shares in September 2001, the share price has achieved a compounded annual return, up until 31 December 2017, of 32 percent including dividends.
At the end of 2017 Lundin Petroleum's market capitalisation was SEK 63.9 billion which made Lundin Petroleum one of the largest independent oil and gas companies in Europe by market capitalisation.
During 2017, a total of 213 million shares were traded on NASDAQ Stockholm to a value of approximately SEK 39 billion, representing an average daily trading volume of approximately 0.85 million shares per trading day. The share trading turnover during 2017 equated to approximately 63 percent of the average number of shares in issue during 2017 and approximately 1.2 times the number of shares in free fl oat.
Lundin Petroleum's objective is to create attractive shareholder returns by investing through the business cycle with capital investments allocated to exploration, development and production assets. The Company's ambition is to create shareholder returns both through share price appreciation as well as by paying a predictable and sustainable cash dividend with the aim of progressively increasing the cash dividend in line with the growth of the Company's earnings and free cash fl ow generation. The progressiveness of the dividend will depend, among other things, on the performance of the Company's main producing assets as well as the capital investment needs, the oil price level, the debt gearing level and the debt amortisation profi le.
The Board has proposed to pay an inaugural cash dividend of SEK 4 per share, amounting to approximately MUSD 165 to be paid after the 2018 AGM. The ambition remains to further increase the cash dividend to at least MUSD 350 from 2019 and to grow the capacity of annual dividends upon production of fi rst oil from Johan Sverdrup.
Source: Bloomberg
The registered share capital amounted to SEK 3,478,713 at year end 2017, represented by 340,386,445 shares with a quota value of SEK 0.01 each (rounded off), representing one vote each. All outstanding shares are common shares and carry equal rights to participation in Lundin Petroleum's assets and earnings.
During 2017, Lundin Petroleum purchased 1,233,310 own shares at an average purchase price of SEK 186.14 and the Company's total shareholding at year end 2017 amounted to 1,233,310 shares.
Lundin Petroleum had 29,491 shareholders at the end of 2017. Shares in free fl oat amounted to 51.2 percent and exclude the shareholding held by the Lundin family and Statoil.
The top 10 shareholder list excludes shareholdings through nominee accounts and only includes institutional shareholders who hold the shares directly as reported by Euroclear Sweden.
| The 10 largest shareholders as at 31 December 2017 |
Number of shares |
% |
|---|---|---|
| Nemesia S.à.r.l.1 | 87,187,538 | 25.6 |
| Statoil ASA | 68,417,676 | 20.1 |
| Landor Participations Inc.2 | 10,488,956 | 3.1 |
| Swedbank Robur fonder | 6,682,051 | 2.0 |
| Nordea Fonder | 3,804,261 | 1.1 |
| Abu Dhabi Investment Authority | 2,325,288 | 0.7 |
| SPP Fonder | 2,152,739 | 0.6 |
| Vanguard Energy Fund | 2,116,332 | 0.6 |
| Fjärde AP-fonden | 1,976,411 | 0.6 |
| SEB | 1,672,972 | 0.5 |
| Other shareholders | 153,562,221 | 45.1 |
| Total | 340,386,445 | 100% |
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.
Source: Euroclear Sweden
The main changes to the shareholder base in 2017 were driven by investment style with a shift towards investors focused on dividend yields and cash fl ow multiples valuation as opposed to previous years where focus was on traditional net asset valuation methodologies.
Source: IPREO
Production 86 Mboepd
2P reserves replacement ratio
144%
Reserves and resource base
~1 billion barrels Cash operating costs
4.25 USD/boe
Safe operations 0.47 LTIR
Oil spills
Zero recordable oil spills
Carbon intensity 5.1 CO2e kg/boe
for Edvard Grieg
The health and safety of the people working for us is our highest priority and we focus on reducing risks throughout all our operations. We rely on our skilled and dedicated workforce to assess potential risks and implement measures to mitigate them. We foster an open culture to learn from incidents and we continually assess our operations to identify areas for improvement. We also test and review our emergency preparedness on a regular basis. These measures help ensure a safe working environment for everyone working for or on behalf of Lundin Petroleum.
In 2017, there were no serious personal injuries or process safety incidents. The Lost Time Incident Rate (LTIR) was 0.47 per million hours worked and the Total Recordable Incident Rate (TRIR) was 3.30 per million hours worked.
Lundin Petroleum supports the principles of the Paris Agreement to strengthen the global response to climate change and we are committed to play our part in supporting industry initiatives to reduce carbon emissions. Through our investment in carbon mitigating technology and improved emissions management, Lundin Petroleum operates with one of the lowest carbon intensity levels in the industry, which we also consider a competitive advantage. The emission level from the Edvard Grieg platform was 5.1 kg CO2 equivalent per barrel in 2017, which is a reduction compared to 2016 and a level about 75 percent lower than the world average. Our low carbon performance is set to improve further in the coming years with the investment in power from shore for both the Edvard Grieg and Johan Sverdrup fi elds.
Beyond emissions we also focus on measures to minimise the impact of our operations on the surrounding environment by reducing discharges to sea. In 2017, there were no material environmental incidents throughout our operations. We also focus on managing waste from our operations and initiated a waste reduction initiative in 2017 that requires suppliers to reduce the use of non-recyclable packaging material.
1 Adjusted for IPC spin-off
Source: NOROG and IOGP for world and Norway data (2016 averages). Edvard Grieg is 2017 data, Johan Sverdrup full field estimate
Read more about Lundin Petroleum's HSE performance in the Sustainability Report 2017 available on www.lundin-petroleum.com i
The majority of Lundin Petroleum's production in 2017 came from its key operated Edvard Grieg asset in the Utsira High in the Norwegian North Sea. The fi eld contributed close to 80 percent of total production at a cash operating cost of less than USD 4 per barrel. Increased facilities capacity, high production effi ciency and strong reservoir performance were the key drivers behind this excellent performance.
Appraisal drilling results have confi rmed additional reserves in the southwest area of the fi eld which, combined with the results from the development wells drilled in 2017 and the strong reservoir performance, has seen no water production to date and has resulted in a signifi cant reserves increase for the fi eld. The best estimate gross ultimate recovery increased by 51 MMboe to 274 MMboe at year end 2017 which is a 47 percent increase on the original PDO estimate. This positive upgrade will extend Edvard Grieg plateau production to end 2019, and possibly even longer, with further upside and infi ll drilling opportunities. The ambition is to keep the Edvard Grieg facilities full for many years to come and appraisal drilling on the nearby Luno II and Rolvsnes oil discoveries, both possible sub-sea tie-back opportunities to the Edvard Grieg facilities, are planned for 2018.
During 2017, Lundin Petroleum produced 31.4 MMboe at an average rate of 86.1 Mboepd, excluding production from the IPC assets. This performance was 15 percent above the mid-point of the original guidance and above the revised guidance for 2017.
Capacity testing of Edvard Grieg, that has confi rmed that the facilities are able to produce at rates 15 percent above design levels, combined with strong facilities and reservoir performance at both the Edvard Grieg fi eld and the Alvheim area, are the main reasons for the strong production performance in 2017.
Lundin Petroleum's production guidance for 2018 is in the range of 74 to 82 Mboepd with Edvard Grieg representing approximately 75 percent of total production in 2018.
The Ivar Aasen fi eld produces through the Edvard Grieg facilities and the contractual allocation of facilities capacity between the fi elds changes through time. The Edvard Grieg production well capacity signifi cantly exceeds the available contractual capacity and the reduced production compared to 2017 is due to the capacity constraint. Increased reserves were booked for the Edvard Grieg fi eld at the end of 2017 and will see plateau production levels sustained beyond the start-up of Johan Sverdrup.
The giant Johan Sverdrup fi eld is on track to start production in late 2019 and is expected to increase Lundin Petroleum's net production to above 130 Mboepd and then grow to over 160 Mboepd at full fi eld plateau levels. This is set to double today's production levels, excluding any contribution from the signifi cant contingent resource base or any contribution from the exploration wells that Lundin Petroleum is planning to drill.
Phase 1 of the Johan Sverdrup project is ahead of schedule with close to 70 percent complete at the beginning of 2018 and remains fi rmly on track for fi rst oil in late 2019. Key project milestones in 2017 were the offshore installation of the riser platform jacket and the assembly of the drilling platform topsides. During 2018, the remaining three platform jackets will be installed along with the topsides for the drilling and the riser platforms as well as the oil and gas export pipelines. The remaining two topsides, for the processing and living quarter platforms, will be installed in 2019. The gross production capacity for Phase 1 is estimated at 440 Mbopd.
The development concept for Phase 2 of the project has been fi nalised and the PDO is scheduled for the second half of 2018. Phase 2 involves the installation of an additional processing platform at the fi eld centre and will see gross production capacity increase to 660 Mbopd. Phase 2 is scheduled to come on-stream in 2022.
The project keeps getting better and better with further cost reductions and an increased resource estimate. The latest cost estimate for Phase 1 represents a saving of nearly 30 percent compared to the PDO, excluding additional foreign exchange rate savings. The breakeven price for the full fi eld has been reduced to less than 20 USD per barrel. These improvements, in combination with the resource upgrade for the fi eld to between 2.1 and 3.1 billion boe, truly shows the world class quality of the Johan Sverdrup project.
Lundin Petroleum's main strategy is to pursue organic growth success in Norway, an attractive region with multiple prospective hydrocarbon areas assessed to have yet to find resources of over 16 billion boe and with a regulatory and fiscal regime that promotes exploration activity.
During 2017, the Company drilled four appraisal wells including wells on the Alta and Gohta oil discoveries in the southern Barents Sea and on the southwest area of the Edvard Grieg fi eld, resulting in a signifi cant reserves increase for the fi eld.
An active appraisal programme is planned for 2018 targeting more than 200 MMboe of net resources with the aim of progressing resources towards reserves. Appraisal activities include wells at Luno II and Rolvsnes in the Utsira High, both potential subsea tie-back developments to the Edvard Grieg platform. In the southern Barents Sea an appraisal well and extended well test will be conducted on the Alta oil discovery.
Lundin Petroleum has been active in expanding and diversifying its exploration position in Norway through a combination of licensing round awards and acquisitions. Since the beginning of 2017 its acreage has been increased by approximately 50 percent and two new core exploration areas have been added at the Mandal High in the North Sea and the Frøya High/Froan Basin in the Norwegian Sea.
Six exploration wells were drilled in 2017, one in the Alvheim area and fi ve in the southern Barents Sea, resulting in the Filicudi oil discovery in PL533. Additionally, a large high-specifi cation 3D seismic survey called TopSeis was acquired over the Alta and Gohta discoveries and area prospectivity.
The exploration programme for 2018 is targeting over 500 MMboe of net unrisked prospective resources. Nine wells are planned to be drilled, four in the southern Barents Sea, four in the North Sea and one in the Norwegian Sea. Two of these wells will target prospects in the new Mandal High and Frøya High/Froan Basin core exploration areas.
| Reserves Summary | Proved plus Probable (2P reserves) |
Proved plus Probable plus Possible (3P reserves) |
|---|---|---|
| End 2016 | 714.1 | 898.1 |
| 2017 production | -31.9 | -31.9 |
| Sales/acquisitions | -1.7 | -2.2 |
| Revisions | +45.8 | +31.5 |
| Reserves end 2017 | 726.3 | 895.5 |
| Reserves replacement ratio | 144% | 99% |
Excluding IPC assets
Lundin Petroleum increased its reserves in 2017 with a 2P reserves replacement ratio of 144 percent. The main reason for the increase in reserves relates to Lundin Petroleum's two main assets, the Edvard Grieg and Johan Sverdrup fi elds both located on the Utsira High in the Norwegian North Sea.
The best estimate gross ultimate recovery from Edvard Grieg at end 2017 is 274 MMboe, which is cumulative production to end 2017 plus 2P reserves, and represents an increase of 51 MMboe from end 2016 and a 47 percent increase from the original PDO. The signifi cant reserves upgrade at Edvard Grieg is driven by drilling results and production performance to date which indicate more oil-in-place and with a greater proportion in the high quality high recovery factor sands as compared to the lower quality reservoirs. The upgrade of reserves in the Johan Sverdrup fi eld refl ects the positive drilling results and optimisation of the reservoir development plan. Further reserves increases have been attributed to the Alvheim and Volund fi elds.
96 percent of the 2P reserves is related to oil and natural gas liquids (NGL). All reserves are independently audited by ERC Equipoise Ltd. (ERCE).
Lundin Petroleum had 203 MMboe of net contingent resources at year end 2017. A signifi cant work programme is planned for 2018, including four appraisal projects, aimed at maturing contingent resources into reserves.
Contingent resources end 2017 203 MMboe
Lundin Petroleum reports all of its reserves in working interest barrels of oil equivalent. Definitions of reserves and resources can be found on page 110.
i
2017 was marked by Lundin Petroleum transitioning from global operations to a strategic focus on Norway, which means we operate in a world class governance environment and are well placed to pursue our ambition to become a sustainability leader in our sector.
As part of this transition, our Corporate Responsibility strategy has been reassessed to make sure it is relevant and addresses material sustainability challenges related to the operating context. This work included a third party materiality assessment that reviewed laws and regulations, voluntary initiatives as well as issues important to civil society and our peers in Norway. The assessment shows that our Corporate Responsibility framework is robust and remains relevant as the material issues identifi ed are essentially the same as in previous years, namely health and safety, environment, labour standards, human rights and anti-corruption. It also showed that a key issue for Lundin Petroleum in 2017 and going forward is our action to address climate change.
Concerted efforts by governments, business and civil society were taken in 2017 to translate the Paris Agreement into concrete actions. Lundin Petroleum was part of this process with intensifi ed efforts to ensure that we produce oil and gas in the most carbon effi cient way possible. Our environmental policy was revised to include climate related objectives, we developed an environmental strategy for our Norwegian operations setting out specifi c goals and targets to reduce our environmental footprint and we continued to actively support the industry roadmap to achieve emission reductions on the NCS.
Read more about Lundin Petroleum's performance and management approach on environmental, governance and social issues in the Sustainability Report available on www.lundin-petroleum.com
The Sustainability Report provides comprehensive information on how sustainability issues are part of Lundin Petroleum's business model to create long term sustainable value and constitutes the disclosure on non-fi nancial reporting required under Swedish law implementing the EU Directive 2014/95/EU. The report has been developed as a tool for stakeholders to assess our sustainability approach and performance and to engage with us on issues that are important to them. We welcome this engagement as part of our work to address key sustainability challenges.
Through our management efforts and investments in new technologies, Lundin Petroleum succeeded yet again to lower the carbon intensity of its oil and gas production in 2017 to a level that is 75 percent lower than the world industry average. This means that Lundin Petroleum operates with one of the lowest carbon emission intensity levels in the industry. We are therefore well positioned to continue to supply reliable and carbon effi cient energy for many years to come.
In a lower oil price environment it will be innovative companies with a focus on sustainability that will have the ability to transform into the energy companies needed in the future. At Lundin Petroleum, we see it as a competitive advantage that we can deliver energy that is produced in a responsible, carbon effi cient and cost effective manner.
The Lundin Foundation was established in 2005 and is a globally recognised leader in impact investments. Through Lundin Petroleum's partnership with the Lundin Foundation, we support innovative solutions to address key social and sustainability issues in Europe. Projects that assist the integration of refugees and migrants into the workforce are carried out in Norway and Sweden and mentoring and training is provided to young entrepreneurs with sustainable business ideas in northern Norway.
More information on projects run by the Lundin Foundation can be found in Lundin Petroleum's Sustainability Report.
Promoting good governance and requiring the highest standards of ethical business conduct – internally and throughout our value chain
Our exposure to corruption is continuously assessed through reviews and audits and is determined a limited risk area given the focus on operations in Norway. Internal anti-corruption processes are nonetheless maintained to ensure high awareness of the risk that exists within the industry. Anti-corruption commitments are included in Lundin Petroleum's Contractor Declaration and were added in 2017 to our evaluation of contractors in the tender process.
There were no reported cases of suspected or actual corruption in 2017.
An integral part of our business model to create long term sustainable value is to ensure that human rights are respected throughout all our operations. While we operate in a low risk environment in Norway, we are attentive to potential risks within our operations as well as in the value chain.
Lundin Petroleum's human rights due diligence process is guided by the principles for business and human rights embodied in the UN Global Compact and the UN Guiding Principles on Business and Human Rights as well as Lundin Petroleum's Human Rights Policy and Guidelines. The process entails identifying, assessing and determining any potential human rights risks and sets out further preventative or mitigating measures. Human rights were added in 2017 as a criterion for contractor evaluation at the tender process to further emphasise the importance of respect for human rights in the value chain.
Screenings conducted in 2017 did not identify any human rights issues.
Maintaining an inclusive working environment and a focus on high performance has been the key to our success in attracting and retaining the best possible talent in the industry over the years. We will continue to build on this base of world class employees through our commitment to develop and invest in our key resource.
The organisation changed in 2017 as the non-Norwegian assets were spun-off to IPC with Lundin Petroleum becoming fully focused on Norway. At the end of 2017, Lundin Petroleum had a total of 411 employees with a majority based in Norway. Consultants and contractors are also engaged by the Company for services related to exploration, project development and other operational activities with a total of 42 engaged during 2017.
Lundin Petroleum values diversity and strives to maintain an open and inclusive work environment. A total of 28 different nationalities were represented in the employee base in 2017. Women represented 27 percent of the total workforce and 27 percent of the managerial positions. The proportion of women in Lundin Petroleum's Board of Directors was 38 percent.
We are committed to providing our staff and contractors with a safe and enabling working environment. We support the principle of freedom of association in trade unions and promote diversity in our employee base, ensuring that all employment opportunities are offered on the basis of skills and experience.
The oil and gas industry is exposed to numerous risks due to the nature of the operational context and the often rapid change and dynamic character of the business environment. This is a risk universe that can present both challenges and opportunities.
Lundin Petroleum's risk management approach has been designed to identify and manage the most material risks for the business, from health, safety and environmental protection to the capacity to achieve short and long-term business objectives to fi nancial risks relating to a volatile oil price environment and accurate fi nancial reporting.
A standardised risk management methodology is used to perform quantitative and qualitative risk assessments and to prioritise activities and resources which enables the Company to deal effectively with any potential threats and opportunities. The risk assessment starts with an understanding of events in terms of severity and probability of an incident occurring that takes context and uncertainty into consideration. Risks are then rated based on a fi ve level scale within a risk management matrix to indicate the appropriate level of attention from management, including identifi cation of corresponding opportunities.
Lundin Petroleum's risk management process is driven by the Board to encourage foresight, pro-activeness and informed decision-making. Management is responsible for establishing risk management processes and for reviewing and measuring the effectiveness of mitigation efforts and local management has the day-to-day responsibility for implementing the systems and monitoring their impact.
A majority of Lundin Petroleum's activities are located in Norway, a country with a robust regulatory framework covering key issues for oil and gas operations, such as health, safety, security, environment, human rights and anti-corruption. Risks and opportunities are nevertheless continuously considered in a broader context with emerging trends and associated risks being identifi ed by internal and external sources. Key trends are then reviewed by management on a quarterly basis in order to raise the internal awareness. Monitoring risk is an important part of the continuous risk management process. It involves local operational accountability and clear responsibility for continuous identifi cation of risks by risk owners.
Lundin Petroleum's risk universe falls into three areas: strategic, operational and fi nancial risks which include risks to the Company's reputation or the effect that external risks could have on the business. A description of the specifi c risks, not listed in any order of priority in the table below, show how Lundin Petroleum works to address and mitigate these risks within each area. This summary gives an overview of Lundin Petroleum's risk universe however other risks may also exist or arise.
| Strategic Risk | ||
|---|---|---|
| Description | Impact | Mitigation |
| 1. Shareholder value creation | ||
| Inability of business strategy to create shareholder value. Failure to understand and unlock the full value of the asset portfolio. |
Loss of investor confi dence. Negative impact on share price and market position. |
Lundin Petroleum seeks to generate sustainable shareholder value by proactively investing in exploration to organically grow the reserve base, exploiting the existing asset base and acquiring new reserves, resources or acreages where opportunities exist to enhance value. |
| 2. Laws and regulations | ||
| Breach of applicable laws and regulations. Complexity and changes to applicable laws and regulations that may negatively affect the Company. |
Investigations and litigation. Financial impact, reputational damage, cancellation or modifi cation of contractual rights, uncertainty in taxation. |
Lundin Petroleum strives to ensure comprehensive interpretation of and adherence to applicable laws and regulations through a robust corporate governance framework with appropriate measures to detect potential, and react to identifi ed, legal risks. |
| For more information on the preliminary investigation in Sweden in relation to past operations in Sudan, see page 32. |
||
| 3. Ethical business conduct | ||
| Breach of norms and standards regarding compliance and ethical business conduct. |
Investigations and litigation. Risk of non-compliance with ethical business practices, fraud, bribery and corruption. Loss of legal or social licence to operate with severe impact on short- and long-term growth plans. |
A consistent application of the Code of Conduct, together with Corporate policies and procedures in the management system clearly defi ne responsibilities and obligations to ensure that Lundin Petroleum operates according to the highest level of ethical standards. Expectations of ethical business conduct are implemented in contractual clauses and in a Contractor Declaration. |
| 4. Stakeholder engagement | ||
| Failure to manage stakeholder relations and meet expectations. Ineffective communication with stakeholders. |
Damaging effect on social licence to operate and reputation Ineffective communication may lead to a loss of investor, partner or employee confi dence. |
Lundin Petroleum has strong internal and external communication channels and seeks an active engagement with its various stakeholders to maintain an open and informed dialogue. For more information on stakeholder engagement, see the 2017 Sustainability Report. |
| 5. Climate change | ||
| Climate change initiatives could lead to stricter regulation on emissions or imposition of mandatory technology in the areas where Lundin Petroleum operates. |
Increase in capital and operating costs due to new climate change related requirements. |
Lundin Petroleum conducts activities in Norway that has a pro-active role in addressing climate change. The carbon footprint and energy effi ciency of its operations are reviewed on an ongoing basis and greenhouse gas emissions are disclosed regularly. |
| Operational Risk | ||||
|---|---|---|---|---|
| Description | Impact | Mitigation | ||
| 6. Health, Safety and Environment (HSE) | ||||
| Operational incidents such as fi re, process safety, major accidents, collision, or well control incidents are a signifi cant risk within the oil and gas industry. |
Loss of health, safety, security and environmental protection. Financial and reputational impact. |
Lundin Petroleum has a robust HSE culture in place to reduce the risks of incidents and maintains a strong HSE management to ensure the safety and security for people and the environment. For more information on HSE management, see the 2017 Sustainability Report. |
||
| 7. Security / IT Security | ||||
| Safety and security is important for the oil and gas industry and the risk ranges from personnel security or other attacks on physical assets, including information systems. |
Vulnerability of information to cyber threats or malware attacks enhances the risk to system security potentially affecting people's data privacy as well as the critical systems related to the assets. |
Security risks are regularly monitored, assessed and subject to audit. With operations in Norway, exposure to this risk is assigned a lower risk ranking but high awareness is nonetheless maintained. Networks are monitored to prevent and remedy any external attacks. A unifi ed and resilient internal network is maintained through fi rewalls and procedures. |
||
| 8. Concentration of operations | ||||
| Current production concentrated to a few fi elds. |
A signifi cant proportion of production comes from the Edvard Grieg and the Alvheim area. Increased vulnerability for serious technical issues and long-term production shutdowns. |
The Company has highly competent and robust operational teams and holds critical spares in inventory. An insurance covering the fi nancial liquidity impact from a loss of production is subscribed for the Edvard Grieg fi eld, which reduces the impact of any unexpected long-term shutdowns. |
||
| 9. Reserves and resources | ||||
| Uncertainty in estimates of economically recoverable reserves and inability to bring estimates into resources and reserves. |
Uncertainty of future business and subsurface data. Decline in revenue. |
Reserves and resource calculations are performed according to industry standards and undergo a comprehensive internal peer review in addition to an annual audit process by an independent auditor. |
||
| 10. Delay of development projects | ||||
| Delay in delivery of development projects, most notably the signifi cant Johan Sverdrup project. |
Combined effect of delay and cost overruns effect liquidity. |
Quality project management and execution of work to date. The Johan Sverdrup project progress has been ahead of schedule with lower cost estimates. |
| Financial Risk | ||
|---|---|---|
| Description | Impact | Mitigation |
| 11. Market conditions | ||
| Exposure to variations in oil price. | The Company's fi nancial earnings, cash fl ow generation and liquidity position are affected by the commodity price of oil. |
Lundin Petroleum's policy is to adopt a fl exible and proactive approach towards oil price hedging based on an assessment of the benefi ts of hedge contracts in specifi c circumstances. The Company actively reviews the contractor base and their position of liquidity in low oil price market conditions. |
| 12. Liquidity and funding | ||
| Failure to keep investments and costs in line with budgets. Delays in the Johan Sverdrup development projects leading to delayed cash fl ow. Uncertainty of future capital requirements and their availability. |
Reduction in the borrowing capacity of the Company. Reduction in the liquidity headroom within the Company's loan agreements. |
An annual budget and supplementary budget approval process and a Corporate Authorisation Policy have been implemented to ensure a rigorous and continual oversight of all expenditures. The signifi cant funding requirements for the Johan Sverdrup project has been secured through external fi nancing. The Company has signifi cant liquidity headroom due to its borrowing facilities for the foreseeable future and has capacity to issue unsecured subordinated debt to increase liquidity headroom. |
| 13. Interest and currency | ||
| The underlying value of the Company's assets is predominantly USD denominated whilst certain costs are denominated in other currencies and therefore represent a foreign exchange risk in relation to market fl uctuations of foreign currencies. |
Exposure to market fl uctuations that could affect earnings and liquidity. |
The exposure to interest rate and currency risk is continuously assessed and monitored and hedging instruments are used to manage this risk. |
| 14. Financial reporting | ||
| Inaccurate fi nancial reporting. | Regulatory action, liability, loss of shareholder confi dence. |
A monthly management reporting process is in place to review and control the fi nancial reporting. The internal control system provides reasonable assurance against inaccurate reporting and internal and external audits provide verifi cation. |
| 15. Asset management and cost control | ||
| Risk of destroying value by ineffective cost control and assets operating beyond their lifetime. |
Cost overruns and effect on uptime. Failure of management system processes and to follow the Value Process. |
Lundin Petroleum has new assets that are constantly monitored with a focus on operator effi ciency, respect of policies and procedures, including the Value Process as well as control of partner production. Cost saving benefi ts have been realised throughout 2017 through contractor management and internal cost control processes. |
| 16. Asset retirement | ||
| Decommissioning fi nancial estimates of fi elds at the end of the economic life cycle. |
Financial and tax impact, liability, implications of abandonment and reclamation. |
Decommissioning is considered throughout the asset's life cycle according to the policy for asset retirement liability. Financial estimates are reviewed annually for development projects and for operated assets. |
Lundin Petroleum's corporate governance framework seeks to ensure that its business is conducted efficiently and responsibly, that responsibilities are allocated in a clear manner and that the interests of shareholders, management and the Board of Directors remain fully aligned
Through its corporate governance framework, Lundin Petroleum aims to ensure that its business is conducted in an effi cient and responsible manner in the best interests of all shareholders and other stakeholders.
The corporate governance framework is further tied to Lundin Petroleum's sustainability profi le in order to ensure that we continue to deliver sustainable value creation whilst operating in accordance with the highest ethical and operational industry standards.
| Guiding principles | 28 |
|---|---|
| Nomination Committee | 31 |
| Shareholders meetings | 32 |
| External auditors | 33 |
| Board of Directors | 33 |
| Board committees | 38 |
| Group management | 40 |
| Policy on remuneration | 42 |
| Internal control over fi nancial reporting | 44 |
| Auditor's report | 45 |
Since its creation in 2001, Lundin Petroleum has been guided by general principles of corporate governance, which form an integral part of Lundin Petroleum's business model and seek to:
As a Swedish public limited company listed on NASDAQ Stockholm, Lundin Petroleum is subject to the Rule Book for Issuers of NASDAQ Stockholm, which can be found on www.nasdaqomxnordic.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, EU rules and other regulations such as the Rule Book for Issuers and good practice on the securities market. The Code of Governance can be found on www.bolagsstyrning.se
The Code of Governance is based on the "comply or explain principle", which entails that a company may choose to apply another solution than the one provided by the Code of Governance if it fi nds an alternative solution 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.
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 two deviations from the Code of Governance in 2017, one in respect of the composition of the Nomination Committee as further described in the schedule on page 31, and one in respect of Board member attendance at the Extraordinary General Meeting (EGM) held on 22 March 2017 as described under EGM 2017 on page 33. There were no infringements of applicable stock exchange rules during the year, nor any breaches of good practice on the securities market.
Lundin Petroleum AB (publ), company registration number 556610-8055, has its corporate head offi ce 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
Jakob Thomasen appointed as a new Board member at the AGM held on 4 May 2017.
Spin-off and Lex Asea distribution of IPC completed on 24 April 2017.
AGM approved share repurchase programme initiated in August 2017 and 1,233,310 own shares repurchased in 2017 at an average price of SEK 186.14.
Review of corporate governance structure post-IPC spin-off to ensure principles of good governance maintained throughout the new organisation.
The Articles of Association contain customary provisions regarding the Company's governance and do not contain any limitations as to how many votes each shareholder may cast at Shareholders' Meetings, nor any special provisions regarding the appointment and dismissal of Board members or amendments to the Articles of Association.
The Articles of Association are available on the Company's website.
Lundin Petroleum's Code of Conduct is a set of principles formulated by the Board to give overall guidance to employees, contractors and partners on how the Company is to conduct its activities in an economically, socially and environmentally responsible way, for the benefi t of all stakeholders, including shareholders, employees, business partners, host and home governments and local communities. The Company applies the same standards to all of its activities to satisfy both its commercial and ethical requirements and strives to continuously improve its performance and to act in accordance with good oilfi eld practice and high standards of corporate citizenship. The Code of Conduct is an integral part of the Company's contracting procedures and any violations of the Code of Conduct will be the subject of an inquiry and appropriate remedial measures. In addition, performance
under the Code of Conduct and Corporate Responsibility (CR) is regularly reported to the Board.
The Code of Conduct is available on the Company's website.
Dedicated Group policies, procedures and guidelines have been developed to outline specifi c rules and controls. The policies, guidelines and procedures cover areas such as Operations, Accounting and Finance, Health and Safety, Environment, Anti-Corruption, Human Rights, Stakeholder Relations, Legal, Information Systems, Insurance & Risk Management, Human Resources, Inside Information and Corporate Communications and are continuously reviewed and updated as and when required.
In 2017 Lundin Petroleum developed a corporate HSEQ (Health, Safety, Environmental and Quality) Leadership Charter, which sets out the governance framework as well as operational governance for managing the business in accordance with high HSEQ standards. The Charter, adopted early 2018, sets out four core foundation themes: leadership, risk and opportunity management, continuous improvement and implementation. It further details how these themes are to be operationalised.
CR and HSE policies are available on the Company's website.
The 2018 Annual General Meeting (AGM) will be held on 3 May 2018 at 1 p.m. in Vinterträdgården at Grand Hôtel, Södra Blasieholmshamnen 8, in Stockholm. Shareholders who wish to attend the meeting must be recorded in the share register maintained by Euroclear Sweden on 26 April 2018 and must notify the Company of their intention to attend the AGM no later than 26 April 2018.
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.
Lundin Petroleum's Rules of Procedure of the Board The Rules of Procedure of the Board contain the fundamental rules regarding the division of duties between the Board, the Committees, the Chairman of the Board and the Chief Executive Offi cer (CEO). The Rules of Procedure also include instructions to the CEO, instructions for the fi nancial reporting to the Board and the terms of reference of the Board Committees and the Investment Committee. The Rules of Procedure are approved annually by the Board.
The object of Lundin Petroleum's business is to explore for, develop and produce oil and gas and to develop other energy resources, as laid down in the Articles of Association. The Company aims to create value for its shareholders through exploration and organic growth, while operating in an economically, socially and environmentally responsible way for the benefi t of all stakeholders. By tying the corporate governance framework to its sustainability profi le, Lundin Petroleum has managed to achieve the high goals set out in the sustainability strategy. To achieve such sustainable value creation, Lundin Petroleum applies a governance structure that favours straightforward decision making processes, with easy access to relevant decision makers, while nonetheless providing the necessary checks and balances for the control of the activities, both operationally and fi nancially.
The shares of Lundin Petroleum are listed on NASDAQ Stockholm. The total number of shares is 340,386,445 shares with a quota value of SEK 0.01 each (rounded-off), representing a registered share capital of SEK 3,478,713. All shares of the Company carry the same voting rights and the same rights to a share of the Company's assets and earnings. The Board has been authorised by previous AGMs to decide upon repurchases and sales of the Company's own shares as an instrument to optimise the Company's capital structure and to secure the Company's obligations under its incentive plans. During 2017, the Company purchased 1,233,310 own shares at an average purchase price of SEK 186.14.
Lundin Petroleum had at the end of 2017 a total of 29,491 shareholders listed with Euroclear Sweden, which represents a decrease of 3,235 shareholders compared to the end of 2016, i.e. a decrease of approximately ten percent. As at 31 December 2017, the major shareholders of the Company, which held more than ten percent of the shares and votes, were Nemesia S.à.r.l., an investment company wholly owned by a Lundin family trust, which held 25.6 percent of the shares. In addition, Landor Participations Inc., an investment company wholly owned by a trust whose settler is Ian H. Lundin, held 3.1 percent of the shares. Furthermore, Statoil ASA held 20.1 percent of the shares as per 31 December 2017.
Further information regarding the shares and shareholders of Lundin Petroleum in 2017 can be found on pages 10–11.
The Nomination Committee is formed in accordance with the Company's Nomination Committee Process approved at the 2014 AGM. 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 submit proposals to the Nomination Committee by e-mail to [email protected]
The members of the Nomination Committee for the 2018 AGM were announced and posted on the Company's website on 10 October 2017, i.e. within the time frame of six months before the AGM as prescribed by the Code of Governance. Statoil ASA and other larger shareholders of the Company were invited to join but declined the invitation.
The Nomination Committee has held four meetings during its mandate so far. 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 the chairman of the Nomination Committee, commented at the meetings on the Company's business operations and future outlook, as well as on the oil and gas industry in general.
The full Nomination Committee report, including the fi nal proposals to the 2018 AGM, are published on the Company's website together with the notice of the 2018 AGM.
| Nomination Committee for the 2018 AGM | ||||||
|---|---|---|---|---|---|---|
| Member | Appointed by | Meeting attendance |
Shares represented as at 1 Aug 2017 |
Shares represented as at 31 Dec 2017 |
Independent of the Company and Group management |
Independent of the Company's major shareholders |
| Hans Ek | SEB Investment Management AB |
4/4 | 0.6 percent | 0.6 percent | Yes | Yes |
| Filippa Gerstädt | Nordea Fonder | 4/4 | 1.1 percent | 1.4 percent | Yes | Yes |
| Ian H. Lundin | Nemesia S.à.r.l and Landor Participations Inc., also non-executive Chairman of the Board of Lundin Petroleum |
4/4 | 28.7 percent | 28.7 percent | Yes | No1 |
| Åsa Nisell | Swedbank Robur Fonder |
4/4 | 2.2 percent | 2.0 percent | Yes | Yes |
| Total 32.7 percent (rounded) |
Total 32.7 percent |
1 For details, see schedule on pages 34–35.
The Shareholders' Meeting is the highest decision-making body of Lundin Petroleum where the shareholders exercise their voting rights and infl uence the business of the Company. Shareholders may request that a specifi c issue be included in the agenda provided such request reaches the Board in due time. The AGM is held each year before the end of June at the seat of the Board in Stockholm. The notice of the AGM is announced in the Swedish Gazette (Post- och Inrikes Tidningar) and on the Company's website no more than six and no less than four weeks prior to the meeting. The documentation for the AGM is provided on the Company's website in Swedish and in English at the latest three weeks before the AGM.
3
The 2017 AGM was held on 4 May 2017 at Grand Hôtel in Stockholm. The AGM was attended by 669 shareholders, personally or by proxy, representing 64.74 percent of the share capital. The Chairman of the Board, all of the Board members including the CEO were present, as well as the Company's auditor and all of the members of the Nomination Committee for the 2017 AGM. The members of the Nomination Committee for the 2017 AGM were Åsa Nisell (Swedbank Robur Fonder), Hans Ek (SEB Investment Management AB), Ian H. Lundin (Nemesia S.à.r.l., and Landor Participations Inc., as well as non-executive Chairman of the Board of Lundin Petroleum) and Magnus Unger (then non-executive Board member of Lundin Petroleum). 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 2017 AGM include:
· Adoption of the Company's income statement and balance sheet and the consolidated income statement and balance sheet and deciding that no dividend was to be declared for 2016.
· Re-election of the registered accounting fi rm PricewaterhouseCoopers AB as the Company's statutory auditor until the 2018 AGM, authorised public accountant Johan Rippe being the designated auditor in charge.
An electronic system with voting devices was used for the two last items requiring a qualifi ed majority. The minutes of the 2017 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.
An EGM was held on 22 March 2017 in Stockholm in respect of the Board's proposal for a spin-off of the Company's Malaysian, French and Dutch assets into International Petroleum Corporation (IPC) through a Lex Asea dividend distribution. The EGM resolved, in accordance with the Board proposal, to distribute all shares in IPC to the shareholders, which distribution was completed on 24 April 2017. In accordance with the Lex Asea provision, the Swedish tax authorities determined in June 2017 that 92.5 percent of the acquisition cost should be allocated to Lundin Petroleum shares and 7.5 percent to IPC shares.
In June 2010, the Swedish International Public Prosecution Offi ce commenced an investigation into alleged complicity in violations of international humanitarian law in Sudan during 1997–2003. The Company has cooperated extensively and proactively with the Prosecution Offi ce by providing information regarding its operations in Block 5A in Sudan during the relevant time period. Ian H. Lundin and Alex Schneiter have been interviewed by the Prosecution Offi ce and have been notifi ed of the suspicions that are the basis for the investigation. This is a normal part of Swedish legal procedure for any investigation and no charges have been brought, nor does this mean that charges will be brought. As repeatedly stated, Lundin Petroleum categorically refutes all allegations of wrongdoing and is cooperating with the Prosecution Offi ce's investigation. Lundin Petroleum strongly believes that it was a force for good in Sudan and that its activities contributed to the improvement of the lives of the people of Sudan.
More information regarding the past operations in Sudan during 1997–2003 can be found on www.lundinhistoryinsudan.com
The Chairman of the Board and the CEO, who is also a Board member, attended the EGM, however, a quorum of Board members was not present as required by Code of Governance rule 1.2. Given the detailed information presented in the notice of the EGM, and the information memorandum, it was considered suffi cient that the Chairman of the Board and the CEO represent the Board at the EGM.
Lundin Petroleum's statutory auditor audits annually the Company's fi nancial statements, the consolidated fi nancial statements, the Board's and the CEO's administration of the Company's affairs and reports on the Corporate Governance Report. The auditor also reviews the Sustainability Report to confi rm that it contains the required information. In addition, the auditor 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 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.
The auditor's fees are described in the notes to the fi nancial statements, see Note 30 on page 93 and Note 7 on page 98. 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 Audit Committee.
Lundin Petroleum's independent qualifi ed reserves auditor certifi es 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 current auditor is ERC Equipoise Ltd. For further information regarding the Company's reserves and resources, see the Operations Review on pages 12–19.
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 and diverse 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. The Code of Governance stipulates that gender balance shall be strived for.
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 fi nal number each year. The Board members are elected for a period of one year.
The Nomination Committee for the 2017 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. There are no deputy members and no members 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 Henrika Frykman, the Company's Vice President Legal.
The Nomination Committee considered that the Board as proposed and elected by the 2017 AGM is a broad and versatile group of knowledgeable and skilled individuals who are motivated and prepared to undertake the tasks required of the Board in today's challenging international business environment. The Board members possess substantial expertise and experience relating to the oil and gas industry internationally, and in particular in relation to Lundin Petroleum's core area of operation, Norway, public company fi nancial matters, Swedish practice and compliance matters and CR/HSE matters. The Nomination Committee considered that the proposed Board fulfi ls the requirements regarding independence in relation to the Company, Group management and the Company's major shareholders.
Gender balance was specifi cally discussed and the Nomination Committee noted that 38 percent of the Board members are women and that the Company has thus met since 2015 the recommendation of the Swedish Corporate Governance Board, that larger listed Swedish companies should strive to achieve 35 percent female Board representation by 2017. The Nomination Committee nonetheless believes that it is important to continue to strive for gender balance when future changes in the composition of the Board are considered.
| Board of Directors: | Ian H. Lundin | Alex Schneiter | Peggy Bruzelius | C. Ashley Heppenstall |
|---|---|---|---|---|
| Function | Chairman (since 2002) | President & Chief Executive Offi cer, Director |
Director | Director |
| Elected | 2001 | 2016 | 2013 | 2001 |
| Born | 1960 | 1962 | 1949 | 1962 |
| Education | Bachelor of Science degree in Petroleum Engineering from the University of Tulsa. |
Graduate from the University of Geneva with a degree in Geology and a Masters degree in Geophysics. |
Master of Science (Economics and Business) from the Stockholm School of Economics. |
Bachelor of Science degree in Mathematics from the University of Durham. |
| 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. |
Alex Schneiter has worked with public companies where the Lundin family has a major shareholding since 1993 and was COO of Lundin Petroleum during 2001–2015 and is the Company's CEO since 2015. |
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 and was CEO of Lundin Petroleum during 2002–2015. |
| Other board duties | Member of the board of Bukowski Auktioner AB. |
– | Chair of the board of Lancelot Asset Management AB, member of the board of Diageo PLC, Akzo Nobel NV and Skandia Liv. |
Chairman of the board of Etrion Corporation and Africa Energy Corp. and member of the board of ShaMaran Petroleum Corp., Lundin Gold Inc., Filo Mining Corp. and International Petroleum Corp. |
| Shares in Lundin Petroleum (as at 31 December 2017) |
Nil1 | 317,910 | 8,000 | 1,520,126 |
| Board Attendance | 12/12 | 12/12 | 12/12 | 12/12 |
| Audit Committee Attendance |
– | – | 6/6 | 6/6 |
| Compensation Committee Attendance |
4/4 | – | – | – |
| Remuneration for Board and Committee work |
SEK 1,180,000 | Nil | SEK 670,000 | SEK 617,500 |
| Remuneration for special assignments outside the directorship |
SEK 1,500,000 | Nil | Nil | SEK 5,203,800 |
| Independent of the Company and the Group management |
Yes | No2 | Yes | No3 |
| Independent of the Company's major |
No1 | Yes | Yes | No3 |
1 Ian H. Lundin is the settler of a trust that owns Landor Participations Inc., an investment company that holds 10,488,956 shares in the Company, and is a member of the Lundin family that holds, through a family trust, Nemesia S.à.r.l., which holds 87,187,538 shares in the Company.
2 Alex Schneiter is in the Nomination Committee's and the Company's opinion not deemed independent of the Company and Group management since he is the President and CEO of Lundin Petroleum.
3 C. Ashley Heppenstall is in the Nomination Committee's and the Company's opinion not deemed independent of the Company and Group management since he was the President and CEO of Lundin Petroleum until 2015, and not of the Company's major shareholders since he is a director of several companies in which entities associated with the Lundin family are major shareholders.
shareholders
| Lukas H. Lundin | Grace Reksten Skaugen | Jakob Thomasen | Cecilia Vieweg |
|---|---|---|---|
| Director | Director, CR/HSE representative | Director | Director |
| 2001 | 2015 | 2017 | 2013 |
| 1958 | 1953 | 1962 | 1955 |
| Graduate from the New Mexico Institute of Mining, Technology and Engineering. |
MBA from the BI Norwegian School of Management, Bachelor of Science (Honours Physics) and Doctorate in laser physics from Imperial College of Science and Technology at the University of London. |
Graduate of the University of Copenhagen, Denmark, masters degree in Geoscience and completed the Advanced Strategic Management programme at IMD, Switzerland. |
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. |
Grace Reksten Skaugen has been a director of Corporate Finance with SEB Enskilda Securities in Oslo and has worked in several roles within private equity and venture capital in Oslo and London. She was a member of the Board of Directors of Statoil ASA from 2002 until 2015. She is currently a member of HSBC European Senior Advisory Council and Norway country advisor to Proventus AB. |
Jakob Thomasen was formerly the CEO of Maersk Oil and a member of the Executive Board of the Maersk Group from 2009 until 2016. |
Cecilia Vieweg was General Counsel and member of the Executive Management of AB Electrolux from 1999–2016. 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., Filo Mining Corp., International Petroleum Corp. and Lundin Foundation, member of the board of Bukowski Auktioner AB. |
Chair of the board of NAXS Nordic Access Buyout A/S, Deputy Chair of the board of Orkla ASA and member of the board of Investor AB and Euronav NV, founder and board member of the Norwegian Institute of Directors and council member of the International Institute for Strategic Studies in London. |
Chairman of the DHI Group and member of the board of the University of Copenhagen. |
– |
| 788,3314 | 5,000 | 5,900 | 3,500 |
|---|---|---|---|
| 12/12 | 11/12 | 5/55 | 12/12 |
| – | – | 3/35 | – |
| – | 4/4 | – | 4/4 |
| SEK 512,000 | SEK 617,500 | SEK 317,500 | SEK 670,000 |
| Nil | Nil | Nil | Nil |
| Yes | Yes | Yes | Yes |
| No4 | Yes | Yes | Yes |
4 Lukas H. Lundin is a member of the Lundin family that holds, through a family trust, Nemesia S.à.r.l., which holds 87,187,538 shares in the Company.
5 Jakob Thomasen is a member of the Board of Directors and is a member of the Audit Committee as of 4 May 2017.
Magnus Unger declined re-election at the AGM on 4 May 2017. During the period 1 January to 4 May 2017, he attended seven out of seven Board meetings held and two out of three Audit Committee meetings held. For additional information regarding Magnus Unger, please see the Company's Annual Report 2016, and for remuneration paid to him, please refer to Note 28 on pages 90–91.
The Chairman of the Board, Ian H. Lundin, is responsible for ensuring that the Board's work is well organised and conducted in an effi cient manner. He upholds the reporting instructions for management, as drawn up by the CEO and as approved by the Board, however, he does not take part in the day-to-day decision-making concerning the operations of the Company. The Chairman maintains close contacts with the CEO to ensure the Board is at all times suffi ciently informed of the Company's operations and fi nancial status.
During 2017, twelve Board meetings were held, including the statutory meeting. 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, industry partners and other business interests. In September 2017, the Board visited the Samsung shipyard in Geoje in South Korea where two platforms for the Johan Sverdrup fi eld were being built, 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, as well as a fi nancial update discussing the Company's current and future fi nancing needs and hedging strategy, and an investor relations and valuation update. In-depth operations reviews were given regarding the Group's exploration, development and production activities, with a continued focus on the Norwegian operations and the major Johan Sverdrup development project. Group management also attended a number of Board meetings during the year to present and report on specifi c questions, and a monthly operational report was circulated to the Board, as well as a quarterly CR/HSE report.
A formal review of the work of the Board was conducted in November 2017 through a questionnaire submitted to all Board members, with the objective of ensuring that the Board functions in an effi cient manner and to enable the Board to strengthen its focus on matters which may be raised.
The overall feedback from the members of the Board was positive and showed that the Board functions well. The different backgrounds, knowledge and qualifi cations of the individual members of the Board complement each other and the meetings are constructive with good discussions and feedback from Board members and management. The diversity and wide spectrum of qualifi cations of experience of the Board members are considered as benefi cial and the Board is viewed as competent for addressing actual and potential issues facing the Company.
The size of the Board was considered appropriate, however, individual feedback received noted that additional directors could be considered. The Board members were of the view that
· Establishing the overall goals and strategy of the Company.
their knowledge of the Company and the oil and gas industry in general increased during the year. The need for a retirement policy was considered, however, the Board acknowledged that there was already a natural process of renewing the Board and that such a policy was therefore not needed. Visits at operational locations were appreciated and considered very useful for the understanding of the business. Committee work further functions very well and the composition of the Committees is appropriate. Individual feedback received noted that Board meetings are well prepared and managed, and questions and comments are addressed in an open and constructive manner, however there is room to improve time management. The results of the Board evaluation were presented to the Nomination Committee.
More information on the Board members can be found on www. lundin-petroleum.com
i
In addition to the topics covered by the Board as per its yearly work cycle, the following signifi cant matters were addressed by the Board during the year.
– Discussing in detail the Company's spin-off of the non-Norwegian assets, and considering and approving the transaction and all related materials, subject to EGM approval.
of Procedure
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. The Policy on Remuneration approved by the AGM also comprises remuneration paid to Board members for work performed outside the directorship.
The Board has implemented a policy for share ownership by Board members and 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, including for work performed outside the directorship, is detailed further in the schedule on pages 34–35 and in the notes to the fi nancial statements, see Note 28 on pages 90–91.
To maximise the effi ciency of the Board's work and to ensure a thorough review of specifi c 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 advice and assistance of external reward consultants. For further information regarding Group remuneration matters, see the remuneration section of this report on pages 42–43.
The Audit Committee assists the Board in ensuring that the Company's fi nancial reports are prepared in accordance with International Financial Reporting Standards (IFRS), the Swedish Annual Accounts Act and accounting practices applicable to a company incorporated in Sweden and listed on NASDAQ Stockholm. The Audit Committee itself does not perform audit work, however, it supervises the Company's fi nancial reporting and gives recommendations and proposals to ensure the reliability of the reporting. The Committee also supervises the effi ciency of the Company's fi nancial internal controls, internal audit and risk management in relation to the fi nancial reporting and provides support to the Board in the decision making processes regarding such matters. The Committee monitors the audit of the Company's fi nancial reports and also reports thereon to the Board. In addition, the Committee is empowered by the Committee's terms of reference to make decisions on certain issues delegated to it, such as review and approval of the Company's fi rst and third quarter reports 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.
The Board has a leadership and supervisory role in all CR/ HSE matters within the Group and appoints yearly one nonexecutive 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/HSE related matters and to regularly report on such matters to the Board. More information about the Company's CR/HSE activities can be found in the Responsibility section on pages 20–23 and in the Sustainabilty Report available on the Company's website.
Management structure
The Company's CEO, Alex Schneiter, is responsible for the management of the day-to-day operations of Lundin Petroleum. He is appointed by, and reports to, the Board. 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 comprises, in addition to the CEO:
· The Investment Committee, which in addition to the CEO includes:
–the Chief Operating Offi ce (COO), Nick Walker, who is responsible for Lundin Petroleum's exploration, development and production operations and HSE; and
| Audit Committee 2017 | ||
|---|---|---|
| Members | Meeting attendance |
Audit Committee work during the year |
| Peggy Bruzelius, Chair C. Ashley Heppenstall Magnus Unger1 Jakob Thomasen1 |
6/6 6/6 2/3 3/3 |
–Assessment of the 2016 year end report and the 2017 half year report for completeness and accuracy and recommendation for approval to the Board. – Assessment and approval of the fi rst and third quarter reports 2017 on behalf of the Board. – Evaluation of accounting issues in relation to the assessment of the fi nancial reports. – Follow-up and evaluation of the results of the internal audit and risk management of the Group. – Three meetings with the statutory auditor to discuss the fi nancial reporting, internal controls, risk management, etc. – 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 statutory auditor for election at the 2018 AGM. |
| Other Requirements – The composition and the members of the Audit Committee fulfi l the requirements of the Swedish Companies Act. – The Audit Committee members have extensive experience in fi nancial, accounting and audit matters. Peggy Bruzelius' current and previous assignments include high level management positions in fi nancial institutions and companies and she has chaired Audit Committees of other companies. C. Ashley Heppenstall is the Company's previous CFO and CEO and Jakob Thomasen was previously CEO of Maersk Oil, and both have extensive experience in fi nancial matters. |
||
| Compensation Committee 2017 | ||
| Members | Meeting attendance |
Compensation Committee work during the year |
| Cecilia Vieweg, Chair Grace Reksten Skaugen Ian H. Lundin |
4/4 4/4 4/4 |
– Ongoing review of the Executive Performance Management Process through various work sessions across the year. – Review, restructure and update of contracts of employment, including review of remuneration, for Group management following the IPC spin-off. – Discussions and recommendations to the Board in remuneration matters in connection with the IPC spin-off. – 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 2016. – Continuous monitoring and evaluation of remuneration structures, levels, programmes and the Policy on Remuneration. – Preparing a proposal for the 2017 Policy on Remuneration for Board and AGM approval. – Consultation and meetings with Company stakeholders, including institutional investors, regarding the proposed LTIP 2017. – Preparing a proposal for LTIP 2017 for Board and AGM approval through various work sessions and preparation discussions. – Review of the 2014 LTIP pay out and vesting and approval recommendation to the Board. – 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 Group management for Board approval. – Review and approval of the CEO's proposals for the principles of compensation of other employees. – Review and approval of the CEO's proposals for 2017 LTIP awards. – Undertaking a remuneration benchmark study and various contacts and ongoing reviews in relation thereto across the year. – Frequent contacts, ongoing dialogue and decisions by email outside of formal meetings to provide oversight and approvals for remuneration and severance terms as presented by Group management. Other Requirements – The composition of the Compensation Committee fulfi ls the independence requirements of the Code of Governance. |
1 Magnus Unger was a member of the Audit Committee until 4 May 2017 and Jakob Thomasen is a member of the Audit Committee as of 4 May 2017.
The tasks of the CEO and the division of duties between the Board and the CEO are defi ned in the Rules of Procedure and the Board's instructions to the CEO. In addition to the overall management of the Company, the CEO's tasks include ensuring that the Board receives all relevant information regarding the Company's operations, including profi t trends, fi nancial position and liquidity, as well as information regarding important events such as signifi cant disputes, agreements and developments in important business relations. The CEO is also responsible for preparing the required information for Board decisions and for ensuring that the Company complies with applicable legislation, securities regulations and other rules such as the Code of Governance. Furthermore, the CEO maintains regular contacts with the Company's stakeholders, including shareholders, the fi nancial markets, business partners and public authorities. To fulfi l his duties, the CEO works closely with the Chairman of the Board to discuss the Company's operations, fi nancial status, up-coming Board meetings, implementation of decisions and other matters.
Under the leadership of the CEO, Group management is responsible for ensuring that the operations are conducted in compliance with the Code of Conduct, all Group policies, procedures and guidelines in a professional, effi cient and responsible manner. Regular management meetings are held to discuss all commercial, technical, CR/HSE, fi nancial, legal and other 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 fi nancial 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, assists 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.
The Internal Audit function is responsible for providing independent and objective assurance on internal control, governance and risk management. This work includes regular audits performed in accordance with an annual risk based internal audit plan, which is approved by the Audit Committee. The audit plan is derived from an independent risk assessment conducted by the Internal Audit function and is designed to address the most signifi cant risks identifi ed associated with the Company's operations and processes. The audits are executed using a methodology for evaluating the design and effectiveness of internal controls to ensure that risks are adequately addressed and processes are operated effectively. Opportunities for improving the effi ciency of the internal control, governance, and risk management processes which have been identifi ed through the audits are reported to management for action.
The Internal Audit Manager has a direct reporting line to the Audit Committee and submits regularly reports on fi ndings identifi ed in the audits together with updates on the status of management's implementation of agreed actions.
Alex Schneiter President and Chief Executive Offi cer
Christine Batruch Vice President Corporate Responsibility
Nick Walker Chief Operating Offi cer
Alex Budden Vice President Communications and Investor Relations
Teitur Poulsen Chief Financial Offi cer
Henrika Frykman Vice President Legal
More information on Group management can be found on www. lundin-petroleum.com
i
Sean Reddy Vice President Human Resources and Shared Services
Compensation Committee therefore prepares yearly for approval by the Board and for submission for fi nal 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 yearly variable salary for Group management is assessed against annual performance targets that refl ect the key drivers for value creation and growth in shareholder value. These annual performance targets include delivery against specifi c production, reserves and resource replacement, fi nancial, health and safety, environment, corporate responsibility and strategic targets. Each member of Group management is set different performance weightings against each of the specifi c targets refl ecting their infl uence on the performance outcome. The performance target structure and specifi c targets are reviewed annually by the Compensation Committee to ensure that it aligns with the strategic direction and risk appetite of the Company and the performance target structure and specifi c targets are approved by the Board.
Within the Policy on Remuneration, the Board of Directors may approve yearly variable salary in excess of twelve months base salary in circumstances or in respect of performance which it considers to be exceptional. To have this discretion is important to accommodate the uncertainties and cyclical nature of the oil and gas industry. The Board has made two such decisions that are reported in this Annual Report. The Board determined that it was reasonable to recognise for the fi nancial year 2016 the exceptional performance in relation to production and fi nancial management, and for the fi nancial year 2017, the exceptional performance that led to the successful spin-off of IPC and signifi cant value creation for shareholders.
Lundin Petroleum aims to offer all 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 benefi ts. 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.
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
The 2017 AGM resolved to approve a performance based LTIP 2017, that follows the same principles as the previously approved LTIPs 2014–2016, 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 fulfi lment of a performance condition under a three year performance period commencing on 1 July 2017 and expiring on 30 June 2020. 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 others 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 2017 and the total LTIP award made in respect of 2017 was 355,954.
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 refl ected in the outcome of the performance condition, for example, in light of operating cash fl ow, 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 2017, 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 2017 are further subject to certain disposition restrictions to ensure participants build 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 2017, the Compensation Committee undertook on behalf of the Board a review of the work and performance of Group management, including the CEO. The results were presented to the 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 verifi es on a yearly basis whether the Company has complied with the Policy on Remuneration. Both reports are available on the Company's website.
At an extraordinary general meeting held on 22 March 2017, the Company's shareholders resolved upon a dividend in kind of all shares in IPC. In this Policy on Remuneration, the term "Group management" refers to the President and Chief Executive Offi cer, the Chief Operating Offi cer, the Chief Financial Offi cer and Vice President level employees. Following the dividend in kind, Group management will be comprised of six executives in 2017.
This Policy on Remuneration also comprises remuneration paid to members of the Board of Directors for work performed outside the directorship.
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's and the AGMs' 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 confl ict 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:
For information regarding the Board's proposal for remuneration to Group management to the 2018 AGM, including a similar LTIP as approved by the 2014–2017 AGMs, see the Directors' report, pages 57–58.
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 refl ect the key drivers for value creation and growth in shareholder value. Through its Performance Management Process, the Company sets predetermined and measurable performance criteria for each executive, aimed at promoting longterm 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 (if any). However, the Compensation Committee may recommend to the Board 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 2017 is estimated to range between no payout at minimum level and MSEK 20.0 (excluding social costs) at maximum level, based on the current composition of Group management.
The Company believes that it is appropriate to structure its longterm 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 2017 LTIP for Group management, which follows the same principles as the LTIP approved by the 2014–2016 AGMs, is available as part of the documentation for the AGM on www.lundin-petroleum.com
The cost at grant of the proposed 2017 LTIP is estimated to range between no cost at minimum level and MSEK 43.8 (excluding social costs) at maximum level, based on the current composition of Group management.
Other benefi ts shall be based on market terms and shall facilitate the discharge of each executive's duties. Such benefi ts include statutory pension benefi ts comprising a defi ned contribution scheme with premiums calculated on the full 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 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 benefi ts 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.
In addition to Board's fees resolved by the AGM, remuneration as per prevailing market conditions may be paid to members of the Board for work performed outside the directorship.
The Board is authorised to deviate from the Policy on Remuneration in accordance with Chapter 8, Section 53 of the Swedish Companies Act in case of special circumstances in a specifi c case.
Remunerations outstanding to Group management comprise awards granted under the Company's previous LTIP programs and include 122,263 LTIP Awards under the 2014 Performance Based Incentive Plan, 191,454 LTIP Awards under the 2015 Performance Based Incentive Plan, 227,670 LTIP Awards under the 2016 Performance Based Incentive Plan, 761 unit bonus awards under the 2014 Unit Bonus Plan, 1,864 unit bonus awards under the 2015 Unit Bonus Plan and 2,421 unit bonus awards under the 2016 Unit Bonus Plan. The awards will be recalculated as a result of the dividend in kind of IPC in accordance with the applicable plan rules. Further information about these plans is available in Note 29 of the Company's Annual Report 2016.
The control environment is the foundation of Lundin Petroleum's system for internal control over financial reporting
According to the Swedish Companies Act and the Code of Governance, the Board has overall responsibility for establishing and monitoring an effective system for internal control. The purpose of this report is to provide shareholders and other parties with an understanding of how internal control is organised at Lundin Petroleum.
Lundin Petroleum's system for internal control over fi nancial reporting is based on the Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The fi ve components of this framework are control environment, risk assessment, control activities, information and communication and monitoring activities.
The control environment is the foundation of Lundin Petroleum's system for internal control over fi nancial reporting and is characterised by the fact that the main part of the Group's operations are located to Norway where the Company has carried out operations for many years using well established processes. The control environment is defi ned by the Company's policies and procedures, guidelines and codes as well as its responsibility and authority structure. The business culture established within the Group is also fundamental to ensure highest level of ethics, morals and integrity.
Risks relating to fi nancial reporting are evaluated and monitored by the Board through the Audit Committee. The Group's risk assessment process is used as a means to monitor that risks are managed and consists in identifying and evaluating risks and also determine the potential impact on the fi nancial reporting. Regular reviews on local level as well as on Group level are made to assess any changes made in the Group that may affect internal control.
Control activities range from high level reviews of fi nancial results in management meetings to detailed reconciliation of accounts and day to day review and authorisation of payments. The monthly review and analysis of the fi nancial reporting made on Company level and Group level are important control activities performed to ensure that the fi nancial reporting does not contain any signifi cant errors and also to prevent fraud. In addition, it is common in the oil and gas industry that projects are organised through joint ventures, where the partners have audit rights over the joint venture. Regular audits control that costs are allocated and accounted for in accordance with the joint operating agreement.
Lundin Petroleum has processes in place aiming to ensure effective and correct information in regards to fi nancial reporting, both internally within the organisation as well as externally to the public. All information regarding the Company's policies, procedures and guidelines is available on the Group's intranet and any updates and changes to reporting and accounting policies are issued via email and at regular fi nance meetings. In addition, the Communication and Investor Relations Policy ensures that the public is provided with accurate, timely and relevant information.
Monitoring of control activities is made at different levels of the organisation and involves both formal and informal procedures performed by management, process owners or control owners. In addition, the Group's Internal Audit function maintains test plans and performs independent testing of selected controls to identify any weaknesses and opportunities for improvement. The results from the testing are presented to the external auditors who determine to what extent they can rely on this testing for the Group audit.
The Internal Audit Manager has a direct reporting line to the Audit Committee and submits regularly reports on fi ndings identifi ed in the audits together with updates on the status of management's implementation of agreed actions. The Audit Committee assists the Board in their role to ensure that steps are taken to address any weaknesses revealed in internal and external audits and to implement proposed actions.
It is common in the oil and gas industry that projects are organised through joint ventures with production licences awarded to a group of companies forming a joint venture. When entering into an exploration license there is no guarantee that oil or gas will be found and in a joint venture the risk is shared between the partners. One partner is appointed to be the operator and is responsible for managing the operations, including the accounting for the joint venture. All partners have audit rights over the joint venture to ensure that costs are incurred in accordance with the joint operating agreement and that accounting procedures are followed.
Stockholm, 23 March 2018
The Board of Directors of Lundin Petroleum AB (publ)
To the general meeting of the shareholders in 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 2017 on pages 28–44 and that it has been prepared in accordance with the Annual Accounts Act.
Our examination has been conducted in accordance with FAR's auditing standard RevU 16 The auditor's examination of the corporate governance statement. This means that our 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 believe that the examination has provided us with suffi cient basis for our opinions.
A corporate governance statement has been prepared. Disclosures in accordance with chapter 6 section 6 the second paragraph points 2–6 the Annual Accounts Act and chapter 7 section 31 the second paragraph the same law are consistent with the annual accounts and the consolidated accounts and are in accordance with the Annual Accounts Act.
Stockholm 26 March 2018
PricewaterhouseCoopers AB
Johan Rippe Johan Malmqvist Authorised Public Accountant Authorised Public Accountant Lead Partner
2017 has been an inflection year for Lundin Petroleum with record high operating cash flow leading to free cash flow generation for the first time since 2011.
The exceptional operational performance during 2017, combined with an improving macro environment, has allowed us to accelerate our inaugural cash dividend and has positioned the Company to be able to grow the dividend going forward at the same time as leaving capacity to fund our organic growth strategy.
| Financial summary Continuing operations |
2017 | 2016 |
|---|---|---|
| Production in Mboepd | 86.1 | 59.3 |
| Revenue in MUSD | 1,997.0 | 950.0 |
| EBITDA in MUSD | 1,501.5 | 752.5 |
| Operating cash flow in MUSD | 1,530.0 | 857.9 |
| Net result in MUSD | 380.9 | -399.3 |
| Earnings/share in USD1 | 1.13 | -0.79 |
| Earnings/share fully diluted in USD1 | 1.13 | -0.79 |
| Net debt | 3,883.6 | 4,075.5 |
The numbers included in the table above are based on continuing operations (including 2016 comparatives) 1 Based on net result attributable to shareholders of the Parent Company
| Directors' report | 48 |
|---|---|
| Consolidated income statement | 59 |
| Consolidated statement of comprehensive income | 60 |
| Consolidated balance sheet | 61 |
| Consolidated statement of cash fl ow | 62 |
| Consolidated statement of changes in equity | 63 |
| Accounting policies | 64 |
| Notes to the fi nancial statements of the Group | 70 |
| - Note 1 – Revenue | 70 |
| - Note 2 – Production costs | 70 |
| - Note 3 – Segment information | 70 |
| - Note 4 – Finance income | 72 |
| - Note 5 – Finance costs | 72 |
| - Note 6 – Share in result of associated company | 72 |
| - Note 7 – Income tax | 72 |
| - Note 8 – Loss from sale of assets | 74 |
| - Note 9 – Discontinued operations | 75 |
| - Note 10 – Oil and gas properties | 76 |
| - Note 11 – Other tangible assets | 78 |
| - Note 12 – Goodwill | 78 |
| - Note 13 – Financial assets | 78 |
| - Note 13.1 – Other shares and participations | 79 |
| - Note 14 – Inventories | 79 |
| - Note 15 – Trade and other receivables | 79 |
| - Note 16 – Cash and cash equivalents | 79 |
| - Note 17 – Equity | 80 |
| - Note 17.1 – Share capital and share premium | 80 |
| - Note 17.2 – Other reserves | 80 |
| - Note 17.3 –Earnings per share | 81 |
| - Note 18 – Financial liabilities | 81 |
| - Note 19 – Provisions | 81 |
| - Note 20 – Trade and other payables | 82 |
| - Note 21 – Financial assets and liabilities | 83 |
| - Note 22 – Changes in liabilities with cash fl ow | |
|---|---|
| movements from fi nancing activities | 85 |
| - Note 23 – Financial risks, sensitivity analysis and | |
| derivative instruments | 85 |
| - Note 24 – Pledged assets | 88 |
| - Note 25 – Contingent liabilities and assets | 88 |
| - Note 26 – Related party transactions | 88 |
| - Note 27 – Average number of employees | 89 |
| - Note 28 – Remuneration to the Board of Directors, | |
| Group management and other employees | 90 |
| - Note 29 – Long-term incentive plans | 92 |
| - Note 30 – Remuneration to the Group's auditors | 93 |
| - Note 31 – Subsequent events | 93 |
| Annual accounts of the Parent Company | 94 |
| Parent Company income statement | 95 |
| Parent Company comprehensive income statement | 95 |
| Parent Company balance sheet | 96 |
| Parent Company statement of cash fl ow | 97 |
| Parent Company statement of changes in equity | 97 |
| Notes to the fi nancial statements of the Parent Company | 98 |
| - Note 1 – Finance income | 98 |
| - Note 2 – Finance costs | 98 |
| - Note 3 – Income taxes | 98 |
| - Note 4 – Other receivables | 98 |
| - Note 5 – Accrued expenses and prepaid income | 98 |
| - Note 6 – Pledged assets, contingent liabilities and assets | 98 |
| - Note 7 – Remuneration to the auditor | 98 |
| - Note 8 – Proposed Disposition of Unappropriated | |
| Earnings | 98 |
| - Note 9 – Shares in subsidiaries | 99 |
| Board assurance | 100 |
| Auditor's report | 101 |
Lundin Petroleum AB (publ) Reg No. 556610-8055
The address of Lundin Petroleum AB's registered offi ce is Hovslagargatan 5, Stockholm, Sweden.
Lundin Petroleum is an independent oil and gas exploration and production company with operations focused on Norway. The spin-off of Lundin Petroleum's non-Norwegian producing assets into International Petroleum Corporation (IPC) was completed at the end of April 2017 and the results from the assets in Malaysia, France and the Netherlands are reported as discontinued operations.
The Group does not carry out any signifi cant research and development. The Parent Company has no foreign branches.
On 24 April 2017, Lundin Petroleum completed the spin-off of its assets in Malaysia, France and the Netherlands (the IPC assets) into IPC by distributing the IPC shares, on a pro-rata basis, to Lundin Petroleum shareholders. The results of the IPC business are included in the Lundin Petroleum fi nancial statements until the completion of the spin-off and are shown as discontinued operations. For more information see Note 9.
Lundin Petroleum has updated the accounting judgement of the consolidation of the Russian operations and concluded that the investment in Mintley Caspian Ltd., which is the holding company of PetroResurs, Lundin Petroleum´s investment in Russia, should be reclassifi ed to a joint venture. The investment in Mintley Caspian Ltd. was therefore deconsolidated at the end of the third quarter 2017. The deconsolidation has no signifi cant impact to the income statement since the investment in Russia was fully impaired in prior years and the carrying value is considered to be close to zero. The deconsolidation has triggered a shift of MUSD 82.0 within total equity between equity attributable to the owners of the parent company and noncontrolling interest. The shift within total equity had a negative impact on equity attributable to the owners of the parent company with this change being recorded during 2017.
Lundin Petroleum divested a 39 percent working interest in the Brynhild fi eld to CapeOmega with an effective date of 1 January 2017 and a completion date of 30 November 2017. The transaction involved a consideration of MUSD 93.7, including historical tax and uplift balances. The transaction resulted in a net after tax accounting loss of MUSD 14.4 arising from the difference between the consideration received and the book value of the associated assets being divested.
In accordance with the Norwegian Petroleum Tax Act the consideration is paid on an after tax basis and the remaining tax balances were transferred from Lundin Petroleum to CapeOmega. Lundin Petroleum is therefore not liable to tax payments for the consideration received. For further information see Note 8.
All the reported numbers and updates in the operational review relate to the fi nancial year ended 31 December 2017 unless otherwise specifi ed.
Lundin Petroleum has 726.3 million barrels of oil equivalent (MMboe) of proved plus probable net reserves and 895.5 MMboe of proved plus probable plus possible net reserves as at 31 December 2017 as certifi ed by an independent third party. Lundin Petroleum also has discovered oil and gas resources which classify as contingent resources and are not yet classifi ed as reserves. The best estimate contingent resources net to Lundin Petroleum amounted to 203.4 MMboe as at 31 December 2017.
Production for the year amounted to 86.1 thousand barrels of oil equivalent per day (Mboepd) (compared to 59.3 Mboepd for 2016), which was above the revised production guidance for the year of at or above 85 Mboepd and 15 percent above the mid-point of the original production guidance of 70 to 80 Mboepd. This performance is due to strong facilities and reservoir performance at both the Edvard Grieg fi eld and the Alvheim area. The production guidance for 2018 is between 74 to 82 Mboepd.
Total cash operating cost for the year, including netting off tariff income, was USD 4.25 per barrel which was 20 percent below the original guidance of USD 5.30 per barrel. This performance is due to a combination of reduced costs and the increased production volumes.
The production was comprised as follows:
| Production in Mboepd | 2017 | 2016 |
|---|---|---|
| Norway | ||
| Crude oil | 77.6 | 53.2 |
| Gas | 8.5 | 6.1 |
| Total production | 86.1 | 59.3 |
| Quantity in Mboe | 31,427.7 | 21,701.4 |
Production in
| Mboepd | WI1 | 2017 | 2016 |
|---|---|---|---|
| Edvard Grieg | 65%2 | 66.7 | 42.0 |
| Ivar Aasen | 1.385% | 0.7 | – |
| Alvheim | 15% | 12.4 | 10.0 |
| Volund | 35% | 3.9 | 2.7 |
| Bøyla | 15% | 1.1 | 1.7 |
| Brynhild | 51%3 | 1.2 | 2.6 |
| Gaupe | 40% | 0.2 | 0.3 |
| Quantity in Mboepd | 86.1 | 59.3 |
1 Lundin Petroleum's working interest (WI)
2 WI 50% up to 30 June 2016
3 WI 90% up to 30 November 2017 Net production from the Edvard Grieg fi eld during the year was higher than forecast at 66.7 Mboepd due to increased facilities capacity, good production effi ciency and strong reservoir performance. The Ivar Aasen fi eld, which produces through the Edvard Grieg facilities, commenced production in December 2016 and the combined fi elds have been producing with a strong level of reliability, with Edvard Grieg production effi ciency of 94 percent for the year. Capacity testing of the Edvard Grieg facilities confi rmed that the facilities are able to produce at rates 15 percent above design levels at 145 thousand barrels of oil per day (Mbopd) combined from Edvard Grieg and Ivar Aasen. The current production fully utilises this higher facilities capacity whilst also honouring the contractual allocation of facilities capacity between the Edvard Grieg and Ivar Aasen fi elds. The contractual allocation changes through time, with the fi nal contractual change occurring at the end of the third quarter 2018. The contractual capacity allocation is refl ected in the 2018 production guidance.
The total operating cost for the Edvard Grieg fi eld was USD 4.61 per barrel for the year and cash operating cost, including netting off tariff income, was USD 3.71 per barrel for the year.
In April 2017, Lundin Petroleum announced the successful Edvard Grieg Southwest appraisal well 16/1-27 which encountered a 15 metres gross oil column with signifi cantly better sand quality and thickness compared to prognosis. The well results confi rmed additional reserves in this area of the fi eld, which combined with the results from the other wells drilled during the year and the strong reservoir performance, which has seen no water production to date, has resulted in the fi eld's best estimate gross ultimate recovery increasing by 51 MMboe to 274 MMboe as at year end 2017, which is a 47 percent increase on the original estimate in the Plan for Development and Operation (PDO).
The Edvard Grieg development drilling plan within the PDO has been optimised within the same number of planned wells to access the southwest area of the fi eld with one production well and one water injection well targeting this area of the fi eld. During the year, three production wells and two water injection wells were successfully drilled on the Edvard Grieg fi eld with results in line or better than expectations. Two further production wells have been successfully drilled in the fi rst quarter of 2018. To date, 13 out of a total of 14 development wells have been completed with drilling operations planned to continue into the second quarter of 2018. The production capacity from the nine production wells drilled so far exceeds expectations and signifi cantly exceeds the available facilities capacity.
Net production from the Ivar Aasen fi eld during the year was in line with forecast at 0.7 Mboepd. Water injection commenced during the second quarter of 2017 and the PDO drilling programme was completed during the third quarter of 2017.
Production during the year from the Alvheim area, consisting of the Alvheim, Volund and the Bøyla fi elds, was ahead of forecast due to reservoir performance continuing to be better than expected as well as higher than expected Alvheim FPSO production effi ciency of 97 percent. The total operating cost for the Alvheim area was USD 3.70 per barrel for the year.
Net production from the Alvheim fi eld during the year was better than forecast at 12.4 Mboepd. The reservoir continues to outperform with the most recent infi ll well A5 as well as the Viper and Kobra wells, which came on stream in 2016, all continuing to produce ahead of expectations. Drilling of two infi ll wells on the Boa area of the fi eld were completed during the year with results in line with expectations and both wells started production in the fi rst quarter of 2018.
Net production from the Volund fi eld during the year was ahead of forecast at 3.9 Mboepd. Two new Volund infi ll wells were completed during the year and came on stream in the third quarter, with production from both wells exceeding expectations.
Net production from the Bøyla fi eld during the year was in line with forecast at 1.1 Mboepd.
Net production from the Brynhild fi eld during the year was lower than forecast at 1.2 Mboepd. The fi eld has been shut-in since July 2017 due to a fl ow restriction that developed in the pipeline between the Brynhild subsea wells and the Haewene Brim FPSO. The restriction was due to an oil-water emulsion that developed in the pipeline due to a failure of the subsea emulsion inhibitor chemical injection system. Operations to clear the restriction have been successfully completed and the plan is to re-start production from the fi eld during the second quarter 2018. The water injection system was re-instated in February 2017. Terms for a revised processing and operations service agreement were agreed with Shell, which reduces future operating costs for the fi eld.
In June 2017, Lundin Petroleum announced that it had entered into an agreement to divest a 39 percent working interest in the Brynhild fi eld to CapeOmega. Lundin Norway has retained operatorship of the Brynhild fi eld and following completion of the transaction at the end of November 2017 has a 51 percent working interest in the fi eld. The effective date of the transaction is 1 January 2017.
Despite no remaining reserves being attributed to the Gaupe fi eld, the fi eld is producing intermittently subject to favourable economic conditions and net production during the year was in line with forecast at 0.2 Mboepd.
Phase 1 of the Johan Sverdrup project is on schedule with close to 70 percent completed in February 2018. Construction on all elements of Phase 1 of the project is underway with over 50 million direct man-hours having been worked to date. With the good progress on the project Phase 1 costs continue to be reduced.
Construction of the steel jacket for the riser platform was completed at the Kværner Verdal yard in Norway and was installed offshore at the end of July 2017. This is the fi rst major offshore installation milestone and was achieved on schedule. The remaining three jackets and the four topsides are scheduled for installation in 2018 and 2019.
Construction of the remaining three steel jackets is underway at the Kværner Verdal yard in Norway and at the Dragados yard in Spain. Construction of the drilling platform and living quarters, through EPC contracts, is underway in Norway by Aibel and Kværner respectively and construction of the riser platform and processing platform is ongoing at Samsung Heavy Industries in Korea with Aker Solutions being contracted for the procurement and engineering of the riser platform and processing platform.
The three large modules making up the drilling platform topsides were assembled on a barge on schedule in September 2017 and are currently located in Haugesund in Norway for hook-up and fi nal completion. Installation of the four subsea water injection drilling templates and associated fl owlines has been completed. In addition, civil engineering works are underway on the onshore power system at Haugsneset and for the oil export pipeline landfall at Mongstad.
The pre-drilling of development wells commenced in March 2016 with eight production wells completed in 2016 with results in line with expectations. Three pilot wells have been drilled to assist with the placement of the development wells with results in line with or better than prognosis. In addition, the pre-drilling of nine water injection wells was completed in 2017 with results in line with expectations. Pre-drilling activities were completed signifi cantly ahead of schedule.
At the time of submitting the Phase 1 PDO in 2015, the capital expenditure for Phase 1 was estimated at gross NOK 123 billion (nominal). Due to improvements in project execution and delivery the latest cost estimate, as released by Statoil in February 2018, is NOK 88 billion (nominal). This represents a saving of almost 30 percent compared to the original estimate in the PDO, excluding additional foreign exchange rate savings in US dollar terms. The gross oil production capacity for Phase 1 of the project is estimated at 440 Mbopd and is scheduled to start production in late 2019.
| Licence | Field | WI | Operator | PDO Approval | Estimated gross reserves |
Production start achieved/expected |
Gross plateau production rate expected |
|---|---|---|---|---|---|---|---|
| Johan Sverdrup Unit |
Johan Sverdrup | 22.6% | Statoil | August 2015 | 2.1–3.1 billion boe | Late 2019 | 660 Mbopd |
The Johan Sverdrup partnership has decided on concept selection (DG2) for Phase 2 of the project, which will involve the installation of an additional processing platform bridge linked to the Phase 1 fi eld centre and additional subsea facilities to allow the tie-in of 28 additional wells to access the Avaldsnes, Kvitsøy and Geitungen satellite areas of the fi eld. These additional facilities will take the full fi eld gross plateau level to 660 Mbopd. Phase 2 costs are estimated at below NOK 45 billion (nominal) and represent approximately a 50 percent reduction compared to the estimate in the original PDO for Phase 1, which is due to a combination of market conditions and optimisation of the Phase 2 facilities concept. Front End Engineering Design (FEED) contracts in connection with Phase 2 of the project have been awarded to Aker Solutions for the processing platform, Kværner for the jacket and Siemens for the expansion of the power from shore facilities. Additionally, procurement activities are being progressed for long-lead equipment items for Phase 2. The PDO submission for Phase 2 is scheduled for the second half of 2018 and Phase 2 is scheduled to come onstream in 2022.
In February 2018, Statoil also provided an update on resources for the Johan Sverdrup fi eld with gross resources increasing to between 2.1 and 3.1 billion boe with 95 percent of the resources being oil.
Full fi eld breakeven oil price is estimated at below 20 USD per barrel.
In February 2017, the Tonjer well testing a possible northern extension of the Johan Sverdrup fi eld was announced to have encountered an oil column of 16 metres in Draupne reservoirs of lower quality compared to the main Johan Sverdrup reservoir. This result has no impact on the Johan Sverdrup development or the resources and the partnership will assess the results of the well as regards to possible future development.
In April 2017, Lundin Petroleum announced the completion of the Edvard Grieg Southwest appraisal well with results as reported in the Production section above.
In May 2017, Lundin Petroleum announced that the Gohta-3 appraisal well located in PL492 some 4 km north of the original discovery well encountered a 300 metres gross sequence of Permian age carbonates with poor reservoir quality. The resource estimate for the discovery has been reduced as a consequence of this well. Gohta is considered a possible joint development opportunity together with the larger adjacent Alta discovery.
In July 2017, Lundin Petroleum announced that the Alta-4 appraisal well located approximately 2 km south of the original Alta discovery well had encountered a gross hydrocarbon column of 48 metres, comprising 4 metres of gas and 44 metres of oil in a sequence of Permian-Triassic carbonate sediments of varying reservoir characteristics. Pressure data show the same fl uid contacts and gradients as observed in previous wells drilled on the Alta discovery, confi rming good communication across the large Alta structure. A production test was performed in the oil zone, producing at a stabilised rate of 6,050 bopd with low pressure drawdown and constrained by rig testing facilities. The production test confi rmed very good reservoir properties and good lateral continuity within the Permian-Triassic clastic reservoirs. In August 2017, a geological sidetrack was completed approximately 900 metres north of the Alta-4 well which confi rmed the reservoir sequence and fl uid contacts. An extended well test will be conducted at Alta in 2018 to reduce the uncertainty around the recovery mechanism in this complex reservoir and provide the basis for development studies.
Lundin Petroleum has a rig contract with Ocean Rig for the charter of the Leiv Eiriksson semi-submersible rig on a fl exible basis which has drilled all of the operated wells in the southern Barents Sea in 2017 and will be used to conduct the Alta extended well test in 2018.
Lundin Petroleum has a rig contract with COSL Offshore Management for the charter of the COSL Innovator semisubmersible rig for a fl exible term with multiple well option slots for a well programme in the Utsira High area in 2018. The rig will be utilised to drill appraisal wells at Luno II in PL359 and at Rolvsnes in PL338C. Both Luno II and Rolvsnes are possible subsea tie-back development opportunities to the Edvard Grieg facilities. Drilling operations at Luno II commenced in February 2018.
| Licence | Operator | WI | Well | Spud Date | Status |
|---|---|---|---|---|---|
| PL265 | Statoil | 22.6% | 16/2-22S (Johan Sverdrup – Tonjer) |
January 2017 | Completed February 2017 |
| PL338 | Lundin Norway | 65% | 16/1-27 (Edvard Grieg Southwest) |
March 2017 | Completed April 2017 |
| PL492 | Lundin Norway | 40% | 7120/1-5 (Gohta-3) | March 2017 | Completed May 2017 |
| PL609 | Lundin Norway | 40% | 7220/11-4 (Alta-4) | June 2017 | Completed July 2017 sidetrack completed August 2017 |
In February 2017, Lundin Petroleum announced a discovery on the Filicudi prospect in PL533 in the southern Barents Sea. The well, which was drilled approximately 40 km southwest of the Johan Castberg discovery in PL532, encountered a 129 metres hydrocarbon column, with 63 metres of oil and 66 metres of gas, in high quality Jurassic and Triassic sandstone reservoirs. A sidetrack well was drilled that also confi rmed the reservoir and hydrocarbon column. After full review of the well data the discovery is estimated to contain gross contingent resources of 23 MMboe with additional upside potential in the eastern area of the discovery that would require further appraisal drilling.
In June 2017, the Volund West prospect in PL150B in the North Sea, to the west of the Volund fi eld, was drilled and was dry. While the well encountered good reservoir sands there were poor hydrocarbon shows.
In August 2017, the Korpfjell prospect in PL859 in the southeastern Barents Sea was drilled and proved a small noncommercial gas discovery. The well encountered a gas column of 34 metres in sandstones with good reservoir quality in the shallow Jurassic age target with estimated gross resources of between 40 and 75 MMboe. Further drilling is planned in 2018 in PL859 to test the deeper prospectivity on the block.
In September 2017, the Børselv prospect in PL609 located on-trend north of the Alta and Neiden oil discoveries in the southern Barents Sea was drilled and was dry. The well encountered a 380 metres thick sequence of Permian-Carboniferous carbonates with medium to poor reservoir quality with oil shows, but the reservoir was water bearing.
In November 2017, the Hufsa prospect in PL533 in the southern Barents Sea on trend with the Filicudi oil discovery in the same block was drilled. The well encountered Jurassic and Triassic reservoir sands. A non-commercial gas discovery was made in the main well while the sidetrack was dry.
In January 2018, the Hurri prospect in PL533 in the southern Barents Sea on trend with the Filicudi oil discovery in the same block was drilled. The well encountered good quality Jurassic reservoir sands but was dry.
In February 2018, the Frosk prospect in PL340 in the North Sea, located northwest of the Bøyla fi eld, was drilled and proved an oil discovery. The discovery is estimated to contain gross resources of between 30 and 60 MMboe, which is signifi cantly more than the pre-drill estimates, and has a positive impact on the assessment of further exploration potential in the area.
Additionally, acquisition of a large high-specifi cation 3D seismic survey was completed in September 2017 over the Alta, Gohta and Filicudi discoveries and associated prospectivity. Processed seismic data from the survey will be available in 2018.
In January 2017, the Ministry of Petroleum and Energy announced the licence awards in the 2016 APA licensing round. Lundin Petroleum was awarded four licences, of which two as operator in PL902 (WI 50%) and PL886 (WI 40%) and two nonoperated in PL896 and PL869 (both with WI 20%).
In November 2017, Lundin Petroleum applied for licences in the 24th licensing round and awards are anticipated to be announced in mid-2018.
During the year, a licence exchange was completed with Engie to swap 10 percent of Lundin Petroleum's working interest in PL778 for Engie's 20 percent working interest in both PL715 and PL722. The acquisitions of Shell's 20 percent working interest in PL715 and North E&P's 40 percent working interest in PL805 were completed. In addition, Lundin Petroleum completed a farm-in with Fortis Petroleum for a 10 percent working interest each in PL539 and PL860 on the Mandal High in the Norwegian North Sea. Subsequent to which Lundin Petroleum agreed the acquisition of a package of licences from Fortis Petroleum including a further 10 percent interest in each of PL539 and PL860 and 30 percent working interests in each of PL820S and PL825. Lundin Petroleum has agreed a licence swap arrangement to acquire Statoil's 20 percent working interest in PL860 which is subject to government approval and upon
| Licence | Well | Spud Date | Target | WI | Operator | Result |
|---|---|---|---|---|---|---|
| Southern Barents Sea | ||||||
| PL533 | 7219/12-1 | November 2016 | Filicudi | 35% | Lundin Norway | Oil and gas discovery |
| PL859 | 7435/12-1 | August 2017 | Korpfjell | 15% | Statoil | Small non-commercial gas discovery |
| PL609 | 7220/6-3 | August 2017 | Børselv | 40% | Lundin Norway | Dry |
| PL533 | 7219/12-2 | October 2017 | Hufsa | 35% | Lundin Norway | Non-commcercial gas discovery |
| PL533 | 7219/12-3 | December 2017 | Hurri | 35% | Lundin Norway | Dry |
| Alvheim Area | ||||||
| PL150B | 24/9-11S | June 2017 | Volund West | 35% | Aker BP | Dry |
| PL340 | 24/9-12S | January 2018 | Frosk | 15% | Aker BP | Oil discovery |
completion will increase Lundin Petroleum's working interest in PL860 to 40 percent. Lundin Petroleum farmed out its 20 percent working interest in PL685 to Wellesley Petroleum and farmed out a 15 percent interest and transferred operatorship in each of PL758 and PL800 to Capricorn.
During the year, Lundin Petroleum relinquished PL410, PL579, PL625, PL653, PL674BS, PL678, PL694, PL734, PL736S, PL765, PL766, PL778 and PL789. Notices were also provided to relinquish PL700, PL700B, PL715 and PL805 which will become effective in 2018.
In January 2018, the Ministry of Petroleum and Energy announced the licence awards in the 2017 APA licensing round. Lundin Petroleum was awarded a total of 14 licences, of which six as operator in PL934 (WI 40%), PL886B (WI 40%), PL950 (WI 50%), PL952 (WI 60%), PL954 (WI 40%) and PL533B (WI 35%). Eight non-operated licences were awarded in PL904 (WI 20%), PL167C (20%), PL914S (WI 1.385%), PL916 (WI 20%), PL917 (WI 20%), PL919 (WI 15%), PL935 (WI 20%) and PL936 (WI 30%).
At year end 2016, Lundin Petroleum removed the contingent resources from its books associated with the Morskaya oil discovery and wrote down the entire book value of the asset. Management is reviewing options for the Morskaya asset. An appraisal plan has been agreed with the Russian licensing authority, Rosnedra, in order to maintain the licence in good standing while options for the asset are being reviewed. The appraisal plan requires no signifi cant activities for several years.
The discontinued operations are reported on and accounted for until 24 April 2017 when the spin-off to IPC was completed.
The non-Norwegian producing assets spun-off to IPC had 29.4 MMboe of proved plus probable reserves as at 31 December 2016 as certifi ed by an independent third party.
Production for the non-Norwegian producing assets spun-off to IPC amounted to 3.8 Mboepd and was comprised as follows:
| Production in Mboepd | 2017 | 2016 |
|---|---|---|
| Crude oil | ||
| France | 0.8 | 2.6 |
| Malaysia | 2.5 | 8.6 |
| Total crude oil production | 3.3 | 11.2 |
| Gas | ||
| Netherlands | 0.5 | 1.6 |
| Indonesia | – | 0.5 |
| Total gas production | 0.5 | 2.1 |
| Total production | 3.8 | 13.3 |
| Quantity in Mboe | 1,370.4 | 4,858.2 |
The Indonesian assets were sold to PT Medco Energi International TBK effective April 2016 and thus there was no production.
For continuing operations, six low potential medical treatment incidents and one low level lost time incident were reported for the year in Norway, resulting in a Lost Time Incident Rate (LTIR) of 0.47 per million hours worked and a Total Recordable Incident Rate (TRIR) of 3.30 per million hours worked.
There were no material environmental incidents.
The operating profi t from continuing operations for the fi nancial year ended 31 December 2017 amounted to MUSD 812.4 (MUSD -244.7). The operating profi t for the year was driven by the increased production and higher oil prices compared to last year. Last year was also negatively impacted by an impairment charge of MUSD 506.1 in respect of Russia.
The net result from continuing operations for the year amounted to MUSD 380.9 (MUSD -399.3). The net result from continuing operations in the year was mainly driven by the excellent production performance and a net foreign exchange gain as a result of the weakening US Dollar against the Norwegian Krone and the Euro, partly offset by expensed exploration costs and an impairment charge.
The net result from continuing operations attributable to shareholders of the Parent Company for the year amounted to MUSD 384.7 (MUSD -256.7) or MUSD 431.2 (MUSD -356.7) including discontinued operations representing earnings per share from continuing operations of USD 1.13 (USD -0.79) or USD 1.27 (USD -1.09) including discontinued operations.
Earnings before interest, tax, depletion and amortisation (EBITDA) from continuing operations for the year amounted to MUSD 1,501.5 (MUSD 752.5) representing EBITDA per share of USD 4.41 (USD 2.31). Operating cash fl ow from continuing operations for the year amounted to MUSD 1,530.0 (MUSD 857.9) representing operating cash fl ow per share of USD 4.50 (USD 2.63).
Revenue and other income for the year amounted to MUSD 1,997.0 (MUSD 950.0) 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 1,958.3 (MUSD 975.9). The average price achieved by Lundin Petroleum for a barrel of oil equivalent from own production amounted to USD 51.63 (USD 42.31) and is detailed in the following table. The average Dated Brent price for the year amounted to USD 54.25 (USD 43.73) per barrel.
Net sales of oil and gas from own production for the year are detailed in Note 3 and were comprised as follows:
| Sales from own production Average price per boe expressed in USD |
2017 | 2016 |
|---|---|---|
| Crude oil sales | ||
| Norway | ||
| – Quantity in Mboe | 28,106.9 | 20,654.5 |
| – Average price per boe | 53.37 | 43.60 |
| Gas and NGL sales | ||
| Norway | ||
| – Quantity in Mboe | 3,943.1 | 2,352.1 |
| – Average price per boe | 39.23 | 30.94 |
| Total sales from continuing operations | ||
| – Quantity in Mboe | 32,050.0 | 23,006.6 |
| – Average price per boe | 51.63 | 42.31 |
The table above excludes crude oil revenue from third party activities.
Net sales of crude oil from third party activities for the year amounted to MUSD 303.5 (MUSD 2.1) and consisted of crude oil purchased from outside the Group by Lundin Petroleum Marketing SA and sold to the market.
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. 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 an income of MUSD 13.8 (cost of MUSD 29.1) in the year due to the timing of the cargo liftings compared to production.
Other revenue amounted to MUSD 24.9 (MUSD 3.2) for the year and included a quality differential compensation on Alvheim blended crude and tariff income of MUSD 21.7 (MUSD 0.3) which is due to net income from Ivar Aasen tariffs paid to Edvard Grieg.
Production costs including inventory movements for the year amounted to MUSD 164.2 (MUSD 168.4) and are detailed in Note 2. The total production cost per barrel of oil equivalent produced is detailed in the table below:
| continuing operations | 2017 | 2016 |
|---|---|---|
| Cost of operations | ||
| – In MUSD | 117.3 | 113.1 |
| – In USD per boe | 3.73 | 5.21 |
| Tariff and transportation expenses | ||
| – In MUSD | 37.9 | 33.9 |
| – In USD per boe | 1.21 | 1.56 |
| Cash operating costs | ||
| – In MUSD | 155.2 | 147.0 |
| – In USD per boe 1 | 4.94 | 6.77 |
| Change in inventory position | ||
| – In MUSD | -0.4 | -0.7 |
| – In USD per boe | -0.02 | -0.04 |
| Other | ||
| – In MUSD | 9.4 | 22.1 |
| – In USD per boe | 0.30 | 1.02 |
| Production costs from | ||
| continuing operations | ||
| – In MUSD | 164.2 | 168.4 |
| – In USD per boe | 5.22 | 7.75 |
Note: USD per boe is calculated by dividing the cost by total production volume for the year.
1 The numbers in this table are excluding tariff income netting. Lundin Petroleum's cash operating cost for the reporting period of USD 4.94 is reduced to USD 4.25 when tariff income is netted off.
The total cost of operations for the year amounted to MUSD 117.3 (MUSD 113.1). The total cost of operations excluding operational projects amounted to MUSD 105.9 (MUSD 103.8).
The cost of operations per barrel amounted to USD 3.73 (USD 5.21) including operational projects and USD 3.37 (USD 4.78) excluding operational projects.
Tariff and transportation expenses for the year amounted to MUSD 37.9 (MUSD 33.9) or USD 1.21 (1.56) per barrel. The main reason for the reduction per barrel is due to the increased volumes in the Oseberg transportation system that the Edvard Grieg pipeline is part of.
Other costs amounted to MUSD 9.4 (MUSD 22.1) and related to the business interruption insurance and the operating cost share arrangement on the Brynhild fi eld whereby the amount of operating cost varies with the oil price until the end of May 2017. This arrangement was being marked-to-market against the oil price curve.
Depletion and decommissioning costs amounted to MUSD 567.3 (MUSD 386.2) at an average rate of USD 18.05 (USD 17.80) per barrel and are detailed in Note 10. The higher depletion costs for the year compared to last year is due to the depletion charge associated with the Edvard Grieg fi eld as a result of the higher production levels achieved.
Exploration costs expensed in the income statement for the year amounted to MUSD 73.1 (MUSD 101.9) and are detailed in Note 10. Exploration and appraisal costs are capitalised as they are incurred. When exploration drilling is unsuccessful, the capitalised costs are expensed. All capitalised exploration costs are reviewed on a regular basis and are expensed where their recoverability is considered highly uncertain.
During the year, exploration costs relating to Norway of MUSD 72.0 were expensed and mainly related to the unsuccessful Gohta appraisal well in PL492, the non-commercial gas discovery on the Korpfjell prospect in PL859, and the dry wells on the Hufsa prospect in PL533, the Volund West prospect in PL150B, the Børselv prospect in PL609 and the Hurri prospect in PL533 as well as a number of Norwegian exploration licences in the process of relinquishment.
Impairment costs amounted to MUSD 30.6 (MUSD 506.1) and are detailed in Note 10. The impairment costs related to the Brynhild fi eld in PL148. The impairment costs in the comparative period related to Russia.
Loss from sale of assets for the year amounted to MUSD 14.4 (MUSD –) and related to the after tax result on the divestment of a 39 percent working interest in the Brynhild fi eld and are detailed in Note 8.
Other costs of sales for the year amounted to MUSD 303.3 (MUSD 2.1) and related to oil purchased from outside the Group by Lundin Petroleum Marketing SA.
The general administrative and depreciation expenses for the year amounted to MUSD 31.7 (MUSD 30.0) which included a charge of MUSD 4.3 (MUSD 4.6) in relation to the Group's longterm incentive plans (LTIP), see Note 29. Fixed asset depreciation expenses for the year amounted to MUSD 2.5 (MUSD 3.1).
Finance income for the year amounted to MUSD 256.7 (MUSD 2.7) and is detailed in Note 4.
The net foreign currency exchange gain for the year amounted to MUSD 255.3 (MUSD –). 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. Lundin Petroleum has hedged certain foreign currency operational expenditure amounts against the US Dollar and for the year, the net realised exchange loss on settled foreign exchange hedges amounted to MUSD 1.8 (MUSD 29.1).
The US Dollar weakened against the Euro during the year resulting in a net foreign currency exchange gain on the US Dollar denominated external loan which is borrowed by a subsidiary using Euro as functional currency. In addition, the Norwegian Krone weakened against the Euro in the year, generating a net foreign currency exchange loss on an intercompany loan balance denominated in Norwegian Krone.
Finance costs for the year amounted to MUSD 186.6 (MUSD 221.5) and are detailed in Note 5.
Interest expenses for the year amounted to MUSD 115.0 (MUSD 137.3) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 63.5 (MUSD 23.4) associated with the funding of the Norwegian development projects was capitalised in the year. The total interest expense has increased compared to last year mainly due to higher interest rates. The result on interest rate hedge settlements amounted to a loss of MUSD 17.4 (MUSD 19.5).
The amortisation of the deferred fi nancing fees amounted to MUSD 17.5 (MUSD 38.9) for the year and related to the expensing of the fees incurred in establishing the fi nancing facilities over the period of usage of the facilities. The decrease compared to last year is related to the fact that the current fi nancing facilities were entered into during the second quarter of 2016 following which the unamortised portion of the capitalised fi nancing fees incurred in establishing the previous fi nancing facilities and the short term revolving credit facility were expensed amounting to MUSD 22.3.
Loan facility commitment fees for the year amounted to MUSD 11.1 (MUSD 9.3) with the increase compared to the same period last year being due to the increased available borrowing amounts under the Group's reserve-based lending facility.
Lundin Petroleum owns 121.5 million shares in ShaMaran Petroleum Corp. (ShaMaran) and this investment was booked at the fair value of the shares at the date of acquisition and under accounting rules, subsequent movements in the fair value of the shares were being recognised in the consolidated statement of comprehensive income. During the year, ShaMaran announced that it had achieved fi rst oil from the Atrush fi eld. As the share price of ShaMaran did not recover in the period since fi rst oil, an impairment charge was recorded representing the cumulative loss recorded in other comprehensive income equal to MUSD 11.2 that was recycled to the income statement.
Share in result of associated company amounted to MUSD 0.4 (MUSD –) and related to the share in the result of the investment in Mintley Caspian Ltd. following the deconsolidation of this investment at the end of the third quarter 2017 and are detailed in Note 6.
The overall tax charge for the year amounted to MUSD 501.2 (credit of MUSD 64.2) and is detailed in Note 7.
The current tax charge for the year amounted to a credit of MUSD 0.5 (credit MUSD 78.4) which included a tax credit of MUSD 1.5 (credit MUSD 78.9) relating to the tax refund on Norwegian exploration and appraisal expenditure.
The deferred tax charge for the year amounted to MUSD 501.7 (MUSD 14.2) which predominantly related to Norway. The deferred tax amount arises primarily where there is a difference in depletion for tax and accounting purposes.
The Group operates in various countries and fi scal regimes where corporate income tax rates are different from the regulations in Sweden. Corporate income tax rates for the Group vary between 12.5 and 78 percent. The effective tax rate for the year is affected by items which do not receive a full tax credit such as the reported net foreign currency exchange gain, Norwegian fi nancial items and by the uplift allowance applicable in Norway for development expenditures against the offshore tax regime.
The net result attributable to non-controlling interest for the year amounted to MUSD -3.8 (MUSD -142.6) and related to the non-controlling interest's share in Mintley Caspian Ltd., which is the holding company of Lundin Petroleum´s investment in Russia, which was fully consolidated up to the end of the third quarter 2017. Lundin Petroleum has updated the accounting judgement of the consolidation of this investment and concluded that this investment should be reclassifi ed to a joint venture. The investment was therefore deconsolidated at the end of the third quarter 2017.
The net result from discontinued operations amounted to MUSD 46.5 (MUSD -100.0) and is detailed in Note 9.
Oil and gas properties amounted to MUSD 4,937.1 (MUSD 4,376.4) and are detailed in Note 10.
Development and exploration and appraisal expenditure incurred for the year was as follows:
| Development expenditure in MUSD |
2017 | 2016 |
|---|---|---|
| Norway | 950.0 | 877.1 |
| Development expenditures from continuing operations |
950.0 | 877.1 |
An amount of MUSD 950.0 (MUSD 877.1) of development expenditure was incurred in Norway during the year, primarily on the Johan Sverdrup, Edvard Grieg and Alvheim area. In addition an amount of MUSD 63.5 of interest was capitalised.
| Exploration and appraisal expenditure in MUSD |
2017 | 2016 |
|---|---|---|
| Norway | 227.1 | 142.1 |
| Russia | 1.1 | 1.4 |
| Exploration and appraisal expenditure | ||
| from continuing operations | 228.2 | 143.5 |
Exploration and appraisal expenditure of MUSD 227.1 (MUSD 142.1) was incurred in Norway during the year, primarily on the Filicudi, Hufsa and Hurri exploration wells in PL533, the Korpfjell exploration well in PL859, the Børselv exploration well in PL609 and the appraisal wells Edvard Grieg Southwest in PL338, Gotha-3 in PL492 and Alta-4 in PL609.
Other tangible fi xed assets amounted to MUSD 13.2 (MUSD 166.1) and the decrease compared to the last year is related to the spin-off of the IPC business and are detailed in Note 11.
Goodwill associated with the accounting for the Edvard Grieg transaction during 2016 amounted to MUSD 128.1 (MUSD 128.1) and is detailed in Note 12.
Financial assets amounted to MUSD 6.7 (MUSD 9.4) and are detailed in Note 13. Other shares and participations amounted to MUSD 6.3 (MUSD 8.9) and related to the shares held in ShaMaran which are reported at market value.
Derivative instruments amounted to MUSD 26.5 (MUSD 17.0) and related to the marked-to-market gain on the outstanding interest rate and currency hedge contracts due to be settled after twelve months and are detailed in Note 21.
Inventories amounted to MUSD 33.7 (MUSD 54.9) and are detailed in Note 14. The decrease compared to last year is related to the spin-off of the IPC business.
Trade and other receivables amounted to MUSD 304.4 (MUSD 288.9) and are detailed in Note 15. Trade receivables, which are all current, amounted to MUSD 202.7 (MUSD 193.4) and included invoiced cargoes. Underlift amounted to MUSD 29.4 (MUSD 28.9) and was attributable to an underlift position on the producing fi elds, mainly from the Alvheim area. Joint operations debtors relating to various joint venture receivables amounted to MUSD 15.6 (MUSD 31.2). Prepaid expenses and accrued income amounted to MUSD 29.3 (MUSD 29.4) and represented mainly prepaid operational and insurance expenditure. Brynhild operating cost share amounted to MUSD – (MUSD 3.0) and related to the marked-to-market valuation of the arrangement where the share of the operating cost varies with the oil price. This arrangement ended during the year. IPC working capital receivable amounted to MUSD 23.5 (MUSD –) and related to a residual receivable from IPC for working capital balances following the IPC spin-off which is due in 2018. Other current assets amounted to MUSD 3.9 (MUSD 3.0) and included VAT receivables and other miscellaneous receivable balances.
Derivative instruments amounted to MUSD 7.7 (MUSD 0.8) and related to the marked-to-market gain on the outstanding interest rate and currency hedge contracts due to be settled within twelve months and are detailed in Note 21.
Current tax assets amounted to MUSD – (MUSD 77.5) and related to the Norwegian corporate tax refund in respect of 2016 which was received in the fourth quarter of 2017.
Cash and cash equivalents amounted to MUSD 71.4 (MUSD 69.5). Cash balances are held to meet ongoing operational funding requirements.
Financial liabilities amounted to MUSD 3,880.0 (MUSD 4,048.3) and are detailed in Note 18. Bank loans amounted to MUSD 3,955.0 (MUSD 4,145.0) and related to the outstanding loan under the Group's reserve-based lending facility. Capitalised fi nancing fees relating to the establishment costs of the Group's fi nancing facility amounted to MUSD 75.0 (MUSD 96.7) and are being amortised over the expected life of the facility.
Provisions amounted to MUSD 420.6 (MUSD 420.0) and are detailed in Note 19. The provision for site restoration amounted to MUSD 414.6 (MUSD 407.1) and related to future decommissioning obligations. The site restoration provision related to Norway amounted to MUSD 414.6 (MUSD 316.1). The increase in Norway mainly refl ects the additional liability for Edvard Grieg, the Alvheim area and for the Johan Sverdrup development project partly offset by the 39 percent divestment in Brynhild. The buyers decommissioning costs are limited at MNOK 305 for the 39 percent share in Brynhild.
Deferred tax liabilities amounted to MUSD 1,302.2 (MUSD 669.3) and are detailed in Note 7. 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 3.1 (MUSD 29.8) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts due to be settled after twelve months and are detailed in Note 21.
Other non-current liabilities amounted to MUSD – (MUSD 33.8) and related to the full consolidation of Mintley Caspian Ltd. in which the non-controlling interest entity has made funding advances. The subsidiary was deconsolidated at the end of the third quarter, see section Changes in the Group on page 48.
Trade and other payables amounted to MUSD 259.0 (MUSD 308.4) and are detailed in Note 20. Overlift amounted to MUSD 12.8 (MUSD 29.9) and was attributable to an overlift position on the producing fi elds, mainly from Brynhild and NGL from Edvard Grieg. Joint operations creditors and accrued expenses amounted to MUSD 188.9 (MUSD 238.8) and related to activity in Norway. Other accrued expenses amounted to MUSD 19.5 (MUSD 16.9) and other current liabilities amounted to MUSD 7.7 (MUSD 9.5).
Derivative instruments amounted to MUSD 6.4 (MUSD 37.6) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts due to be settled within twelve months and are detailed in Note 21.
Current provisions amounted to MUSD 7.7 (MUSD 6.9) and related to the current portion of the provision for Lundin Petroleum's Unit Bonus Plan.
The Annual General Meeting will be held in Stockholm on 3 May 2018.
The intention of the Board of Directors is to propose to the 2018 AGM the adoption of a Policy on Remuneration for 2018 that follows in essence the same principles as applied in 2017 and that contains similar elements of remuneration for Group management as the 2017 Policy on Remuneration being base salary, yearly variable salary, Long-term Incentive Plan (LTIP) and other benefi ts.
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, LTIP 2015, LTIP 2016 and LTIP 2017 approved by the 2014 AGM, the 2015 AGM, the 2016 AGM and the 2017 AGM respectively. LTIP 2018 gives the participants the possibility to receive shares in Lundin Petroleum subject to the fulfi lment of a performance condition under a three year performance period commencing on 1 July 2018 and expiring on 1 July 2021. 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 2018. The total number of performance shares that may be allotted under LTIP 2018 is 460,000, corresponding to approximately 0.1 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 refl ected in the outcome of the performance condition, for example, in light of operating cash fl ow, 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 2018, or perform any shareholders' rights regarding the LTIP awards during the performance period. The LTIP awards entitle participants to acquire already existing shares. The
Board of Directors will consider means to secure the Company's expected fi nancial exposure related to LTIP 2018. 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.
Remuneration as per prevailing market conditions may further be paid to members of the Board of Directors for work performed outside the directorship.
In addition, as in previous years, the Board of Directors will further seek authorisation to deviate from the Policy on Remuneration in case of special circumstances in a specifi c case.
For a detailed description of the Policy on Remuneration applied in 2017, see the Corporate Governance report on pages 42–43. The remuneration to Board and Group management is detailed in Notes 28 and 29.
For the number of shares outstanding and the repurchases of own shares, see page 30, Corporate Governance Report.
For the AGM resolution on the authorisation to issue new shares, see page 32, Corporate Governance Report.
The Board of Directors proposes to the AGM 2018 that an inaugural cash dividend distribution for the year 2017 of SEK 4.00 per share be made for payment after the 2018 AGM. This represents an amount equal to approximately MSEK 1,354.1, or approximately MUSD 165, based on the current number of shares, excluding own shares held by the Company.
For details of the dividend policy, see page 10, Share and Shareholders.
The Annual General Meeting 2018 has an unrestricted equity at its disposal of MSEK 54,071.8, including the net result for the year of MSEK 46,648.6.
The Board of Directors propose that the Annual General Meeting dispose of the unrestricted equity as follows:
| Dividend payable at SEK 4.00 per share 1 | 1,354.1 |
|---|---|
| Brought forward | 52,717.7 |
| Unrestricted equity | 54,071.8 |
1 Dividend is based on the number of shares outstanding at the record date and the total dividend amount may change by the record date depending on repurchases of own shares.
Based on a comprehensive review of the fi nancial position of the Company and the Group as a whole, as well as the proposed authorisation to repurchase shares, the Board of Directors is of the opinion that the proposed dividend is justifi able in view of the requirements that the nature and scope of, and risks involved in the Company's operations, place on the size of the Company's and Group's equity, as well as their consolidation needs, liquidity and position in other respects. The Board of Directors considered that there is negative equity at Group level, however such equity is based on historical accounting determinations of book value, depreciations and foreign exchange results, and does not take into account the fair market value of the assets held by the Group. The Board of Directors' full statement in accordance with Chapter 18, Section 4 of the Swedish Companies Act is available on www.lundin-petroleum.com.
At the 2018 AGM, all the current members of the Board of Directors will be proposed for re-election by the Nomination Committee. In addition, the Nomination Committee proposes that the size of the Board of Directors be increased to nine members and that Torstein Sanness, the former Managing Director of Lundin Norway AS, will be elected as a new member of the Board of Directors.
The result of the Group's operations and fi nancial position at the end of the fi nancial year are shown in the following income statement, statement of comprehensive income, balance sheet, statement of cash fl ow, statement of changes in equity and related notes, which are presented in US Dollars.
The Parent Company's income statement, balance sheet, statement of cash fl ow, statement of changes in equity and related notes presented in Swedish Krona can be found on pages 94–99.
Subsequent events are detailed in Note 31.
For a detailed description of risk management, see the Strategic report on pages 24–27.
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 28–44.
Lundin Petroleum has issued a Sustainability Report which is separate from the Financial Statements. The Sustainability Report is available on www.lundin-petroleum.com.
Lundin Petroleum has issued a Report on Payments to Government, which is separate from the Financial Statements. The Report on Payments to Government is available on www.lundin-petroleum.com.
for the Financial Year Ended 31 December
| Expressed in MUSD | Note | 2017 | 2016 |
|---|---|---|---|
| Revenue and other income | 1 | 1,997.0 | 950.0 |
| Cost of sales | |||
| Production costs | 2 | -164.2 | -168.4 |
| Depletion and decommissioning costs | 10 | -567.3 | -386.2 |
| Exploration costs | 10 | -73.1 | -101.9 |
| Impairment costs of oil and gas properties | 10 | -30.6 | -506.1 |
| Loss from sale of assets | 8 | -14.4 | – |
| Other cost of sales | 3 | -303.3 | -2.1 |
| Gross profi t/loss | 844.1 | -214.7 | |
| General, administration and depreciation expenses | -31.7 | -30.0 | |
| Operating profi t/loss | 812.4 | -244.7 | |
| Net fi nancial items | |||
| Finance income | 4 | 256.7 | 2.7 |
| Finance costs | 5 | -186.6 | -221.5 |
| 70.1 | -218.8 | ||
| Share in result of associated company | 6 | -0.4 | – |
| Profi t/loss before tax | 882.1 | -463.5 | |
| Income tax | 7 | -501.2 | 64.2 |
| Net result from continuing operations | 380.9 | -399.3 | |
| Discontinued operations | |||
| Net result – IPC | 9 | 46.5 | -100.0 |
| Net result | 427.4 | -499.3 | |
| Attributable to: | |||
| Shareholders of the Parent Company | 431.2 | -356.7 | |
| Non-controlling interest | -3.8 | -142.6 | |
| 427.4 | -499.3 | ||
| Earnings per share – USD1 | 17.3 | ||
| From continuing operations | 1.13 | -0.79 | |
| From discontinued operations | 0.14 | -0.30 | |
| Earnings per share – fully diluted – USD1 | 17.3 | ||
| From continuing operations | 1.13 | -0.79 | |
| From discontinued operations | 0.14 | -0.30 |
1 Based on net result attributable to shareholders of the Parent Company.
for the Financial Year Ended 31 December
| Expressed in MUSD | 2017 | 2016 |
|---|---|---|
| Net result | 427.4 | -499.3 |
| Items that may be subsequently reclassifi ed to profi t or loss: | ||
| Exchange differences foreign operations | -96.2 | 13.8 |
| Cash fl ow hedges | 76.4 | 64.3 |
| Available-for-sale fi nancial assets | 4.9 | 5.3 |
| Other comprehensive income | -14.9 | 83.4 |
| Total comprehensive income | 412.5 | -415.9 |
| Attributable to: | ||
| Shareholders of the Parent Company | 416.3 | -278.2 |
| Non-controlling interest | -3.8 | -137.7 |
| 412.5 | -415.9 |
for the Financial Year Ended 31 December
| Expressed in MUSD | Note | 2017 | 2016 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 10 | 4,937.1 | 4,376.4 |
| Other tangible fi xed assets | 11 | 13.2 | 166.1 |
| Goodwill | 12 | 128.1 | 128.1 |
| Financial assets | 13 | 6.7 | 9.4 |
| Deferred tax assets | 7 | – | 13.5 |
| Derivative instruments | 21 | 26.5 | 17.0 |
| Total non-current assets | 5,111.6 | 4,710.5 | |
| Current assets | |||
| Inventories | 14 | 33.7 | 54.9 |
| Trade and other receivables | 15 | 304.4 | 288.9 |
| Derivative instruments | 21 | 7.7 | 0.8 |
| Current tax assets | 7 | – | 77.5 |
| Cash and cash equivalents | 16 | 71.4 | 69.5 |
| Total current assets | 417.2 | 491.6 | |
| TOTAL ASSETS | 5,528.8 | 5,202.1 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Share capital | 17.1 | 0.5 | 0.5 |
| Additional paid in capital | 17.1 | 527.9 | 979.1 |
| Other reserves | 17.2 | -445.7 | -430.8 |
| Retained earnings | -864.7 | -430.7 | |
| Net result | 431.2 | -356.7 | |
| Shareholders' equity | -350.8 | -238.6 | |
| Non-controlling interest | – | -113.6 | |
| Total equity | -350.8 | -352.2 | |
| Liabilities | |||
| Non-current liabilities | |||
| Financial liabilities | 18 | 3,880.0 | 4,048.3 |
| Provisions | 19 | 420.6 | 420.0 |
| Deferred tax liabilities | 7 | 1,302.2 | 669.3 |
| Derivative instruments | 21 | 3.1 | 29.8 |
| Other non-current liabilities | – | 33.8 | |
| Total non-current liabilities | 5,605.9 | 5,201.2 | |
| Current liabilities | |||
| Trade and other payables | 20 | 259.0 | 308.4 |
| Derivative instruments | 21 | 6.4 | 37.6 |
| Current tax liabilities | 7 | 0.6 | 0.2 |
| Provisions | 19 | 7.7 | 6.9 |
| Total current liabilities | 273.7 | 353.1 | |
| Total liabilities | 5,879.6 | 5,554.3 | |
| TOTAL EQUITY AND LIABILITIES | 5,528.8 | 5,202.1 | |
for the Financial Year Ended 31 December
| Expressed in MUSD | Note | 2017 | 2016 |
|---|---|---|---|
| Cash fl ows from operating activities | |||
| Net result | 380.9 | -399.3 | |
| Adjustments for: | |||
| Exploration costs | 73.1 | 101.9 | |
| Depletion, depreciation and amortisation | 570.9 | 391.7 | |
| Impairment of oil and gas properties | 30.6 | 506.1 | |
| Current tax | -0.5 | -78.4 | |
| Deferred tax | 501.7 | 14.2 | |
| Impairment of other shares | 11.2 | – | |
| Long-term incentive plans | 12.7 | 15.6 | |
| Foreign currency exchange gain/loss | -258.0 | -24.9 | |
| Interest expense | 115.0 | 137.3 | |
| Capitalised fi nancing fees | 17.5 | 38.9 | |
| Other | 26.4 | 12.6 | |
| Interest received | 1.0 | 2.3 | |
| Interest paid | -177.3 | -153.7 | |
| Income taxes paid/received | 82.2 | 273.5 | |
| Changes in working capital: | |||
| Changes in inventories | -3.8 | -15.3 | |
| Changes in underlift position | -2.0 | -2.1 | |
| Changes in receivables | 126.9 | 163.0 | |
| Changes in overlift position | -17.1 | 29.9 | |
| Changes in liabilities | -192.1 | -344.6 | |
| Total cash fl ows from operating activities | 1,299.3 | 668.7 | |
| Cash fl ows from investing activities | |||
| Investment in oil and gas properties | -1,178.2 | -1,020.6 | |
| Investment in other fi xed assets | -1.6 | -1.1 | |
| Investment in other shares and participations1 | -1.3 | 25.8 | |
| Decommissioning costs paid | -0.4 | -1.0 | |
| Disposal of fi xed assets2 | 93.7 | – | |
| Other | -7.8 | – | |
| Total cash fl ows from investing activities | -1,095.6 | -996.9 | |
| Cash fl ows from fi nancing activities | |||
| Changes in long-term liabilities | 22 | -188.7 | 288.7 |
| Financing fees paid | – | -104.0 | |
| Cash funded from/to discontinued operations | 31.7 | 92.5 | |
| Purchase of own shares | -28.0 | – | |
| Issuance of shares/Sale of treasury shares3 | – | 64.1 | |
| Total cash fl ows from fi nancing activities | -185.0 | 341.3 | |
| Changes in cash and cash equivalents | 18.7 | 13.1 | |
| Cash and cash equivalents at the beginning of the year | 56.1 | 42.4 | |
| Currency exchange difference in cash and cash equivalents | -3.2 | 0.6 | |
| Cash and cash equivalents of deconsolidated operations | -0.2 | – | |
| Cash and cash equivalents of discontinued operations | – | 13.4 | |
| Cash and cash equivalents at the end of the year | 71.4 | 69.5 |
1 Comparative amount of MUSD 25.8 relates to cash received on closing of the Edvard Grieg transaction with Statoil ASA.
Cash received on the divestment of a 39 percent working interest in the Brynhild fi eld on closing including settlement of net working capital.
Cash received on the additional sale of newly issued and treasury shares to Statoil ASA.
The effects of currency exchange differences due to the translation of foreign group companies have been excluded as these effects do not affect the cash fl ow. 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 | |||||||
|---|---|---|---|---|---|---|---|
| Expressed in MUSD | Share capital1 |
Additional paid-in capital |
Other reserves2 |
Retained earnings |
Total | Non controlling interest |
Total equity |
| Balance at 1 January 2016 | 0.5 | 445.0 | -509.3 | -434.4 | -498.2 | 24.1 | -474.1 |
| Comprehensive income | |||||||
| Net result | – | – | – | -356.7 | -356.7 | -142.6 | -499.3 |
| Currency translation difference | – | – | 8.9 | – | 8.9 | 4.9 | 13.8 |
| Cash fl ow hedges | – | – | 64.3 | – | 64.3 | – | 64.3 |
| Available-for-sale fi nancial assets | – | – | 5.3 | – | 5.3 | – | 5.3 |
| Total comprehensive income | – | – | 78.5 | -356.7 | -278.2 | -137.7 | -415.9 |
| Transactions with owners | |||||||
| Share issuance | 0.0 | 534.1 | – | – | 534.1 | – | 534.1 |
| Value of employee services | – | – | – | 3.7 | 3.7 | – | 3.7 |
| Total transactions with owners | 0.0 | 534.1 | – | 3.7 | 537.8 | – | 537.8 |
| Balance at 31 December 2016 | 0.5 | 979.1 | -430.8 | -787.4 | -238.6 | -113.6 | -352.2 |
| Comprehensive income | |||||||
| Net result | – | – | – | 431.2 | 431.2 | -3.8 | 427.4 |
| Currency translation difference | – | – | -96.2 | – | -96.2 | – | -96.2 |
| Cash fl ow hedges | – | – | 76.4 | – | 76.4 | – | 76.4 |
| Available-for-sale fi nancial assets | – | – | 4.9 | – | 4.9 | – | 4.9 |
| Total comprehensive income | – | – | -14.9 | 431.2 | 416.3 | -3.8 | 412.5 |
| Transactions with owners | |||||||
| Change in consolidation | – | – | – | -82.0 | -82.0 | 117.1 | 35.1 |
| Distributions | – | -410.0 | – | – | -410.0 | – | -410.0 |
| Purchase of own shares | – | -28.0 | – | – | -28.0 | – | -28.0 |
| Spin off IPC | – | – | – | – | – | 0.3 | 0.3 |
| Share based payments | – | -13.2 | – | – | -13.2 | – | -13.2 |
| Value of employee services | – | – | – | 4.7 | 4.7 | – | 4.7 |
| Total transactions with owners | – | -451.2 | – | -77.3 | -528.5 | 117.4 | -411.1 |
| Balance at 31 December 2017 | 0.5 | 527.9 | -445.7 | -433.5 | -350.8 | – | -350.8 |
1 Lundin Petroleum AB's issued share capital described in detail in Note 17.1.
2 Other reserves are described in detail in Note 17.2.
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 specifi ed in the Parent Company accounting policies on page 94.
The preparation of fi nancial statements in conformity with IFRS requires the use of certain critical accounting estimates and also requires management to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are signifi cant to the consolidated fi nancial statements are disclosed under the headline "Critical accounting estimates and judgements". The consolidated fi nancial statements have been prepared under the historical cost convention, as modifi ed by the revaluation of available for sale fi nancial assets and fi nancial assets and liabilities (including derivative instruments) at fair value through other comprehensive income.
As from 1 January 2016, Lundin Petroleum has applied the following new accounting standards: Annual Improvements to IFRSs - 2012-2014 Improvements Cycle.
The adoption of these amendments did not have any impact on the consolidated fi nancial statements of the Group.
The Group has not adopted the following standards and interpretations that are not mandatory for the fi nancial year 2017. The Group has assessed the impact on the Group's consolidated fi nancial statements for the standards with an effective date of 1 January 2018.
IFRS 9 Financial instruments, the standard addresses the classifi cation, measurement and recognition of fi nancial assets and fi nancial liabilities, introduces new rules for hedge accounting and a new impairment model for fi nancial assets. Effective from 1 January 2018, the new impairment model under this standard requires the recognition of impairment provisions based on expected credit losses rather than only incurred credit losses as is the case under IAS 39. The Group has concluded that this standard has no signifi cant impact on the fi nancial statements. The Group will apply the new rules retrospectively from 1 January 2018 which means that the comparatives will not be restated.
IFRS 15 Revenue from contract with customers, the standard addresses revenue recognition and establishes principles for reporting useful information to users of fi nancial statements. Effective from 1 January 2018, the standard permits either a full retrospective or a modifi ed retrospective approach for the adoption. The Group has concluded that this standard will have no impact on the timing when revenue is recognised in the Group, but will have an impact on the consolidated income statement as certain transactions will no longer be reported as revenue but as
other revenue instead. This change primarily relates to reporting of change in under- and overlift which is detailed in Note 1. The Group intends to adopt the standard using the full retrospective approach which means that the comparatives will be restated.
IFRS 16 Leases, this standard will replace IAS 17 "Leases" and requires assets and liabilities arising from all leases, with some exceptions, to be recognised on the balance sheet. Effective from 1 January 2019. The Group is yet to assess the full impact of this standard.
Subsidiaries are all 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. Identifi able assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.
The non-controlling interest in a subsidiary represents the portion of the subsidiary not owned by the Group. The equity of the subsidiary relating to the non-controlling shareholders is shown as a separate item within equity for the Group. The Group recognises any non-controlling interest on an acquisitionby-acquisition basis, either at fair value or at the non-controlling interest's proportionate share of the recognised amounts of the acquiree's identifi able net assets.
Inter-company transactions, balances, income and expenses on transactions between group companies are eliminated. Profi ts and losses resulting from intercompany transactions 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 co-licences 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 fi nancial statements account for the production, capital costs, operating costs and current assets and liabilities relating to its working interests in joint arrangements.
Information about incorporated joint arrangements is available on www.lundin-petroleum.com.
An investment in an associated company is an investment in an undertaking where the Group exercises signifi cant infl uence but not control, generally accompanying a shareholding of at least 20 percent but not more than 50 percent of the voting rights. Such investments are accounted for in the consolidated fi nancial statements in accordance with the equity method and are initially recognised at cost. The difference between the acquisition cost of shares in an associated company and the net fair value of the assets, liabilities and contingent liabilities of the associated company recognised at the date of acquisition is recognised as goodwill. The goodwill is included within the carrying amount of the investment and is assessed for impairment as part of the investment. The Group's share in the post-acquisition results of the associated company is recognised in the income statement and the Group's share in post-acquisition movements in other comprehensive income of the associated company are recognised directly in other comprehensive income of the Group. When the Group's accumulated share of losses in an associated company equals or exceeds its interest in the associated company, the Group does not recognise further losses, unless it has incurred obligations or made payments on behalf of the associate.
Unrealised gains on transactions between the Group and its associates are eliminated to the extent of the Group's percentage in the associates. Unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Accounting policies of associates have been changed where necessary to ensure consistency with the policies adopted by the Group.
Investments where the shareholding is less than 20 percent of the voting rights are treated as available for sale fi nancial assets. If the value of these assets has declined signifi cantly or has lasted for a longer period, the cumulative loss is removed from equity and an impairment charge is recognised in the income statement. Dividends received attributable to these assets are recognised in the income statement as part of net fi nancial items.
Items included in the fi nancial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates (functional currency). The consolidated fi nancial statements are presented in US Dollars, which is the currency the Group has elected to use as the presentation currency.
Monetary assets and liabilities denominated in foreign currencies are translated at the rates of exchange prevailing at the balance sheet date and foreign exchange currency 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 fi nance income/costs in the income statement except deferred exchange differences on qualifying cash fl ow hedges which are recorded in other comprehensive income.
The balance sheets and income statements of foreign Group companies are translated for consolidation purposes using the current rate method. All assets and liabilities are translated at the balance sheet date rates of exchange, whereas the income statements are translated at average rates of exchange for the year, except for transactions where it is more relevant to use the rate of the day of the transaction. The translation 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 fi nancing exploration activities, are recorded directly in other comprehensive income.
For the preparation of the annual fi nancial statements, the following currency exchange rates have been used.
| 31 December 2017 | 31 December 2016 | |||
|---|---|---|---|---|
| Average | Period end | Average Period end | ||
| 1 USD equals NOK | 8.2712 | 8.2050 | 8.4014 | 8.6200 |
| 1 USD equals EUR | 0.8855 | 0.8338 | 0.9037 | 0.9487 |
| 1 USD equals SEK | 8.5481 | 8.2080 | 8.5610 | 9.0622 |
Non-current assets, long-term liabilities and provisions consist of amounts that are expected to be recovered or paid more than twelve months after the balance sheet date. Current assets and current liabilities consist solely of amounts that are expected to be recovered or paid within twelve months after the balance sheet date.
Oil and gas properties are recorded at historical cost less depletion. All costs for acquiring concessions, licences or interests in production sharing contracts and for the survey, drilling and development of such interests are capitalised on a fi eld area cost centre basis.
Costs directly associated with an exploration well are capitalised. If it is determined that a commercial discovery has not been achieved, these exploration costs are charged to the income statement. During the exploration and development phases, no depletion is charged. The fi eld will be transferred from the non-production cost pool to the production cost pool within oil and gas properties once production commences, and accounted for as a producing asset. Routine maintenance and repair costs for producing assets are expensed 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 fi eld 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 confi dence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimates.
Probable reserves are those unproved reserves which analysis of geological and engineering data 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 percent 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 defi cit 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 fi eld area less any provision for site restoration costs, royalties and deferred production or revenue related taxes is higher than the anticipated future net cash fl ow from oil and gas reserves attributable to the Group's interest in the related fi eld areas. Capitalised costs cannot be carried unless those costs can be supported by future cash fl ows from that asset. Provision is made for any impairment, where the net carrying value, according to the above, exceeds the recoverable amount, which is the higher of value in use and fair value less costs to sell, determined through estimated future discounted net cash fl ows using prices and cost levels used by Group management in their internal forecasting. If there is no decision to continue with a fi eld specifi c exploration programme, the costs will be expensed at the time the decision is made.
Other tangible 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 fi ve years for offi ce equipment and other assets.
Additional costs to existing assets are included in the assets' net book value or recognised as a separate asset, as appropriate, only when it is probable that future economic benefi ts associated with the item will fl ow to the Group and the cost of the item can be measured reliably. The net book value of any replaced parts is written off. Other additional expenses are deemed to be repair and maintenance costs and are charged to the income statement when they are incurred.
The net book value is written down immediately to its recoverable amount when the net book value is higher. The recoverable amount is the higher of an asset's fair value less cost to sell and value in use.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred and the fair value of noncontrolling interest over the net identifi able assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net assets acquired, the difference is recognised in profi t or loss.
Goodwill is also recognised as the offsetting accounting entry to the deferred tax liability booked on the difference between the assigned fair value of an asset and the related tax base acquired in a business combination.
At each balance sheet date the Group assesses whether there is an indication that an asset may be impaired. Where an indicator of impairment exists or when impairment testing for an asset is required, the Group makes a formal assessment of the recoverable amount. Where the carrying value of an asset exceeds its recoverable amount the asset is considered impaired and is written down to its recoverable amount.
The recoverable amount is the higher of fair value less costs to sell and value in use. Value in use is calculated by discounting estimated future cash fl ows to their present value using a discount rate that refl ects current market assessments of the time value of money and the risks specifi c to the asset. When the recoverable amount is less than the carrying value an impairment loss is recognised with the expensed charge to the income statement. If indications exist that previously recognised impairment losses no longer exist or are decreased, the recoverable amount is estimated. When a previously recognised impairment loss is reversed the carrying amount of the asset is increased to the estimated recoverable amount but the increased carrying amount may not exceed the carrying amount after depreciation that would have been determined had no impairment loss been recognised for the asset in prior years.
Assets and liabilities are recognised initially at fair value plus transaction costs and subsequently measured at amortised cost unless stated otherwise. Financial assets are derecognised when the rights to receive cash fl ows from the investments have expired, or have been transferred and the Group has transferred substantially all risks and rewards of ownership.
Lundin Petroleum recognises the following fi nancial assets and liabilities:
The Group has only cash fl ow hedges which qualify for hedge accounting. The effective portion of changes in the fair value of derivatives that qualify as cash fl ow hedges are recognised in other comprehensive income. The gain or loss relating to the 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 fi eld is included in the current receivables and valued at the reporting date spot price or prevailing contract price and an overlift of production from a fi eld is included in the
current liabilities and valued at the reporting date spot price or prevailing contract price.
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 outfl ow of resources is required to settle the obligation and a reliable estimate can be made of the amount.
Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a discount rate that refl ects current market assessments of the time value of money and the risks specifi c to the obligation. The increase in the provision due to passage of time is recognised as fi nance costs.
On fi elds where the Group is required to contribute to site restoration costs, a provision is recorded to recognise the future commitment. An asset is created, as part of the oil and gas property, to represent the discounted value of the anticipated site restoration liability and depleted over the life of the fi eld on a unit of production basis. The corresponding accounting entry to the creation of the asset recognises the discounted value of the future liability. The discount applied to the anticipated site restoration liability is subsequently released over the life of the fi eld and is charged to fi nancial expenses. Changes in site restoration costs and reserves are treated prospectively and consistent with the treatment applied upon initial recognition.
Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortised costs using the 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 fi nancial 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 fi nancial liability, or a shorter period where appropriate.
Revenues from the sale of oil and gas are recognised in the income statement net of royalties taken in kind. Sales of oil and gas are recognised upon delivery of products and customer acceptance or on performance of services. Incidental revenues from the production of oil and gas are offset against capitalised costs of the related cost centre until quantities of proven and probable reserves are determined and commercial production has commenced.
Lifting or offtake arrangements for oil and gas produced in certain of the Group's jointly owned operations are such that each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative production after permanent differences less stock is underlift or overlift. Underlift and overlift are valued at market value and included within receivables and payables respectively. Movements during an accounting period are refl ected through the change in under/ overlift position as part of other income.
Service income, generated by providing technical and management services to joint operations, is recognised as other income. The fi scal regime in the area of operations defi nes whether royalties are payable in cash or in kind. Royalties payable in cash are accrued in the accounting period in which the liability arises. Royalties taken in kind are subtracted from production for the period to which they relate.
Borrowing costs attributable to the acquisition, construction or production of qualifying assets are added to the cost of those assets. Qualifying assets are assets that take a substantial period of time to complete for their intended use or sale. Investment income earned on the temporary investment of specifi c borrowings pending to be used for the qualifying asset, is deducted from the borrowing costs eligible for capitalisation.
This applies on the interest on borrowings to fi nance fi elds under development which is capitalised within oil and gas properties until production commences. All other borrowing costs are recognised in the income statement in the period
in which they occur. Interest on borrowings to fi nance the acquisition of producing oil and gas properties is charged to the income statement as incurred.
Short-term employee benefi ts such as salaries, social premiums and holiday pay, are expensed when incurred.
Pensions are the most common long-term employee benefi ts. The pension schemes are funded through payments to insurance companies. The Group's pension obligations consist mainly of defi ned contribution plans. A defi ned contribution plan is a pension plan under which the Group pays fi xed contributions. The Group has no further payment obligations once the contributions have been paid. The contributions are recognised as an expense when they are due.
The Group has one obligation under a defi ned benefi t plan. The relating liability recognised in the balance sheet is valued at the discounted estimated future cash outfl ows as calculated by an external actuarial expert. Actuarial gains and losses are 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 fi nancial statements but not deductible for tax purposes until they are actually incurred. However, the deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction
other than a business combination that at the time of the transaction affects neither accounting nor taxable profi t 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 profi t 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 fi scal environment, is at a country level. Information for segments is only disclosed when applicable. Segmental information is presented in Note 3, Note 7 and Note 10.
The management of Lundin Petroleum has to make estimates and judgements when preparing the fi nancial statements of the Group. Uncertainties in the estimates and judgements could have an impact on the carrying amount of assets and liabilities and the Group's result. The most important estimates and judgements in relation thereto are:
Estimates of oil and gas reserves are used in the calculations for impairment tests and accounting for depletion and site restoration. Standard recognised evaluation techniques are used to estimate the proved and probable reserves. These techniques take into account the future level of development required to produce the reserves. An independent reserves auditor reviews these estimates, see page 109 Reserve Quantity Information. Changes in estimates of oil and gas reserves, resulting in different future production profi les, will affect the discounted cash fl ows used in impairment testing, the anticipated date of site decommissioning and restoration and the depletion charges in accordance with the unit of production method. Changes in estimates in oil and gas reserves could for example result from additional drilling, observation of long-term reservoir performance or changes in economic factors such as oil price and infl ation rates.
Information about the carrying amounts of the oil and gas properties and the amounts charged to income, including depletion, exploration costs, and impairment costs is presented in Note 10.
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 a potential impairment the assumptions that management uses to estimate the future cash fl ows to calculate the recoverable amounts 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 fl ow estimates and the discount rate applied is reviewed throughout the year. Goodwill relating to acquisitions of oil and gas properties forms part of the impairment testing of oil and gas properties and is tested at least once a 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 10.
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 outfl ows in relation to the site decommissioning and restoration can be different. To refl ect 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 fi eld. 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 19.
A tax liability is recognised when a future payment, in application of a tax regulation, is considered probable and can be reasonably estimated. The exercise of judgment is required to assess the impact of new events on the amount of the liability.
Deferred tax assets are recognised for unused tax losses to the extent that it is probable that future taxable profi ts will be available against which the losses can be utilised. Estimation and judgement is required to determine the value of the deferred tax asset, based upon the timing and level of future taxable profi ts.
All events up to the date when the fi nancial statements were authorised for issue and which have a material effect in the fi nancial statements have been disclosed. Subsequent events are presented in Note 31.
of the Group
| MUSD | 2017 | 2016 |
|---|---|---|
| Crude oil from own production | 1,500.2 | 901.0 |
| Crude oil from third party activities | 303.5 | 2.1 |
| Condensate | 43.0 | 14.3 |
| Gas | 111.6 | 58.5 |
| Net sales of oil and gas from continuing operations | 1,958.3 | 975.9 |
| Change in under/over lift position | 13.8 | -29.1 |
| Other revenue | 24.9 | 3.2 |
| Revenue and other income from continuing operations | 1,997.0 | 950.0 |
For further information on revenue, see the Directors Report on pages 53–54.
| MUSD | 2017 | 2016 |
|---|---|---|
| Cost of operations | 117.3 | 113.1 |
| Tariff and transportation expenses | 37.9 | 33.9 |
| Change in inventory position | -0.4 | -0.7 |
| Other production costs | 9.4 | 22.1 |
| Production costs from continuing operations | 164.2 | 168.4 |
For further information on production costs, see the Directors Report on page 54.
The Group operates within several geographical areas with the focus on Norway following the IPC spin-off during the year. Operating segments are reported at country level which is consistent with the internal reporting provided to Group management.
The following tables present segment information from continuing operations regarding; revenue and other income, production costs, depletion and decommissioning costs, exploration costs, impairment costs of oil and gas properties, loss from sale of assets, other cost of sales, gross profi t/loss and certain asset and liability information regarding the Group's business segments. In addition segment information is reported in Note 7 and Note 10.
Revenues are derived from various external customers. There were no intercompany sales or purchases in the year or in the previous year other than to Lundin Petroleum Marketing SA which performs trading activities for Norway. These intercompany transactions are reported into segment Norway 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 25 percent of the total revenue is contracted with one customer. The Parent Company is included in Other in the table below.
| MUSD | 2017 | 2016 |
|---|---|---|
| Norway | ||
| Crude oil from own production | 1,500.2 | 901.0 |
| Condensate | 43.0 | 14.3 |
| Gas | 111.6 | 58.5 |
| Net sales of oil and gas | 1,654.8 | 973.8 |
| Change in under/over lift position | 13.8 | -29.1 |
| Other revenue | 24.4 | 1.5 |
| Revenue and other income | 1,693.0 | 946.2 |
| Production costs | -164.2 | -168.4 |
| Depletion and decommissioning costs | -567.3 | -386.2 |
| Exploration costs | -72.0 | -101.9 |
| Impairment costs of oil and gas properties | -30.6 | – |
| Loss from sale of assets | -14.4 | – |
| Gross profi t | 844.5 | 289.7 |
| MUSD | 2017 | 2016 |
|---|---|---|
| Other | ||
| Crude oil from third party activities | 303.5 | 2.1 |
| Net sales of oil and gas | 303.5 | 2.1 |
| Other revenue | 0.5 | 1.7 |
| Revenue and other income | 304.0 | 3.8 |
| Exploration costs | -1.1 | – |
| Impairment costs of oil and gas properties1 | – | -506.1 |
| Other cost of sales | -303.3 | -2.1 |
| Gross profi t | -0.4 | -504.4 |
1 The impairment costs of oil and gas properties relates to Russia.
| MUSD | 2017 | 2016 |
|---|---|---|
| Total from continuing operations | ||
| Crude oil from own production | 1,500.2 | 901.0 |
| Crude oil from third party activities | 303.5 | 2.1 |
| Condensate | 43.0 | 14.3 |
| Gas | 111.6 | 58.5 |
| Net sales of oil and gas | 1,958.3 | 975.9 |
| Change in under/over lift position | 13.8 | -29.1 |
| Other revenue | 24.9 | 3.2 |
| Revenue and other income | 1,997.0 | 950.0 |
| Production costs | -164.2 | -168.4 |
| Depletion and decommissioning costs | -567.3 | -386.2 |
| Exploration costs | -73.1 | -101.9 |
| Impairment costs of oil and gas properties | -30.6 | -506.1 |
| Loss from sale of assets | -14.4 | – |
| Other cost of sales | -303.3 | -2.1 |
| Gross profi t/loss | 844.1 | -214.7 |
| Assets | Equity and Liabilities | |||
|---|---|---|---|---|
| MUSD | 2017 | 2016 | 2017 | 2016 |
| Norway | 5,427.7 | 4,608.4 | 4,998.4 | 4,291.8 |
| Russia | 0.3 | 0.7 | 1.6 | 372.2 |
| Sweden | 1.5 | 2.6 | 23.7 | 7.5 |
| France | – | 220.8 | – | 121.7 |
| Netherlands | – | 75.0 | – | 45.1 |
| Malaysia | – | 343.6 | – | 466.0 |
| Indonesia | – | 6.8 | – | 195.2 |
| Corporate | 3,237.4 | 4,225.0 | 3,979.9 | 4,335.3 |
| Other | 170.0 | 162.1 | 184.1 | 162.4 |
| Intercompany balance elimination | -3,308.1 | -4,442.9 | -3,308.1 | -4,442.9 |
| Assets/liabilities per country | 5,528.8 | 5,202.1 | 5,879.6 | 5,554.3 |
| Shareholders' equity | N/A | N/A | -350.8 | -238.6 |
| Non-controlling interest | N/A | N/A | – | -113.6 |
| Total equity for the Group | N/A | N/A | -350.8 | -352.2 |
| Total consolidated | 5,528.8 | 5,202.1 | 5,528.8 | 5,202.1 |
For detailed information of the oil and gas properties per country, see also Note 10.
For further information on revenue and other income, production costs, depletion and decommissioning costs, exploration costs, impairment costs of oil and gas properties, loss from sale of assets and other cost of sales, see the Directors Report on pages 53–55.
| MUSD | 2017 | 2016 |
|---|---|---|
| Foreign currency exchange gain, net | 255.3 | – |
| Interest income | 1.0 | 2.3 |
| Guarantee fees | 0.4 | 0.4 |
| Finance income from continuing operations | 256.7 | 2.7 |
Exchange rate variations result primarily from fl uctuations in the value of the USD currency against a pool of currencies which mainly includes, amongst others, EUR and NOK. Lundin Petroleum has USD denominated debt recorded in subsidiaries using a functional currency other than USD. For further information on the foreign exchange movement, see the Directors Report on page 55.
| MUSD | 2017 | 2016 |
|---|---|---|
| Interest expense | 115.0 | 137.3 |
| Foreign currency exchange loss, net | – | 4.2 |
| Result on interest rate hedge settlement | 17.4 | 19.5 |
| Unwinding of site restoration discount | 13.7 | 11.6 |
| Amortisation of deferred fi nancing fees | 17.5 | 38.9 |
| Loan facility commitment fees | 9.3 | |
| Impairment of other shares | 11.2 | – |
| Other | 0.7 | 0.7 |
| Finance costs from continuing operations | 186.6 | 221.5 |
During 2017, MUSD 63.5 (MUSD 23.4) of interest was capitalised relating to development projects.
| MUSD | 2017 | 2016 |
|---|---|---|
| Group´s share of net result | 0.4 | – |
| Total result from share in result of associated company | 0.4 | – |
The result from share in associated company consisted of the 70 percent non-controlling equity share of the result of Mintley Caspian Ltd owned by Lundin Petroleum. The results of Mintley Caspian Ltd have been fully consolidated into the Lundin Petroleum consolidated accounts until 30 September 2017 and as such, there is no amount recorded for 2016 in the share in result from associated company.
| Tax charge MUSD |
2017 | 2016 |
|---|---|---|
| Current tax | ||
| Norway | -1.5 | -78.9 |
| Russia | 0.1 | 0.1 |
| Other | 0.9 | 0.4 |
| Current tax from continuing operations | -0.5 | -78.4 |
| Deferred tax | ||
| Norway | 501.7 | 98.5 |
| Russia | – | -83.5 |
| Other | – | -0.8 |
| Deferred tax from continuing operations | 501.7 | 14.2 |
| Total tax from continuing operations | 501.2 | -64.2 |
For further information on income taxes, see the Directors Report on page 56.
The tax on the Group's profi t before tax differs from the theoretical amount that would arise using the tax rate of Sweden as follows:
| MUSD | 2017 | 2016 |
|---|---|---|
| Loss before tax | 882.1 | -463.5 |
| Tax calculated at the corporate tax rate in Sweden 22% (22%) | -194.1 | 102.0 |
| Effect of foreign tax rates | -398.7 | -60.8 |
| Tax effect of expenses non-deductible for tax purposes | -76.3 | -120.3 |
| Tax effect of uplift on expenses | 108.4 | 150.9 |
| Tax effect of income not subject to tax | 69.4 | -5.9 |
| Tax effect of utilisation of unrecorded tax losses | 1.1 | 8.6 |
| Tax effect of creation of unrecorded tax losses | -12.4 | -7.1 |
| Adjustments to prior year tax assessments | 1.4 | -3.2 |
| Tax credit from continuing operations | -501.2 | 64.2 |
The tax rate in Norway is 78 percent and is the primary reason for the effect of foreign tax rates in the table above. The effect of non deductible expenses mainly relates to non deductible fi nancial expenses in Norway. The uplift on expenses relates to uplift on development expenses for oil and gas assets in Norway. The effect of non-taxable income mainly relates to non taxable foreign currency exchange gains.
There is no tax charge/credit relating to components of other comprehensive income.
| Current | Deferred | ||||
|---|---|---|---|---|---|
| Corporation tax liability - current and deferred MUSD |
2017 | 2016 | 2017 | 2016 | |
| Norway | – | – | 1,302.2 | 621.3 | |
| France | – | – | – | 50.0 | |
| Netherlands | – | – | – | -2.0 | |
| Switzerland | 0.3 | – | – | – | |
| Russia | 0.3 | 0.2 | – | – | |
| Total | 0.6 | 0.2 | 1,302.2 | 669.3 |
There was also a tax receivable of MUSD 77.5 reported in current tax assets as per 31 December 2016 mainly related to Norway.
For further information on tax liabilities, see the Directors Report on page 57.
| Specifi cation of deferred tax assets and tax liabilities 1 | ||
|---|---|---|
| MUSD | 2017 | 2016 |
| Deferred tax assets | ||
| Unused tax loss carry forwards | 526.7 | 708.6 |
| Other deductible temporary differences | 18.4 | 9.6 |
| 545.1 | 718.2 | |
| Deferred tax liabilities | ||
| Accelerated allowances | 1,846.4 | 1,371.1 |
| Brynhild operating cost share | – | 1.6 |
| Deferred tax on excess values | 0.9 | 1.1 |
| Other taxable temporary differences | – | 0.2 |
| 1,847.3 | 1,374.0 |
1 The specifi cation of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the balance sheet when they relate to the same jurisdiction.
The deferred tax asset is primarily relating to tax loss carried forwards in Norway for an amount of MUSD 135.3 (MUSD 320.7) and unused uplift carry forward in Norway of MUSD 391.4 (MUSD 374.3). 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 in Norway. 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 29. The tax losses can be carried forward and utilised for up to 9 years. A deferred tax asset of MUSD 7 relating to the tax loss carry forwards has not been recognised as at 31 December 2017 due to the uncertainty as to the timing and the extent of the tax loss carry forward utilisation. As a result of the IPC spin-off, Dutch tax loss carry forwards as per spin-off date are no longer available for the Group.
The Group also has Swedish tax loss carry forwards of approximately MUSD 73 (MUSD 47). The related deferred tax asset has not been recognised due to the uncertainty of the timing and extent of the utilisation of the tax losses.
Lundin Petroleum divested a 39 percent working interest in the Brynhild fi eld to CapeOmega with an effective date of 1 January 2017 and a completion date of 30 November 2017. The transaction involved a consideration of MUSD 93.7, including historical tax and uplift balances. The transaction resulted in a net after tax accounting loss of MUSD 14.4 arising from the difference between the consideration received and the book value of the associated assets being divested. The after tax accounting loss is reported as loss from sale of assets as detailed in the following table:
| MUSD | |
|---|---|
| Assets | |
| Oil and gas properties | – |
| Deferred tax | 143.9 |
| Total assets divested | 143.9 |
| Liabilities | |
| Site restoration provision | 32.0 |
| Working capital | 3.8 |
| Total liabilities divested | 35.8 |
| Net assets divested | 108.1 |
| Consideration received | 93.7 |
| Net after tax accounting loss | 14.4 |
On 24 April 2017, Lundin Petroleum completed the spin-off of its assets in Malaysia, France and The Netherlands (the IPC assets) into a newly formed company called International Petroleum Corporation (IPC) by distributing the IPC shares, on a pro- rata basis to Lundin Petroleum shareholders. The results of the IPC business are included in the Lundin Petroleum fi nancial statements until spin-off date and are shown as discontinued operations.
| MUSD | 2017 | 2016 |
|---|---|---|
| Revenue and other income | 69.1 | 209.9 |
| Cost of sales | ||
| Production costs | -17.4 | -59.1 |
| Depletion and decommissioning costs | -19.1 | -85.2 |
| Depletion of other assets | -10.4 | -31.1 |
| Exploration costs | 0.1 | -14.2 |
| Impairment costs of oil and gas properties | – | -126.0 |
| Gross profi t/loss | 22.3 | -105.7 |
| Sale of assets | – | -3.5 |
| General, administration and depreciation expenses | -2.3 | -1.9 |
| Operating profi t/loss | 20.0 | -111.1 |
| Net fi nancial items | ||
| Finance income | – | 23.9 |
| Finance costs | -24.1 | -7.9 |
| -24.1 | 16.0 | |
| Profi t/loss before tax | -4.1 | -95.1 |
| Income tax | 11.2 | -4.9 |
| -5.3 | -100.0 | |
| Gain on distribution of assets | 51.8 | – |
| Net result from discontinued operations | 46.5 | -100.0 |
| MUSD | 31 December 2017 |
31 December 2016 |
|---|---|---|
| Production cost pools | 2,169.7 | 2,641.8 |
| Non-production cost pools | 2,767.4 | 1,734.6 |
| 4,937.1 | 4,376.4 |
| MUSD | Norway | France | Netherlands | Malaysia | Total |
|---|---|---|---|---|---|
| Cost | |||||
| 1 January | 4,351.6 | 306.3 | 119.2 | 423.8 | 5,200.9 |
| Additions | 250.3 | 0.9 | 0.6 | 1.3 | 253.1 |
| Spin off IPC | – | -328.6 | -124.1 | -425.1 | -877.8 |
| Change in estimates | 66.9 | – | – | – | 66.9 |
| Currency translation difference | 223.2 | 21.4 | 4.3 | – | 248.9 |
| 31 December | 4,892.0 | – | – | – | 4.892.0 |
| Depletion | |||||
| 1 January | -2,016.2 | -142.2 | -107.3 | -293.4 | -2,559.1 |
| Depletion charge for the year | -568.4 | -4.6 | -1.9 | -12.6 | -587.5 |
| Spin off IPC | – | 162.2 | 113.1 | 306.0 | 581.3 |
| Impairment | -30.6 | – | – | – | -30.6 |
| Currency translation difference | -107.1 | -15.4 | -3.9 | – | -126.4 |
| 31 December | -2,722.3 | – | – | – | -2,722.3 |
| Net book value | 2,169.7 | – | – | – | 2,169.7 |
| MUSD | Norway | France | Netherlands | Indonesia | Malaysia | Total |
|---|---|---|---|---|---|---|
| Cost | ||||||
| 1 January | 3,567.1 | 312.7 | 126.0 | 64.4 | 412.1 | 4,482.3 |
| Additions | 664.4 | 2.8 | 2.5 | 0.1 | 15.2 | 685.0 |
| Change in estimates | 10.9 | 0.8 | -4.0 | – | -4.1 | 3.6 |
| Disposal | – | – | – | -64.5 | – | -64.5 |
| Reclassifi cations | 43.8 | – | -1.3 | – | 0.5 | 43.0 |
| Currency translation difference | 65.4 | -10.0 | -4.0 | – | 0.1 | 51.5 |
| 31 December | 4,351.6 | 306.3 | 119.2 | – | 423.8 | 5,200.9 |
| Depletion | ||||||
| 1 January | -1,600.1 | -132.6 | -101.2 | -46.8 | -232.3 | -2,113.0 |
| Depletion charge for the year | -388.7 | -14.4 | -9.7 | – | -61.1 | -473.9 |
| Disinvestments | – | – | – | 46.8 | – | 46.8 |
| Currency translation difference | -27.4 | 4.8 | 3.6 | – | – | -19.0 |
| 31 December | -2,016.2 | -142.2 | -107.3 | – | -293.4 | -2,559.1 |
| Net book value | 2,335.4 | 164.1 | 11.9 | – | 130.4 | 2,641.8 |
Depletion from continuing operations amounted to MUSD 568.4 (MUSD 388.7) and is included within the depletion and decommissioning costs line in the income statement. Depletion from discontinued operations amounted to MUSD 19.1 (MUSD 85.2) and is included within the net result from discontinued operations line in the income statement.
| MUSD | Norway | France | Netherlands | Russia | Malaysia | Total |
|---|---|---|---|---|---|---|
| 1 January | 1,720.6 | 6.9 | 7.1 | – | – | 1,734.6 |
| Additions | 990.3 | 0.1 | 0.1 | 1.1 | -0.1 | 991.5 |
| Expensed exploration costs | -72.0 | – | – | -1.1 | 0.1 | -73.0 |
| Spin off IPC | – | -7.2 | -7.5 | – | – | -14.7 |
| Change in estimates | 35.6 | – | – | – | – | 35.6 |
| Currency translation difference | 92.9 | 0.2 | 0.3 | – | – | 93.4 |
| 31 December | 2,767.4 | – | – | – | – | 2,767.4 |
| MUSD | Norway | France | Netherlands | Indonesia | Russia | Malaysia | Other | Total |
|---|---|---|---|---|---|---|---|---|
| 1 January | 1,020.6 | 6.9 | 6.6 | – | 490.2 | 121.8 | – | 1,646.1 |
| Additions | 834.3 | 0.3 | 0.7 | 0.3 | 1.5 | 14.1 | -0.6 | 850.6 |
| Expensed exploration costs | -101.9 | -0.1 | -1.3 | -0.3 | – | -13.1 | 0.6 | -116.1 |
| Impairment | – | – | – | – | -506.1 | -122.3 | – | -628.4 |
| Change in estimates | 6.3 | – | – | – | – | – | – | 6.3 |
| Reclassifi cations | -43.8 | – | 1.3 | – | – | -0.5 | – | -43.0 |
| Currency translation difference | 5.1 | -0.2 | -0.2 | – | 14.4 | – | – | 19.1 |
| 31 December | 1,720.6 | 6.9 | 7.1 | – | – | – | – | 1,734.6 |
Expensed exploration costs from continuing operations amounted to MUSD 73.1 (MUSD 101.9) and are included within the exploration costs line in the income statement. Expensed exploration costs from discontinued operations amounted to MUSD -0.1 (MUSD 14.2) and is included within the net result from discontinued operations line in the income statement.
Lundin Petroleum carried out its impairment testing at 31 December 2017 on an asset basis in conjunction with the annual reserves audit process. Lundin Petroleum used a combination of the oil price forward curve at the year end and the price deck as used by ERCE for the yearend 2017 reserves certifi cation process as a basis for its price forecast, a future cost infl ation factor of 2% (2%) per annum and a discount rate of 8% (8%) to calculate the future post-tax cash fl ows.
Non-cash impairment costs from continuing operations amounted to MUSD 30.6 (MUSD 506.1) and related to the Brynhild fi eld in PL148 with the impairment costs in the comparative period relating to the Morskaya oil discovery in the Russian Caspian Sea. Non cash impairment costs from discontinued operations amounted to MUSD – (MUSD 126.0) and are included within the net result from discontinued operations line in the income statement.
During 2017, MUSD 63.5 (MUSD 23.4) of capitalised interest costs were added to oil and gas properties and relate to Norwegian development projects. The interest rate for capitalised borrowing costs is calculated at the external facility borrowing rate of LIBOR plus a margin of 3.15% per annum (margin of 3.00% per annum increased to 3.15% per annum from February 2016).
The Group participates in joint operations with third parties in oil and gas exploration and appraisal activities. The Group is contractually committed under various concession agreements to complete certain exploration and appraisal programmes. The commitments as at 31 December 2017 are estimated to be MUSD 52.8 (MUSD 88.6 of which MUSD 85.5 related to continuing operations) of which third parties who are joint operations partners will contribute approximately MUSD 31.1 (MUSD 61.4 of which MUSD 59.8 related to continuing operations).
| 2017 2016 |
||||||||
|---|---|---|---|---|---|---|---|---|
| Real | Real | |||||||
| MUSD | FPSO | estate | Other | Total | FPSO | estate | Other | Total |
| Cost | ||||||||
| 1 January | 204.8 | 11.2 | 36.5 | 252.5 | 207.2 | 11.2 | 46.5 | 264.9 |
| Additions | – | – | 1.6 | 1.6 | -1.7 | – | 1.3 | -0.4 |
| Disposals | – | – | – | – | – | – | -11.5 | -11.5 |
| Spin off IPC | -205.5 | – | -8.6 | -214.1 | – | – | – | – |
| Change in consolidation | – | -0.6 | -0.4 | -1.0 | – | – | – | – |
| Currency translation difference | 0.7 | – | 1.3 | 2.0 | -0.7 | – | 0.2 | -0.5 |
| 31 December | – | 10.6 | 30.4 | 41.0 | 204.8 | 11.2 | 36.5 | 252.5 |
| Depreciation | ||||||||
| 1 January | -54.8 | -1.8 | -29.8 | -86.4 | -23.7 | -1.7 | -35.2 | -60.6 |
| Disposals | – | – | – | – | – | – | 9.4 | 9.4 |
| Depreciation charge for the year | -10.4 | – | -2.8 | -13.2 | -31.1 | -0.1 | -4.2 | -35.4 |
| Spin off IPC | 65.2 | – | 6.8 | 72.0 | – | – | – | – |
| Change in consolidation | – | 0.6 | 0.3 | 0.9 | – | – | – | – |
| Reclassifi cation | – | – | – | – | – | – | 0.2 | 0.2 |
| Currency translation difference | – | – | -1.1 | -1.1 | – | – | – | – |
| 31 December | – | -1.2 | -26.6 | -27.8 | -54.8 | -1.8 | -29.8 | -86.4 |
| Net book value | – | 9.4 | 3.8 | 13.2 | 150.0 | 9.4 | 6.7 | 166.1 |
The depreciation charge for the year is based on cost and an estimated useful life of three to fi ve years for offi ce equipment and other assets. Real estate is depreciated using an estimated useful life of 20 years and taking into account its residual value. Depreciation from continuing operations amounted to MUSD 2.5 (MUSD 3.1) and is included within the general, administration and depreciation line in the income statement. Depreciation from discontinued operations amounted to MUSD 0.3 (MUSD 1.2) and is included within the net result from discontinued operations line in the income statement.
The FPSO located on the Bertam fi eld, Malaysia, is being depreciated over the committed contract term and included in the net result from discontinued operations line in the income statement.
| MUSD | 2017 | 2016 |
|---|---|---|
| 1 January | 128.1 | – |
| Additions | – | 128.1 |
| 31 December | 128.1 | 128.1 |
The Group's goodwill arose from the acquisition of a further 15 percent interest in the Edvard Grieg fi eld in 2016. Goodwill was included in the Group's impairment testing as per 31 December 2017 and will be tested for impairment annually as part of the annual impairment testing of oil and gas properties.
| MUSD | 31 December 2017 |
31 December 2016 |
|---|---|---|
| Other shares and participations | 6.3 | 8.9 |
| Other | 0.4 | 0.5 |
| 6.7 | 9.4 |
| 31 December 2016 | ||||
|---|---|---|---|---|
| Number of shares | Share % | Book amount MUSD |
Book amount MUSD |
|
| ShaMaran Petroleum Corp. | 121,584,842 | 5.6 % | 6.3 | 8.9 |
| 6.3 | 8.9 |
During 2017, the fair value of the ShaMaran shares was impaired by MUSD 11.2, see section fi nancial expenses in the Directors´ report, page 55.
The fair value of ShaMaran is calculated using the quoted share price at the Toronto Stock Exchange at the balance sheet date and is detailed below.
| ShaMaran Petroleum Corp. MUSD |
2017 | 2016 |
|---|---|---|
| 1 January | 8.9 | 4.1 |
| Additions | 1.4 | – |
| Fair value movement | -6.2 | 5.2 |
| Currency translation difference | 2.2 | -0.4 |
| 31 December | 6.3 | 8.9 |
| MUSD | 31 December 2017 |
31 December 2016 |
|---|---|---|
| Hydrocarbon stocks | 4.1 | 17.1 |
| Drilling equipment and consumable materials | 29.6 | 37.8 |
| 33.7 | 54.9 |
| MUSD | 31 December 2017 |
31 December 2016 |
|---|---|---|
| Trade receivables | 202.7 | 193.4 |
| Underlift | 29.4 | 28.9 |
| Joint operations debtors | 15.6 | 31.2 |
| Prepaid expenses and accrued income | 29.3 | 29.4 |
| Brynhild operating cost share | – | 3.0 |
| IPC working capital | 23.5 | – |
| Other | 3.9 | 3.0 |
| 304.4 | 288.9 |
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.
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. This arrangement ended during the year.
The IPC working capital relates to a residual receivable from IPC for working capital balances following the IPC spin-off which is due in 2018.
Cash and cash equivalents include only cash at hand or on bank. No short term deposits are held as at 31 December 2017.
| Additional paid in capital |
||||
|---|---|---|---|---|
| MUSD | Number of shares | Par value MSEK |
Par value MUSD |
MUSD |
| 31 December 2015 | 311,070,330 | 3.2 | 0.5 | 445.0 |
| Share issuance | 29,316,115 | 0.3 | 0.0 | 499.8 |
| Treasury shares transferred | – | – | – | 34.3 |
| Movements | 29,316,115 | 0.3 | 0.0 | 534.1 |
| 31 December 2016 | 340,386,445 | 3.5 | 0.5 | 979.1 |
| Distributions | – | – | – | -410.0 |
| Purchase of own shares | – | – | – | -28.0 |
| Share based payments | – | – | – | -13.2 |
| Movements | – | – | – | -451.2 |
| 31 December 2017 | 340,386,445 | 3.5 | 0.5 | 527.9 |
Included in the number of shares issued at 31 December 2017 are 1,233,310 shares which Lundin Petroleum holds in its own name. In 2016, Lundin Petroleum AB issued 27,580,806 new shares to Statoil ASA as part of the Edvard Grieg transaction where an additional 15 percent working interest in the Edvard Grieg fi eld was acquired. In addition, the Company also issued 1,735,309 new shares and transferred 2 million treasury shares held to Statoil ASA.
| MUSD | Available-for sale reserve |
Hedge reserve | Currency translation reserve |
Total |
|---|---|---|---|---|
| 1 January 2016 | -10.2 | -141.0 | -358.1 | -509.3 |
| Total comprehensive income | 5.3 | 64.3 | 8.9 | 78.5 |
| 31 December 2016 | -4.9 | -76.7 | -349.2 | -430.8 |
| Total comprehensive income | 4.9 | 76.4 | -96.2 | -14.9 |
| 31 December 2017 | – | -0.3 | -445.4 | -445.7 |
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.
| 2017 | 2016 | |
|---|---|---|
| Net result attributable to shareholders of the Parent Company, USD | ||
| From continuing operations | 384,692,005 | -256,696,668 |
| From discontinued operations | 46,460,065 | -100,043,259 |
| 431,152,070 | -356,739,927 | |
| Weighted average number of shares for the year | 340,237,772 | 325,808,486 |
| Earnings per share, USD | ||
| From continuing operations | 1.13 | -0.79 |
| From discontinued operations | 0.14 | -0.30 |
| 1.27 | -1.09 | |
| Weighted average diluted number of shares for the year | 341,380,316 | 326,738,233 |
| Earnings per share, USD | ||
| From continuing operations | 1.13 | -0.79 |
| From discontinued operations | 0.14 | -0.30 |
| Earnings per share fully diluted, USD | 1.27 | -1.09 |
| MUSD | 31 December 2017 |
31 December 2016 |
|---|---|---|
| Bank loans | 3,955.0 | 4,145.0 |
| Capitalised fi nancing fees | -75.0 | -96.7 |
| 3,880.0 | 4,048.3 |
Capitalised fi nancing fees amounted to MUSD 75.0 (MUSD 96.7) and related to the establishment costs of the external credit facility. The capitalised fi nancing fees are being amortised over the duration of the credit facility.
For further information, see Note 21
| MUSD | Site Restoration |
LTIP | Farm in payment |
Pension provision |
Other | Total |
|---|---|---|---|---|---|---|
| 1 January 2017 | 407.1 | 10.1 | 5.0 | 1.2 | 3.5 | 426.9 |
| Additions | 78.3 | 7.7 | – | 0.1 | 0.9 | 87.0 |
| Changes in estimates | 24.2 | – | – | – | – | 24.2 |
| Disposals | -32.0 | – | – | – | – | -32.0 |
| Payments | -3.8 | -8.1 | – | -0.1 | -0.3 | -12.3 |
| Unwinding of discount | 13.7 | – | – | – | – | 13.7 |
| Spin off IPC | -91.1 | – | -5.2 | – | -1.4 | -97.7 |
| Currency translation difference | 18.2 | – | 0.2 | – | 0.1 | 18.5 |
| 31 December 2017 | 414.6 | 9.7 | – | 1.2 | 2.8 | 428.3 |
| Non-current | 414.6 | 2.8 | – | 1.2 | 2.0 | 420.6 |
| Current | – | 6.9 | – | – | 0.8 | 7.7 |
| Total | 414.6 | 9.7 | – | 1.2 | 2.8 | 428.3 |
| MUSD | Site Restoration |
LTIP | Farm in payment |
Pension provision |
Other | Total |
|---|---|---|---|---|---|---|
| 1 January 2016 | 368.2 | 7.0 | 4.6 | 1.2 | 3.7 | 384.7 |
| Additions | 24.2 | 10.4 | – | 0.1 | 0.7 | 35.4 |
| Changes in estimates | 7.4 | – | 0.5 | – | – | 7.9 |
| Payments | -10.7 | -7.3 | – | -0.1 | -0.2 | -18.3 |
| Unwinding of discount | 15.2 | – | – | – | – | 15.2 |
| Reclassifi cation | – | – | – | – | -0.6 | -0.6 |
| Currency translation difference | 2.8 | – | -0.1 | – | -0.1 | 2.6 |
| 31 December 2016 | 407.1 | 10.1 | 5.0 | 1.2 | 3.5 | 426.9 |
| Non-current | 407.1 | 3.2 | 5.0 | 1.2 | 3.5 | 420.0 |
| Current | – | 6.9 | – | – | – | 6.9 |
| Total | 407.1 | 10.1 | 5.0 | 1.2 | 3.5 | 426.9 |
In calculating the present value of the site restoration provision, a pre-tax discount rate of 3.5 percent (3.5 percent) was used which is based on long-term risk-free interest rate projections. The additions in 2017 mainly relates to the liability associated with Norwegian development projects. Based on the estimates used in calculating the site restoration provision as at 31 December 2017, approximately 70 percent of the total amount is expected to be settled after more than 15 years.
For more information on the Group's LTIP, see Note 29.
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 (TCHF 138) 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 (TCHF 1,800).
| MUSD | 31 December 2017 |
31 December 2016 |
|---|---|---|
| Trade payables | 30.1 | 13.3 |
| Overlift | 12.8 | 29.9 |
| Joint operations creditors and accrued expenses | 188.9 | 238.8 |
| Other accrued expenses | 19.5 | 16.9 |
| Other | 7.7 | 9.5 |
| 259.0 | 308.4 |
The accounting policies for fi nancial assets and liabilities have been applied to the line items below:
| 31 December 2017 MUSD |
Total | Loan receivables and other receivables at amortised cost |
Financial assets at amortised cost |
Assets at fair value in OCI 2 |
Fair value recognised in profi t/loss |
Derivatives used for hedging |
|---|---|---|---|---|---|---|
| Other shares and participations | 6.3 | – | – | 6.3 | – | – |
| Other non-current fi nancial assets | 0.4 | – | 0.4 | – | – | – |
| Derivative instruments | 34.2 | – | – | – | – | 34.2 |
| Joint operations debtors | 15.6 | 15.6 | – | – | – | – |
| Other current receivables1 | 259.5 | 230.1 | – | – | 29.4 | – |
| Cash and cash equivalents | 71.4 | 71.4 | – | – | – | – |
| 387.4 | 317.1 | 0.4 | 6.3 | 29.4 | 34.2 |
| 31 December 2017 MUSD |
Total | Other liabilities at amortised cost |
Financial liabilities at amortised cost |
Fair value recognised in profi t/loss |
Derivatives used for hedging |
|---|---|---|---|---|---|
| Financial liabilities | 3,880.0 | – | 3,880.0 | – | – |
| Derivative instruments | 9.5 | – | – | – | 9.5 |
| Joint operations creditors | 188.9 | 188.9 | – | – | – |
| Other current liabilities | 51.2 | 38.4 | – | 12.8 | – |
| 4,129.6 | 227.3 | 3,880.0 | 12.8 | 9.5 |
| 31 December 2016 MUSD |
Total | Loan receivables and other receivables at amortised cost |
Financial assets at amortised cost |
Assets at fair value in OCI2 |
Fair value recognised in profi t/loss |
Derivatives used for hedging |
|---|---|---|---|---|---|---|
| Other shares and participations | 8.9 | – | – | 8.9 | – | – |
| Other non-current fi nancial assets | 0.5 | – | 0.5 | – | – | – |
| Derivative instruments | 17.8 | – | – | – | – | 17.8 |
| Joint operations debtors | 31.2 | 31.2 | – | – | – | – |
| Other current receivables1 | 305.8 | 276.9 | – | – | 28.9 | – |
| Cash and cash equivalents | 69.5 | 69.5 | – | – | – | – |
| 433.7 | 377.6 | 0.5 | 8.9 | 28.9 | 17.8 |
| 31 December 2016 MUSD |
Total | Other liabilities at amortised cost |
Financial liabilities at amortised cost |
Fair value recognised in profi t/loss |
Derivatives used for hedging |
|---|---|---|---|---|---|
| Financial liabilities | 4,048.3 | – | 4,048.3 | – | – |
| Other non-current liabilities | 33.8 | 33.8 | – | – | – |
| Derivative instruments | 67.4 | – | – | – | 67.4 |
| Joint operations creditors | 238.8 | 238.8 | – | – | – |
| Other current liabilities | 52.9 | 23.0 | – | 29.9 | – |
| 4,441.2 | 295.6 | 4,048.3 | 29.9 | 67.4 |
1 Prepayments are not included in other current assets, as prepayments are not deemed to be fi nancial instruments.
2 Other comprehensive income.
The fair value of loan receivables and other receivables is a fair approximation of the book value.
For fi nancial assets and liabilities measured at fair value in the balance sheet, the following fair value measurement hierarchy is used: – Level 1: based on quoted prices in active markets;
– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;
– Level 3: based on inputs which are not based on observable market data.
Based on this hierarchy, fi nancial assets and liabilities measured at fair value can be detailed as follows:
| 31 December 2017 MUSD |
Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Other shares and participations | 6.3 | – | – |
| Derivative instruments – non-current | – | 26.5 | – |
| Derivative instruments – current | – | 7.7 | – |
| Underlift | 29.4 | – | – |
| 35.7 | 34.2 | – | |
| Liabilities | |||
| Derivative instruments – non current | – | 3.1 | – |
| Derivative instruments – current | – | 6.4 | – |
| Overlift | 12.8 | – | – |
| 12.8 | 9.5 | – |
| 31 December 2016 | |||
|---|---|---|---|
| MUSD | Level 1 | Level 2 | Level 3 |
| Assets | |||
| Other shares and participations | 8.9 | – | |
| Derivative instruments – non-current | – | 17.0 | |
| Derivative instruments – current | – | 0.8 | – |
| Underlift | 28.9 | – | – |
| 37.8 | 17.8 | – | |
| Liabilities | |||
| Derivative instruments - non current | – | 29.8 | |
| Derivative instruments - current | – | 37.6 | – |
| Overlift | 29.9 | – | – |
| 29.9 | 67.4 | – |
The outstanding derivative instruments can be specifi ed as follows:
| Fair value of outstanding derivative instruments in the balance sheet |
31 December 2017 | 31 December 2016 | ||
|---|---|---|---|---|
| MUSD | Assets | Liabilities | Assets | Liabilities |
| Interest rate swap | 28.3 | 6.7 | 17.8 | 31.6 |
| Currency hedge | 5.9 | 2.8 | – | 35.8 |
| Total | 34.2 | 9.5 | 17.8 | 67.4 |
| Non-current | 26.5 | 3.1 | 17.0 | 29.8 |
| Current | 7.7 | 6.4 | 0.8 | 37.6 |
| Total | 34.2 | 9.5 | 17.8 | 67.4 |
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 2017 amounted to a net receivable of MUSD 21.6 (MUSD -13.8).
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 2017 amounted to a net receivable of MUSD 3.1 (MUSD -35.8).
For risks in the fi nancial reporting, see the section Internal control over fi nancial reporting in the Corporate Governance report on page 44 and Risk Management on pages 24–27 for more information.
The changes in liabilities whose cash fl ow movements are disclosed as part of fi nancing activities in the cash fl ow statement are as follows.
| Non-cash changes | |||||||
|---|---|---|---|---|---|---|---|
| At 1 January 2017 |
Cash fl ows |
Amortisation of deferred fi nancing fees |
Spin off IPC |
Change in consolidation |
Foreign exchange movement |
At 31 December 2017 |
|
| Financial liabilities | 4,048.3 | -190.0 | 17.5 | 8.6 | – | -4.4 | 3,880.0 |
| Other non-current liabilities | 33.8 | 1.3 | – | – | -35.1 | – | – |
| 4,082.1 | -188.7 | 17.5 | 8.6 | -35.1 | – | 3,880.0 |
As an international oil and gas exploration and production company, Lundin Petroleum is exposed to fi nancial risks such as currency risk, interest rate risk, credit risks, liquidity risks as well as the risk related to the fl uctuation in the oil price. The Group seeks to control these risks through sound management practice and the use of internationally accepted fi nancial instruments, such as oil price, interest rate and foreign exchange hedges. Lundin Petroleum uses fi nancial instruments solely for the purpose of minimising risks in the Group's business.
For further information on risks in the fi nancial reporting, see the section Internal Control over fi nancial reporting in the Corporate Governance report on page 44 and Risk Management on pages 24–27.
The Group's objectives when managing capital are to safeguard the Group's ability to continue as a going concern and to meet its committed work programme requirements in order to create shareholder value. The Group may put in place new credit facilities, repay debt, or other such restructuring activities as appropriate. Group management continuously monitors and manages the Group's net debt position in order to assess the requirement for changes to the capital structure to meet the objectives and to maintain fl exibility. Lundin Petroleum is not subject to any externally imposed capital requirements.
Apart from the proposed inaugural cash dividend to the AGM 2018, no signifi cant changes were made in the objectives, policies or processes during 2017.
Lundin Petroleum monitors capital on the basis of net debt and fi nancial agreements. Net debt is calculated as bank loans as shown in the balance sheet less cash and cash equivalents.
| MUSD | 31 December 2017 | 31 December 2016 |
|---|---|---|
| Bank loans | 3,955.0 | 4,145.0 |
| Cash and cash equivalents | -71.4 | -69.5 |
| Net debt | 3,883.6 | 4,075.5 |
The decrease in net debt compared to 2016 is mainly due to the positive free cash fl ow generated during 2017.
Interest rate risk is the risk to the earnings due to uncertain future interest rates.
Lundin Petroleum is exposed to interest rate risk through the credit facility, see also Liquidity risk below. The interest rate for capitalised borrowing costs is calculated at the external facility borrowing rate of LIBOR plus a margin of 3.15% per annum (margin of 3.00% per annum increased to 3.15% per annum from February 2016). Lundin Petroleum will assess the benefi ts of interest rate hedging on borrowings on a continuous basis. If the hedging contract provides a reduction in the interest rate risk at a price that is deemed acceptable to the Group, then Lundin Petroleum may choose to enter into an interest rate hedge.
The total interest expense for 2017 amounted to MUSD 178.5 which included MUSD 63.5 of capitalised interest related to borrowings for the Group's development activities. A 100 basis point shift in the interest rate would have resulted in a change in the total interest expense for the year of MUSD 13.4, taking into account the Group's interest rate hedges for 2017.
The Group has entered into interest rate hedging as follows:
| Borrowings MUSD |
Fixing of fl oating LIBOR Rate per annum |
Settlement period |
|---|---|---|
| 3,000 | 1.87% | Jan 2018 – Dec 2018 |
| 3,000 | 1.42% | Jan 2019 – Dec 2019 |
| 1,750 | 2.01% | Jan 2020 – Dec 2020 |
| 1,000 | 2.17% | Jan 2021 – Dec 2021 |
| 1,000 | 2.37% | Jan 2022 – Dec 2022 |
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 Krone (NOK) and Euro (EUR), as well as US Dollar, making Lundin Petroleum sensitive to fl uctuations 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 has entered into currency hedging contracts fi xing the rate of exchange from US Dollar into Norwegian Krone to meet Norwegian Krone operational requirements as summarised in the table below.
| Buy | Sell | Average contractual exchange rate |
Settlement period |
|---|---|---|---|
| MNOK 3,493.0 | MUSD 424.2 | NOK 8.23:USD 1 | Jan 2018 – Dec 2018 |
| MNOK 1,672.4 | MUSD 200.4 | NOK 8.35:USD 1 | Jan 2019 – Dec 2019 |
| MNOK 1,000.0 | MUSD 130.0 | NOK 7.69:USD 1 | Jan 2020 – Dec 2020 |
| MNOK 750.0 | MUSD 98.3 | NOK 7.63:USD 1 | Jan 2021 – Dec 2021 |
| MNOK 500.0 | MUSD 65.6 | NOK 7.62:USD 1 | Jan 2022 – Dec 2022 |
Under IAS 39, subject to hedge effectiveness testing, all of the hedges are treated as effective and changes to the fair value are refl ected in other comprehensive income. At 31 December 2017, a net current receivable of MUSD 1.3 (MUSD -36.8) and a net non-current receivable of MUSD 23.4 (MUSD -12.8) have been recognised representing the fair value of the outstanding currency and interest rate hedges.
The following table summarises the effect that a change in these currencies against the US Dollar would have on operating profi t 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 2017.
| Operating result in the fi nancial statements, MUSD | 812.4 | 812.4 | |
|---|---|---|---|
| Shift of currency exchange rates | Average rate 2017 | 10% USD weakening | 10% USD strengthening |
| EUR/USD | 0.8855 | 0.8050 | 0.9741 |
| SEK/USD | 8.5481 | 7.7710 | 9.4029 |
| NOK/USD | 8.2712 | 7.5193 | 9.0983 |
| RUR/USD | 58.3353 | 53.0321 | 64.1688 |
| CHF/USD | 0.9848 | 0.8953 | 1.0833 |
| Total effect on operating result, MUSD | -69.2 | 69.2 |
The foreign currency risk to the Group's income and equity from conversion exposure is not hedged.
As described in the Directors' report on page 55, the foreign exchange result in the income statement is mainly impacted by foreign exchange movements on the revaluation of the loan and working capital balances. A 10 percent strengthening in the US Dollar currency rate against the other Group currency rates would result in a MUSD 318.5 lower reported foreign exchange gain in the income statement.
The impact on the foreign exchange result from a change in the US Dollar currency compared to the other Group currencies is mainly due to the bank loans denominated in US Dollar.
Price of oil and gas are affected by the normal economic drivers of supply and demand as well as the fi nancial investors and market uncertainty. Factors that infl uence these include operational decisions, natural disasters, economic conditions, political instability or confl icts or actions by major oil exporting countries. Price fl uctuations can affect Lundin Petroleum's fi nancial 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 2017:
| Net result from continuing operations in the fi nancial statements, MUSD | 380.9 | 380.9 |
|---|---|---|
| Possible shift | -10% | 10% |
| Total effect on net result from continuing operations, MUSD | -38.5 | 38.5 |
The impact on the net result from a change in oil price is reduced due to the 78 percent tax rate in Norway.
Lundin Petroleum's policy is to adopt a fl exible approach towards oil price hedging, based on an assessment of the benefi ts of the hedge contract in specifi c circumstances. Based on analysis of the circumstances, Lundin Petroleum will assess the benefi ts of forward hedging monthly sales contracts for the purpose of establishing cash fl ow. If it believes that the hedging contract will provide an enhanced cash fl ow then it may choose to enter into an oil price hedge.
For the year ended 31 December 2017, the Group did not enter into oil price hedging contracts and there are no oil price hedging contracts outstanding as at 31 December 2017.
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 2017, the Group's trade receivables amounted to MUSD 202.7 (MUSD 193.4). There is no recent history of default. Other long-term and short-term receivables are considered recoverable and no provision for bad debt was accounted for as at 31 December 2017. Cash and cash equivalents are maintained with banks having strong long-term credit ratings.
Liquidity risk is defi ned as the risk that the Group could not be able to settle or meet its obligations on time or at a reasonable price. Group treasury is responsible for liquidity, funding as well as settlement management. In addition, liquidity and funding risks and related processes and policies are overseen by Group management.
In February 2016, Lundin Petroleum replaced its existing USD 4.0 billion lending facility, which was due to reduce in availability from June 2016 and mature in 2019, with a committed seven year senior secured reserve-based lending facility of up to USD 5.0 billion, with an initial committed amount of USD 4.3 billion. The committed amount has subsequently been increased to USD 5.0 billion. The facility is secured against certain cash fl ows generated by the Group. The amount available under the facility is recalculated every six months based upon the calculated cash fl ow generated by certain producing fi elds and fi elds under development at an oil price and economic assumptions agreed with the banking syndicate providing the facility.
The facility agreement provides that an "event of default" occurs where the Group does not comply with certain material covenants or where certain events occur as specifi ed in the agreement, as are customary in fi nancing agreements of this size and nature. Two of the main covenants are the net debt to EBIDTA and the EBITDA to fi nancial charges testing the ability to repay debt. If such an event of default occurs and subject to any applicable cure periods, the external lenders may take certain specifi ed actions to enforce their security, including accelerating the repayment of outstanding amounts under the credit facility.
The table below analyses the Group's fi nancial liabilities into relevant maturity groupings based on the remaining period at the balance sheet date to the contractual maturity date. Loan repayments are made based upon a net present value calculation of the assets' future cash fl ows. No loan repayments are currently forecast under this calculation.
| MUSD | 31 December 2017 | 31 December 2016 |
|---|---|---|
| Non-current | ||
| Repayment within 1–2 years: | ||
| – Derivative instruments | – | 29.8 |
| Repayment within 2–5 years: | ||
| – Bank loans | 3,955.0 | 1,132.9 |
| – Derivative instruments | 3.1 | – |
| Repayment after 5 years: | ||
| – Bank loans | – | 3,012.1 |
| – Other non-current liabilities | – | 33.8 |
| 3,958.1 | 4,208.6 | |
| Current | ||
| Repayment within 6 months: | ||
| – Trade payables | 30.1 | 13.3 |
| – Overlift | 12.8 | 29.9 |
| – Tax liabilities | 0.6 | 0.2 |
| – Joint operations creditors | 188.9 | 238.8 |
| – Other current liabilities | 7.7 | 9.5 |
| – Derivative instruments | 3.2 | 19.5 |
| Repayment after 6 months: | ||
| – Derivative instruments | 3.2 | 18.1 |
| 246.5 | 329.3 |
In February 2016, Lundin Petroleum entered into a committed seven year senior secured reserve-based lending facility of USD 5.0 billion. The fi nancing facility is a reserve-based lending facility secured against certain cash fl ows generated by the Group. The amount available under the facility is recalculated every six months based upon the calculated cash fl ow generated by certain producing fi elds and fi elds under development at an oil price and economic assumptions agreed with the banking syndicate providing the facility. 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 assets at 31 December 2017 amounted to MUSD 6.715.3 (MUSD 743.8) and represented the carrying value of the pledge of the Group companies whose shares are pledged as described in the Parent Company section on page 98.
As part of the IPC spin-off that was completed on 24 April 2017, the Company has indemnifi ed IPC for certain legal proceedings related to the period before spin-off. The Company has not provided for any costs in relation hereto as per 31 December 2017 as it does not believe the proceedings will lead to any liability for the Company.
Lundin Petroleum recognises the following related parties: associated companies, jointly controlled entities, key management personnel and members of their close family or other parties that are partly, directly or indirectly, controlled by key management personnel or of its family or of any individual that controls, or has joint control or signifi cant infl uence over the entity.
During the year, the Group has entered into transactions with related parties on a commercial basis and the material transactions are described below:
| MUSD | 2017 | 2016 |
|---|---|---|
| Sale of oil and related products | 176.2 | 155.0 |
| Sale of services | 3.4 | 0.3 |
| Purchase of services | -1.9 | -0.4 |
Since 30 June 2016, being the date Statoil ASA's holding in Lundin Petroleum increased to 20.1 percent, the Group has sold oil and related products to the Statoil group on an arm's-length basis amounting to MUSD 176.2 for the year (MUSD 155.0).
The related party transactions concern other parties that are controlled by key management personnel. Key management personnel include members of the Board of directors and Group management. The remuneration to the Board of directors and Group management is disclosed in Note 28. The increase in related party transactions compared to 2016 is due to the IPC spin off following what certain services are provided to and purchased from IPC.
As at the date of the IPC spin-off, the Group had a residual receivable for working capital from IPC of MUSD 27.4 which has been reduced to MUSD 23.5. This receivable is reported as current asset as it is due during 2018.
| 2017 | 2016 | |||
|---|---|---|---|---|
| Average number of employees per country | Total employees |
of which men | Total employees |
of which men |
| Parent Company in Sweden | 2 | 1 | 2 | 1 |
| Subsidiaries abroad continuing operations | ||||
| Norway | 354 | 266 | 344 | 258 |
| Switzerland | 34 | 21 | 45 | 26 |
| Russia | 16 | 10 | 16 | 10 |
| Netherlands | 1 | 1 | 1 | 1 |
| Total | 405 | 298 | 406 | 295 |
| Total continuing operations | 407 | 299 | 408 | 296 |
| Discontinued operations1 | ||||
| Malaysia | 57 | 36 | 105 | 66 |
| France | 47 | 36 | 48 | 40 |
| Netherlands | 5 | 3 | 5 | 3 |
| Total discontinued operations1 | 109 | 75 | 158 | 109 |
1 Average number of employees until IPC spin-off.
| 2017 | 2016 | |||
|---|---|---|---|---|
| Board members and Group management | Total at year end |
of which men | Total at year end |
of which men |
| Parent Company in Sweden | ||||
| Board members1 | 7 | 4 | 7 | 4 |
| Subsidiaries abroad | ||||
| Group management | 7 | 5 | 7 | 6 |
| Total Group | 14 | 9 | 14 | 10 |
1 Alex Schneiter, Chief Executive Offi cer (CEO) and Board Member is only included in Group management.
| 2017 | 2016 | ||||
|---|---|---|---|---|---|
| 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 | 569 | 106 | 582 | 116 | |
| Employees | 314 | 178 | 308 | 157 | |
| Subsidiaries abroad continuing operations | |||||
| Group management | 10,625 | 1,325 | 6,696 | 1,069 | |
| Other employees | 84,730 | 20,910 | 75,432 | 18,812 | |
| Total continuing operations | 96,238 | 22,519 | 83,018 | 20,154 | |
| of which pension costs | 8,822 | 7,655 | |||
| Discontinued operations | |||||
| Other employees | 3,612 | 804 | 17,960 | 3,025 | |
| of which pension costs | 314 | 1,157 |
Note: No performance based incentive plan vested in 2016.
| Salaries and other remuneration for the Board members and Group management 1 TUSD |
Fixed Board remuneration/ fi xed salary |
Other benefi ts1 |
Short-term variable salary 2 |
Performance based incentive plan |
Remuneration for committee work |
Remuneration outside of directorship |
Pension | Total 2017 |
|---|---|---|---|---|---|---|---|---|
| Parent Company in Sweden |
||||||||
| Board members | ||||||||
| Ian H. Lundin | 126 | – | – | – | 12 | 175 | – | 313 |
| Peggy Bruzelius | 60 | – | – | – | 18 | – | – | 78 |
| C. Ashley Heppenstall | 60 | – | – | 3,516 | 12 | 609 | – | 4,197 |
| Lukas H. Lundin | 60 | – | – | – | – | – | – | 60 |
| Grace Reksten Skaugen | 60 | – | – | – | 12 | – | – | 72 |
| Jakob Thomasen | 31 | – | – | – | 6 | – | – | 37 |
| Magnus Unger | 29 | – | – | – | 6 | 18 | – | 53 |
| Cecilia Vieweg | 60 | – | – | – | 17 | – | – | 77 |
| Total Board members | 486 | – | – | 3,516 | 83 | 802 | – | 4,887 |
| Subsidiaries abroad Group management |
||||||||
| Alex Schneiter | 772 | 19 | 965 | 2,183 | – | – | 176 | 4,115 |
| Other 3 | 2,048 | 269 | 1,601 | 2,768 | – | – | 404 | 7,090 |
| Total Group management | 2,820 | 288 | 2,566 | 4,951 | – | – | 580 | 11,205 |
Other benefi ts include school fees and health insurance for Group management.
2 To improve the relevance of remuneration reporting, this table will from this year on include the short-term variable salary for the fi nancial year reported, previously having refl ected timing of decision. This column shows bonuses awarded for achievements in 2017, including a discretionary award to the CEO and some other members of Group management, see page 41.
3 Comprises nine persons which is higher than in prior years as part of Group management moved to IPC following the IPC spin-off. Comprises Chief Financial Offi cer (both pre and post IPC spin-off), Chief Operating Offi cer, Vice President Corporate Responsibility, Vice President Legal (both pre and post IPC spin-off), Vice President Communications and Investor Relations, Vice President Corporate Finance and Vice President Human Resources and Shared Services.
Note: The performance based incentive plan that was awarded in 2014 when C. Ashley Heppenstall was the CEO of the Company vested in 2017. The amount mentioned in the table above relates to this award and does not relate to his work as Board Member.
| remuneration for the Board members and Group management1 TUSD |
Fixed Board remuneration/ fi xed salary |
Other benefi ts1 |
Short-term variable salary2 |
Unit bonus plan |
Remuneration for committee work |
Remuneration for work outside of directorship |
Pension | Total 2016 |
|---|---|---|---|---|---|---|---|---|
| Parent Company in Sweden | ||||||||
| Board members | ||||||||
| Ian H. Lundin | 123 | – | – | – | 12 | 175 | – | 310 |
| Peggy Bruzelius | 58 | – | – | – | 17 | – | – | 75 |
| C. Ashley Heppenstall | 58 | – | – | – | 6 | 608 | – | 672 |
| Lukas H. Lundin | 58 | – | – | – | – | – | – | 58 |
| William A. Rand | 29 | – | – | – | 12 | – | – | 41 |
| Grace Reksten Skaugen | 58 | – | – | – | 6 | – | – | 64 |
| Magnus Unger | 58 | – | – | – | 12 | 18 | – | 88 |
| Cecilia Vieweg | 58 | – | – | – | 17 | – | – | 75 |
| Total Board members | 500 | – | – | – | 82 | 801 | – | 1,383 |
| Subsidiaries abroad | ||||||||
| Group management | ||||||||
| Alex Schneiter | 771 | 39 | 900 | – | – | – | 162 | 1,872 |
| Other3 | 2,598 | 144 | 1,998 | 246 | – | – | 438 | 5,424 |
| Total Group management | 3,369 | 183 | 2,898 | 246 | – | – | 600 | 7,296 |
¹ Other benefi ts include school fees and health insurance for Group management.
2 To improve the relevance of remuneration reporting, this table will from this year on include the short-term variable salary for the fi nancial year reported, previously having refl ected timing of decision. This column shows bonuses awarded for achievements in 2016, including a discretionary award to the CEO and some other members of Group management, see also page 41. Due to this, the numbers in this table have changed compared to the annual report 2016. 3
Comprises six persons (Chief Financial Offi cer, Chief Operating Offi cer, Vice President Corporate Responsibility, Vice President Legal, Vice President Corporate Planning and Investor Relations, Vice President Corporate Finance).
Note: No performance based incentive plan vested in 2016.
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 for Group management is between 15 percent and 18 percent of the qualifying income for pension purposes. The Company provides for 60 percent of the pension contribution and the employee for the remaining 40 percent. Qualifying income is defi ned as annual base salary and short-term variable salary and is capped at approximately TCHF 846 (TCHF 846). The normal retirement age for the CEO is 65 years.
A mutual termination period of between three months 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, 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 benefi ts 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.
See page 41–43 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 2017.
The Company maintains the long-term incentive plans (LTIP) described below.
In 2008, Lundin Petroleum implemented a LTIP scheme consisting of a Unit Bonus Plan which provides for an annual grant of units that will lead to a cash payment at vesting. The LTIP has a three year duration whereby the initial grant of units vested equally in three tranches: one third after one year; one third after two years; and the fi nal third after three years. The cash payment is conditional upon the holder of the units remaining an employee of the Group at the time of payment. The share price for determining the cash payment at the end of each vesting period will be the average of the Lundin Petroleum closing share price for the period fi ve trading days prior to and following the actual vesting date. The exercise price at vesting date 31 May 2017 was SEK 169.79.
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 2017 and the year in which the units will vest.
| Plan | |||||
|---|---|---|---|---|---|
| Unit Bonus Plan | 2014 | 2015 | 2016 | 2017 | Total |
| Outstanding at the beginning of the period | 117,433 | 277,928 | 360,099 | – | 755,460 |
| Recalculation awards following IPC spin-off / dividend | 7,405 | 17,002 | 21,339 | – | 45,746 |
| Awarded during the period | – | – | – | 288,216 | 288,216 |
| Forfeited during the period | -466 | -10,188 | -28,163 | – | -38,817 |
| Exercised during the period | -124,372 | -148,840 | -129,232 | – | -402,444 |
| Outstanding at the end of the period | – | 135,902 | 224,043 | 288,216 | 648,161 |
| Vesting date | |||||
| 31 May 2018 | – | 135,902 | 113,320 | 96,072 | 345,294 |
| 31 May 2019 | – | – | 110,723 | 96,072 | 206,795 |
| 31 May 2020 | – | – | – | 96,072 | 96,072 |
| Outstanding at the end of the period | – | 135,902 | 224,043 | 288,216 | 648,161 |
The costs associated with the unit bonus plans are as given in the following table.
| Unit Bonus Plan MUSD |
2017 | 2016 |
|---|---|---|
| 2013 | – | 2.0 |
| 2014 | 1.5 | 2.0 |
| 2015 | 1.9 | 3.6 |
| 2016 | 2.4 | 2.5 |
| 2017 | 1.7 | – |
| 7.5 | 10.1 |
LTIP awards are recognised in the fi nancial 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 2017 amounted to MUSD 9.7 (MUSD 10.1). The provision is calculated based on Lundin Petroleum's share price at the balance sheet date. The closing share price at 31 December 2017 was SEK 187.80.
The 2015, 2016 and 2017 AGMs resolved a long-term performance based incentive plan in respect of Group management and a number of key employees.
The 2017 plan is effective from 1 July 2017 and the 2017 award has been accounted for from the second half of 2017. The awards made in respect of 2017 vest over three years from 1 July 2017 subject to certain performance conditions being met. Each award was fair valued at the date of grant at SEK 100.10 using an option pricing model.
The 2016 plan is effective from 1 July 2016 and vest over three years from 1 July 2016 subject to certain performance conditions being met. The outstanding number of awards increased compared to the original number of awards as a result of the dividend distribution of the IPC business as per the plan rules. Each original award was fair valued at the date of grant at SEK 89.30 using an option pricing model. Awards given to employees now employed by IPC following the IPC spin-off have been pro-rated until the spin-off date 24 April 2017.
The 2015 plan is effective from 1 July 2015 and vest over three years from 1 July 2015 subject to certain performance conditions being met. The outstanding number of awards increased compared to the original number of awards as a result of the dividend distribution of the IPC business as per the plan rules. Each original award was fair valued at the date of grant at SEK 91.40 using an option pricing model. Awards given to employees now employed by IPC following the IPC spin-off have been pro-rated until the spin-off date 24 April 2017.
The following table shows the number of units issued under the LTIPs, the amount outstanding as at 31 December 2017 and the year in which the units will vest.
| Plan | |||||
|---|---|---|---|---|---|
| Performance Based Incentive Plan | 2014 | 2015 | 2016 | 2017 | Total |
| Outstanding at the beginning of the period | 602,554 | 684,372 | 512,595 | – | 1,799,521 |
| Recalculation awards following IPC spin-off / dividend | 38,077 | 38,310 | 24,615 | – | 101,002 |
| Awarded during the period | – | – | – | 355,954 | 355,954 |
| Forfeited during the period | – | -76,179 | -130,308 | – | -206,487 |
| Exercised during the period | -640,631 | – | – | – | -640,631 |
| Outstanding at the end of the period | – | 646,503 | 406,902 | 355,954 | 1,409,359 |
| Vesting date | |||||
| 30 June 2018 | – | 646,503 | – | – | 646,503 |
| 30 June 2019 | – | – | 406,902 | – | 406,902 |
| 30 June 2020 | – | – | – | 355,954 | 355,954 |
| Outstanding at the end of the period | – | 646,503 | 406,902 | 355,954 | 1,409,359 |
The costs associated with the long-term performance based incentive plans are as given in the following table.
| Performance Based Incentive Plan | ||
|---|---|---|
| MUSD | 2017 | 2016 |
| 2014 | 0.8 | 1.5 |
| 2015 | 1.5 | 1.9 |
| 2016 | 1.4 | 0.9 |
| 2017 | 0.7 | – |
| 4.4 | 4.3 |
LTIP awards are recognised in the fi nancial statements pro rata over their vesting period. The total effect on equity for the Performance Based Incentive Plan at 31 December 2017 amounted to MUSD 7.3 (MUSD 7.7). The effect on equity is calculated based on the fair value at date of grant.
| TUSD | 2017 | 2016 |
|---|---|---|
| PwC | ||
| Audit fees | 501 | 830 |
| Out of which to PricewaterhouseCoopers AB | 242 | 200 |
| Audit related | 44 | 84 |
| Out of which to PricewaterhouseCoopers AB | 20 | – |
| Tax advisory services | 23 | 24 |
| Out of which to PricewaterhouseCoopers AB | – | – |
| Other fees | 18 | 36 |
| Out of which to PricewaterhouseCoopers AB | 7 | 6 |
| Total PwC | 586 | 974 |
| Out of which to PricewaterhouseCoopers AB | 269 | 206 |
| Remuneration to other auditors than PwC | 79 | 41 |
| Total audit fees excluding fees for IPC spin-off | 665 | 1,015 |
| Out of which to PricewaterhouseCoopers AB | 269 | 206 |
| Fees PwC for IPC spin-off | 471 | – |
| Out of which to PricewaterhouseCoopers AB | – | – |
| Total audit fees | 1,136 | 1,015 |
| Out of which to PricewaterhouseCoopers AB | 269 | 206 |
Audit fees include the review of the 2017 half year report. Audit related costs include special assignments such as licence audits and PSC audits.
There are no subsequent events to report.
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 46,648.6 (MSEK -103.3) for the year.
The result included MSEK 46,542.9 fi nancial income as a result of an internal restructuring prior to the IPC spin-off. The result excluding this fi nancial income amounts to MSEK 105.7 (MSEK -103.3).
The result included general and administrative expenses of MSEK 146.7 (MSEK 106.6) and net fi nance income of MSEK 243.1 (MSEK -0.5) when excluding the fi nance income as a result of the internal restructuring. Net fi nancial income includes MSEK 238.6 (MSEK –) dividend received from a subsidiary.
The fi nancial income as a result of the internal restructuring consists of received dividends from a subsidiary and results on the sale of subsidiary companies offset by the charges in relation to the IPC spin-off. As part of the internal restructuring that was completed on 7 April 2017, Lundin Petroleum AB sold all the shares held in two subsidiary companies and acquired all the shares of a newly incorporated company that holds all the shares in Lundin Norway AS. These transactions increased the shares in subsidiaries of the Company to MSEK 55,118.9.
Pledged assets of MSEK 55,118.9 (MSEK 6,740.3) relate to the carrying value of the pledge of the shares in respect of the fi nancing facility entered into by its fully-owned subsidiary Lundin Petroleum Holding BV, see also Note 24 in the notes to the fi nancial statements of the Group.
In June 2010, the Swedish International Public Prosecution Offi ce commenced an investigation into alleged violations of international humanitarian law in Sudan during 1997–2003. The Company has cooperated extensively and proactively with the Prosecution Offi ce by providing information regarding its operations in Block 5A in Sudan during the relevant time period. Ian H. Lundin and Alex Schneiter have been interviewed by the Prosecution Offi ce and were notifi ed of the suspicions that are the basis for the investigation. This is a normal part of Swedish legal procedure for any investigation and no charges have been brought, nor does this mean that charges will be brought. As repeatedly stated, Lundin Petroleum categorically refutes all allegations of wrongdoing and will cooperate with the Prosecution Offi ce's investigation. Lundin Petroleum strongly believes that it was a force for good in Sudan and that its activities contributed to the improvement of the lives of the people of Sudan.
The fi nancial statements of the Parent Company are prepared in accordance with accounting policies generally accepted in Sweden, applying RFR 2 issued by the Swedish Financial Reporting Board and the Annual Accounts Act (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 64–69.
for the Financial Year Ended 31 December
| Expressed in MSEK | Note | 2017 | 2016 |
|---|---|---|---|
| Revenue | 9.4 | 3.8 | |
| General and administration expenses | -146.7 | -106.6 | |
| Operating loss | -137.3 | -102.8 | |
| Result from fi nancial investments | |||
| Finance income | 1 | 46,786.4 | 3.5 |
| Finance cost | 2 | -0.5 | -4.0 |
| 46,785.9 | -0.5 | ||
| Profi t/loss before tax | 46,648.6 | -103.3 | |
| Income tax | 3 | – | – |
| Net result | 46,648.6 | -103.3 |
for the Financial Year Ended 31 December
| Expressed in MSEK | 2017 | 2016 |
|---|---|---|
| Net result | 46,648.6 | -103.3 |
| Other comprehensive income | – | – |
| Total comprehensive income | 46,648.6 | -103.3 |
| Attributable to: | ||
| Shareholders of the Parent Company | 46,648.6 | -103.3 |
| 46,648.6 | -103.3 |
for the Financial Year Ended 31 December
| Expressed in MSEK | Note | 2017 | 2016 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Shares in subsidiaries | 9 | 55,118.9 | 12,256.6 |
| Total non-current assets | 55,118.9 | 12,256.6 | |
| Current assets | |||
| Prepaid expenses and accrued income | 1.5 | 5.4 | |
| Other receivables | 4 | 6.0 | 15.3 |
| Cash and cash equivalents | 4.8 | 3.2 | |
| Total current assets | 12.3 | 23.9 | |
| TOTAL ASSETS | 55,131.2 | 12,280.5 | |
| EQUITY AND LIABILITIES | |||
| Restricted equity | |||
| Share capital | 3.5 | 3.5 | |
| Statutory reserve | 861.3 | 861.3 | |
| Total restricted equity | 864.8 | 864.8 | |
| Unrestricted equity | |||
| Other reserves | 6,599.2 | 6,828.8 | |
| Retained earnings | 824.0 | 4,622.6 | |
| Net result | 46,648.6 | -103.3 | |
| Total unrestricted equity | 54,071.8 | 11,348.1 | |
| Total equity | 54,936.6 | 12,212.9 | |
| Non-current liabilities | |||
| Provisions | 0.6 | 0.6 | |
| Payables to Group companies | – | 49.4 | |
| Total non-current liabilities | 0.6 | 50.0 | |
| Current liabilities | |||
| Trade payables | 3.0 | 1.9 | |
| Payables to Group companies | 181.9 | – | |
| Accrued expenses and prepaid income | 5 | 8.7 | 14.4 |
| Other liabilities | 0.4 | 1.3 | |
| Total current liabilities | 194.0 | 17.6 | |
| TOTAL EQUITY AND LIABILITIES | 55,131.2 | 12,280.5 |
for the Financial Year Ended 31 December
| Expressed in MSEK | 2017 | 2016 |
|---|---|---|
| Cash fl ow from operations | ||
| Net result | 46,648.6 | -103.3 |
| Adjustment for | ||
| Foreign currency exchange loss | -1.6 | -2.2 |
| Internal restructuring | -46,606.6 | – |
| Other | – | 26.8 |
| Changes in working capital: | ||
| Changes in current assets | 13.2 | -3.2 |
| Changes in current liabilities | 176.0 | 10.6 |
| Total cash fl ow from operations activities | 229.6 | -71.3 |
| Cash fl ow from fi nancing activities | ||
| Changes in long-term liabilities | – | -467.5 |
| Purchase of own shares | -229.6 | – |
| Proceeds from share issues /treasury shares | – | 544.1 |
| Total cash fl ow from fi nancing activities | -229.6 | 76.6 |
| Change in cash and cash equivalents | – | 5.3 |
| Cash and cash equivalents at the beginning of the year | 3.2 | 0.4 |
| Currency exchange difference in cash and cash equivalents | 1.6 | -2.5 |
| Cash and cash equivalents at the end of the year | 4.8 | 3.2 |
for the Financial Year Ended 31 December
| Restricted Equity | Unrestricted Equity | |||||
|---|---|---|---|---|---|---|
| Expressed in MSEK | Share capital |
Statutory reserve |
Other reserves |
Retained earnings |
Total | Total equity |
| Balance at 1 January 2016 | 3.2 | 861.3 | 2,295.3 | 4,622.6 | 6,917.9 | 7,782.4 |
| Total comprehensive income | – | – | – | -103.3 | -103.3 | -103.3 |
| Transactions with owners | ||||||
| Issuance of shares/sale of treasury shares | 0.31 | – | 4,533.51 | – | 4,533.5 | 4,533.8 |
| Balance at 31 December 2016 | 3.5 | 861.3 | 6,828.8 | 4,519.3 | 11,348.1 | 12,212.9 |
| Total comprehensive income | – | – | – | 46,648.6 | 46,648.6 | 46,648.6 |
| Transactions with owners | ||||||
| Purchase of own shares | – | – | -299.6 | – | -299.6 | -299.6 |
| Distributions | – | – | – | -3,695.3 | 3,695.3 | 3,695.3 |
| Total transactions with owners | – | – | -299.6 | -3,695.3 | -3,924.9 | -3,924.9 |
| Balance at 31 December 2017 | 3.5 | 861.3 | 6,599.2 | 47,472.6 | 54,071.8 | 54,936.6 |
1 In 2016, Lundin Petroleum AB issued 27,580,806 new shares to Statoil ASA as part of the Edvard Grieg transaction. In addition, the Company also issued 1,735,309 new shares and transferred 2 million treasury shares held to Statoil ASA in exchange for a cash consideration of MSEK 544.1 based upon a share price of SEK 145.66 per share. These three share transactions increased the share capital/premium of the Company by an amount of MSEK 4,533.8.
of the Parent Company
| MSEK | 2017 | 2016 |
|---|---|---|
| Result on internal restructuring | 46,542.9 | – |
| Dividend | 238.6 | – |
| Guarantee fees | 3.3 | 3.5 |
| Foreign exchange gain | 1.6 | – |
| 46,786.4 | 3.5 |
The result on the internal restructuring consists of received dividends from a subsidiary (MSEK 54,656.2), the result on the sale of subsidiary companies (MSEK -8,049.1) and the charges in relation to the IPC spin-off (MSEK 64.2).
| MSEK | 2017 | 2016 |
|---|---|---|
| Interest expenses Group | 0.5 | 1.8 |
| Foreign exchange losses, net | – | 2.2 |
| 0.5 | 4.0 |
| MSEK | 2017 | 2016 |
|---|---|---|
| Net result before tax | 46,648.6 | -103.3 |
| Tax calculated at the corporate tax rate in Sweden 22% (22%) |
-10,262.7 | 22.7 |
| Tax effect of received dividend | 12,076.9 | – |
| Tax effect of expenses non-deductible for | ||
| tax purposes | -1,775.7 | -1.9 |
| Increase unrecorded tax losses | -38.5 | -20.8 |
| – | – |
| MSEK | 31 December 2017 |
31 December 2016 |
|---|---|---|
| Due from Group companies | 0.7 | 11.7 |
| VAT receivable | 1.2 | 0.7 |
| Other | 4.1 | 2.9 |
| 6.0 | 15.3 |
| MSEK | 31 December 2017 |
31 December 2016 |
|---|---|---|
| Social security costs | 1.5 | 1.6 |
| Directors fees | 1.3 | 0.5 |
| Audit fees | 0.6 | 0.8 |
| Outside services | 5.0 | 11.5 |
| 8.7 | 14.4 |
Pledged assets relate to the carrying value of the pledge of the shares in respect of the fi nancing facility entered into by the wholly-owned subsidiary Lundin Petroleum Holding BV, see Note 23 in the notes to the fi nancial statements of the Group.
| MSEK | 2017 | 2016 |
|---|---|---|
| PwC | ||
| Audit fees | 2.1 | 1.6 |
| Audit related | 0.1 | – |
| 2.2 | 1.6 |
There has been no remuneration to any auditors other than PricewaterhouseCoopers AB.
The Annual General Meeting 2018 has an unrestricted equity at its disposal of MSEK 54,071.8, including the net result for the year of MSEK 46,648.6.
The Board of Directors propose that the Annual General Meeting dispose of the unrestricted equity as follows:
| Dividend payable at 4.00 SEK per share 1 | 1,354.1 |
|---|---|
| Brought forward | 52,717.7 |
| Unrestricted equity | 54,071.8 |
1 Dividend is based on the number of shares outstanding at the record date and the total dividend amount may change by the record date depending on repurchases of own shares.
| MSEK | Registration number |
Registered offi ce | Total number of shares issued |
Percentage owned |
Nominal value per share |
Book amount 31 Dec 2017 |
|---|---|---|---|---|---|---|
| Directly owned | ||||||
| Lundin Petroleum Holding BV | 68246226 | The Hague, Netherlands | 100 | 100 | EUR 1.00 | 55,118.9 |
| Indirectly owned | ||||||
| Lundin Norway AS | 986 209 409 | Lysaker, Norway | 4,930,000 | 100 | NOK 100.00 | |
| Lundin Petroleum Marketing SA | 660.6.133.015-6 | Collonge-Bellerive, Switzerland |
1,000 | 100 | CHF 100.00 | |
| Lundin Petroleum SA | 660.0.330.999-0 | Collonge-Bellerive, Switzerland |
1,000 | 100 | CHF 100.00 | |
| Lundin Petroleum Services BV | 68359985 | The Hague, Netherlands | 100 | 100 | EUR 1.00 | |
| Lundin Russia BV | 27290574 | 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 |
As at 23 March 2018, the Board of Directors and the President of Lundin Petroleum AB have adopted this annual report for the fi nancial year ended 31 December 2017.
The Board of Directors and the President & CEO certify that the annual fi nancial report for the Parent Company has been prepared in accordance with generally accepted accounting principles in Sweden and that the consolidated accounts have been prepared in accordance with IFRS as adopted by the EU and give a true and fair view of the fi nancial position and profi t of the Company and the Group and provides a fair review of the performance of the Group's and Parent Company's business, and describes the principal risks and uncertainties that the Company and the companies in the Group face.
Stockholm, 23 March 2018
Lundin Petroleum AB (publ) Reg. Nr. 556610-8055
Ian H. Lundin Chairman
Alex Schneiter President & CEO Peggy Bruzelius Board Member
C. Ashley Heppenstall Board Member
Lukas H. Lundin Board Member
Grace Reksten Skaugen Board Member
Jakob Thomasen Board Member
Cecilia Vieweg Board Member
Our audit report was issued on March 26, 2018
PricewaterhouseCoopers AB
Johan Rippe Authorised Public Accountant Lead Partner
Johan Malmqvist Authorised Public Accountant
We have audited the annual accounts and consolidated accounts of Lundin Petroleum AB (publ) for the year 2017. The annual accounts and consolidated accounts of the company are included on pages 46–100 in this document.
In our opinion, the annual accounts have been prepared in accordance with the Annual Accounts Act and present fairly, in all material respects, the fi nancial position of parent company as of 31 December 2017 and its fi nancial performance and cash fl ow 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 fi nancial position of the group as of 31 December 2017 and their fi nancial performance and cash fl ow for the year then ended in accordance with International Financial Reporting Standards (IFRS), 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 general meeting of shareholders adopts the income statement and balance sheet for the parent company and the group.
Our opinions in this report on the the annual accounts and consolidated accounts are consistent with the content of the additional report that has been submitted to the parent company's audit committee in accordance with the Audit Regulation (537/2014) Article 11.
We conducted our audit in accordance with International Standards on Auditing (ISA) and generally accepted auditing standards in Sweden. Our responsibilities under those standards are further described in the Auditor's Responsibilities section. We are independent of the parent company and the group in accordance with professional ethics for accountants in Sweden and have otherwise fulfi lled our ethical responsibilities in accordance with these requirements. This includes that, based on the best of our knowledge and belief, no prohibited services referred to in the Audit Regulation (537/2014) Article 5.1 have been provided to the audited company or, where applicable, its parent company or its controlled companies within the EU.
We believe that the audit evidence we have obtained is suffi cient and appropriate to provide a basis for our opinions.
Lundin Petroleum is an oil and gas company with exploration, development and production activities that have been located in Norway, Malaysia, France, the Netherlands and Russia during the fi nancial year 2017. As per 24 April 2017 a dividend in kind was executed in the form of shares in the newly formed International Petroleum Corporation, where the operations in Malaysia, France and the Netherlands had been placed. Thereafter the operations were primarily located in Norway during the rest of fi nancial year. We designed our audit by determining materiality and assessing the risks of material misstatement in the consolidated fi nancial statements. In particular, we considered where management made subjective judgements; for example, in respect of signifi cant accounting estimates that involved making assumptions and considering future events that are inherently uncertain. As in all of our audits, we also
addressed the risk of management override of internal controls, including among other matters consideration of whether there was evidence of bias that represented a risk of material misstatement due to fraud.
We tailored the scope of our audit in order to perform suffi cient work to enable us to provide an opinion on the consolidated fi nancial statements as a whole, taking into account the structure of the Group, the accounting processes and controls, and the industry in which the group operates.
Our planning of the audit included an assessment of the level of audit work to be performed at the group's headquarters and at local offi ces. Following the group's organisation certain processes for accounting and fi nancial reporting are performed outside the group's headquarter which means that we performed our audit work both at the group's headquarters and in those locations.
In determining the level of audit work required for the purposes of the group audit in each entity of the group we considered the geographical location, the size of each entity and the risk associated with the accounts in each entity in relation to the group's consolidated accounts as a whole. This analysis also included the nature and extent of audit procedures in each entity where a combination of full audits and specifi ed audit procedures were performed based on size and risk in the individual entity. Following this analysis and in dialogue with the group's audit committee, we performed, through our component audit teams, a full audit in Norway, as well as for the parent company and specifi ed audit procedures in the Netherlands. For entities considered to be of insignifi cant size to the group we performed analytical procedures. At the group's headquarters we performed the audit of the parent company, the consolidation, the annual report and key judgments and estimates in the group. Given the size of the Norwegian operations, our procedures as group auditors have also included several meetings with management from Norway including physical visits to the Norwegian offi ce location.
We have obtained reporting from our component auditors at two occasions during 2017 and we have reported the results from our procedures to management and the Audit Committee after the review of the Report for the six months period ended 30 June, 2017 and after the year-end audit of the fi nancial year 2017.
The scope of our audit was infl uenced by our application of materiality. An audit is designed to obtain reasonable assurance whether the fi nancial statements are free from material misstatement. Misstatements may arise due to fraud or error. They are considered material if individually or in aggregate, they could reasonably be expected to infl uence the economic decisions of users taken on the basis of the consolidated fi nancial statements. Based on our professional judgement, we determined certain quantitative thresholds for materiality, including the overall group materiality for the consolidated fi nancial statements as a whole. These, together with qualitative considerations, helped us to determine the scope of our audit and the nature, timing and extent of our audit procedures and to evaluate the effect of misstatements, both individually and in aggregate on the fi nancial statements as a whole.
Key audit matters of the audit are those matters that, in our professional judgment, were of most signifi cance in our audit of the annual accounts and consolidated accounts of the current period. These matters were addressed in the context of our audit of, and in forming our opinion thereon, the annual accounts and consolidated accounts as a whole, but we do not provide a separate opinion on these matters.
The carrying value of oil and gas properties represents the majority of the assets in the balance sheet in the Group and amounted to MUSD 4,937.1 (MUSD 4,376.4) as per 31 December 2017.
During the year management follows a process to identify potential indicators of impairment and to the extent that indicators are identifi ed impairment tests are prepared.
In an impairment test the carrying value of oil and gas properties is supported by the higher of either value in use calculations, which are based on discounted future cash fl ow forecasts, or fair value less cost of disposal (recoverable amount). The assessment is performed for each cash generating unit separately both for producing and nonproducing fi elds. Each fi eld, or fi elds with shared infrastructure, in the development or production phase, typically represents a separate cash generating unit. For exploration and evaluation assets, the assessment is generally performed on a fi eld cost centre basis and by exploration well.
The assessment to identify potential impairment indicators and to perform impairment tests requires management to exercise signifi cant judgement as described in the Accounting Policies "Critical accounting estimates and judgements" as well as in note 10 to the Annual Report where there is a risk that the valuation of oil and gas properties and any potential impairment charge or reversal of impairment may be incorrect.
Management's assessment requires consideration of a number of factors, including but not limited to, the determination of cash generating units, the Group's intention to proceed with a future work programme, the probability of success of future drilling, the size of proved and probable reserves, short and long term oil prices, future capital expenditures and operating costs as well as discount and infl ation rates.
The estimation of oil and natural gas reserves is a signifi cant area of judgement due to the technical uncertainty in assessing the estimated quantities. The estimates have a direct impact on depletion charges and are fundamental to the impairment assessment of oil and gas properties, but are also an indicator of the future potential of the Group's performance.
Following the impairment tests for producing fi elds, impairment charges were recorded during the second and third quarter of MUSD 30.6 in total related to the Brynhild fi eld in PL148. The assessment as per 31 December 2017 concluded that there were no additional impairment indicators identifi ed for producing fi elds and no impairment or reversal of impairment was recorded.
As part of the impairment testing process for producing fi elds, the goodwill of MUSD 128.1 that originates from the Edvard Grieg transaction in 2016 was also tested for impairment which is in accordance with the requirement to test goodwill on an annual basis. Management has concluded that the carrying values could be supported as per 31 December 2017.
For non-producing fi elds the company has written off MUSD 73.1 during the year as exploration costs.
Refer to pages 55 and 56 in the Directors' report, pages 65 and 69 in the Accounting Policies and note 10 in the fi nancial statements for more information.
For producing fi elds we obtained the Group's impairment tests supporting the impairment charges in the second and third quarters as well as the impairment indicator assessment as per 31 December 2017.
As part of our internal controls work, we evaluated management's controls over determining the impairment indicators and the process by which this was performed. Our internal controls testing supported management's conclusion that impairment indicators existed in the second and third quarters but that there were no additional impairment indicators triggering the need for further impairment tests for the Company's oil and gas assets or goodwill as per 31 December 2017.
Following this assessment we performed testing for the Brynhild fi eld in PL148 where impairment indicators had existed during the year and where the carrying value had been fully impaired. In respect of the impairment model applied by management, we considered and tested controls around input data to the impairment test and the review and approval of the impairment calculation.
The assumptions that underpin management's assessment of potential impairment indicators and impairment tests are inherently judgmental. Our audit work therefore assessed and challenged the reasonableness of management's key judgements. Specifi cally our work included, but was not limited to, the following procedures:
We obtained the estimation of proven and probable reserves certifi ed by the Group's external reserves auditor, ERC Equipoise Ltd (ERCE). Our audit work included but was not limited to:
For non-producing oil and gas properties we obtained a listing of capitalised exploration expenditures by fi eld cost centre and by well as of December 31, 2017. We tested the mathematical accuracy of this listing and reconciled the listing to the general ledger. We then assessed and challenged the continued capitalisation of exploration expenditures by reviewing the underlying documentation prepared by management for each of the fi elds and discussed with management. On a sample basis, we also reconciled and corroborated information provided on expenditures incurred and wells drilled to license budgets, resource and value estimates, progress reporting in the joint venture, future plans and/or well commitments.
The calculation of taxes under the Norwegian Petroleum Tax Act involves complexity and requires management judgement in the application of the tax regulations to the calculation of current and deferred taxes.
For the year ended 31 December 2017 the current and deferred income tax expense amounted to MUSD 501.2 (MUSD 64.2) of which MUSD 501.7 (MUSD 14.2) related to deferred tax.
The group has recognised a net deferred tax liability of MUSD 1,302.2 at December 31, 2017 (MUSD 669.3) that primarily relate to Lundin Norway AS. This net amount relates to deferred tax liabilities arising primarily from the tax value of oil and gas assets being lower than the book value resulting in a temporary difference with offsetting entries for deferred tax assets that are mainly related to asset retirement obligations and losses and uplift carried forward that are expected to be utilised in the future.
As part of the sales transaction for the Brynhild fi eld, the tax basis for the license was transferred to the buyer. As a result, the related deferred tax asset of MUSD 143.9 was expensed and presented together with the consideration from the sale resulting in a net loss of MUSD 14.4.
Refer to pages 56 and 57 in the Directors' report, pages 68 and 69 in the Accounting Policies and note 7 and 8 in the fi nancial statements for more information.
The group has recognised site restoration provisions in the amount of MUSD 414.6 as of December 31, 2017 (MUSD 407.1).
The calculation of decommissioning and site restoration provisions requires signifi cant management judgement amongst other due to the inherent complexity in estimating future decommissioning costs. The decommissioning of offshore infrastructure is a relatively immature activity and consequently there is limited historical precedent against which to benchmark estimates of future costs. These factors increase the complexity involved in determining accurate accounting provisions that are material to the group's balance sheet.
Management reviews decommissioning and site restoration provisions on an annual basis but recognises provisions for new fi elds and wells on an ongoing basis as installations are made offshore. This review incorporates the effects of any changes in local regulations, management's expected approach to decommissioning, cost estimates, year of decommissioning, infl ation and discount rates, and the effects of changes in exchange rates.
Refer to page 57 in the Directors' report, pages 67–69 in the Accounting Policies and note 19 in the fi nancial statements for more information.
We obtained the annual tax calculation for the Norwegian entity as prepared by management.
The tax calculation is subject to the company's internal controls. We tested management's review control over the detailed tax calculation and effective tax rate reconciliation, the reconciliation of the tax assessment received against the prior year tax return and review of uncertain tax positions.
As part of our substantive procedures, we tested the mathematical accuracy of the tax calculation and formulas applied. We reconciled the tax positions as of December 31, 2017 and December 31, 2016 used in the calculation to underlying documentation. We examined the application of the tax regulations and considered the classifi cation of tax expense including the presentation of net loss from the Brynhild sales transaction.
Furthermore, we tested the reconciliation of the effective tax rate to underlying documentation. Uncertain tax positions were examined based on the application of tax regulations and by reviewing any correspondence with tax authorities.
We critically assessed management's annual review of site restoration provisions recorded. The provisions contains estimates from both operated assets and non-operated assets.
The recorded provisions are subject to the company's internal controls. We tested management's controls over preparation and review of cost estimates used in calculating the provisions and the review and approval of the fi nal site restoration provisions.
For operated assets we have gained an understanding of the mandatory or constructive obligations with respect to the decommissioning of each asset based on the contractual arrangements and relevant local regulation to validate the appropriateness of the cost estimate. We obtained management's calculation of site restoration provisions for each fi eld. We tested mathematical accuracy of the calculations and reconciled the calculated provision to the general ledger. As part of our testing we considered the competence and objectivity of the internal experts who produced the cost estimates and challenged key assumptions such as rig rates, discount rate, and year of decommissioning. We also corroborated the assumptions to other assumptions made by the Company including as part of impairment testing.
For non-operated assets we have assessed the competence and objectivity of the operator performing the estimate, challenged the discount rate, year of decommissioning and other assumptions applied in the calculation and verifi ed that the accounting records appropriately refl ect the external estimates performed.
| Key audit matter | How our audit addressed the Key audit matter |
|---|---|
| Spin-off of International Petroleum Corporation On 24 April 2017, Lundin Petroleum completed the spin-off of its assets in Malaysia, France and the Netherlands in the form of a distribution of the International Petroleum Corporation (IPC) shares to the Lundin Petroleum shareholders. The distribution was approved by an Extraordinary General Meeting in the fi rst quarter 2017 and resulted in a dividend liability and a decrease of equity of MUSD 410.0 that was accounted for in the report for the three months ended 31 March 2017. Upon completion of the distribution that was executed on 24 April 2017 a net gain on of MUSD 51.9 was recorded in the group's income statement. This gain is recorded in accordance with IFRIC 17 and represent the difference in book value of the assets being distributed (net assets in IPC) and the book value of the distribution liability. Before the completion of the distribution, a restructuring of the group was performed which resulted in a dividend income of MSEK 46,543 in the parent company's income statement and an uplift in the value of shares in subsidiaries to MSEK 55,119 in the parent company's balance sheet. Refer to pages 48 and 53 in the Directors' report and note 9 in the fi nancial statements. |
We have examined management's documentation describing the transactions and collected all relevant documents, approvals and contracts presented by management. Our work related to the impact on the group's fi nancial statements has included but not been limited to: · obtaining management's calculation of the fair value of the distribution being recorded in the report for the three months period ended 31 March 2017; · obtaining and evaluating the key assumptions applied by management in the calculation of the fair value of the distribution, being future oil prices, proved and probable reserves as well as contingent and prospective reserves and the discount rate; · obtaining management's calculation of the net gain recorded upon distribution and compared the amounts to relevant supporting documents; · testing of the mathematical accuracy of the calculations. Our work over the impact from the internal restructuring to the parent company's income statement and balance sheet included but was not limited to: · obtaining all the relevant contracts supporting the internal restructuring; · comparing the individual transactions and their impact to contracts and other supporting materials; · testing of the mathematical accuracy of the calculations. |
This document also contains other information than the annual accounts and consolidated accounts and is found on pages 1–27, and 106-111. The Board of Directors and the Managing Director are responsible for this other information.
Our opinion on the annual accounts and consolidated accounts does not cover this other information and we do not express any form of assurance conclusion regarding this other information.
In connection with our audit of the annual accounts and consolidated accounts, our responsibility is to read the information identifi ed above and consider whether the information is materially inconsistent with the annual accounts and consolidated accounts. In this procedure we also take into account our knowledge otherwise obtained in the audit and assess whether the information otherwise appears to be materially misstated.
If we, based on the work performed concerning this information, conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.
The Board of Directors and the Managing Director are responsible for the preparation of the annual accounts and consolidated accounts and that they give a fair presentation in accordance with the Annual Accounts Act and, concerning the consolidated accounts, in accordance with IFRS as adopted by the EU. The Board of Directors and the Managing Director are also responsible for such internal control as they 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.
In preparing the annual accounts and consolidated accounts, The Board of Directors and the Managing Director are responsible for the assessment of the company's and the group's ability to continue as a going concern. They disclose, as applicable, matters related to going concern and using the going concern basis of accounting. The going concern basis of accounting is however not applied if the Board of Directors and the Managing Director intends to liquidate the company, to cease operations, or has no realistic alternative but to do so.
The Audit Committee shall, without prejudice to the Board of Director's responsibilities and tasks in general, among other things oversee the company's fi nancial reporting process.
Our objectives are to obtain reasonable assurance about whether the annual accounts and consolidated accounts as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinions. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs and generally accepted auditing standards in Sweden will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to infl uence the economic decisions of users taken on the basis of these annual accounts and consolidated accounts.
A further description of our responsibility for the audit of the annual accounts and consolidated accounts is available on Revisorsinspektionen's website www.revisorsinspektionen.se/ revisornsansvar. This description is part of the auditor´s report.
In addition to our audit of the annual accounts and consolidated accounts, we have also audited the administration of the Board of Directors and the Managing Director of Lundin Petroleum AB (publ) for the year 2017 and the proposed appropriations of the company's profi t or loss.
We recommend to the general meeting of shareholders that the profi t be appropriated in accordance with the proposal in the statutory administration report and that the members of the Board of Directors and the Managing Director be discharged from liability for the fi nancial year.
We conducted the audit in accordance with generally accepted auditing standards in Sweden. Our responsibilities under those standards are further described in the Auditor's Responsibilities section. We are independent of the parent company and the group in accordance with professional ethics for accountants in Sweden and have otherwise fulfi lled our ethical responsibilities in accordance with these requirements.
We believe that the audit evidence we have obtained is suffi cient and appropriate to provide a basis for our opinions.
Responsibilities of the Board of Directors and the Managing Director The Board of Directors is responsible for the proposal for appropriations of the company's profi t or loss. At the proposal of a dividend, this includes an assessment of whether the dividend is justifi able considering the requirements which the company's and the group's type of operations, size and risks place on the size of the parent company's and the group's equity, consolidation requirements, liquidity and position in general.
The Board of Directors is responsible for the company's organization and the administration of the company's affairs. This includes among other things continuous assessment of the company's and the group's fi nancial situation and ensuring that the company's organization is designed so that the accounting, management of assets and the company's fi nancial affairs otherwise are controlled in a reassuring manner. The Managing Director shall manage the ongoing administration according to the Board of Directors' guidelines and instructions and among other matters take measures that are necessary to fulfi ll the company's accounting in accordance with law and handle the management of assets in a reassuring manner.
Our objective concerning the audit of the administration, and thereby our opinion about discharge from liability, is to obtain audit evidence to assess with a reasonable degree of assurance whether any member of the Board of Directors or the Managing Director in any material respect:
· has undertaken any action or been guilty of any omission which can give rise to liability to the company, or
· in any other way has acted in contravention of the Companies Act, the Annual Accounts Act or the Articles of Association. Our objective concerning the audit of the proposed appropriations of the company's profi t or loss, and thereby our opinion about this, is to assess with reasonable degree of assurance whether the proposal is in accordance with the Companies Act.
Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with generally accepted auditing standards in Sweden will always detect actions or omissions that can give rise to liability to the company, or that the proposed appropriations of the company's profi t or loss are not in accordance with the Companies Act.
A further description of our responsibility for the audit of the administration is available on Revisorsinspektionen's website: www.revisorsinspektionen.se/revisornsansvar. This description is part of the auditor´s report.
PricewaterhouseCoopers AB, Torsgatan 21, 113 97 Stockholm, was appointed by the Annual General meeting on 4 May 2017 and has been the company's auditor since the company was listed on the Stockholm Stock Exchange 6 September, 2001.
Stockholm, 26 March 2018
PricewaterhouseCoopers AB
Johan Rippe Authorised Public Accountant Lead Partner Johan Malmqvist Authorised Public Accountant
Lundin Petroleum discloses alternative performance measures as part of its fi nancial statements prepared in accordance with ESMA's (European Securities and Markets Authority) guidelines. Defi nitions of the performance measures are provided under the key ratio defi nitions below.
| Financial data from continuing operations MUSD |
2017 | 2016 | 2015 | 2014 | 2013 |
|---|---|---|---|---|---|
| Revenue | 1,997.0 | 950.0 | 380.3 | 627.2 | 952.4 |
| EBITDA1 | 1,501.5 | 752.5 | 246.3 | 570.9 | 833.8 |
| Net result | 380.9 | -399.3 | -679.7 | -414.8 | 60.2 |
| Operating cash fl ow1 | 1,530.0 | 857.9 | 558.1 | 1,046.9 | 863.8 |
| Data per share from continuing operations USD |
|||||
| Shareholders' equity per share | -1.03 | -0.70 | -1.61 | 1.40 | 3.90 |
| Operating cash fl ow per share | 4.50 | 2.63 | 1.81 | 3.39 | 2.79 |
| Cash fl ow from operations per share | 3.82 | 2.05 | 0.77 | 1.43 | 2.23 |
| Earnings per share | 1.13 | -0.79 | -2.18 | -1.33 | 0.21 |
| Earnings per share fully diluted | 1.13 | -0.79 | -2.18 | -1.33 | 0.21 |
| EBITDA per share | 4.41 | 2.31 | 0.80 | 1.85 | 2.69 |
| EBITDA per share fully diluted | 4.40 | 2.30 | 0.79 | 1.84 | 2.69 |
| Dividend per share | 1.21 | – | – | – | – |
| Number of shares issued at year end | 340,386,445 | 340,386,445 | 311,070,330 | 311,070,330 | 317,910,580 |
| Number of shares in circulation at year end | 339,153,135 | 340,386,445 | 309,070,330 | 309,070,330 | 309,570,330 |
| Weighted average number of shares for the year | 340,237,772 | 325,808,486 | 309,070,330 | 309,170,986 | 310,017,074 |
| Weighted average number of shares for the year fully diluted |
341,380,316 | 326,738,233 | 310,019,890 | 309,475,038 | – |
| Share price SEK |
|||||
| Share price | 187.80 | 198.10 | 122.60 | 112.40 | 125.40 |
| Key ratios from continuing operations (%) | |||||
| Return on equity 2 | – | – | – | -48 | 5 |
| Return on capital employed | 22 | -9 | -19 | -8 | 15 |
| Net debt/equity ratio 2 | – | – | – | 605 | 99 |
| Equity ratio | -6 | -17 | -10 | 9 | 29 |
| Share of risk capital | 17 | -3 | 1 | 28 | 53 |
| Interest coverage ratio | 6 | -2 | -8 | -10 | 45 |
| Operating cash fl ow/interest ratio | 12 | 5 | 7 | 45 | 128 |
| Yield | 5 | n/a | n/a | n/a | n/a |
1 Excludes the reported after tax accounting loss of MUSD 14.4 in 2017 on the divestment of a 39 percent working interest in the Brynhild fi eld..
2 As the equity at 31 December 2017, 31 December 2016 and 31 December 2015 is negative, these ratios have not been calculated.
Operating profi t before depletion of oil and gas properties, exploration costs, impairment costs, depreciation of other tangible assets and gain on sale of assets.
Revenue less production costs and less current taxes.
Cost of operations, tariff and transportation expenses and royalty and direct production taxes.
Shareholders' equity divided by the number of shares in circulation at year end.
Operating cash fl ow divided by the weighted average number of shares for the year.
Cash fl ow from operations in accordance with the consolidated statement of cash fl ow divided by the weighted average number of shares for the year.
Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the year.
Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the year after considering any dilution effect.
EBITDA divided by the weighted average number of shares for the year.
The number of shares at the beginning of the year with changes in the number of shares weighted for the proportion of the year they are in issue.
The number of shares at the beginning of the year with changes in the number of shares weighted for the proportion of the year they are in issue after considering any dilution effect.
Net result divided by average total equity.
Income before tax plus interest expenses plus/less currency exchange differences on fi nancial 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 fi nancial items plus interest expenses plus/less currency exchange differences on fi nancial loans divided by interest expenses.
Revenue less production costs and less current taxes divided by the interest expense for the year.
Dividend per share in relation to quoted share price at the end of the fi nancial year.
| MUSD | 2017 | 2016 | 2015 | 2014 | 2013 |
|---|---|---|---|---|---|
| Revenue from own production | 1,693.5 | 947.9 | 380.3 | 627.2 | 952.4 |
| Revenue from third party activities | 303.5 | 2.1 | – | – | – |
| Production costs | -164.2 | -168.4 | -104.6 | -11.3 | -85.1 |
| Depletion and decommissioning costs | -567.3 | -386.2 | -159.1 | -88.5 | -130.2 |
| Exploration costs | -73.1 | -101.9 | -146.5 | -272.2 | -285.4 |
| Impairment costs of oil and gas properties | -30.6 | -506.1 | -526.0 | -400.7 | -81.7 |
| Loss from sale of assets | -14.4 | – | – | – | – |
| Other cost of sales | -303.3 | -2.1 | – | – | – |
| Gross profi t/loss | 844.1 | -214.7 | -555.9 | -145.5 | 370.0 |
| General, administration and depreciation expenses | -31.7 | -30.0 | -32.8 | -48.4 | -36.8 |
| Operating profi t/loss | 812.4 | -244.7 | -588.7 | -193.9 | 333.2 |
| Net fi nancial items | 70.1 | -218.8 | -670.9 | -480.0 | -73.2 |
| Share in result of associated company | -0.4 | – | – | – | – |
| Profi t/loss before tax | 882.1 | -463.5 | -1,259.6 | -673.9 | 260.0 |
| Income tax | -501.2 | 64.2 | 579.9 | 259.1 | -199.8 |
| Net result from continuing operations | 380.9 | -399.3 | -679.7 | -414.8 | 60.2 |
| Net result from discontinued operations | 46.5 | -100.0 | -186.6 | -17.1 | 12.7 |
| Net result | 427.4 | -499.3 | -866.3 | -431.9 | 72.9 |
| Net result attributable to the shareholders of the Parent Company: |
431.2 | -356.7 | -861.7 | -427.2 | 77.6 |
| Net result attributable to non-controlling interest: | -3.8 | -142.6 | -4.6 | -4.7 | -4.7 |
| Net result | 427.4 | -499.3 | -866.3 | -431.9 | 72.9 |
1 The above table is based on continuing operations only (excluding the discontinued IPC operations following the spin-off in 2017 and excluding the discontinued Russian onshore assets following the sale in 2014). The result from discontinued operations is reported separately in the income statement.
| Proved plus probable reserves (2P) from continuing operations |
Norway oil reserves MMbbl |
Norway gas reserves Bn scf 2 |
|---|---|---|
| 1 January 2017 | 684.4 | 178.1 |
| Changes during the year | ||
| Sales | -1.7 | – |
| Revisions | 40.1 | 20.2 |
| Extensions and discoveries | 2.1 | 1.1 |
| Production | -29.2 | -15.8 |
| 31 December 2017 | 695.7 1 | 183.6 |
1 The year end 2017 2P oil reserves reported include 19.3 MMbbl of NGL's.
2 The factor of 6,000 is used by the Company to convert one scf to one boe.
| Proved plus probable plus possible reserves (3P) from continuing operations |
Norway oil reserves MMbbl |
Norway gas reserves Bn scf 2 |
|---|---|---|
| 1 January 2017 | 858.0 | 240.8 |
| Changes during the year | ||
| Sales | -2.2 | – |
| Revisions | 27.1 | 9.2 |
| Extensions and discoveries | 2.6 | 1.4 |
| Production | -29.2 | -15.8 |
| 31 December 2017 | 856.3 1 | 235.6 |
1 The year end 2017 3P oil reserves reported include 23.8 MMbbl of NGL's.
2 The factor of 6,000 is used by the Company to convert one scf to one boe.
Lundin Petroleum calculates reserves and resources according to 2007 Petroleum Resources Management System (PRMS) Guidelines of the Society of Petroleum Engineers (SPE), World Petroleum Congress (WPC), American Association of Petroleum Geologists (AAPG) and Society of Petroleum Evaluation Engineers (SPEE). Lundin Petroleum's reserves are audited by ERC Equipoise Ltd. (ERCE), an independent reserves auditor. Reserves are defi ned as those quantities of petroleum which are anticipated to be commercially recovered by application of development projects to known accumulations from a given date forward under defi ned conditions. Estimation of reserves is inherently uncertain and to express an uncertainty range, reserves are subdivided into Proved, Probable and Possible categories. Unless stated otherwise, Lundin Petroleum reports its Proved plus Probable (2P) reserves and its Proved plus Probable plus Possible (3P) reserves.
| 3P Reserves | ||||
|---|---|---|---|---|
| 2P Reserves | ||||
| Proved reserves | Probable reserves | Possible reserves | ||
| Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and governmental regulations. Proved reserves can be categorised as developed or undeveloped. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confi dence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimates. |
Probable reserves are those unproved reserves which analysis of geological and engineering data 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 2P reserves. In this context, when probabilistic methods are used, there should be at least a 50 percent probability that the actual quantities recovered will equal or exceed the 2P estimate. |
Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of 3P reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10 percent probability that the actual quantities recovered will equal or exceed the 3P estimate. |
| Contingent resources | Prospective resources |
|---|---|
| ---------------------- | ----------------------- |
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies. 2C is the best estimate of the quantity that will actually be recovered from the accumulation by the project. It is the most realistic assessment of recoverable quantities if only a single result were reported. If probabilistic methods are used, there should be at least 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. Unless stated otherwise, Lundin Petroleum reports its 2C contingent resources.
Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and chance of development.
| bbl | Barrel (1 barrel = 159 litres) |
|---|---|
| bcf | Billion cubic feet (1 cubic foot = 0.028 m3 ) |
| Bn | Billion |
| boe | Barrels of oil equivalent |
| boepd | Barrels of oil equivalent per day |
| bopd | Barrels of oil per day |
| Bn boe | Billion barrels of oil equivalent |
| Mbbl | Thousand barrels |
| Mboe | Thousand barrels of oil equivalent |
| Mboepd | Thousand barrels of oil equivalent per day |
| MMboe | Million barrels of oil equivalent |
| MMbbl | Million barrels |
| MMbopd Million barrels of oil per day | |
| Mcf | Thousand cubic feet |
| MMscf | Million standard cubic feet |
| Bn scf | Billion standard cubic feet |
| CHF | Swiss Franc |
|---|---|
| CAD | Canadian Dollar |
| EUR | Euro |
| GBP | British Pound |
| NOK | Norwegian Krone |
| RUR | Russian Rouble |
| SEK | Swedish Krona |
| 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
Since Lundin Petroleum was incorporated in May 2001 and up to 31 December 2017 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 |
| New share issue | 2016 | 0.01 | 29,316,115 | 340,386,445 | 3,478,713 |
| Total | 340,386,445 | 340,386,445 | 3,478,713 |
Lundin Petroleum will publish the following interim reports:
| · 2 May 2018 | Three month report (January – March 2018) |
|---|---|
| · 31 July 2018 | Six month report (January – June 2018) |
| · 7 November 2018 | Nine month report (January – September 2018) |
| · 31 January 2019 | Year end report |
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 fi nancial year. All shareholders who are registered in the shareholders' register and who have duly notifi ed 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 3 May 2018 at 13.00 (Swedish time). Location: Vinterträdgården, Grand Hôtel, Södra Blasieholmshamnen 8 in Stockholm.
Shareholders wishing to attend the meeting shall:
· 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 26 April 2018.
This information is information that Lundin Petroleum AB is required to make public pursuant to the Securities Markets Act. The information was submitted for publication at 08.00 CEST on 29 March 2018.
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 proved and probable reserves and resource estimates may also be deemed to constitute forward-looking statements and refl ect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to 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 fi nancial risks. These risks and uncertainties are described in more detail under the heading "Risks and Risk Management" and elsewhere in the Company's annual report. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. Actual results may differ materially from those expressed or implied by such forward-looking statements. Forwardlooking statements are expressly qualifi ed by this cautionary statement.
Printed by Exakta Print Malmö and Landsten Reklam, Sweden 2018.
Exakta Print is FSC® and ISO 14001 certified and is committed to all round excellence in its environmental performance. The paper used for this report contains material sourced from responsibly managed forests, certified in accordance with the FSC® and is manufactured by Exakta Print to ISO 14001 international standards.
Front cover photograph by Øyvind Sætre
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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