Annual Report • Mar 6, 2019
Annual Report
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Annual Report 2018
Lundin Petroleum is one of the leading independent oil and gas companies in Europe with a strategic focus on Norway. We create sustainable, long-term value across the full spectrum of the oil and gas value chain.
The Johan Sverdrup development project in combination with a pipeline of potential new projects means that Lundin Petroleum has a strong production growth trajectory for the coming years.
Lundin Petroleum operates with one of the lowest carbon emissions intensities in the industry.
Record free cash fl ow generation, resulting in a proposed dividend for 2018 of USD 1.48 per share, corresponding to MUSD 500
| Our business model | 2 |
|---|---|
| 2018 performance | 4 |
| Management review | 6 |
| Operations | 8 |
| Responsibility | 16 |
| Risk management | 18 |
| Guiding principles | 22 |
|---|---|
| Board of Directors | 27 |
| Group management | 33 |
| Internal control over fi nancial reporting | 38 |
| Auditor's report | 39 |
| Financial summary | 40 |
|---|---|
| Directors' report | 42 |
| Financial statements of the Group | 53 |
| Accounting policies | 58 |
| Financial statements of the Parent Company | 89 |
| Board assurance | 95 |
| Auditor's report | 96 |
| Key fi nancial data | 101 |
|---|---|
| Relevant reconcilliations of alternative | |
| performance measured | 102 |
| Key ratio defi nitions | 103 |
| Five year fi nancial data | 104 |
| Reserve quantity information | 105 |
| Defi nitions and abbreviations | 106 |
| Share data | 107 |
| Shareholder information | 108 |
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.
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".
Our vision is to grow a profitable upstream exploration and production company focused on organic growth, in a safe and environmentally responsible manner for the long-term benefit of our shareholders and society.
Lundin Petroleum has grown to become one of the largest operated acreage holders in Norway, with a proven track record of discovering, developing and producing oil and gas resources efficiently and responsibly.
By actively pursuing new exploration acreage in core areas we secure access to new reservoirs and plays. Our subsurface expertise, in combination with cuttingedge technology, ensure an organic growth strategy that is sustainable and successful.
Our active organic growth strategy has delivered a strong long-term production profile and a pipeline of future growth opportunities. This gives us the capacity to deliver increased free cash flows and a sustainable and progressive dividend.
The oil and gas industry must be part of the solution for making global energy systems sustainable for future generations. Thanks to carbon mitigation technology and improved emissions management, Lundin Petroleum operates with one of the lowest carbon intensity levels in the industry – about a quarter of the industry world average.
Our low carbon performance is set to improve further in the coming years, with power from shore for Johan Sverdrup and Edvard Grieg.
In 2018, power supply from shore started for Johan Sverdrup. This will help reduce emissions by an estimated 460,000 tonnes per year, equivalent to the emissions of 230,000 cars, and will make Johan Sverdrup among the most carbon efficient fields in the world.
Lundin Petroleum Annual Report 2018 3
4 Lundin Petroleum Annual Report 2018
at industry leading low operating cost generated record high operating cash flow and free cash flow for 2018.
Lundin Petroleum Annual Report 2018 5
Our industry leading cost efficient growth and strong financial outlook enables us to distribute material and sustainable dividends, while continuing to deliver on our successful organic growth strategy.
Alex Schneiter President and CEO
2018 was a standout year across all areas of our business, with excellent performance from our producing assets, strong financial results and success with the drill bit. This success has been achieved while maintaining an industry leading low carbon intensity per produced barrel, at about one quarter of the industry world average.
Buoyed by stronger commodity prices, operating cost below guidance and very strong production effi ciency, we delivered a record high free cash fl ow in 2018. For the fi fth consecutive year, we more than replaced our produced barrels with reserves. In light of these results and our strong fi nancial outlook for the next decade, I am pleased that the Board of Directors has proposed an annual cash dividend of USD 500 million, which we aim to increase as the business continues to grow.
Our production for 2018 was at the upper end of the guidance for the year, supported by excellent performance from Edvard Grieg and the Alvheim area. Plateau production for Edvard Grieg has been further extended to mid-2020 and the infi ll and tie-back opportunities identifi ed in the area will allow us to keep the facilities full for many years to come.
The giant Johan Sverdrup fi eld is now less than a year away from start-up and 2018 was a critical year of project delivery. All four steel jackets and the topsides for the
drilling and riser platforms have been successfully installed offshore and the remaining topsides will be installed during spring 2019. With the current progress, it is safe to say that we are fi rmly on track for expected fi rst oil in November 2019.
When Phase 1 reaches plateau production in 2020, our production is expected to reach over 150 Mboepd. At full fi eld plateau production in 2023 our production will be over 170 Mboepd, with potential to reach over 200 Mboepd as our successful organic growth strategy continues to deliver.
We had signifi cant success in 2018 with new discoveries made near our core areas on the Utsira High and the Alvheim area and we matured our appraisal opportunities further towards development. As a result, we now have seven potential new projects in the pipeline. Complementing our organic growth strategy, we also made strategic acquisitions to increase our working interest in key assets such as Luno II, in order to bring commercial and operational alignment with the Edvard Grieg partnership, and in the licences containing the Rolvsnes oil discovery and the Goddo prospect, an area that has potential of over 250 MMboe gross resources.
2019 will be one of the most signifi cant years in Lundin Petroleum's history. It started with a record award in the 2018 APA licensing round, growing our acreage position in Norway by about 70 percent since year-end 2017. Johan Sverdrup is on schedule for production start and we will deliver our busiest exploration programme to date, targeting over 750 MMboe of additional net resources.
I would like to thank all of my colleagues for an outstanding 2018 and our shareholders and the Board for your continued support. I look forward to another successful period of delivery and growth for our Company.
Alex Schneiter President and CEO
2018 was an outstanding year for our Company both from an operational and fi nancial perspective. Based on this success and the future growth prospects of the business, the Board of Directors is proposing an annual cash dividend of USD 500 million, sustainable down to an oil price of below USD 50 per barrel.
With our success, we take our responsibility toward society and the environment seriously. Whilst we transition to a lower carbon energy system, it is a fact that hydrocarbons will remain a signifi cant component of the energy mix for generations to come. There will be a continued demand for oil and gas as an affordable energy source necessary to maintain economic growth, reduce poverty and improve living standards across the globe. We will however need affordable energy which has a much lower impact on the environment. Therefore, we have to become much smarter in how we produce, store, transport and consume energy. The emergence of renewables will certainly be a key factor in reducing carbon emissions but energy effi ciency may play an even more important role.
At Lundin Petroleum, we are committed to produce oil and gas in the most effi cient way possible with minimum impact on the environment. We are very proud to be best in class in
this area with a carbon intensity per produced barrel of oil that is among the lowest in our industry. When the Johan Sverdrup fi eld comes onstream, the carbon emissions will drop even further, as power required to run the platforms will be supplied from hydropower generated onshore. This solution will make Johan Sverdrup one of the most carbon effi cient fi elds in the world.
The Utsira High in the North Sea is the backbone of the Company and will ensure sustainable growth for decades to come. However, we will not stop there and I am excited about our exploration and appraisal campaign for 2019 which is our most ambitious programme so far. We are active in all areas on the Norwegian Continental shelf, from the south to the very north, and are pushing the frontiers of technology always further in cooperation with our service providers.
The Board of Directors continuously monitors the challenges for our industry and I am pleased that in 2018 we formed a special committee to ensure that we continue to stay on top of all health, safety and environmental issues. Responsibility in all we do is key to our current and future success.
On behalf of the Board, I would like to extend my deepest gratitude and thanks to the people who make it possible for our Company to continue delivering success for the benefi t of all our shareholders and stakeholders.
Ian H. Lundin Chairman of the Board
Edvard Grieg production efficiency 98%
2P reserves replacement ratio
Johan Sverdrup Phase 1 ~85% complete
Organic growth 4 appraisal successes 2 new discoveries
2018 was another year of strong operational delivery meeting all of our key targets. With Johan Sverdrup on track for production startup in November 2019 and a pipeline of seven potential new projects, we have a significant production growth trajectory ahead of us.
Nick Walker Chief Operating Officer
Lundin Petroleum's average production rate for 2018 was 81.1 Mboepd. This strong performance was at the upper end of the guidance range for the year, driven by the continued excellent reservoir and facilities performance from both the Edvard Grieg fi eld and the Alvheim area.
Lundin Petroleum's production growth trajectory for the coming years is among the strongest in the industry. Once the Johan Sverdrup full fi eld development is completed, Lundin Petroleum is set to more than double 2018 production levels.
The outlook for continued growth beyond Johan Sverdrup looks promising, following the exploration and appraisal success in 2018. Seven potential new projects, in combination with a quality asset base and an active exploration drilling programme, will ensure that Lundin Petroleum continues to deliver strong production growth for many more years to come.
Lundin Petroleum's key operated asset, the Edvard Grieg fi eld, continues to exceed expectations on both reservoir and facility performance. Edvard Grieg achieved a strong production effi ciency of 98 percent for 2018.
The PDO development drilling programme was completed during the year, with all development well results in line with or better than prognosis. Water production build-up is signifi cantly slower than expected, which has resulted in further extending the fi eld's plateau production to mid-2020. A pipeline of future
opportunities to keep the Edvard Grieg facilities full for even longer have been identifi ed in the area. An infi ll drilling programme is planned to commence in 2020 and the nearby Luno II and Rolvsnes discoveries are planned as subsea tiebacks to the Edvard Grieg facilities, projects that are set to be sanctioned in 2019 and implemented in parallell.
The 4D seismic survey that was acquired over the Edvard Grieg fi eld in 2018 indicates that the water injection fl ood front is further away from the main production wells than predicted by the current reservoir models. This information is still under review and has not been incorporated into the reservoir models used to support the year end 2018 reserves estimate.
| Reserves Summary | Proved plus Probable (2P reserves) |
Proved plus Probable plus Possible (3P reserves) |
|---|---|---|
| End 2017 | 726.3 | 895.5 |
| 2018 production | -30.1 | -30.1 |
| Revisions | +49.2 | +35.4 |
| Reserves end 2018 | 745.4 | 900.9 |
| Reserves replacement ratio | 163% | 118% |
Reserves were increased in 2018 with a 2P reserves replacement ratio of 163 percent and it was the fi fth consecutive year that Lundin Petroleum has more than replaced produced barrels with reserves. Oil and natural gas liquids (NGL) represent 96 percent of the 2P reserves and all reserve estimates are independently audited by ERC Equipoise Ltd. (ERCE).
The main reason for the increase in 2018 relates to the Johan Sverdrup fi eld, driven by positive well results from the development drilling in combination with the Phase 2 PDO sanction of full fi eld water alternating gas injection (WAG) for enhanced recovery, which has resulted in associated contingent resources being promoted to reserves.
During 2019, sanctioning of the Edvard Grieg infi ll well programme, the Luno II project and the Rolvsnes extended well test are expected to continue the trend of 2P reserves replacement exceeding production.
Lundin Petroleum's contingent resources at year end 2018 amounted to 225 MMboe, which represents an increase of 40 MMboe from year end 2017, before projects matured to reserves.
New discoveries on Frosk in the Alvheim area and Lille Prinsen in the Utsira High area and positive results from the appraisal wells on Luno II, Rolvsnes and Gekko, together with the acquisition of an additional 15 percent interest in Luno II were the main drivers for the increase.
Lundin Petroleum reports all of its reserves in working interest barrels of oil equivalent. Definitions of reserves and resources can be found on page 106.
i
2018 has been a key installation year for the Johan Sverdrup project. With the installation of three jackets, two topsides, one bridge, over 400 km of pipelines and 200 km of cables for power from shore, it has likely been the busiest installation campaign ever for a project on the Norwegian continental shelf. The remaining two topsides for the process and living quarter platforms will be installed in spring 2019 and with the good progress that is being made on the project, Phase 1 remains fi rmly on track for expected fi rst oil in November 2019.
Phase 2 will involve the installation of an additional processing platform at the fi eld centre and will see gross production capacity increase to 660 Mbopd. First oil for Phase 2 is planned during the fourth quarter of 2022.
Johan Sverdrup is quite simply a fantastic story for us. The discovery we made back in 2010 is set to start production later in 2019 and will create value for society for generations to come.
Kristin Færøvik Managing Director, Lundin Norway
Gross resources 2.2–3.2 billion boe
Costs reduced ~50% since PDO including foreign exchange gains
Phase 1 start-up November 2019
Production capacity 440 Mbopd
Phase 2 start-up Q4 2022
Production capacity 660 Mbopd
2018 was all about progressing contingent resources towards commercialisation. Through an active exploration and appraisal campaign, new discoveries were made and appraisal opportunities were matured further towards development. Together with the infi ll drilling programme at Edvard Grig, set to be sanctioned in 2019, Lundin Petroleum has seven potential new projects in the pipeline.
Frøya High/ Froan Basin
Norway
Through appraisal drilling and test production, the commercial potential of the unique Alta and Rolvsnes discoveries was signifi cantly de-risked in 2018. The long-term production behavior from the Rolvsnes reservoir needs to be understood better and the next step is to conduct an extended well test via a subsea tie-back of the suspended appraisal well to the Edvard Grieg platform. The extended well test will be sanctioned in the fi rst quarter of 2019 with implementation in parallel with the Luno II development project and is expected to come online in mid-2021.
A plan for development will be submitted in the fi rst quarter of 2019 for the Luno II discovery, scheduled to come on-stream in 2021 as a subsea tie-back to the nearby Edvard Grieg platform. The Gekko appraisal well was successfully completed in October 2018 and options for the economic development of the fi eld are being assessed.
The Frosk and Lille Prinsen discoveries will be further appraised in 2019, including a long-term production test on Frosk through the Bøyla subsea facilities into Alvheim. It is expected that Lille Prinsen will be economic to develop and an appraisal well is planned for 2019.
Utsira High Area Edvard Grieg Infills Luno II
Mandal High
Rolvsnes Lille Prinsen
More information on Lundin Petroleum's operations can be found in the Directors' Report on pages 43–46.
Through licensing rounds and strategic transactions, Lundin Petroleum actively renewed and diversifi ed its exploration portfolio in 2018, including adding the Northern North Sea as a new core area. Following the record award in the APA 2018 licensing round, Lundin Petroleum holds 82 licences in Norway, which is an increase in acreage position by about 70 percent since year-end 2017.
In 2019, Lundin Petroleum plans to drill a total of 17 exploration and appraisal wells out of which 15 are exploration wells targeting over 750 MMboe of net unrisked resources. The 2019 exploration programme will target prospects in all seven core exploration areas and is the largest and most diverse exploration programme for Lundin Petroleum to date.
The appraisal well and the extended production test on the Alta discovery in the southern Barents Sea were successfully completed in September 2018. The results exceeded expectations, demonstrating sustainable fl ow rates and excellent reservoir productivity and connectivity to a large volume of oil. Through these positive results, the understanding of this complex carbonate reservoir has been signifi cantly advanced, the development of which would be a fi rst on the Norwegian Continental shelf.
Studies for commercialising Alta and Gohta are being progressed to determine additional appraisal drilling requirements and development options. The current development concept for Alta is a subsea fi eld development connected to a standalone fl oating production and storage vessel. The adjacent Gohta discovery is also considered a possible joint development opportunity.
The large amount of new information from the positive results from the Alta extended well test and latest generation 3D seismic survey (Topseis) over the entire Alta and Gohta area is under evaluation. The contingent resources for the Alta and Gohta discoveries are therefore unchanged from year-end 2017 and will be updated during 2019 when the future appraisal plans for the area is defi ned and all the additional data has been processed.
Lundin Petroleum's sustainability approach is to develop and produce oil and gas resources efficiently and responsibly.
Responsible conduct and business success go hand in hand. Our business model rests on our commitment to carry out our activities in an effi cient and responsible manner for the longterm benefi t of shareholders and society.
In line with this commitment, a thorough review of our Code of Conduct was completed in 2018 to ensure that the core principles governing our responsible business conduct fully refl ect our operational context. The Code of Conduct provides guidance to all employees, contractors and partners on how to conduct activities in an economically, socially and environmentally responsible way. To highlight and emphasise the importance of these guiding principles and everyone's commitment to abide by them, a ceremony attended by the Board's CR/HSE Committee, management and employees was held to sign the updated Code of Conduct. New policies were also adopted in the areas of diversity, security (relating to the General Data Protection Regulation, GDPR) and transparent tax reporting to better refl ect current practice in relation to these important areas. The e-learning tool was further revised to ensure that all employees are familiar with these governing documents and the new formal requirements.
Improving energy effi ciency and reducing carbon emissions remain a core focus for Lundin Petroleum and we can again report one of the lowest carbon emission intensity levels in the industry. We also intensifi ed our engagement to address climate change with key stakeholders, through support to
research and development, sharing of best practice within the industry and by participating in the global dialogue.
In line with our commitment to actively support the Sustainable Development Goals (the SDGs), we joined a campaign initiated by the UN, in collaboration with Reuters and The Business Debate. The initiative aims to promote how global businesses and organisations work to achieve economic development in an environmentally sustainable manner. Climate change requires unprecedented action and collaboration between various societal actors and through this initiative, we had the opportunity to illustrate how our Company can contribute to achieving the SDG goals. We do this by providing society with affordable energy while addressing the climate change challenge through our industry leading work in developing and producing oil and gas resources effi ciently and responsibly with a low carbon footprint.
Read more about Lundin Petroleum's management and performance approach on environmental, social and governance issues in our 2018 Sustainability Report, available on www.lundin-petroleum.com.
The Sustainability Report provides comprehensive information on how Lundin Petroleum integrates sustainability issues into its business model to create longterm sustainable value for all stakeholders. The Sustainability Report conforms to the new Global Reporting Initiative (GRI) standards and constitutes our disclosure on non-fi nancial reporting required under Swedish law implementing the EU Directive 2014/95/EU. It also constitutes our Communication on Progress (COP) to the UN Global Compact.
The Sustainability Report is a tool for stakeholders to assess our sustainability approach and performance and we welcome this engagement as a means to improve how we address key sustainability issues within the industry.
Our commitment to safe and responsible practices and low carbon operations is fundamental to delivering on our business model to create long-term sustainable value.
Christine Batruch Vice President Corporate Responsibility
Our people are our key asset and reducing health and safety risks throughout our operations is our highest priority. We continue to foster an open culture to learn from incidents and improve how we address health and safety concerns. Our highly skilled workforce actively assess potential risks and contributes to develop and implement mitigation strategies. Our emergency preparedness is tested on a regular basis to ensure full readiness in the event of an incident. Together these measures help to ensure that we provide a safe working environment and protect the environment wherever we operate.
Our robust health and safety culture is refl ected in our 2018 performance as there were no serious personal injuries or process safety incidents during the year. The Lost Time Incident Rate (LTIR) was 0.5 per million hours worked and the Total Recordable Incident Rate (TRIR) was 1.0 per million hours worked. There were no material incidents with impact on the environment.
Lundin Petroleum operates with one of the lowest carbon emissions intensity levels in the industry. Work to further reduce carbon emissions from our operations continued in 2018 and reduction targets were achieved. The carbon emission level from the operated Edvard Grieg platform was 4.9 kg CO2 equivalent per barrel in 2018.
Lundin Petroleum supports the commitments set out in the Paris Agreement to address global climate change and actively participates in industry initiatives that aim to reduce carbon emissions, such as the Norwegian oil and gas roadmap for 2030 and 2050.
A standardised risk management methodology is used to perform quantitative and qualitative risk assessments to prioritise control activities and enable the Company to deal effectively with both potential opportunities and threats.
The majority of production comes from the Edvard Grieg fi eld and the Alvheim area. This concentration of operations increases the vulnerability for long-term production shutdowns.
Highly skilled and experienced operational teams are employed throughout the organisation and critical spares are held in inventory. Insurance covering the fi nancial liquidity impact from a loss of production is subscribed for the Edvard Grieg fi eld, reducing the fi nancial impact of any unexpected long-term shutdowns.
Delay in delivery of development projects due to safety incidents, installation schedules or missed targets. The risk of cost overruns and a delay in production that could affect liquidity.
Lundin Petroleum has a proven track record of safe work systems and successfully delivering development projects. The large Johan Sverdrup project is progressing ahead of schedule and has achieved signifi cant cost savings compared to original estimates.
Operational incidents such as a signifi cant fi re, process safety, major accidents involving impact on people and the environment, collision or well control issues are a signifi cant risk within the oil and gas industry.
Lundin Petroleum has a strong HSEQ (Health, Safety, Environmental and Quality) management system to reduce the risk of such incidents, which is subject to incident investigations and audits. The Company maintains a robust HSE culture throughout the organisation to ensure safety and security for people and the environment. i
Uncertainty in estimates of economically recoverable reserves and inability to bring estimates into resources and reserves.
Reserves and resource evaluations are performed according to international industry standards and undergo a comprehensive internal peer review in addition to an annual reserves audit process by an external independent reserves auditor.
Security risks are of serious concern in the oil and gas industry and range from personnel security to attacks on physical assets, including information data loss and system intrusions.
Security risks are regularly monitored and audited. The risk level in Norway is assessed as low but high levels of awareness are nonetheless maintained. Business continuity plans are in place, networks are monitored to prevent and remedy any external attacks and training on cyber risk awareness is being implemented.
This summary gives an overview of Lundin Petroleum's risk universe, however other risks may also exist or arise.
More information on how Lundin Petroleum works to address risks related to maintaining a sustainable and ethical business can be found in the Sustainability Report.
Incorrect fi nancial estimates of future decommissioning costs for fi elds at the end of the economic life cycle could lead to fi nancial and tax impact, liability and other implications of abandonment and reclamation.
Decommissioning cost estimates are reviewed on an annual basis throughout an asset's life cycle, including in the development phase, according to the Company's policy on asset retirement liability.
Delayed or inaccurate fi nancial reporting impacting external reporting requirements. Risk of regulatory action, shareholder law suits and loss of investor confi dence.
Lundin Petroleum maintains robust internal controls and reporting processes to mitigate this risk. Financial reporting is subject to internal controls, a monthly management reporting process and is verifi ed by internal and external audits.
As a result of the Company carrying debt, a rise in interest rates carries a risk of impacting the Company's earnings and free cash fl ow potential. A foreign exchange risk exists in relation to market fl uctuations of foreign currencies, given that the underlying value of the Company's assets is predominantly USD denominated whilst certain costs are denominated in other currencies.
The exposure to interest rate and currency risk is continuously assessed and monitored. Hedging instruments are used to manage this risk, which is also subject to robust internal controls.
Investments and costs overrunning budgets or production underperformance leading to the Company being unable to fund its fi nancial commitments from cash fl ow, debt or equity.
Lundin Petroleum strives to maintain a good asset management strategy to ensure continued asset integrity to maximise cash fl ow and borrowing capacity. Access to debt capital markets is achieved through a proactive banking relationship strategy to ensure optimal debt availability. Access to the equity capital markets is achieved through an active investor relations strategy.
Volatility in the oil price could affect fi nancial earnings, cash fl ow generation and the overall investment and liquidity position.
Lundin Petroleum updates the asset business plan regularly throughout the year, a process that includes stress testing the business for a prolonged period of lower oil prices. If such a scenario demonstrates a liquidity shortfall, the Company will consider a number of options including reducing investment levels, raising additional debt or entering into oil price hedging.
Negative perception of the oil and gas industry, leading to the risk of reduced access to licences. Failure to adapt to climate legislation.
Lundin Petroleum operates with one of the lowest carbon emissions intensities in the industry and in a country with worldleading environmental governance. Carbon footprint and energy effi ciency of operations are reviewed on an ongoing basis and greenhouse gas emissions are disclosed regularly.
Risk of non-compliance with ethical business practices, fraud, bribery and corruption. Non-compliance could lead to investigations and litigation and loss of legal or social licence to operate.
Lundin Petroleum operates according to the highest level of ethical standards, ensured through the consistent application of its Code of Conduct and policies and procedures. Internal awareness training is conducted to communicate expectations of ethical business conduct to staff and reference to the Code of Conduct is integrated into business supplier contracts.
Breach of applicable laws and regulations or complexity and changes to regulation that could negatively affect the Company. May lead to investigations, litigation, negative fi nancial impact, reputational damage and cancellation or modifi cation of contractual rights.
Lundin Petroleum adheres to applicable laws and regulations and has a robust corporate governance framework in place to ensure it acts in accordance with good oilfi eld practice and high standards of corporate citizenship. Lundin Petroleum operates in Norway, a country with a world-leading regulatory framework for oil and gas activities.
Reputational risk and potential loss of stakeholder and investor confi dence through potential criminal trial and fi nancial penalties in relation to the preliminary investigation in Sweden into the Company's past operations in Sudan during 1997–2003.
Lundin Petroleum is actively defending its interests through the Swedish legal process and maintains a transparent and effective engagement with its various stakeholders to ensure an open and informed dialogue. More information on the preliminary investigation led by the Swedish Prosecution Authority can be found on page 34.
Inability to meet stakeholder expectations and create shareholder value either through current business strategy or due to market conditions. Failure to sustain the organic growth strategy.
Lundin Petroleum creates sustainable shareholder value by investing in an active organic growth strategy in Norway, supported by excellent resource potential, highly skilled employees as well as attractive fi scal terms for a full cycle strategy.
| Guiding principles | 22 |
|---|---|
| Shareholders' meetings | 25 |
| External auditors of the Company | 25 |
| Nomination Committee | 26 |
| Board of Directors | 27 |
| Board committees | 30 |
| Group management | 33 |
| Policy on Remuneration | 35 |
| Internal control over fi nancial reporting | 38 |
| Auditor's report | 39 |
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 Swedish Corporate Governance Code and has been subject to a review by the Company's statutory auditor.
Lundin Petroleum reports one deviation from the Corporate Governance Code in 2018 in respect of the composition of the Nomination Committee as further described on page 26. 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.
The 2019 Annual General Meeting (AGM) will be held on 29 March 2019 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 Saturday 23 March 2019 (please note that since the record date is on a Saturday, shareholders must be registered in the share register on Friday 22 March 2019, at the latest) and must notify the Company of their intention to attend the AGM no later than 25 March 2019.
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 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.
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. Lundin Petroleum's business is to explore for, develop and produce oil and gas. 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. Lundin Petroleum's principles of corporate governance 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. Abiding to corporate governance principles builds trust in Lundin Petroleum, which results in increased shareholder value. By ensuring the business is conducted in a responsible manner, the corporate governance structure ultimately paves the way to increased effi ciency.
Our corporate governance structure ensures safe, responsible and efficient operations and is fundamental to our past and future operational success.
Ian H. Lundin Chairman of the Board
"
Highlights 2018
Main external rules and regulations for corporate governance at Lundin Petroleum
Main internal rules and regulations for corporate governance at Lundin Petroleum
A new CR/HSE Committee was established building on the work of the previous CR/HSE Board representative.
The AGM resolved to declare an inaugural cash dividend of SEK 4.00 per share.
Adoption of an updated Code of Conduct to better refl ect the operating context of the Company.
The Corporate Governance Code is based on the tradition of self- regulation and the principle of "comply or explain". It 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 Corporate Governance Code can be found on www.bolagsstyrning.se.
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. An updated Code of Conduct was issued in 2018 to better refl ect the operating context of the Company. The Code of Conduct is available on the Company's website.
Corporate policies, procedures and guidelines have been developed to outline specifi c rules and controls, to increase effi ciency and improve performance by facilitating compliance. They 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. During 2018, new corporate policies adopted include a Diversity Policy, Security Policy, Market Risk Policy and Tax Policy. All policies, procedures and guidelines are continuously reviewed and updated as and when required and have been integrated into local management systems.
In 2018 Lundin Petroleum adopted 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 the
highest standards. The Charter sets out four core foundation themes: leadership, risk and opportunity management, continuous improvement and implementation and is applicable across the organisation. It further details how these themes are to be operationalised.
CR and HSE related policies are available on the Company's website.
The Rules of Procedure of the Board contain the fundamental rules regarding the division of duties between the Board, the Committees, the Chairman of the Board and the Chief Executive 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 reviewed and approved annually by the Board.
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 Annual General Meetings (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 2018, the Company purchased 640,000 own shares at an average purchase price of SEK 186.77 and held as per 31 December 2018 1,873,310 own shares in total.
Lundin Petroleum had at the end of 2018 a total of 28,801 shareholders listed with Euroclear Sweden, which represents a decrease of 690 compared to the end of 2017, i.e. a decrease of approximately two percent. Shares in free fl oat amounted to 51.8 percent and exclude shares held by an entity associated with the Lundin family and by Equinor.
| The 10 largest shareholders as at 31 December 2018 |
Number of shares |
Percent (rounded) |
|---|---|---|
| Nemesia1 | 95,478,606 | 28.1 |
| Equinor | 68,417,676 | 20.1 |
| Vanguard | 6,959,519 | 2.0 |
| JP Morgan Asset Management | 5,741,518 | 1.7 |
| BlackRock | 5,733,873 | 1.7 |
| USS Investment Management | 4,950,000 | 1.5 |
| Norges Bank | 4,102,761 | 1.2 |
| State Street Global Advisors | 4,058,739 | 1.2 |
| Credit Suisse | 4,047,202 | 1.2 |
| Nordea Fonder | 3,500,205 | 1.0 |
| Other shareholders | 137,396,346 | 40.4 |
| Total | 340,386,445 | 100 |
An investment company wholly owned by a Lundin family trust. Source: Q4 Inc.
1
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. 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 and all proceedings are simultaneously translated from Swedish to English and from English to Swedish.
The 2018 AGM was held on 3 May 2018 at Grand Hôtel in Stockholm. The AGM was attended by 801 shareholders, personally or by proxy, representing 68.91 percent of the share capital. The Chairman of the Board, all Board members including the CEO were present, as well as the Company's auditor and the majority of the members of the Nomination Committee for the 2018 AGM. The members of the Nomination Committee for the 2018 AGM were Hans Ek (SEB Investment Management AB), Filippa Gerstädt (Nordea Funds), Åsa Nisell (Swedbank Robur Fonder) and Ian H. Lundin (Nemesia S.à.r.l., and Landor Participations Inc., as well as non-executive Chairman of the Board of Lundin Petroleum).
The resolutions passed by the 2018 AGM include:
members, except for the Chief Executive Offi cer, and SEK 165,000 to each Committee Chair and SEK 110,000 to other Committee members and SEK 165,000 to the CR/HSE Board representative with the total fees for Committee work, including fees for the Committee Chairs and CR/HSE Board representative fees, not to exceed SEK 1,155,000.
An electronic system with voting devices was used for the two last items requiring a qualifi ed majority. The minutes of the 2018 AGM and all AGM materials, in Swedish and English, are available on the Company's website, together with the CEO's address to the AGM.
Lundin Petroleum's statutory auditor audits annually the Company's 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.
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 expectation is to create shareholder returns both through share price appreciation and by distributing a sustainable yearly dividend - paid in quarterly instalments and denominated in USD - with the plan of maintaining or increasing the dividend over time in line with the Company's fi nancial performance and being sustainable below an oil price of USD 50 per barrel. The dividend shall be sustainable in the context of allowing the Company to continue to pursue its organic growth strategy and to develop its contingent resources whilst maintaining a conservative gearing ratio and retaining an appropriate liquidity position within its available credit lines.
| Nomination Committee for the 2019 AGM | |||||||
|---|---|---|---|---|---|---|---|
| Member | Appointed by | Meeting attendance |
Shares represented as at 1 Aug 2018 |
Shares represented as at 31 Dec 2018 |
Independent of the Company and Group management |
Independent of the Company's major shareholders |
|
| Hans Ek | SEB Investment Management AB |
3/3 | 0.6 percent | 0.5 percent | Yes | Yes | |
| Filippa Gerstädt | Nordea Funds | 3/3 | 1.0 percent | 1.0 percent | Yes | Yes | |
| Åsa Nisell | Swedbank Robur Fonder |
2/21 | 1.3 percent | 0.5 percent | Yes | Yes | |
| Ian H. Lundin | Nemesia S.à.r.l and non-executive Chairman of the Board of Lundin Petroleum |
3/3 | 27.7 percent | 28.1 percent | Yes | No2 | |
| Total 30.6 percent Total 30.0 | percent (rounded) |
1 Åsa Nisell was a member of the Nomination Committee until 9 January 2019 but stepped down as a result of Swedbank Robur Fonder no longer being a larger shareholder of the Company.
2 For details, see schedule on pages 28–29.
The Company's external auditor is the registered accounting fi rm PricewaterhouseCoopers AB, which was fi rst elected as the Company's statutory auditor in 2001. The auditor's fees are described in the notes to the fi nancial statements, see Note 30 on page 88 and Note 7 on page 93. 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 8–15.
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 2019 AGM were announced and posted on the Company's website on 3 September 2018. Equinor ASA was invited to join but declined the invitation.
Ian H. Lundin was unanimously elected as Chairman of the Nomination Committee. The fact that he is the Chairman of the Nomination Committee and Chairman of Lundin Petroleum constitutes a deviation from rule 2.4 in the Corporate Governance Code, however this deviation was considered justifi ed as Ian H. Lundin represents the major shareholder of the Company.
The Nomination Committee has held three 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.
Summary of the Nomination Committee's work during their mandate:
The full Nomination Committee report, including the fi nal proposals to the 2019 AGM, is available on the Company's website.
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 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. There are no deputy members and no members appointed by employee organisations. In addition, the Board is supported by a corporate secretary, the Company's Vice President Legal Henrika Frykman, who is not a Board member.
The Nomination Committee for the 2018 AGM considered that a Board size of nine members would be appropriate taking into account the nature, size, complexity and geographical scope of the Company's business. The Nomination Committee considered that the Board as proposed and elected by the 2018 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 specifi cally Norway, being Lundin Petroleum's core area of operation, public company fi nancial matters, Swedish practice and compliance matters and CR/HSE matters. The Nomination Committee considered that the proposed Board fulfi lled 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 33 percent of the proposed Board members were women. The Company aims to promote diversity at all levels of the Company, and the Nomination Committee applies the diversity requirements of the Corporate Governance Code. The recommendation of the Swedish Corporate Governance Board is that larger listed Swedish companies should strive to achieve 35 percent female Board representation by 2018, which had been achieved by the Company during 2015–2018. Whilst the percentage of women on the proposed Board was slightly lower than in the past, the Nomination Committee considered that the experience of the Board members, and in particular the signifi cant Norwegian experience of the new proposed Board member Torstein Sanness, outweighed the slight decline. The Nomination Committee supports the ambition of the Swedish Corporate Governance Board regarding levels and timing of achieving gender balance and believes that it is important to continue to strive for gender balance when future changes in the composition of the Board are considered.
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 decisionmaking 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.
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 October 2018, the Board visited the Lundin Petroleum operated Edvard Grieg platform in the Norwegian Sea and the Kvaerner Yard at Stord where Johan Sverdrup accomodation platform topsides were being built, and an executive session with Group management was held in connection with the Board meeting. Group management also attended 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.
| Board of Directors: | Ian H. Lundin | Alex Schneiter | Peggy Bruzelius | C. Ashley Heppenstall |
|---|---|---|---|---|
| Function | Chairman (since 2002), member of the Compensation Committee |
President & Chief Executive Offi cer, Director |
Director, Chair of the Audit Committee |
Director, member of the Audit Committee |
| Elected | 2001 | 2016 | 2013 | 2001 |
| Born | 1960 | 1962 | 1949 | 1962 |
| Education | B.Sc. Petroleum Engineering from the University of Tulsa. |
M.Sc. Geophysics and degree in Geology from the University of Geneva. |
M.Sc. Economics and Business from the Stockholm School of Economics. |
B.Sc. Mathematics from the University of Durham. |
| Experience | CEO of International Petroleum Corp. 1989– 1998. CEO of Lundin Oil AB 1998–2001. CEO of Lundin Petroleum 2001–2002. |
Various positions within Lundin related companies since 1993. COO of Lundin Petroleum 2001–2015. CEO of Lundin Petroleum since 2015. |
Managing Director of ABB Financial Services AB 1991- 1997. Head of the asset management division of Skandinaviska Enskilda Banken AB 1997-1998. |
Various positions within Lundin related companies since 1993. CFO of Lundin Oil AB 1998–2001. CFO of Lundin Petroleum 2001–2002. CEO of Lundin Petroleum 2002–2015. |
| Other board duties | Member of the board of Etrion Corporation and Bukowski Auktioner AB. |
– | Chair of the board of Lancelot Asset Management AB, member of the board of Akzo Nobel NV and Skandia Liv. |
Chairman of the board of Africa Energy Corp. and member of the board of Lundin Gold Inc., Filo Mining Corp. and International Petroleum Corp. |
| Shares as at 31 December 2018 |
Nil2 | 208,000 | 8,000 | Nil4 |
|---|---|---|---|---|
| Attendance | ||||
| Board | 9/9 | 9/9 | 9/9 | 9/9 |
| Audit Committee | – | – | 6/6 | 6/6 |
| Compensation Committee | 5/5 | – | – | – |
| CR/HSE Committee | – | – | – | – |
| Remuneration1 | ||||
| Board and Committee work | SEK 1,210,000 | Nil | SEK 690,000 | SEK 635,000 |
| Special assignments outside the directorship |
SEK 1,000,000 | Nil | Nil | SEK 5,328,000 |
| Independent of the Company and Group management |
Yes | No3 | Yes | No4 |
| Independent of major shareholders |
No2 | Yes | Yes | No4 |
1 See also note 28 on pages 84–85.
2 Ian H. Lundin is in the Nomination Committee's and the Company's opinion not deemed independent of the Company's major shareholder as Ian H. Lundin is a member of the Lundin family that holds, through a family trust, Nemesia S.à.r.l., which holds 95,478,606 shares in the Company.
3 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.
| Lukas H. Lundin | Grace Reksten Skaugen | Torstein Sanness | Jakob Thomasen | Cecilia Vieweg |
|---|---|---|---|---|
| Director | Director, Chair of the CR/ HSE Committee, member of the Compensation Committee |
Director, member of the CR/HSE Committee |
Director, member of the Audit Committee and the CR/HSE Committee |
Director, Chair of the Compensation Committee |
| 2001 | 2015 | 2018 | 2017 | 2013 |
| 1958 | 1953 | 1947 | 1962 | 1955 |
| Graduate from the New Mexico Institute of Mining, Technology and Engineering. |
M.Ba. from the BI Norwegian School of Management, B.Sc. Honours Physics and Doctoreate laser physics from Imperial College of Science and Technology at the University of London. |
M.Sc. Engineering in geology, geophysics and mining engineering from the Norwegian Institute of Technology in Trondheim. |
Graduate of the University of Copenhagen, Denmark, M.Sc. in Geoscience and completed the Advanced Strategic Management programme at IMD, Switzerland. |
L.L.M. from the University of Lund. |
| Various key positions within companies where the Lundin family has a major shareholding. |
Former Director of Corporate Finance with SEB Enskilda Securities in Oslo. Board member/deputy chair of Statoil ASA 2002 –2015. Member of HSBC European Senior Advisory Council. |
Managing Director of Lundin Norway AS 2004–2015. Managing Director of Det Norske Oljeselskap AS 2000–2004. Various positions in Saga Petroleum 1972–2000. |
Former CEO of Maersk Oil and a member of the Executive Board of the Maersk Group 2009 - 2016. |
General Counsel and member of the Executive Management of AB Electrolux 1999–2016. Senior positions in AB Volvo Group 1990-1998. Lawyer in private practice. |
| Chairman of the board of Lundin Mining 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. |
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 board of Magnora ASA and member of the board of International Petroleum Corp., Panoro Energy ASA and TGS Nopec ASA. |
Chairman of the DHI Group, ESVAGT and Falck Safety Services and member of the board of University of Copenhagen. |
– |
| 788,3315 | 5,000 | 93,310 | 8,820 | 3,500 |
| 9/9 | 9/9 | 6/66 | 9/9 | 9/9 |
| – | – | – | 6/6 | – |
| – – |
5/5 2/2 |
– 2/2 |
– 2/2 |
5/5 – |
| SEK 525,000 | SEK 717,500 | SEK 317,500 | SEK 690,000 | SEK 690,000 |
4 C. Ashley Heppenstall holds 1,542,618 shares in Lundin Petroleum AB through an investment company, Rojafi . 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.
Nil Nil Nil Nil Nil
Yes Yes No6 Yes Yes
No5 Yes Yes Yes Yes
5 Lukas H. Lundin is in the Nomination Committee's and the Company's opinion not deemed independent of the Company's major shareholder as Lukas H. Lundin is a member of the Lundin family that holds, through a family trust, Nemesia S.à.r.l., which holds 95,478,606 shares in the Company.
6 Torstein Sanness is a member of the Board of Directors as of 3 May 2018. Torstein Sanness is in the Nomination Committee's and the Company's opinion not deemed independent of the Company and Group management since he was the Managing Director of Lundin Norway AS, a subsidiary of the Company, until 2015.
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, an Audit Committee and in 2018, a new CR/HSE Committee. Considering the importance of CR/ HSE matters for the Company, the Board considered it was suitable to establish a full Board Committee to replace and build on the previous work of the 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. Terms of reference were adopted in 2018 also for the CR/HSE Committee. 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. 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 35–37.
Compensation Committee work during 2018:
· 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.
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 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 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.
Audit Committee work during 2018:
· Consideration of the performance review of Group management and Compensation Committee remuneration proposals
· Approval of the year end report
· Adoption of the half year report, reviewed by the statutory auditor
· Audit Committee report regarding the first quarter report · Annual CR/HSE management report and performance
Nine board meetings were held in 2018 and 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.
The CR/HSE Committee assists the Board to monitor the performance and key risks that the Company faces in relation to corporate responsibility and health, safety and environmental matters. The CR/HSE Committee's responsability is to oversee the Company's conduct and performance on CR/HSE matters, to inform the Board and make whatever recommendations to the Board it deems appropriate on any area within its remit where action or improvement is needed. The CR/HSE Committee's tasks further include reviewing and monitoring CR/HSE policies and the effectiveness of CR compliance, as well as considering CR issues, risks, strategies and responses to climate change issues. The CR/HSE Committee reviews Group management's proposals on HSE targets and goals, monitors the appropriateness of HSEQ audit strategies and plans, the execution and results of such plans and reviews and makes recommendations to the Board in relation to the Company's sustainability report. More information about the Company's CR/HSE activities can be found in the Responsibility section on pages 16–17 and in the Sustainability Report available on the Company's website.
CR/HSE Committee work during 2018:
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 28–29 and in the notes to the fi nancial statements, see Note 28 on pages 84–85.
A formal review of the work of the Board was conducted in September 2018 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 improve 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 and 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 there was room for additional directors, whilst a too large composition could make the Board less effi cient. The Board members considered that their knowledge of the Company and the oil and gas industry in general had increased during the year and that Board members are well prepared for the meetings. The need for a retirement policy was considered, however, the Board acknowledged that there was already a natural process of renewing the Board as the Company adapts to the new environment. Visits to operational locations were appreciated and considered very useful for the understanding of the business. Committee work was believed to function well, with well appreciated Committee Chairs, and the composition of the Committees in general was deemed appropriate. Individual feedback received noted that management reports were excellent and that Board meetings were well prepared. 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
President and Chief Executive Offi cer
Vice President Corporate Affairs Alex Budden
Chief Operating Offi cer
Vice President Legal Henrika Frykman
Chief Financial Offi cer
Sean Reddy
Vice President Human Resources and Shared Services
Vice President Corporate Responsibility
Vice President Investor Relations
Lundin Petroleum's Group and local management consists of highly experienced individuals with extensive worldwide oil and gas experience. 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.
The Company's Investment Committee consists of, in addition to the CEO, the Chief Operating Offi ce (COO), Nick Walker, who is responsible for Lundin Petroleum's exploration, development and production operations and HSE, and the Chief Financial Offi cer (CFO), Teitur Poulsen, who is responsible for the fi nancial reporting, internal control, risk management, treasury function and economics. The Investment Committee 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.
In addition to the members of the Investment Committee, Lundin Petroleum's Group management comprises:
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 Corporate Governance Code. 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 and the HSEQ Leadership Charter 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 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, 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 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.
In 2010, the Swedish Prosecution Authority began a preliminary investigation into alleged complicity in violations of international humanitarian law in Sudan during 1997– 2003. The Company has cooperated extensively and proactively with the investigation by providing information regarding its operations in Block 5A in Sudan during the relevant time period and strongly believes that it was a force for development in Sudan. Ian H. Lundin and Alex Schneiter have been interviewed by the Swedish Prosecution Authority and have been notifi ed of the suspicions that are the basis for the investigation. In 2018, the Company was notifi ed by the Swedish Prosecution Authority that the Company may be liable to a corporate fi ne of SEK 3 million and forfeiture of economic benefi ts from the alleged offense in the amount of SEK 3,282 million, based on the profi t of the sale of the Block 5A asset in 2003 of SEK 720 million. Any potential corporate fi ne or forfeiture could only be imposed after the conclusion of a trial, should one occur.
In 2018, the Swedish Prosecution Authority began a preliminary investigation into alleged interference in a judicial matter as a result of allegations of witness harassment. The Company and its representatives are not aware of any details of the alleged actions, despite several requests for details thereof, and reject any knowledge of, or involvement in, any wrongdoing. Ian H. Lundin and Alex Schneiter have been interviewed by the Swedish Prosecution Authority and have been notifi ed of the suspicions that are the basis for the investigation.
Neither investigation entails that charges have been, or will be, brought against any individuals or the Company. Lundin Petroleum remains convinced that there are absolutely no grounds for any allegations of wrongdoing by the Company or any Company representatives in respect of any of these allegations. More information regarding the past operations in Sudan during 1997–2003 can be found on www.lundinhistoryinsudan.com.
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 remuneration; (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 remuneration and long-term incentives are set at the median level, however, in the event of exceptional performance, deviations may be authorised. As the Group continuously competes with the peer group to retain and attract the very best talent in the market, both at operational and executive level, it is considered important that the Group's compensation packages are determined primarily by reference to the remuneration practices within this peer group.
The remuneration of Group management follows the principles that are applicable to all employees, however, these principles must be approved by the shareholders at the AGM. The Compensation Committee therefore prepares yearly for approval by the Board and for submission for 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 remuneration 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, HSE, CR 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 remuneration 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 2018 AGM resolved to approve a performance based LTIP 2018, that follows the same principles as the previously approved LTIPs 2014–2017, 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 2018 and expiring on 30 June 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 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 2018 and the total LTIP award made in respect of 2018 was 278,917.
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 2018, 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 2018 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 2018, 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 members of Group management. Neither the CEO nor other members of 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.
For information regarding the Board's proposal for remuneration to Group management to the 2019 AGM, including a new LTIP, see the Directors' report, pages 50–51.
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. Group Management is expected to be comprised of seven executives in 2018.
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 of Directors' and the Annual General Meeting's decisions on matters relating to the principles of remuneration, remunerations and other terms of employment of Group Management. The Compensation Committee meets regularly and its tasks include monitoring and evaluating programmes for variable remuneration for Group Management and the application of this Policy on Remuneration, as well as the current remuneration structures and levels in the Company.
The Compensation Committee may request the advice and assistance of external reward consultants, however, it shall ensure that there is no 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: a) base salary; b) yearly variable salary; c) long-term incentive plan; and d) other benefi ts.
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 long-term value creation for the Company's shareholders.
The yearly variable salary shall, in the normal course of business, be based upon a predetermined limit, being within the range of one to twelve monthly salaries (if any). The cost of yearly variable salary for 2018 is estimated to range between no payout at minimum level and MSEK 22.1 (excluding social costs) at maximum level, based on the current composition of Group Management. However, the Compensation Committee may recommend to the Board of Directors for approval yearly variable salary outside of this range in circumstances or in respect of performance, which the Compensation Committee considers to be exceptional.
The Company believes that it is appropriate to structure its long-term incentive plans (LTIP) to align Group Management's incentives with shareholder interests. Remuneration which is linked to the share price results in a greater personal commitment to the Company. Therefore, the Board believes that the Company's LTIP for Group Management should be related to the Company's share price.
Information on the principal conditions of the proposed 2018 LTIP for Group Management, which follows the same principles as the LTIP approved by the 2014 - 2017 Annual General Meetings, is available as part of the documentation for the Annual General Meeting on www.lundin-petroleum.com.
The cost at grant of the proposed 2018 LTIP is estimated to range between no cost at minimum level and MSEK 48.7 (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 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.
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 of Directors is authorised to deviate from the Policy on Remuneration in accordance with Chapter 8, Section 53 of the Swedish Companies Act in case of special circumstances in a specifi c case.
Remunerations outstanding to Group Management comprise awards granted under the Company's previous LTIP programs and include 203,553 LTIP Awards under the 2015 Performance Based Incentive Plan, 242,057 LTIP Awards under the 2016 Performance Based Incentive Plan, 258,619 LTIP Awards under the 2017 Performance Based Incentive Plan, 1,700 unit bonus awards under the 2015 Unit Bonus Plan, 4,662 unit bonus awards under the 2016 Unit Bonus Plan, 4,119 unit bonus awards under the 2017 Unit Bonus Plan. Further information about these plans is available in note 29 of the Company's Annual Report 2017.
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 Corporate Governance Code, 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 is located in 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 determining 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 licence 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, 1 March 2019
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 2018 on pages 22–38 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, 4 March 2019
PricewaterhouseCoopers AB
Johan Rippe Johan Malmqvist Authorised Public Accountant Authorised Public Accountant Lead Partner
The strong free cash flow outlook for the next decade has resulted in us implementing an attractive and sustainable new dividend policy
Teitur Poulsen Chief Financial Officer
2018 has been a milestone year for Lundin Petroleum with our high quality asset base generating record high operating cash flow and EBITDA, with free cash flow of MUSD 663.
"
This fi nancial performance has enabled signifi cant debt repayment, with a year-end 2018 net debt to EBITDA ratio of less than 1.8 times. The Company's fi nancial strength has improved markedly over the last two years and with a healthy outlook of continued free cash fl ow generation, the Company's fi nancial position has allowed for a signifi cantly increased dividend for 2018 of MUSD 500 and the Company is well positioned to grow this dividend over time, even at low oil prices.
| Financial summary | 2018 | 2017 |
|---|---|---|
| Production in Mboepd | 81.1 | 86.1 |
| Revenue and other income in MUSD | 2,617.4 | 1,997.0 |
| Operating cash flow in MUSD | 1,847.8 | 1,530.0 |
| EBITDA in MUSD | 1,916.2 | 1,501.5 |
| Free cash flow in MUSD | 663.0 | 203.7 |
| Net result in MUSD | 222.1 | 380.9 |
| Earnings/share in USD1 | 0.66 | 1.13 |
| Net debt | 3,398.2 | 3,883.6 |
The numbers included in the table above for 2017 are based on continuing operations.
1 Based on net result attributable to shareholders of the Parent Company
| Directors' report | 42 |
|---|---|
| Consolidated income statement | 53 |
| Consolidated statement of comprehensive income | 54 |
| Consolidated balance sheet | 55 |
| Consolidated statement of cash fl ow | 56 |
| Consolidated statement of changes in equity | 57 |
| Accounting policies | 58 |
| Notes to the fi nancial statements of the Group | 64 |
| - Note 1 – Revenue | 64 |
| - Note 2 – Production costs | 64 |
| - Note 3 – Segment information | 64 |
| - Note 4 – Finance income | 66 |
| - Note 5 – Finance costs | 66 |
| - Note 6 – Share in result of associated company | 66 |
| - Note 7 – Income tax | 66 |
| - Note 8 – Loss from sale of assets | 68 |
| - Note 9 – Discontinued operations | 68 |
| - Note 10 – Oil and gas properties | 69 |
| - Note 11 – Other tangible assets | 71 |
| - Note 12 – Goodwill | 71 |
| - Note 13 – Financial assets | 71 |
| - Note 13.1 – Other shares and participations | 72 |
| - Note 14 – Inventories | 72 |
| - Note 15 – Trade and other receivables | 72 |
| - Note 16 – Cash and cash equivalents | 72 |
| - Note 17 – Equity | 73 |
| - Note 17.1 – Share capital and share premium | 73 |
| - Note 17.2 – Other reserves | 73 |
| - Note 17.3 –Earnings per share | 74 |
| - Note 18 – Financial liabilities | 74 |
| - Note 19 – Provisions | 75 |
| - Note 20 – Trade and other payables | 76 |
| - Note 21 – Financial assets and liabilities | 76 |
| - Note 22 – Changes in liabilities with cash fl ow | |
|---|---|
| movements from fi nancing activities | 78 |
| - Note 23 – Financial risks, sensitivity analysis and | |
| derivative instruments | 78 |
| - Note 24 – Pledged assets | 82 |
| - Note 25 – Contingent liabilities and assets | 82 |
| - Note 26 – Related party transactions | 82 |
| - Note 27 – Average number of employees | 83 |
| - Note 28 – Remuneration to the Board of Directors, | |
| Group management and other employees | 84 |
| - Note 29 – Long-term incentive plans | 86 |
| - Note 30 – Remuneration to the Group's auditors | 88 |
| - Note 31 – Subsequent events | 88 |
| Annual accounts of the Parent Company | 89 |
| Parent Company income statement | 90 |
| Parent Company comprehensive income statement | 90 |
| Parent Company balance sheet | 91 |
| Parent Company statement of cash fl ow | 92 |
| Parent Company statement of changes in equity | 92 |
| Notes to the fi nancial statements of the Parent Company | 93 |
| - Note 1 – Finance income | 93 |
| - Note 2 – Finance costs | 93 |
| - Note 3 – Income taxes | 93 |
| - Note 4 – Other receivables | 93 |
| - Note 5 – Accrued expenses and prepaid income | 93 |
| - Note 6 – Pledged assets, contingent liabilities and assets | 93 |
| - Note 7 – Remuneration to the auditor | 93 |
| - Note 8 – Proposed disposition of unappropriated | |
| earnings | 93 |
| - Note 9 – Shares in subsidiaries | 94 |
| Board assurance | 95 |
| Auditor's report | 96 |
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 Group invested MUSD 12.5 in research and development (R&D) in 2018. The main goal for the R&D is to maximise the value of the existing assets, improve operational preparedness in new areas of operation and developing platforms for future business opportunities. This means improvement of subsurface understanding which benefi ts both exploration and development activities. A large portion of the R&D investments have been used to focus on protection of the natural environment in the southern Barents Sea.
The Parent Company has no foreign branches.
The Morskaya licence in Russia has been relinquished during the year.
On 24 April 2017, Lundin Petroleum completed the spin-off of its assets in Malaysia, France and the Netherlands (the IPC assets) into 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 the completion of the spin-off and are shown as discontinued operations in the comparative periods and are detailed in Note 9.
All the reported numbers and updates in the operational review relate to the fi nancial year ended 31 December 2018 unless otherwise specifi ed.
Lundin Petroleum has 745.4 million barrels of oil equivalent (MMboe) of proved plus probable net reserves and 900.9 MMboe of proved plus probable plus possible net reserves as at 31 December 2018 as certifi ed by an independent third party. Lundin Petroleum also has discovered oil and gas resources which classify as contingent resources and which are not yet classifi ed as reserves. The best estimate contingent resources net to Lundin Petroleum amounted to 225 MMboe as at 31 December 2018. The proved plus probable reserves replacement ratio for 2018 was 163 percent.
Production was 81.1 thousand barrels of oil equivalent per day (Mboepd) (compared to 86.1 Mboepd for 2017) which was at the upper end of the updated guidance for the year of between 78 and 82 Mboepd and 4 percent above the mid-point of the original production guidance of between 74 and 82 Mboepd. This performance is due to strong facilities and reservoir performance at both the Edvard Grieg fi eld and the Alvheim area. The 2019 production guidance is between 75 and 95 Mboepd.
Operating cost, including netting off tariff income, was USD 3.66 per barrel which was below the revised full year guidance of less than USD 3.80 per barrel and 12 percent below the original guidance of USD 4.15 per barrel. This performance is due to a combination of reduced costs, increased production volumes and the termination of production from the Brynhild fi eld during the year. The 2019 operating cost guidance, including netting off tarriff income, is USD 4.25 per barrel.
| Production in Mboepd | 2018 | 2017 |
|---|---|---|
| Norway | ||
| Crude oil | 71.9 | 77.6 |
| Gas | 9.2 | 8.5 |
| Total production | 81.1 | 86.1 |
| Production in Mboepd |
WI1 | 2018 | 2017 |
|---|---|---|---|
| Edvard Grieg | 65% | 63.6 | 66.7 |
| Ivar Aasen | 1.385% | 0.9 | 0.7 |
| Alvheim | 15% | 9.3 | 12.4 |
| Volund | 35% | 6.5 | 3.9 |
| Bøyla | 15% | 0.7 | 1.1 |
| Brynhild | 51%2 | 0.0 | 1.2 |
| Gaupe | 40% | 0.1 | 0.2 |
| Quantity in Mboepd | 81.1 | 86.1 |
1 Lundin Petroleum's working interest (WI)
2 WI 90% up to 30 November 2017 Production from the Edvard Grieg fi eld was above forecast, supported by continued strong production effi ciency at 98 percent. The PDO development drilling programme was completed in the middle of the year with all development well results in line with or better than prognosis and the overall drilling programme was completed below budget. Edvard Grieg reservoir performance continues to exceed expectations with signifi cantly slower build-up of water production than anticipated, leading to around a six month extension of plateau production to mid-2020. The 4D seismic survey that has been acquired over the Edvard Grieg fi eld as part of the reservoir monitoring programme, indicates that the water injection fl ood front is further away from the main production wells than predicted by the current reservoir models. This information is still under review and has not been incorporated into the reservoir models used to support the year end 2018 reserves estimate. An infi ll drilling programme is being planned at Edvard Grieg commencing in 2020 and sanction of this project is anticipated during 2019. Operating cost for the Edvard Grieg fi eld, including netting off tariff income, was USD 3.95 per barrel.
Production from the Ivar Aasen fi eld was slightly below forecast. During the second quarter 2018, two new water injection wells were successfully drilled to improve pressure support to the eastern area of the fi eld.
Production from the Alvheim area, consisting of the Alvheim, Volund and the Bøyla fi elds, was slightly ahead of forecast, supported by the strong reservoir performance and continued strong production effi ciency for the Alvheim FPSO of 97 percent. The results of the infi ll well in the Kameleon area of the Alvheim fi eld were in line with expectations and the well was brought on line ahead of schedule during the fourth quarter 2018. Combined with the two infi ll wells in the Boa area of the fi eld, brought on line at the beginning of the year, this largely offsets the natural production decline from the area. Operating cost for the Alvheim area was USD 4.96 per barrel.
For the Brynhild fi eld, the decision has been taken to permanently shut-in production and work on a cessation plan is ongoing, which will be submitted in due course to the authorities for approval. The remaining book value for the fi eld was written off at year end 2017.
Despite no remaining reserves being attributable to the Gaupe fi eld, the fi eld has produced intermittently subject to favourable economic conditions. As it is no longer economic to continue with Gaupe fi eld production, the decision was taken in October 2018 to cease production from the fi eld.
Phase 1 of the Johan Sverdrup project is on schedule with approximately 85 percent completed. With the good progress, the expected schedule for Phase 1 fi rst oil is November 2019.
2018 was a key installation year for Phase 1 of the project and the programme for the year was completed as planned. All of the four steel jackets have now been successfully installed offshore, as well as the topsides for the drilling platform and the riser platform. The power from shore cable has been installed and power supply from shore to the offshore facilities commenced in October 2018. Installation of the oil and gas export pipelines has been completed. Two accommodation units are located offshore and at peak approximately 800 personnel have been working on the hook-up of the installed offshore facilities, which is progressing on schedule.
Of the last two remaining topsides, the process platform topside sailed away from the Samsung Heavy Industries yard in South Korea in December 2018 and arrived at the Kværner Stord yard in Norway in February 2019. Construction of the living quarters topside at the Kværner yard has been completed and both these topsides are on schedule for installation in spring 2019.
Pre-drilling operations were completed signifi cantly ahead of schedule with a total of eight pre-drilled producers and twelve water injectors completed. In December 2018, the drilling platform commenced tie-back operations on the eight predrilled production wells.
The latest capital expenditure estimate for Phase 1 is gross NOK 86 billion (nominal) compared to the Phase 1 PDO estimate in 2015 of gross NOK 123 billion (nominal), representing a saving of over 30 percent, excluding additional foreign exchange rate savings in US dollar terms. The gross production capacity of Phase 1 is estimated at 440 Mbopd.
The Phase 2 PDO was submitted to the Norwegian Ministry of Petroleum and Energy in August 2018, with Phase 2 fi rst oil scheduled in the fourth quarter 2022. Phase 2 involves an additional processing platform bridge linked to the Phase 1 fi eld centre, additional subsea facilities to allow the tie-in of additional wells to access the Avaldsnes, Kvitsøy and Geitungen satellite areas of the fi eld and implementation of full fi eld water alternating gas injection (WAG) for enhanced recovery. 28 new wells are planned to be drilled in connection with the Phase 2 development. These additional facilities will take the gross plateau production capacity to 660 Mbopd. With the inclusion of WAG, the gross resource range has been further increased to between 2.2 and 3.2 billion boe.
The Phase 2 capital expenditure is estimated at gross NOK 41 billion (nominal), which represents over a 50 percent saving from the original estimate in the phase 1 PDO, and is due to a combination of market conditions and optimisation of the Phase 2 facilities. The major topsides contracts and the jacket contract for the Phase 2 facilities have been awarded and detailed engineering is progressing to plan. Full fi eld breakeven oil price is estimated at below 20 USD per barrel.
All four wells in the 2018 appraisal drilling and testing programme were successful. Combined with two new exploration discoveries that were made during 2018, this means that Lundin Petroleum has six potential projects being moved through the appraisal phase. These positive results contributed to increasing the booked contingent resources at year end 2018.
The Luno II appraisal well in PL359 on the Utsira High was successfully completed in March 2018 and encountered a gross oil column of 22 metres in Triassic sandstones with very good reservoir quality, which was signifi cantly better than expected. Following the positive well results, the gross resource range for the Luno II discovery has been increased to between 40 and 100 MMboe. The development concept for Luno II is a subsea tieback to the nearby Edvard Grieg platform. Phase 1 of the Luno II development project is expected to be sanctioned and the PDO submitted in the fi rst quarter of 2019. To create commercial and operational alignment between the Edvard Grieg and Luno II partnerships, Lundin Petroleum has acquired Equinor's 15 percent interest in Luno II, increasing the working interest to 65 percent.
Appraisal drilling and production testing operations on the Rolvsnes basement oil discovery in PL338C in the Utsira High area of the North Sea were completed in August 2018. The horizontal well confi rmed good productivity from fractured and weathered basement reservoirs and achieved a constrained production rate of 7,000 bopd. The successful well and testing operations have led to a substantial increase in gross resources for Rolvsnes to between 14 and 78 MMboe from previously 3 to 16 MMboe. The long-term production behavior from this reservoir needs to be understood better and the next step is to conduct an extended well test via a subsea tie-back of the suspended appraisal well to the Edvard Grieg platform. It is expected that the extended well test will be sanctioned in the fi rst quarter of 2019 and implementation will be in parallel with the Luno II development project. The positive well result at Rolvsnes de-risks the similar on-trend prospectivity on the adjacent PL815 licence where an exploration well will be drilled on the Goddo prospect in 2019. The combined Rolvsnes and Goddo prospective area is estimated to contain gross potential resources of more than 250 MMboe.
| Field | WI | Operator | PDO Approval | Estimated gross reserves |
Production start expected |
Expected gross plateau production |
|---|---|---|---|---|---|---|
| Johan Sverdrup | 22.6% | Equinor | August 2015 | 2.2–3.2 billion boe | November 2019 | 660 Mbopd |
| Licence | Operator | WI | Well | Spud Date | Status |
|---|---|---|---|---|---|
| PL359 | Lundin Norway | 65% | Luno II | February 2018 | Completed March 2018 |
| PL338C | Lundin Norway | 50% | Rolvsnes | April 2018 | Completed August 2018 |
| PL609 | Lundin Norway | 40% | Alta | April 2018 | Completed September 2018 |
| PL203 | Aker BP | 15% | Gekko | September 2018 | Completed October 2018 |
The extended production testing on the Alta discovery in the southern Barents Sea was successfully completed in September 2018. The well was produced over a period of about two months with a maximum production rate of 18,000 bopd constrained by the surface facilities and with a total of approximately 660,000 barrels of oil produced to a tanker. The results were better than expected, demonstrating excellent reservoir productivity and connectivity to a large volume of oil. The large amount of new information from the positive results from the Alta extended production test and latest generation 3D seismic survey (Topseis) over the entire Alta and Gohta area is still being evaluated. The contingent resources for the Alta and Gohta discoveries are therefore unchanged from year end 2017 and will be updated during 2019 when the future appraisal plans for the area is defi ned and all the additional data has been processed.
The Gekko appraisal well located to the southeast of the Alvheim fi eld was successfully completed in October 2018. The objective of the two branch well was to test the potential for improved reservoir quality away from the Gekko discovery well and determine the thickness of the oil column. Both well branches encountered good quality Heimdal sands with an approximately 6 metre oil rim below gas. Following the positive well results, the gross resource range for the Gekko discovery is between 28 and 52 MMboe. Options for the economic development of Gekko are being assessed.
The 2018 exploration drilling programme was impacted by changing rig schedules and priorities, which resulted in a number of wells moving into 2019. Five exploration wells were completed in 2018 resulting in two potential commercial discoveries, Frosk and Lille Prinsen. Exploration and appraisal expenditure in 2018 was MUSD 311.
In February 2018, the Frosk prospect in the North Sea, located northwest of the Bøyla fi eld, 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 predrill estimates and has a positive impact on the assessment of further exploration potential in the area. Two follow-up wells on the Froskelår Main and Rumpetroll prospects in the adjacent PL869 will be drilled in the fi rst half of 2019. The fi rst of these wells, Froskelår Main, was drilled in February 2019 resulting in an oil and gas discovery with resources within the pre-drill estimate of 45 to 153 MMboe gross of which part may straddle the UK-Norwegian boundary in the North Sea. Operations are continuing at Froskelår Main with the drilling of two appraisal sidetracks. Additionally, a production test well on the Frosk discovery, to be tied into the Bøyla subsea facilities, will be drilled in the fi rst half of 2019.
In May 2018, the Svanefjell prospect in PL659 in the southern Barents Sea proved a minor, non-commercial gas discovery.
In June 2018, the Lille Prinsen prospect in the North Sea, located northeast of the Ivar Aasen fi eld, proved an oil discovery. The discovery is estimated to contain gross resources of between 15 and 35 MMboe and with signifi cant appraisal upside potential of over 100 MMboe. It is expected that Lille Prinsen will be economic to develop and an appraisal well is planned for 2019.
| Licence | Operator | WI | Well | Spud Date | Result |
|---|---|---|---|---|---|
| PL340 | Aker BP | 15% | Frosk | January 2018 | Oil discovery |
| PL167 | Equinor | 20% | Lille Prinsen | April 2018 | Oil discovery |
| PL659 | Aker BP | 20% | Svanefjell | May 2018 | Minor gas discovery |
| PL830 | Lundin Norway | 40% | Silfari | October 2018 | Dry |
| PL860 | MOL | 40% | Driva/Oppdal | November 2018 | Dry |
| PL857 | Equinor | 20% | Gjøkåsen Shallow | December 2018 | Dry |
| PL767 | Lundin Norway | 50% | Pointer/Setter | January 2019 | Dry |
| PL869 | AkerBP | 20% | Froskelår Main | January 2019 | Oil and gas discovery |
| PL857 | Equinor | 20% | Gjøkåsen Deep | January 2019 | Ongoing |
In December 2018, the Silfari prospect in PL830 located in the Froan Basin area of the Norwegian Sea encountered good quality Jurassic reservoir sands but with no hydrocarbon indications and the second Permian carbonate target encountered no reservoir intervals or hydrocarbons. The potential of the undrilled, adjacent Frøya High area is unaffected by the Silfari result.
In January 2019, the Driva/Oppdal dual target prospect in PL860 located in the Mandal High area of the North Sea was drilled and was dry. While the well encountered Paleocene and Rotliegendes reservoirs there were no hydrocarbons present. The second Mandal High area dual target well, Vinstra/Otta on the adjacent PL539 licence, will be drilled in 2019.
The Gjøkåsen prospect in PL857 located in the southern Barents Sea is a large, multi-horizon structure, remote from well control and as the deeper reservoir targets offset the shallow targets, it requires two wells to fully test the prospect. In February 2019, the Gjøkåsen Shallow prospect was drilled and was dry. The result of the Gjøkåsen Shallow well has no impact on the prospectivity of the Gjøkåsen Deep target which is currently drilling.
In February 2019, the Pointer/Setter prospect in PL767 in the southern Barents Sea was drilled and was dry. Drilling was conducted by the Leiv Eiriksson rig which is under a fl exible contract with suffi cient option slots to meet the Company's operated 2019 drilling programme.
Lundin Petroleum continues to grow its exploration acreage position through licence rounds. In January 2018, the Company was awarded 14 licences in the 2017 APA licensing round, of which six as operator. In June 2018, the Company was awarded three licences in the 24th licensing round, of which one as operator. In January 2019, the Company was awarded 15 licences in the 2018 APA licensing round, of which 9 as operator. Currently, the Company holds 82 licences in Norway, compared to 49 licences at the beginning of January 2018, which is an increase of approximately 70 percent.
In January 2018, Lundin Petroleum acquired a 10 percent working interest in each of PL539 and PL860 and a 30 percent working interest in each of PL820S and PL825 from Fortis Petroleum and also acquired a 20 percent working interest in PL860 from Equinor, increasing Lundin Petroleum's working interest in PL860 to 40 percent and in PL539 to 20 percent.
In May 2018, Lundin Petroleum concluded a licence swap with DNO to create an initial entry position in the Tampen/Horda Platform area of the Norwegian North Sea. Lundin Petroleum received a 10 percent working interest in each of PL926 and PL929 and 15 percent in each of PL921 and PL924 in exchange for DNO receiving 10 percent working interests in each of PL825, PL767, PL902 and PL950.
In June 2018, Lundin Petroleum concluded a licence swap with Edison in the southern Barents Sea where Lundin Petroleum received a 10 percent working interest in PL850, in exchange
for Edison receiving a 10 percent working interest in PL952. In October 2018, Lundin Petroleum acquired a further 20 percent working interest in PL850 from Lime Petroleum, increasing the Company's working interest in PL850 to 30 percent.
In October 2018, Lundin Petroleum acquired Equinor's 15 percent working interest in PL359 containing the Luno II oil discovery. The transaction involved a cash consideration payable to Equinor as well as Lundin Petroleum transferring its remaining interest in PL825 to Equinor.
In January 2019, Lundin Petroleum entered into a sales and purchase agreement involving the acquisition of Lime Petroleum's 30 percent working interest in each of PL338C and PL338E and 20 percent working interest in PL815, which contain the Rolvsnes oil discovery and Goddo prospect. The transaction will increase the Company's working interest in each of PL338C and PL338E to 80 percent and in PL815 to 60 percent. The transaction involves a cash consideration payable to Lime Petroleum and is subject to customary government approvals.
Lundin Petroleum has previously written down the entire contingent resources and book value for the Morskaya oil discovery as it was deemed unlikely that the discovery could commercially be developed in the foreseeable future. Having reviewed potential options, the partnership concluded that it is not possible for the partnership to create value from the asset and consequently the Morskaya licence has been relinquished.
During the year, one lost time incident and one medical treatment incident occurred, resulting in a Lost Time Incident Rate of 0.5 per million hours worked and a Total Recordable Incident Rate of 1.0 per million hours worked. There were no material safety or environmental incidents.
The operating profi t from continuing operations for the fi nancial year amounted to MUSD 1,402.4 (MUSD 812.4). The increase compared to the comparative period was mainly driven by higher oil prices in combination with lower production costs and depletion costs, somewhat offset by lower production volumes.
The net result from continuing operations for the year amounted to MUSD 222.1 (MUSD 380.9) and included a foreign currency exchange loss of MUSD 164.9 (gain of MUSD 255.3). The net result from continuing operations excluding foreign currency exchange results amounted to MUSD 387.0 (MUSD 125.6). The increase compared to the comparative period was mainly driven by higher oil prices in combination with lower production costs and depletion costs, somewhat offset by lower production volumes and an after tax accounting gain of MUSD 98.1 as a result of the re-negotiated improved borrowing terms for the reserve-based credit facility that unwinds to the income statement over the remaining period of the facility.
The net result from continuing operations attributable to shareholders of the Parent Company for the year amounted to MUSD 222.1 (MUSD 384.7) representing earnings per share of USD 0.66 (USD 1.13).
Earnings before interest, tax, depletion and amortisation (EBITDA) from continuing operations for the year amounted to MUSD 1,916.2 (MUSD 1,501.5) representing EBITDA per share of USD 5.65 (USD 4.41). Operating cash fl ow from continuing operations for the year amounted to MUSD 1,847.8 (MUSD 1,530.0) representing operating cash fl ow per share of USD 5.46 (USD 4.50).
Revenue and other income for the year amounted to MUSD 2,617.4 (MUSD 1,997.0) 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 2,607.9 (MUSD 1,958.3). The average price achieved by Lundin Petroleum for a barrel of oil equivalent from own production amounted to USD 67.89 (USD 51.63) and is detailed in the following table. The average Dated Brent price for the year amounted to USD 71.31 (USD 54.25) 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 | 2018 | 2017 |
| Crude oil sales | ||
| Norway | ||
| – Quantity in Mboe | 26,834.7 | 28,106.9 |
| – Average price per boe | 69.97 | 53.37 |
| Gas and NGL sales | ||
| Norway | ||
| – Quantity in Mboe | 3,682.0 | 3,943.1 |
| – Average price per boe | 52.74 | 39.23 |
| Total sales | ||
| – Quantity in Mboe | 30,516.7 | 32,050.0 |
| – Average price per boe | 67.89 | 51.63 |
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 536.1 (MUSD 303.5) and mainly consisted of Grane Blend 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 expense of MUSD 23.3 (income of MUSD 13.8) in the year due to the timing of the cargo liftings compared to production.
Other income for the year amounted to MUSD 32.8 (MUSD 24.9) and included a quality differential compensation on Alvheim blended crude and tariff income of MUSD 29.4 (MUSD 21.7) 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 145.4 (MUSD 164.2) and are detailed in Note 2. The total production cost per barrel of oil equivalent produced is detailed in the table below:
| Production costs | 2018 | 2017 |
|---|---|---|
| Cost of operations | ||
| – In MUSD | 102.5 | 117.3 |
| – In USD per boe | 3.46 | 3.73 |
| Tariff and transportation expenses | ||
| – In MUSD | 35.2 | 37.9 |
| – In USD per boe | 1.19 | 1.21 |
| Operating costs | ||
| – In MUSD | 137.7 | 155.2 |
| – In USD per boe 1 | 4.65 | 4.94 |
| Change in inventory position | ||
| – In MUSD | 0.6 | -0.4 |
| – In USD per boe | 0.02 | -0.02 |
| Other | ||
| – In MUSD | 7.1 | 9.4 |
| – In USD per boe | 0.24 | 0.30 |
| Production costs | ||
| – In MUSD | 145.4 | 164.2 |
| – In USD per boe | 4.91 | 5.22 |
Note: USD per boe is calculated by dividing the cost by total production volume for the period.
1 The numbers in this table are excluding tariff income netting. Lundin Petroleum's operating cost for the year of USD 4.65 (USD 4.94) per barrel is reduced to USD 3.66 (USD 4.25) when tariff income is netted off.
The total cost of operations for the year amounted to MUSD 102.5 (MUSD 117.3). The total cost of operations excluding operational projects amounted to MUSD 93.0 (MUSD 105.9). The reduction compared to the comparative period is the result of the termination of production from the Brynhild fi eld during the year.
The cost of operations per barrel for the year amounted to USD 3.46 (USD 3.73) including operational projects and USD 3.14 (USD 3.37) excluding operational projects.
Tariff and transportation expenses for the year amounted to MUSD 35.2 (MUSD 37.9) or USD 1.19 (USD 1.21) per barrel.
Other costs for the year amounted to MUSD 7.1 (MUSD 9.4) and related to the business interruption insurance. The comparative period also included the operating cost share arrangement on the Brynhild fi eld whereby the amount of operating cost varied 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 for the year amounted to MUSD 458.0 (MUSD 567.3) at an average rate of USD 15.46 (USD 18.05) per barrel and are detailed in Note 10. The lower depletion costs for the year compared to the comparative period is due to the lower depletion rate per barrel for the Edvard Grieg fi eld as a result of the increased reserves per year end 2017 and lower production volumes.
Exploration costs expensed in the income statement for the year amounted to MUSD 53.2 (MUSD 73.1) 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.
Impairment costs in the income statement for the year amounted to MUSD – (MUSD 30.6) and are detailed in note 10. The impairment costs in the comparative period were triggered by the partial sale of the Brynhild fi eld in PL148 where a 39 percent working interest was divested.
Loss from sale of assets in the income statement for the year amounted to MUSD – (MUSD 14.4) and related in the comparative period 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.
Purchase of crude oil from third parties for the year amounted to MUSD 533.8 (MUSD 303.3) and related mainly to Grane Blend crude oil purchased from outside the Group by Lundin Petroleum Marketing SA.
The general administrative and depreciation expenses for the year amounted to MUSD 24.6 (MUSD 31.7) which included a charge of MUSD 3.9 (MUSD 4.3) in relation to the Group's long-term incentive plans (LTIP), see also Note 29. Fixed asset depreciation expenses for the year amounted to MUSD 2.6 (MUSD 2.5).
Finance income for the year amounted to MUSD 192.2 (MUSD 256.7) and is detailed in Note 4.
During the year the reserve-based credit facility was successfully re-negotiated resulting in the interest rate margin over LIBOR being reduced from 3.15 percent to a current rate of 2.25 percent effective as of 1 June 2018. The amendment of the interest rate margin has resulted in an accounting gain of MUSD 183.7 (MUSD –) in accordance with IFRS 9. When a fi nancial liability, measured at amortised cost, is modifi ed without this resulting in derecognition, a gain or loss should be recognised in the income statement based on IFRS 9. The gain or loss is calculated as the difference between the original contractual cash fl ows and the modifi ed cash fl ows discounted at the original effective interest rate.
Other fi nancial income amounted to MUSD 3.3 (MUSD 0.4) and included the change in fair value under IFRS 9 of the shares held in ShaMaran. The shares held in ShaMaran were sold during the year at the prevailing market price.
Finance costs for the year amounted to MUSD 345.4 (MUSD 186.6) and are detailed in Note 5.
The net foreign currency exchange loss for the year amounted to MUSD 164.9 (gain of MUSD 255.3). 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 capital expenditure amounts against the US Dollar and for the year, the net realised exchange gain on these settled foreign exchange hedges amounted to MUSD 5.2 (loss of MUSD 1.8).
The US Dollar strengthened against the Euro during the year resulting in a net foreign currency exchange loss 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.
Interest expenses for the year amounted to MUSD 88.7 (MUSD 115.0) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 87.6 (MUSD 63.5) associated with the funding of the Norwegian development projects was capitalised in the year. The total interest expense is slightly lower compared to the comparative period mainly due to lower drawn debt under the reserve-based credit facility offset by higher interest rates. The result on interest rate hedge settlements amounted to a gain of MUSD 3.5 (loss of MUSD 17.4) and is reported as fi nancial income.
The amortisation of the deferred fi nancing fees for the year amounted to MUSD 17.8 (MUSD 17.5) and related to the fees incurred in establishing the reserve-based credit facility. The fees are being expensed over the expected life of the facility.
Loan facility commitment fees for the year amounted to MUSD 13.0 (MUSD 11.1) with the increase compared to the comparative period being the result of the lower drawn debt under the reserve-based credit facility somewhat offset by a lower margin for commitment fees as agreed through the amendment of the facility effective as of 1 June 2018.
The loan modifi cation fees for the year amounted to MUSD 17.3 (MUSD –) and related to the fees incurred for the re-negotiated reserve-based credit facility resulting in the interest rate margin over LIBOR being reduced from 3.15 percent to a current rate of 2.25 percent effective as of 1 June 2018. The net accounting gain when offsetting these loan modifi cation fees against the reported loan modifi cation gain amounted to MUSD 166.4. The associated deferred taxes amounted to MUSD 68.3 resulting in an after tax accounting gain of MUSD 98.1 that unwinds to the income statement over the remaining period of the facility.
The unwinding of the loan modifi cation gain for the year amounted to MUSD 26.1 (MUSD –) and related to the expensing of the accounting gain from the re-negotiated improved borrowing terms for the reserve-based credit facility over the period of usage of the facility.
Share in result of associated company for the year amounted to MUSD -1.3 (MUSD -0.4) and related to the share in the result of the investment in Mintley Caspian Ltd and are detailed in Note 6.
The overall tax charge for the year amounted to MUSD 1,025.8 (MUSD 501.2) and is detailed in Note 7.
The current tax charge for the year amounted to MUSD 90.4 (MUSD -0.5) of which MUSD 89.0 (MUSD -1.5) related to Norway. The current tax charge for Norway related to Corporate Tax only with no current tax charge to the income statement in relation to the Special Petroleum Tax (SPT) as the Company continues to be sheltered from SPT tax losses. The paid tax installments in Norway during the year amounted to MUSD 14.8 which has resulted in an increase in current tax liabilities compared to the comparative period.
The deferred tax charge for the year amounted to MUSD 935.4 (MUSD 501.7) and 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 results, 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 – (MUSD -3.8) and related in the comparative period 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. The investment in Mintley Caspian Ltd. was deconsolidated at the end of the third quarter 2017 and the results are now reported as share in result of associated company.
Oil and gas properties amounted to MUSD 5,341.1 (MUSD 4,937.1) and are detailed in Note 10.
Development, exploration and appraisal expenditure incurred for the year was as follows:
| in MUSD | 2018 | 2017 |
|---|---|---|
| Norway | 701.9 | 950.0 |
| Development expenditures | 701.9 | 950.0 |
Development expenditure of MUSD 701.9 (MUSD 950.0) was incurred in Norway during the year, primarily on the Johan Sverdrup and Edvard Grieg fi elds. In addition an amount of MUSD 87.6 (MUSD 63.5) of interest was capitalised.
| in MUSD | 2018 | 2017 |
|---|---|---|
| Norway | 310.6 | 227.1 |
| Russia | – | 1.1 |
| Exploration and appraisal expenditure | 310.6 | 228.2 |
Exploration and appraisal expenditure of MUSD 310.6 (MUSD 227.1) was incurred in Norway during the year, primarily for the appraisal wells Luno II in PL359, Rolvsnes in PL338C and Alta in PL609, the exploration wells Frosk in PL340, Svanefjell in PL659, Lille Prinsen in PL167, Silfari in PL830 and Driva/ Oppdal in PL860 as well as for Phase 2 of the Johan Sverdrup project. The income associated with the oil produced during the extended production test of the Alta appraisal well in PL609 during the third quarter was offset against the capitalised appraisal expenditure in the year.
Other tangible fi xed assets amounted to MUSD 13.6 (MUSD 13.2) 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 0.4 (MUSD 6.7) and are detailed in Note 13. The comparative period included the shares held in ShaMaran which were sold during the year to a related party as mentioned in Note 26.
Derivative instruments amounted to MUSD 2.7 (MUSD 26.5) 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 36.5 (MUSD 33.7) and included both well supplies and hydrocarbon inventories and are detailed in Note 14.
Trade and other receivables amounted to MUSD 219.3 (MUSD 304.4) and are detailed in Note 15. Trade receivables, which are all current, amounted to MUSD 153.7 (MUSD 202.7) and included invoiced cargoes. Underlift amounted to MUSD 4.6 (MUSD 29.4) and was attributable to an underlift position on the producing fi elds. Joint operations debtors relating to various joint venture receivables amounted to MUSD 17.0 (MUSD 15.6). Prepaid expenses and accrued income amounted to MUSD 26.9 (MUSD 29.3) and represented mainly prepaid operational and insurance expenditure. Other current assets amounted to MUSD 17.1 (MUSD 27.4) and included a short-term receivable from IPC in relation to certain working capital balances following the IPC spin-off amounting to MUSD 14.0 and other miscellaneous receivable balances.
Derivative instruments amounted to MUSD 34.0 (MUSD 7.7) 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.
Cash and cash equivalents amounted to MUSD 66.8 (MUSD 71.4). Cash balances are held to meet ongoing operational funding requirements.
Financial liabilities amounted to MUSD 3,262.0 (MUSD 3,880.0) and are detailed in Note 18. Bank loans amounted to MUSD 3,465.0 (MUSD 3,955.0) and related to the outstanding loan under the reserve-based credit facility. Capitalised fi nancing fees relating to the establishment of the facility amounted to MUSD 54.1 (MUSD 75.0) and are being amortised over the expected life of the facility. The closing balance associated with the capitalised loan modifi cation gain amounted to MUSD 148.9 (MUSD –) and is being amortised over the expected life of the facility.
Provisions amounted to MUSD 489.1 (MUSD 420.6) and are detailed in Note 19. The provision for site restoration amounted to MUSD 483.9 (MUSD 414.6) and related to the long-term portion of the future decommissioning obligations. The increase mainly refl ects the additional liability for Edvard Grieg and for the Johan Sverdrup development project. The short-term portion of the future decommissioning obligations was classifi ed as current liabilities.
Deferred tax liabilities amounted to MUSD 2,103.0 (MUSD 1,302.2) 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 64.9 (MUSD 3.1) 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.
Trade and other payables amounted to MUSD 204.6 (MUSD 259.0) and are detailed in Note 20. Overlift amounted to MUSD 5.4 (MUSD 12.8) and was attributable to an overlift position in relation to the Edvard Grieg fi eld. Joint operations creditors and accrued expenses amounted to MUSD 147.4 (MUSD 188.9) and related to activity in Norway. Other accrued expenses amounted to MUSD 17.6 (MUSD 19.5) and other current liabilities amounted to MUSD 7.6 (MUSD 7.7).
Derivative instruments amounted to MUSD 20.0 (MUSD 6.4) 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 tax liabilities amounted to MUSD 70.4 (MUSD 0.6) and related mainly to Corporate Tax due in Norway as detailed in Note 7.
Current provisions amounted to MUSD 12.5 (MUSD 7.7) and are detailed in Note 19. The short-term portion of the future decommissioning obligations amounted to MUSD 6.6 (MUSD –) and the current portion of the provision for Lundin Petroleum's Unit Bonus Plan amounted to MUSD 5.9 (MUSD 7.7).
The Annual General Meeting will be held in Stockholm on 29 March 2019.
The intention of the Board of Directors is to propose to the 2019 AGM the adoption of a Policy on Remuneration for 2019 that follows in essence the same principles as applied in 2018 and that contains similar elements of remuneration for Group management as the 2018 Policy on Remuneration being base salary, yearly variable remuneration, 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 similar principles as the LTIPs approved by the 2014 - 2018 Annual General Meetings. LTIP 2019 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 2019 and expiring on 30 June 2022. 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 upon allotment is limited to a value of three times each participant's annual gross base salary for 2019. The total number of performance shares that may be allotted under LTIP 2019 is 500,000, corresponding to approximately 0.15 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 2019, 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 2019. 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 2018, see the Corporate Governance report on pages 36–37. 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 Note 17.1.
For the AGM resolution on the authorisation to issue new shares, see page 25, Corporate Governance Report.
In accordance with the updated dividend policy, the Board of Directors propose that the Annual General Meeting resolves on a dividend for 2018 of USD 1.48 per share, corresponding to USD 500 million (rounded off), to be paid in quarterly instalments of USD 0.37 per share, corresponding to USD 125 million (rounded off). Before payment, each quarterly dividend of USD 0.37 per share shall be converted into a SEK amount, and paid out in SEK, based on the USD to SEK exchange rate published by Sweden's central bank (Riksbanken) four business days prior to each record date (rounded off to the nearest whole SEK 0.01 per share). The fi nal USD equivalent amount received by the shareholders may therefore slightly differ depending on what the USD to SEK exchange rate is on the date of the dividend payment. The SEK amount per share to be distributed each quarter will be announced in a press release four business days prior to each record date.
The fi rst dividend payment is expected to be paid around 5 April 2019, with an expected record date of 2 April 2019 and expected ex-dividend date of 1 April 2019. The second dividend payment is expected to be paid around 8 July 2019, with an expected record date of 3 July 2019 and expected ex-dividend date of 2 July 2019. The third dividend payment is expected to be paid around 7 October 2019, with an expected record date of 2 October 2019 and an expected ex-dividend date of 1 October 2019. The fourth dividend payment is expected to be paid around 9 January 2020, with an expected record date of 3 January 2020 and an expected ex-dividend date of 2 January 2020.
In order to comply with Swedish company law, a maximum total SEK amount shall be pre-determined to ensure that the dividend distributed does not exceed the available distributable reserves of the Company and such maximum amount for the 2018 dividend has been set to a cap of SEK 7.665 billion (i.e., SEK 1.916 billion per quarter). If the total dividend would exceed the cap of SEK 7.665 billion, the dividend will be automatically adjusted downwards so that the total dividend corresponds to the cap of SEK 7.665 billion.
For details of the updated dividend policy, see page 25.
The 2019 Annual General Meeting has an unrestricted equity at its disposal of MSEK 54,256.0, including the net result for the year of MSEK 1,657.8.
Based on the proposed dividend, the Board of Directors propose that the Annual General Meeting dispose of the unrestricted equity as follows:
| The Board of Directors proposes that the shareholders are paid a dividend of USD 1.48 per share 1 |
4,666.0 |
|---|---|
| Brought forward | 49,590.0 |
| Unrestricted equity | 54,256.0 |
1 The amount is based on the USD to SEK exchange rate published by Sweden's central bank (Riksbanken) as at 25 February 2019. The amount is based on the number of shares in circulation on 25 February 2019 and the total dividend amount may change by the record dates as a result of repurchases of own shares or as a result of issue of new shares. The dividend is USD denominated, fl uctuations in the USD to SEK exchange rate between 25 February 2019 and approval of the dividend proposal by the Annual General Meeting will have an impact on the total dividend amount reported in SEK. If the dividend proposal is approved by the Annual General Meeting, the dividend will be recorded as a liability in USD on the date of the Annual General Meeting and the SEK equivalent of the USD liability will fl uctuate until the fourth tranche is converted from USD to SEK.
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 2019 AGM, all the current members of the Board of Directors will be proposed for re-election by the Nomination Committee.
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 89–94.
Subsequent events are detailed in Note 31.
For a detailed description of risk management, see the Strategic report on pages 18–21.
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 22–38.
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 | 2018 | 2017 |
|---|---|---|---|
| Revenue and other income | |||
| Revenue | 2,607.9 | 1,958.3 | |
| Other income | 9.5 | 38.7 | |
| 1 | 2,617.4 | 1,997.0 | |
| Cost of sales | |||
| Production costs | 2 | -145.4 | -164.2 |
| Depletion and decommissioning costs | 10 | -458.0 | -567.3 |
| Exploration costs | 10 | -53.2 | -73.1 |
| Impairment costs of oil and gas properties | 10 | – | -30.6 |
| Loss from sale of assets | 8 | – | -14.4 |
| Other cost of sales | 3 | -533.8 | -303.3 |
| Gross profi t | 1,427.0 | 844.1 | |
| General, administration and depreciation expenses | -24.6 | -31.7 | |
| Operating profi t | 1,402.4 | 812.4 | |
| Net fi nancial items | |||
| Finance income | 4 | 192.2 | 256.7 |
| Finance costs | 5 | -345.4 | -186.6 |
| -153.2 | 70.1 | ||
| Share in result of associated company | 6 | -1.3 | -0.4 |
| Profi t before tax | 1,247.9 | 882.1 | |
| Income tax | 7 | -1,025.8 | -501.2 |
| Net result from continuing operations | 222.1 | 380.9 | |
| Discontinued operations | |||
| Net result – IPC | 9 | – | 46.5 |
| Net result | 222.1 | 427.4 | |
| Attributable to: | |||
| Shareholders of the Parent Company | 222.1 | 431.2 | |
| Non-controlling interest | – | -3.8 | |
| 222.1 | 427.4 | ||
| Earnings per share – USD1 | 17.3 | ||
| From continuing operations | 0.66 | 1.13 | |
| From discontinued operations | – | 0.14 | |
| Earnings per share – fully diluted – USD1 | 17.3 | ||
| From continuing operations | 0.65 | 1.13 | |
| From discontinued operations | – | 0.14 |
1 Based on net result attributable to shareholders of the Parent Company.
| Expressed in MUSD | 2018 | 2017 |
|---|---|---|
| Net result | 222.1 | 427.4 |
| Items that may be subsequently reclassifi ed to profi t or loss: | ||
| Exchange differences foreign operations | 1.5 | -96.2 |
| Cash fl ow hedges | -74.1 | 76.4 |
| Available-for-sale fi nancial assets | – | 4.9 |
| Other comprehensive income | -72.6 | -14.9 |
| Total comprehensive income | 149.5 | 412.5 |
| Attributable to: | ||
| Shareholders of the Parent Company | 149.5 | 416.3 |
| Non-controlling interest | – | -3.8 |
| 149.5 | 412.5 |
| Expressed in MUSD | Note | 2018 | 2017 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Oil and gas properties | 10 | 5,341.1 | 4,937.1 |
| Other tangible fi xed assets | 11 | 13.6 | 13.2 |
| Goodwill | 12 | 128.1 | 128.1 |
| Financial assets | 13 | 0.4 | 6.7 |
| Derivative instruments | 21 | 2.7 | 26.5 |
| Total non-current assets | 5,485.9 | 5,111.6 | |
| Current assets | |||
| Inventories | 14 | 36.5 | 33.7 |
| Trade and other receivables | 15 | 219,3 | 304.4 |
| Derivative instruments | 21 | 34.0 | 7.7 |
| Cash and cash equivalents | 16 | 66.8 | 71.4 |
| Total current assets | 356.6 | 417.2 | |
| TOTAL ASSETS | 5,842.5 | 5,528.8 | |
| EQUITY AND LIABILITIES | |||
| Equity | |||
| Share capital | 17.1 | 0.5 | 0.5 |
| Additional paid in capital | 17.1 | 339.7 | 527.9 |
| Other reserves | 17.2 | -518.3 | -445.7 |
| Retained earnings | -428.0 | -864.7 | |
| Net result | 222.1 | 431.2 | |
| Total equity | -384.0 | -350.8 | |
| Liabilities | |||
| Non-current liabilities | |||
| Financial liabilities | 18 | 3,262.0 | 3,880.0 |
| Provisions | 19 | 489.1 | 420.6 |
| Deferred tax liabilities | 7 | 2,103.0 | 1,302.2 |
| Derivative instruments | 21 | 64.9 | 3.1 |
| Total non-current liabilities | 5,919.0 | 5,605.9 | |
| Current liabilities | |||
| Trade and other payables | 20 | 204.6 | 259.0 |
| Derivative instruments | 21 | 20.0 | 6.4 |
| Current tax liabilities | 7 | 70.4 | 0.6 |
| Provisions | 19 | 12.5 | 7.7 |
| Total current liabilities | 307.5 | 273.7 | |
| Total liabilities | 6,226.5 | 5,879.6 | |
| TOTAL EQUITY AND LIABILITIES | 5,842.5 | 5,528.8 | |
for the Financial Year Ended 31 December
| Expressed in MUSD | Note | 2018 | 2017 |
|---|---|---|---|
| Cash fl ows from operating activities | |||
| Net result | 222.1 | 380.9 | |
| Adjustments for: | |||
| Exploration costs | 53.2 | 73.1 | |
| Depletion, depreciation and amortisation | 460.6 | 570.9 | |
| Impairment of oil and gas properties | – | 30.6 | |
| Current tax | 90.4 | -0.5 | |
| Deferred tax | 935.4 | 501.7 | |
| Impairment of other shares | – | 11.2 | |
| Long-term incentive plans | 14.6 | 12.7 | |
| Foreign currency exchange gain/loss | 162.5 | -258.0 | |
| Interest expense | 88.7 | 115.0 | |
| Loan modifi cation gain | -183.7 | – | |
| Loan modifi cation fees | 17.3 | – | |
| Unwinding of loan modifi cation gain | 26.1 | – | |
| Capitalised fi nancing fees | 17.8 | 17.5 | |
| Other | 12.8 | 26.4 | |
| Interest received | 1.1 | 1.0 | |
| Interest paid | -176.0 | -177.3 | |
| Income taxes paid/received | -15.8 | 82.2 | |
| Changes in working capital: | |||
| Changes in inventories | -2.8 | -3.8 | |
| Changes in underlift position | 24.8 | -2.0 | |
| Changes in receivables | 57.4 | 126.9 | |
| Changes in overlift position | -7.4 | -17.1 | |
| Changes in liabilities | -80.8 | -192.1 | |
| Total cash fl ows from operating activities | 1,718.3 | 1,299.3 | |
| Cash fl ows from investing activities | |||
| Investment in oil and gas properties | -1,060.1 | -1,178.2 | |
| Investment in other fi xed assets | -3.2 | -1.6 | |
| Investment in other shares and participations1 | 9.3 | -1.3 | |
| Decommissioning costs paid | -1.3 | -0.4 | |
| Disposal of fi xed assets2 | – | 93.7 | |
| Other | – | -7.8 | |
| Total cash fl ows from investing activities | -1,055.3 | -1,095.6 | |
| Cash fl ows from fi nancing activities | |||
| Changes in long-term liabilities | 22 | -490.0 | -188.7 |
| Financing fees paid | -17.3 | – | |
| Cash funded from/to discontinued operations | – | 31.7 | |
| Dividends paid | -153.1 | – | |
| Purchase of own shares | -14.3 | -28.0 | |
| Total cash fl ows from fi nancing activities | -674.7 | -185.0 | |
| Changes in cash and cash equivalents | -11.7 | 18.7 | |
| Cash and cash equivalents at the beginning of the year | 71.4 | 56.1 | |
| Currency exchange difference in cash and cash equivalents | 7.1 | -3.2 | |
| Cash and cash equivalents of deconsolidated operations | – | -0.2 | |
| Cash and cash equivalents at the end of the year | 66.8 | 71.4 |
1 Cash received on the sale of the shares held in ShaMaran
2 Cash received on the divestment of a 39 percent working interest in the Brynhild fi eld on closing including settlement of net working capital.
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 2017 | 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 |
| Distribution of IPC assets | – | -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 3 | – | -13.2 | – | – | -13.2 | – | -13.2 |
| Value of employee services 4 | – | – | – | 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 |
| Comprehensive income | |||||||
| Net result | – | – | – | 222.1 | 222.1 | – | 222.1 |
| Currency translation difference | – | – | 1.5 | – | 1.5 | – | 1.5 |
| Cash fl ow hedges | – | – | -74.1 | – | -74.1 | – | -74.1 |
| Total comprehensive income | – | – | -72.6 | 222.1 | 149.5 | – | 149.5 |
| Transactions with owners | |||||||
| Cash distributions | – | -153.1 | – | – | -153.1 | – | -153.1 |
| Purchase of own shares | – | -14.3 | – | – | -14.3 | – | -14.3 |
| Share based payments 3 | – | -20.8 | – | – | -20.8 | – | -20.8 |
| Value of employee services 4 | – | – | – | 5.5 | 5.5 | – | 5.5 |
| Total transactions with owners | – | -188.2 | – | 5.5 | -182.7 | – | -182.7 |
| Balance at 31 December 2018 | 0.5 | 339.7 | -518.3 | -205.9 | -384.0 | – | -384.0 |
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.
3 Represents the cost to hedge the equity-settled share-based long-term incentive plan as described in Note 29.
4 Represents the fair value at the date of grant of the equity-settled share-based long-term incentive plan that is recognised over the vesting period as described in Note 29.
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 89.
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, except for items that are required to be accounted for at fair value as detailed in the Group's accounting policies. Intercompany transactions and balances have been eliminated.
following new accounting standards:
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. Based on this standard, the investment in ShaMaran Petroleum Corp. (ShaMaran) was booked at fair value of the shares with movements in the fair value of the shares being directly recognised in the consolidated income statement. The ShaMaran shares were sold during the year. The Group applies the new rules retrospectively from 1 January 2018 and the comparatives are not restated.
Based on IFRS 9, a net accounting gain of MUSD 166.4 was recognised during the reporting period as a result of the renegotiated improved borrowing terms for the reserve-based credit facility taking effect as of 1 June 2018.
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. Based on this standard, certain transactions are no longer reported as revenue but as other revenue instead. The Group applies the new rules using the full retrospective approach which means that the comparatives have been restated.
The Group has not adopted the following standards and interpretations that are not mandatory for the fi nancial year 2018. The Group has assessed the impact on the Group's consolidated fi nancial statements for the standards with an effective date of 1 January 2019.
IFRS 16 Leases will replace IAS 17. The new standard requires recognition in the balance sheet for each contract, with some exceptions, that meets the defi nition of a lease as a right of use asset and lease liability, while lease payments are to be refl ected as interest expense and a reduction of lease liability. Effective from 1 January 2019, the Group has made the following transition choices in relation to IFRS 16: (a) application of the modifi ed retrospective method, (b) right of use assets will be measured at an amount equal to the lease liability and (c) leases with a less than 12 months remaining lease term at year end 2018 will not be refl ected as leases. The Group has made the following application policy choice: short-term leases (less than 12 months) and leases of low value assets will not be refl ected in the balance sheet, but will be expensed as incurred.
Lundin Petroleum has assessed the impact of IFRS 16 on the fi nancial statements of the Group and only identifi ed one relevant contract containing a lease with no material impact on the fi nancial statements of the Group.
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 acquisition-byacquisition 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/operations/
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.
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 2018 | 31 December 2017 | |||
|---|---|---|---|---|
| Average | Period end | Average Period end | ||
| 1 USD equals NOK | 8.1329 | 8.6885 | 8.2712 | 8.2050 |
| 1 USD equals EUR | 0,8464 | 0,8734 | 0.8855 | 0.8338 |
| 1 USD equals SEK | 8.6921 | 8.9562 | 8.5481 | 8.2080 |
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:
Financial assets that are held for collection of contractual cash fl ows where those cash fl ows represent solely payments of principal and interest are measured at amortised cost. The Group's loans and receivables consist of fi xed or determined cash fl ows related solely to principal and interest amounts or contractual sales of oil and gas. The Group's intent is to hold these receivables until cash fl ows are collected. Loans and receivables are recognised initially at fair value, net of any transaction costs incurred and subsequently measured at amortised cost.
Financial assets measured at FVTPL are assets which do not qualify as fi nancial assets at amortised cost or at fair value through other comprehensive income.
Financial liabilities are measured at amortised cost, unless they are required to be measured at FVTPL, or the Group has opted to measure them at FVTPL. Borrowings and accounts payable are recognised initially at fair value, net of any transaction costs incurred, and subsequently at amortised cost using the effective interest method.
Financial liabilities measured at FVTPL are liabilities which include embedded derivatives and cannot be classifi ed as amortised cost.
The measurement of impairment of fi nancial assets is based on the expected credit losses model. For the trade and other receivables, the Group applies the simplifi ed approach which requires the use of the lifetime expected loss provision for all trade receivables. In estimating the lifetime expected loss provision, the Group considered historical industry default rates as well as credit ratings of major customers. Additional disclosure related to the Group's fi nancial assets is included in Note 21.
Derivative fi nancial instruments are used to manage economic exposure to market risks relating to foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required documentation and approvals for the use of derivative fi nancial instruments. Derivative fi nancial instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently remeasured at their fair value. Where specifi c fi nancial instruments are executed, The Group assesses, both at the time of purchase and on an ongoing basis, whether the fi nancial instrument used in the particular transaction is effective in offsetting changes in fair values or cash fl ows of the transaction.
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, if any, 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 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. 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 upon performance of services and is recognised as other income.
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 105 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 | 2018 | 2017 |
|---|---|---|
| Revenue | ||
| Crude oil from own production | 1,877.6 | 1,500.2 |
| Crude oil from third party activities | 536.1 | 303.5 |
| Condensate | 41.8 | 43.0 |
| Gas | 152.4 | 111.6 |
| Net sales of oil and gas | 2,607.9 | 1,958.3 |
| Other income | ||
| Change in under/over lift position | -23.3 | 13.8 |
| Other revenue | 32.8 | 24.9 |
| Other income | 9.5 | 38.7 |
| Revenue and other income | 2,617.4 | 1,997.0 |
For further information on revenue, see the Directors Report on page 47.
| MUSD | 2018 | 2017 |
|---|---|---|
| Cost of operations | 102.5 | 117.3 |
| Tariff and transportation expenses | 35.2 | 37.9 |
| Change in inventory position | 0.6 | -0.4 |
| Other production costs | 7.1 | 9.4 |
| Production costs | 145.4 | 164.2 |
For further information on production costs, see the Directors Report on pages 47–48.
The Group operates within several geographical areas with a focus on Norway following the IPC spin-off during 2017. Operating segments are reported at country level which is consistent with the internal reporting provided to Group management.
The following tables present segment information regarding; revenue 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 marketing 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 34 percent of the total revenue is contracted with one customer. The Parent Company is included in Other in the table below.
| MUSD | 2018 | 2017 |
|---|---|---|
| Norway | ||
| Crude oil from own production | 1,877.6 | 1,500.2 |
| Condensate | 41.8 | 43.0 |
| Gas | 152.4 | 111.6 |
| Net sales of oil and gas | 2,071.8 | 1,654.8 |
| Change in under/over lift position | -23.3 | 13.8 |
| Other revenue | 32.8 | 24.4 |
| Revenue and other income | 2,081.3 | 1,693.0 |
| Production costs | -145.4 | -164.2 |
| Depletion and decommissioning costs | -458.0 | -567.3 |
| Exploration costs | -53.2 | -72.0 |
| Impairment costs of oil and gas properties | – | -30.6 |
| Loss from sale of assets | – | -14.4 |
| Gross profi t | 1,424.7 | 844.5 |
| MUSD | 2018 | 2017 |
|---|---|---|
| Other | ||
| Crude oil from third party activities | 536.1 | 303.5 |
| Net sales of oil and gas | 536.1 | 303.5 |
| Other revenue | – | 0.5 |
| Revenue and other income | 536.1 | 304.0 |
| Exploration costs | – | -1.1 |
| Other cost of sales | -533.8 | -303.3 |
| Gross profi t/loss | 2.3 | -0.4 |
| MUSD | 2018 | 2017 |
|---|---|---|
| Total from continuing operations | ||
| Crude oil from own production | 1,877.6 | 1,500.2 |
| Crude oil from third party activities | 536.1 | 303.5 |
| Condensate | 41.8 | 43.0 |
| Gas | 152.4 | 111.6 |
| Net sales of oil and gas | 2,607.9 | 1,958.3 |
| Change in under/over lift position | -23.3 | 13.8 |
| Other revenue | 32.8 | 24.9 |
| Revenue and other income | 2,617.4 | 1,997.0 |
| Production costs | -145.4 | -164.2 |
| Depletion and decommissioning costs | -458.0 | -567.3 |
| Exploration costs | -53.2 | -73.1 |
| Impairment costs of oil and gas properties | – | -30.6 |
| Loss from sale of assets | – | -14.4 |
| Other cost of sales | -533.8 | -303.3 |
| Gross profi t | 1,427.0 | 844.1 |
| Assets | Equity and Liabilities | |||
|---|---|---|---|---|
| MUSD | 2018 | 2017 | 2018 | 2017 |
| Norway | 5,762.7 | 5,427.7 | 5,206.2 | 4,998.4 |
| Sweden | 3.9 | 1.5 | 3.7 | 23.7 |
| Other | 104.8 | 170.3 | 104.2 | 185.7 |
| Corporate | 2,596.8 | 3,237.4 | 3,538.1 | 3,979.9 |
| Intercompany balance elimination | -2,625.7 | -3,308.1 | -2,625.7 | -3,308.1 |
| Assets/liabilities per country | 5,842.5 | 5,528.8 | 6,226.5 | 5,879.6 |
| Shareholders' equity | N/A | N/A | -384.0 | -350.8 |
| Total equity for the Group | N/A | N/A | -384.0 | -350.8 |
| Total consolidated | 5,842.5 | 5,528.8 | 5,842.5 | 5,528.8 |
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 47–48.
| MUSD | 2018 | 2017 |
|---|---|---|
| Foreign currency exchange gain, net | – | 255.3 |
| Loan modifi cation gain | 183.7 | – |
| Interest income | 1.7 | 1.0 |
| Gain on interest rate hedge settlement | 3.5 | – |
| Fair value change of other shares | 3.3 | – |
| Guarantee fees | – | 0.4 |
| Finance income | 192.2 | 256.7 |
For further information on fi nance income, see the Directors Report on page 48.
| MUSD | 2018 | 2017 |
|---|---|---|
| Foreign currency exchange loss, net | 164.9 | – |
| Interest expense | 88.7 | 115.0 |
| Loss on interest rate hedge settlement | – | 17.4 |
| Unwinding of site restoration discount | 16.4 | 13.7 |
| Amortisation of deferred fi nancing fees | 17.8 | 17.5 |
| Loan facility commitment fees | 13.0 | 11.1 |
| Loan modifi cation fees | 17.3 | – |
| Unwinding of loan modifi cation gain | 26.1 | – |
| Impairment of other shares | – | 11.2 |
| Other | 1.2 | 0.7 |
| Finance costs | 345.4 | 186.6 |
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 48.
For further information on fi nance costs, see the Directors Report on pages 48–49.
| MUSD | 2018 | 2017 |
|---|---|---|
| Group´s share of net result | 1.3 | 0.4 |
| Total result from share in result of associated company | 1.3 | 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.
| Tax charge MUSD |
2018 | 2017 |
|---|---|---|
| Current tax | ||
| Norway | 89.0 | -1.5 |
| Russia | – | 0.1 |
| Switzerland | 1.4 | 0.9 |
| Current tax | 90.4 | -0.5 |
| Deferred tax | ||
| Norway | 935.4 | 501.7 |
| Deferred tax | 935.4 | 501.7 |
| Total tax | 1,025.8 | 501.2 |
For further information on income taxes, see the Directors Report on page 49.
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 | 2018 | 2017 |
|---|---|---|
| Profi t before tax | 1,247.9 | 882.1 |
| Tax calculated at the corporate tax rate in Sweden 22% (22%) | -274.5 | -194.1 |
| Effect of foreign tax rates | -815.2 | -398.7 |
| Tax effect of expenses non-deductible for tax purposes | -63.6 | -76.3 |
| Tax effect of uplift on expenses | 103.1 | 108.4 |
| Tax effect of income not subject to tax | 31.2 | 69.4 |
| Tax effect of utilisation of unrecorded tax losses | – | 1.1 |
| Tax effect of creation of unrecorded tax losses | -5.7 | -12.4 |
| Adjustments to prior year tax assessments | -1.1 | 1.4 |
| Tax credit | -1,025.8 | -501.2 |
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 foreign currency exchange losses. 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 the reported loan modifi cation gain.
There is no tax charge/credit relating to components of other comprehensive income.
| Current | Deferred | ||||
|---|---|---|---|---|---|
| Corporation tax liability - current and deferred MUSD |
2018 | 2017 | 2018 | 2017 | |
| Norway | 69.5 | – | 2,103.0 | 1,302.2 | |
| Switzerland | 0.9 | 0.3 | – | – | |
| Russia | – | 0.3 | – | – | |
| Total | 70.4 | 0.6 | 2,103.0 | 1,302.2 |
For further information on tax liabilities, see the Directors Report on page 50.
| MUSD | 2018 | 2017 |
|---|---|---|
| Deferred tax assets | ||
| Unused uplift/tax loss carry forwards | 184.9 | 526.7 |
| Other deductible temporary differences | 14.4 | 18.4 |
| 199.3 | 545.1 | |
| Deferred tax liabilities | ||
| Accelerated allowances | 2,301.6 | 1,846.4 |
| Deferred tax on excess values | 0.7 | 0.9 |
| 2,302.3 | 1,847.3 |
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 unused uplift carry forward in Norway for an amount of MUSD 184.9 (MUSD 391.4) and tax loss carried forwards in Norway of MUSD – (MUSD 135.3). Deferred tax assets in relation to uplift/tax loss carry 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 34 (MUSD 29). The tax losses can be carried forward and utilised for up to 9 years. 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.
The Group also has Swedish tax loss carry forwards of approximately MUSD 83 (MUSD 73). 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.
On 30 November 2017, Lundin Petroleum completed the divestment of a 39 percent working interest in the Brynhild fi eld to CapeOmega with an effective date of 1 January 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. There are no losses from sale of assets in 2018.
| MUSD | 2017 |
|---|---|
| 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 the spin-off date and are shown as discontinued operations. There are no results from discontinued operations in 2018.
| MUSD | 2017 |
|---|---|
| Revenue and other income | 69.1 |
| Cost of sales | |
| Production costs | -17.4 |
| Depletion and decommissioning costs | -19.1 |
| Depletion of other assets | -10.4 |
| Exploration costs | 0.1 |
| Impairment costs of oil and gas properties | – |
| Gross profi t/loss | 22.3 |
| Sale of assets | – |
| General, administration and depreciation expenses | -2.3 |
| Operating profi t/loss | 20.0 |
| Net fi nancial items | |
| Finance income | – |
| Finance costs | -24.1 |
| -24.1 | |
| Profi t/loss before tax | -4.1 |
| Income tax | 11.2 |
| -5.3 | |
| Gain on distribution of assets | 51.8 |
| Net result from discontinued operations | 46.5 |
| MUSD | 31 December 2018 |
31 December 2017 |
|---|---|---|
| Production cost pools | 1,759.3 | 2,169.7 |
| Non-production cost pools | 3,581.8 | 2,767.4 |
| 5,341.1 | 4,937.1 |
| MUSD | Norway |
|---|---|
| Cost | |
| 1 January | 4,892.0 |
| Additions | 161.5 |
| Change in estimates | -15.4 |
| Currency translation difference | -286.8 |
| 31 December | 4,751.3 |
| Depletion | |
| 1 January | -2,722.3 |
| Depletion charge for the year | -451.7 |
| Currency translation difference | 182.0 |
| 31 December | -2,992.0 |
| Net book value | 1,759.3 |
| MUSD | Norway | France | Netherlands | Malaysia | Total |
|---|---|---|---|---|---|
| Cost | |||||
| 1 January | 4,351.6 | 306.3 | 119.2 | 423.8 | 5,200.9 |
| Additions | 290.6 | 0.9 | 0.6 | 1.3 | 293.4 |
| Spin off IPC | – | -328.6 | -124.1 | -425.1 | -877.8 |
| Change in estimates | 26.6 | – | – | – | 26.6 |
| 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 |
Depletion from continuing operations amounted to MUSD 451.7 (MUSD 568.4) and is included within the depletion and decommissioning costs line in the income statement. Depletion from discontinued operations amounted to MUSD – (MUSD 19.1) and is included within the net result from discontinued operations line in the income statement.
| 2018 non-production cost pools | |
|---|---|
| MUSD | Norway |
| 1 January | 2,767.4 |
| Additions | 1,087.4 |
| Expensed exploration costs | -53.2 |
| Change in estimates | -6.7 |
| Currency translation difference | -213.1 |
| 31 December | 3,581.8 |
| MUSD | Norway | France | Netherlands | Russia | Malaysia | Total |
|---|---|---|---|---|---|---|
| 1 January | 1,720.6 | 6.9 | 7.1 | – | – | 1,734.6 |
| Additions | 1,028.3 | 0.1 | 0.1 | 1.1 | -0.1 | 1,029.5 |
| Expensed exploration costs | -72.0 | – | – | -1.1 | 0.1 | -73.0 |
| Spin off IPC | – | -7.2 | -7.5 | – | – | -14.7 |
| Change in estimates | -2.4 | – | – | – | – | -2.4 |
| Currency translation difference | 92.9 | 0.2 | 0.3 | – | – | 93.4 |
| 31 December | 2,767.4 | – | – | – | – | 2,767.4 |
Expensed exploration costs from continuing operations amounted to MUSD 53.2 (MUSD 73.1) and are included within the exploration costs line in the income statement. Expensed exploration costs from discontinued operations amounted to MUSD – (MUSD -0.1) 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 2018 on an asset basis in conjunction with the annual reserves audit process. In the assessment Lundin Petroleum used a combination of the oil price forward curve at year end and the price deck as used by ERCE for the year-end 2018 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 amounted to MUSD – (MUSD 30.6) with the impairment costs in the comparative period relating to the Brynhild fi eld in PL148.
During 2018, MUSD 87.6 (MUSD 63.5) 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 until May 2018 and LIBOR plus a margin of 2.25% from June 2018.
The Group is contractually committed to development projects with a remaining commitment as at 31 December 2018 of approximately USD 1.9 billion, mainly relating to the Johan Sverdrup project and excluding the Luno II project and the Rolvsnes extended well test.
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 2018 are estimated to be MUSD 118.1 (MUSD 52.8) of which third parties who are joint operations partners will contribute approximately MUSD 82.2 (MUSD 31.1).
| 2018 | 2017 | ||||||
|---|---|---|---|---|---|---|---|
| MUSD | Real estate |
Other | Total | FPSO | Real estate |
Other | Total |
| Cost | |||||||
| 1 January | 10.6 | 30.4 | 41.0 | 204.8 | 11.2 | 36.5 | 252.5 |
| Additions | – | 3.2 | 3.2 | – | – | 1.6 | 1.6 |
| Spin off IPC | – | – | – | -205.5 | – | -8.6 | -214.1 |
| Change in consolidation | – | – | – | – | -0.6 | -0.4 | -1.0 |
| Currency translation difference | – | -1.6 | -1.6 | 0.7 | – | 1.3 | 2.0 |
| 31 December | 10.6 | 32.0 | 42.6 | – | 10.6 | 30.4 | 41.0 |
| Depreciation | |||||||
| 1 January | -1.2 | -26.6 | -27.8 | -54.8 | -1.8 | -29.8 | -86.4 |
| Depreciation charge for the year | – | -2.6 | -2.6 | -10.4 | – | -2.8 | -13.2 |
| Spin off IPC | – | – | – | 65.2 | – | 6.8 | 72.0 |
| Change in consolidation | – | – | – | – | 0.6 | 0.3 | 0.9 |
| Currency translation difference | – | 1.4 | 1.4 | – | – | -1.1 | -1.1 |
| 31 December | -1.2 | -27.8 | -29.0 | – | -1.2 | -26.6 | -27.8 |
| Net book value | 9.4 | 4.2 | 13.6 | – | 9.4 | 3.8 | 13.2 |
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 2.6 (MUSD 2.5) and is included within the general, administration and depreciation line in the income statement. Depreciation from discontinued operations amounted to MUSD – (MUSD 0.3) and is included within the net result from discontinued operations line in the income statement.
| MUSD | 2018 | 2017 |
|---|---|---|
| 1 January | 128.1 | 128.1 |
| Change | – | – |
| 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 2018 and will be tested for impairment annually as part of the annual impairment testing of oil and gas properties.
| MUSD | 31 December 2018 |
31 December 2017 |
|---|---|---|
| Other shares and participations | – | 6.3 |
| Other | 0.4 | 0.4 |
| 0.4 | 6.7 |
| 31 December 2018 | 31 December 2017 | |||
|---|---|---|---|---|
| Number of shares | Share % | Book amount MUSD |
Book amount MUSD |
|
| ShaMaran Petroleum Corp. | – | – | – | 6.3 |
| – | 6.3 |
The shares held in ShaMaran Petroleum Corp. were sold during the year based on the quoted market share price of ShaMaran, amounting to MUSD 9.3.
The fair value of ShaMaran was calculated using the quoted share price at the Toronto Stock Exchange at the balance sheet date and is detailed below.
| ShaMaran Petroleum Corp. MUSD |
2018 | 2017 |
|---|---|---|
| 1 January | 6.3 | 8.9 |
| Additions | – | 1.4 |
| Fair value movement | 3.3 | -6.2 |
| Disposals | -9.3 | – |
| Currency translation difference | -0.3 | 2.2 |
| 31 December | – | 6.3 |
| MUSD | 31 December 2018 |
31 December 2017 |
|---|---|---|
| Hydrocarbon stocks | 3.3 | 4.1 |
| Drilling equipment and consumable materials | 33.2 | 29.6 |
| 36.5 | 33.7 |
| MUSD | 31 December 2018 |
31 December 2017 |
|---|---|---|
| Trade receivables | 153.7 | 202.7 |
| Underlift | 4.6 | 29.4 |
| Joint operations debtors | 17.0 | 15.6 |
| Prepaid expenses and accrued income | 26.9 | 29.3 |
| IPC working capital | 14.0 | 23.5 |
| Other | 3.1 | 3.9 |
| 219.3 | 304.4 |
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 IPC working capital relates to a residual receivable from IPC for working capital balances following the IPC spin-off which is due by mid-2019.
Cash and cash equivalents include only cash at hand or on bank. No short-term deposits are held as at 31 December 2018.
| Share capital | Additional paid in capital |
|||
|---|---|---|---|---|
| MUSD | Number of shares | Par value MSEK |
Par value MUSD |
MUSD |
| 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 |
| Distributions | – | – | – | -153.1 |
| Purchase of own shares | – | – | – | -14.3 |
| Share based payments | – | – | – | -20.8 |
| Movements | – | – | – | -188.2 |
| 31 December 2018 | 340,386,445 | 3.5 | 0.5 | 339.7 |
Included in the number of shares issued at 31 December 2018 are 1,873,310 shares (1,233,310 shares) which Lundin Petroleum holds in its own name. During 2017, Lundin Petroleum purchased 1,233,310 of its own shares at an average price of SEK 186.14 based on the approval granted at the AGM 2017. During 2018, Lundin Petroleum purchased an additional 640,000 of its own shares at an average price of SEK 186.77 based on the approval granted at the AGM 2018 resulting in 1,873,310 of its own shares held at the end of the year.
The AGM of Lundin Petroleum held on 3 May 2018 in Stockholm approved an inaugural cash dividend distribution for the year 2017 of SEK 4.00 per share and the dividend was distributed on 11 May 2018. Based on the number of shares outstanding, excluding own shares held by the Company, the dividend distribution amounted to MSEK 1,354.1, equaling MUSD 153.1 based on the exchange rate on the date of AGM approval.
| MUSD | Available-for sale reserve |
Hedge reserve | Currency translation reserve |
Total |
|---|---|---|---|---|
| 1 January 2017 | -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 |
| Total comprehensive income | – | -74.1 | 1.5 | -72.6 |
| 31 December 2018 | – | -74.4 | -443.9 | -518.3 |
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.
| 2018 | 2017 | |
|---|---|---|
| Net result attributable to shareholders of the Parent Company, USD | ||
| From continuing operations | 222,148,241 | 384,692,005 |
| From discontinued operations | – | 46,460,065 |
| 222,148,241 | 431,152,070 | |
| Weighted average number of shares for the year | 338,592,250 | 340,237,772 |
| Earnings per share, USD | ||
| From continuing operations | 0.66 | 1.13 |
| From discontinued operations | – | 0.14 |
| 0.66 | 1.27 | |
| Weighted average diluted number of shares for the year | 339,513,634 | 341,380,316 |
| Earnings per share, USD | ||
| From continuing operations | 0.65 | 1.13 |
| From discontinued operations | – | 0.14 |
| Earnings per share fully diluted, USD | 0.65 | 1.27 |
| MUSD | 31 December 2018 |
31 December 2017 |
|---|---|---|
| Bank loans | 3,465.0 | 3,955.0 |
| Capitalised fi nancing fees | -54.1 | -75.0 |
| Capitalised loan modifi cation gain | -148.9 | – |
| 3,262.0 | 3,880.0 |
Capitalised fi nancing fees amounted to MUSD 54.1 (MUSD 75.0) and related to the establishment costs of the reserve-based credit facility. The capitalised fi nancing fees are being amortised over the duration of the facility.
Capitalised loan modifi cation gain amounted to MUSD 148.9 (MUSD –) and related to the re-negotiated improved borrowing terms for the reserve-based credit facility. The capitalised loan modifi cation gain is being amortised over the duration of the facility.
For further information, see Note 21
| Site | Pension | ||||
|---|---|---|---|---|---|
| MUSD | Restoration | LTIP | provision | Other | Total |
| 1 January 2018 | 414.6 | 9.7 | 1.2 | 2.8 | 428.3 |
| Additions | 101.3 | 10.3 | 0.1 | 0.3 | 112.0 |
| Changes in estimates | -15.9 | – | – | – | -15.9 |
| Payments | -1.3 | -10.8 | -0.1 | -1.5 | -13.7 |
| Unwinding of discount | 16.4 | – | – | – | 16.4 |
| Currency translation difference | -24.6 | -0.9 | – | – | -25.5 |
| 31 December 2018 | 490.5 | 8.3 | 1.2 | 1.6 | 501.6 |
| Non-current | 483.9 | 2.4 | 1.2 | 1.6 | 489.1 |
| Current | 6.6 | 5.9 | – | – | 12.5 |
| Total | 490.5 | 8.3 | 1.2 | 1.6 | 501.6 |
| Site | Farm in | Pension | ||||
|---|---|---|---|---|---|---|
| MUSD | Restoration | LTIP | payment | 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 |
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 2018 mainly relate to the liability associated with Norwegian development projects. Based on the estimates used in calculating the site restoration provision as at 31 December 2018, approximately 85 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 2018 |
31 December 2017 |
|---|---|---|
| Trade payables | 26.6 | 30.1 |
| Overlift | 5.4 | 12.8 |
| Joint operations creditors and accrued expenses | 147.4 | 188.9 |
| Other accrued expenses | 17.6 | 19.5 |
| Other | 7.6 | 7.7 |
| 204.6 | 259.0 |
The accounting policies for fi nancial assets and liabilities have been applied to the line items below:
| 31 December 2018 MUSD |
Total | Loan receivables and other receivables at amortised cost |
Financial assets at amortised cost |
Fair value recognised in profi t/loss |
Derivatives used for hedging |
|---|---|---|---|---|---|
| Other non-current fi nancial assets | 0.4 | – | 0.4 | – | – |
| Derivative instruments | 36.7 | – | – | – | 36.7 |
| Joint operations debtors | 17.0 | 17.0 | – | – | – |
| Other current receivables1 | 175.4 | 170.8 | – | 4.6 | – |
| Cash and cash equivalents | 66.8 | 66.8 | – | – | – |
| 296.3 | 254.6 | 0.4 | 4.6 | 36.7 |
| 31 December 2018 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 | 3,262.0 | – | 3,262.0 | – | – |
| Derivative instruments | 84.9 | – | – | – | 84.9 |
| Joint operations creditors | 147.4 | 147.4 | – | – | – |
| Other current liabilities | 110.0 | 104.6 | – | 12.8 | – |
| 3,604.3 | 252.0 | 3,262.0 | 12.8 | 84.9 |
| 31 December 2017 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 | 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 |
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 2018 | |||
|---|---|---|---|
| MUSD | Level 1 | Level 2 | Level 3 |
| Assets | |||
| Derivative instruments – non-current | – | 2.7 | – |
| Derivative instruments – current | – | 34.0 | – |
| Underlift | 4.6 | – | – |
| 4.6 | 36.7 | – | |
| Liabilities | |||
| Derivative instruments – non-current | – | 64.9 | – |
| Derivative instruments – current | – | 20.0 | – |
| Overlift | 5.4 | – | – |
| 5.4 | 84.9 | – | |
| 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 | – | – |
The outstanding derivative instruments can be specifi ed as follows:
| Fair value of outstanding derivative instruments in the balance sheet |
31 December 2018 | 31 December 2017 | |||
|---|---|---|---|---|---|
| MUSD | Assets | Liabilities | Assets | Liabilities | |
| Interest rate swap | 36.7 | 8.1 | 28.3 | 6.7 | |
| Currency hedge | – | 76.8 | 5.9 | 2.8 | |
| Total | 36.7 | 84.9 | 34.2 | 9.5 | |
| Non-current | 2.7 | 64.9 | 26.5 | 3.1 | |
| Current | 34.0 | 20.0 | 7.7 | 6.4 | |
| Total | 36.7 | 84.9 | 34.2 | 9.5 |
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 2018 amounted to a net receivable of MUSD 28.6 (MUSD 21.6).
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 2018 amounted to a net payable of MUSD 76.8 (receivable of MUSD 3.1).
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 2018 |
Cash fl ows |
Loan modifi cation gain |
Amortisation of deferred fi nancing fees |
Unwinding of loan modifi cation gain |
Foreign exchange movement |
At 31 December 2018 |
|
| Financial liabilities | 3,880.0 | -490.0 | -183.7 | 17.8 | 26.1 | 11.8 | 3,262.0 |
| 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 38 and Risk Management on pages 18–21.
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 objectives and to maintain fl exibility. Lundin Petroleum is not subject to any externally imposed capital requirements.
Apart from the updated dividend policy, no signifi cant changes were made to the objectives, policies or processes during 2018.
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 2018 | 31 December 2017 |
|---|---|---|
| Bank loans | 3,465.0 | 3,955.0 |
| Cash and cash equivalents | -66.8 | -71.4 |
| Net debt | 3,398.2 | 3,883.6 |
The decrease in net debt compared to 2017 is mainly due to the positive free cash fl ow generated during 2018.
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 reserve-based credit facility, see also Liquidity risk below. The interest rate for capitalised borrowing costs is calculated at the reserve-based credit facility borrowing rate of LIBOR plus a margin of 2.25% per annum (margin of 3.15% per annum decreased to 2.25% per annum from June 2018). 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 2018 amounted to MUSD 176.3 which included MUSD 87.6 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 7.8, taking into account the Group's interest rate hedges for 2018.
The Group has entered into interest rate hedging as follows:
| Borrowings MUSD |
Fixing of fl oating LIBOR Rate per annum |
Settlement period |
|---|---|---|
| 3,000 | 1.42% | Jan 2019 – Dec 2019 |
| 2,000 | 2.15% | Jan 2020 – Dec 2020 |
| 2,000 | 2.67% | Jan 2021 – Dec 2021 |
| 2,000 | 2.74% | 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 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 NOK to meet part of its future NOK capital requirements relating to the Johan Sverdrup fi eld development and to meet part of its future NOK Corporate Tax requirements as summarised in the table below.
| Buy | Sell | Average contractual exchange rate |
Settlement period |
|---|---|---|---|
| MNOK 3,822.4 | MUSD 464.0 | NOK 8.24:USD 1 | Jan 2019 – Dec 2019 |
| MNOK 2,405.0 | MUSD 306.0 | NOK 7.86:USD 1 | Jan 2020 – Dec 2020 |
| MNOK 2,130.0 | MUSD 272.7 | NOK 7.81:USD 1 | Jan 2021 – Dec 2021 |
| MNOK 1,200.0 | MUSD 158.2 | NOK 7.59:USD 1 | Jan 2022 – Dec 2022 |
| MNOK 410.0 |
MUSD 51.0 | NOK 8.04:USD 1 | Jan 2023 – Dec 2023 |
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 2018, a net current receivable of MUSD 14.0 (MUSD 1.3) and a net non-current receivable of MUSD -62.2 (MUSD 23.4) 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 2018.
| Operating result in the fi nancial statements, MUSD | 1,402.4 | 1,402.4 | |
|---|---|---|---|
| Shift of currency exchange rates | Average rate 2018 | 10% USD weakening | 10% USD strengthening |
| EUR/USD | 0.8464 | 0.7695 | 0.9310 |
| SEK/USD | 8.6921 | 7.9019 | 9.5613 |
| NOK/USD | 8.1329 | 7.3935 | 8.9462 |
| Total effect on operating result, MUSD | -49.0 | 44.5 |
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 48, 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 an additional MUSD 314.9 reported foreign exchange loss 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 loan 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 2018:
| Net result in the fi nancial statements, MUSD | 222.1 | 222.1 |
|---|---|---|
| Possible shift | -10% | 10% |
| Total effect on net result, MUSD | -45.6 | 45.6 |
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 2018, the Group did not enter into oil price hedging contracts and there are no oil price hedging contracts outstanding as at 31 December 2018.
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 2018, the Group's trade receivables amounted to MUSD 153.7 (MUSD 202.7). There is no recent history of default and there are no expected losses. Other long-term and short-term receivables are considered recoverable and no provision for bad debt was accounted for as at 31 December 2018. 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 entered into a committed seven year senior secured reserve-based credit facility of USD 5.0 billion. The facility was amended during the second quarter of 2018 resulting in the interest rate margin over LIBOR being reduced from 3.15 percent to a current rate of 2.25 percent. The facility is secured against certain cash fl ows generated by the Group. The amount available under the facility is recalculated every twelve 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, a pledge over the Company's working interest in some production licences and a charge over some of the bank accounts of the pledged companies.
The amendment of the interest rate margin has resulted in an accounting gain of MUSD 183.7 in accordance with IFRS 9. When a fi nancial liability, measured at amortised cost, is modifi ed without this resulting in derecognition, a gain or loss should be recognised in the income statement based on IFRS 9. The gain or loss is calculated as the difference between the original contractual cash fl ows and the modifi ed cash fl ows discounted at the original effective interest rate. The net accounting gain when offsetting against the incurred loan modifi cation fees of MUSD 17.3 amounted to MUSD 166.4. The associated deferred taxes amounted to MUSD 68.3 resulting in a post-tax accounting gain of MUSD 98.1.
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 EBITDA 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 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 2018 | 31 December 2017 |
|---|---|---|
| Non-current | ||
| Repayment within 1–2 years: | ||
| – Derivative instruments | 19.3 | – |
| Repayment within 2–5 years: | ||
| – Bank loans | 3,465.0 | 3,955.0 |
| – Derivative instruments | 45.6 | 3.1 |
| 3,529.9 | 3,958.1 | |
| Current | ||
| Repayment within 6 months: | ||
| – Trade payables | 26.6 | 30.1 |
| – Overlift | 5.4 | 12.8 |
| – Tax liabilities | 14.8 | 0.6 |
| – Joint operations creditors | 147.4 | 188.9 |
| – Other current liabilities | 7.6 | 7.7 |
| – Derivative instruments | 9.0 | 3.2 |
| Repayment after 6 months: | ||
| – Tax liabilities | 55.6 | – |
| – Derivative instruments | 11.0 | 3.2 |
| 277.4 | 246.5 |
In February 2016, Lundin Petroleum entered into a committed seven year senior secured reserve-based credit facility of USD 5.0 billion with the terms being successfully re-negotiated during 2018 as mentioned in note 23. The facility is a reserve-based credit facility secured against certain cash fl ows generated by the Group. The amount available under the facility is recalculated every twelve 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, a pledge over the Company's working interest in some production licences and a charge over some of the bank accounts of the pledged companies. The pledged assets at 31 December 2018 amounted to MUSD 6,154.3 (MUSD 6,715.3) 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 93.
The Swedish Prosecution Authority issued a notifi cation of a corporate fi ne and forfeiture of economic benefi ts against Lundin Petroleum in relation to past operations in Sudan from 1997 to 2003. The notifi cation indicated that the Prosecutor might seek a corporate fi ne of MSEK 3 and forfeiture of economic benefi ts from the alleged offense in the amount of MSEK 3,282, based on the profi t of the sale of the Block 5A asset in 2003 of MSEK 720. Any potential corporate fi ne or forfeiture would only be imposed after the conclusion of a trial, should one occur. The investigation is in its ninth year and Lundin Petroleum remains convinced that there are absolutely no grounds for any allegations of wrongdoing by any Company representative and the Company will fi rmly contest any corporate fi ne or forfeiture of economic benefi ts. The Company considers this to be a contingent liability and therefore no provision has been recognised.
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 2018 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 | 2018 | 2017 |
|---|---|---|
| Sale of oil and related products | 879.5 | 176.2 |
| Purchases of oil and related products | 296.2 | – |
| Sale of services | 4.2 | 3.4 |
| Purchase of services | 1.8 | 1.9 |
| Interest income | 0.5 | – |
Equinor (previously Statoil) is a related party as Equinor's holding in Lundin Petroleum amounts to 20.1 percent. The Group has sold oil and related products to the Equinor group on an arm's-length basis amounting to MUSD 879.5 for the year (MUSD 176.2). The Group has purchased oil and related products from the Equinor group on an arm's-length basis amounting to MUSD 296.2 for the year (MUSD –).
The Group has acquired from the Equinor group a 15 percent working interest in PL359 containing the Luno II oil discovery. The transaction involved a cash consideration payable to Equinor as well as Lundin Petroleum transferring its 20 percent working interest in PL825 to Equinor. The transaction completed in December 2018.
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.
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 14.0 (MUSD 23.5). This receivable is reported as current asset as it is due by mid-2019.
The Group has sold the shares in ShaMaran to Zebra Holdings and Investments (Guernsey) Ltd. based on the quoted market share price of ShaMaran amounting to MUSD 9.3.
| 2018 | 2017 | ||||
|---|---|---|---|---|---|
| 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 | |||||
| Norway | 370 | 273 | 354 | 266 | |
| Switzerland | 35 | 20 | 34 | 21 | |
| Netherlands | 1 | 1 | 1 | 1 | |
| Russia 1 | – | – | 16 | 10 | |
| Total subsidiaries abroad | 406 | 294 | 405 | 298 | |
| Total | 408 | 295 | 407 | 299 |
1 The Russian business has been fully consolidated into the Lundin Petroleum consolidated accounts until 30 September 2017 and as such, there is no number of employees reported for 2018 as the Russian business is an associated company since 30 September 2017.
| 2018 | 2017 | |||
|---|---|---|---|---|
| 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 | 8 | 5 | 7 | 4 |
| Subsidiaries abroad | ||||
| Group management | 8 | 6 | 7 | 5 |
| Total Group | 16 | 11 | 14 | 9 |
1 Alex Schneiter, Chief Executive Offi cer (CEO) and Board Member is only included in Group management.
| 2018 | 2017 | |||
|---|---|---|---|---|
| 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 | 628 | 122 | 569 | 106 |
| Employees | 386 | 222 | 314 | 178 |
| Subsidiaries abroad | ||||
| Group management | 11,802 | 1,584 | 10,625 | 1,325 |
| Other employees | 94,773 | 22,240 | 84,730 | 20,910 |
| Total | 107,589 | 24,168 | 96,238 | 22,519 |
| of which pension costs | 8,758 | 8,822 |
| Salaries and other remuneration for the Board members and Group management 1 TUSD |
Fixed Board remuneration/ base salary |
Other benefi ts1 |
Short-term variable remuneration 2 |
Performance based incentive plan |
Remuneration for Committee work |
Remuneration for special assignments outside of directorship |
Pension | Total 2018 |
|---|---|---|---|---|---|---|---|---|
| Parent Company in Sweden |
||||||||
| Board members | ||||||||
| Ian H. Lundin | 127 | – | – | – | 13 | 115 | – | 255 |
| Peggy Bruzelius | 60 | – | – | – | 19 | – | – | 79 |
| C. Ashley Heppenstall | 60 | – | – | 4,646 | 13 | 613 | – | 5,332 |
| Lukas H. Lundin | 60 | – | – | – | – | – | – | 60 |
| Grace Reksten Skaugen | 60 | – | – | – | 22 | – | – | 82 |
| Jakob Thomasen | 60 | – | – | – | 19 | – | – | 79 |
| Cecilia Vieweg | 60 | – | – | – | 19 | – | – | 79 |
| Torstein Sanness | 30 | – | – | – | 6 | – | – | 36 |
| Total Board members | 517 | – | – | 4,646 | 111 | 728 | – | 6,002 |
| Subsidiaries abroad Group management |
||||||||
| Alex Schneiter | 855 | 42 | 855 | 2,926 | – | – | 175 | 4,853 |
| Other 3 | 2,410 | 396 | 1,905 | 2,413 | – | – | 441 | 7,565 |
| Total Group management |
3,265 | 438 | 2,760 | 5,339 | – | – | 616 | 12,418 |
Other benefi ts include school fees and health insurance for Group management.
2 This column shows bonuses awarded for achievements in 2018 based on the Policy on Remuneration for Group management, see page 35. 3 Comprises Chief Financial Offi cer, Chief Operating Offi cer, Vice President Corporate Responsibility, Vice President Legal, Vice President Corporate Affairs, Vice President Investor Relations and Vice President Human Resources and Shared Services.
Note: The performance based incentive plan that was awarded in 2015 when C. Ashley Heppenstall was the CEO of the Company vested in 2018. The amount mentioned in the table above relates to this award and does not relate to his work as Board Member. No further awards to C. Ashley Heppenstall are outstanding.
| Salaries and other remuneration for the Board members and Group management1 TUSD |
Fixed Board remuneration/ base salary |
Other benefi ts1 |
Short-term variable remuneration 2 |
Performance based incentive plan |
Remuneration for Committee work |
Remuneration for special assignments 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 |
| Other3 | 2,048 | 269 | 1,601 | 2,768 | – | – | 404 | 7,090 |
| Total Group management |
2,820 | 288 | 2,566 | 4,951 | – | – | 580 | 11,205 |
¹ Other benefi ts include school fees and health insurance for Group management.
2 This column shows bonuses awarded for achievements in 2017, including a discretionary award to the CEO and some other members of Group management. 3
Comprises nine persons 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.
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 remuneration 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 35–37 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 2018.
The Company maintains the long-term incentive plans (LTIP) described below.
In 2008, Lundin Petroleum implemented an 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 fi ve trading days prior to and following the actual vesting date adjusted for any dividend payments between grant date and vesting date. The exercise price at vesting date 31 May 2018 was SEK 279.67.
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 2018 and the year in which the units will vest.
| Plan | |||||
|---|---|---|---|---|---|
| Unit Bonus Plan | 2015 | 2016 | 2017 | 2018 | Total |
| Outstanding at the beginning of the period | 135,902 | 224,043 | 288,216 | – | 648,161 |
| Awarded during the period | – | – | – | 226,389 | 226,389 |
| Forfeited during the period | -2,980 | -5,544 | -6,120 | – | -14,644 |
| Exercised during the period | -132,922 | -110,705 | -94,032 | – | -337,659 |
| Outstanding at the end of the period | – | 107,794 | 188,064 | 226,389 | 522,247 |
| Vesting date | |||||
| 31 May 2019 | – | 107,794 | 94,032 | 75,463 | 277,289 |
| 31 May 2020 | – | – | 94,032 | 75,463 | 169,495 |
| 31 May 2021 | – | – | – | 75,463 | 75,463 |
| Outstanding at the end of the period | – | 107,794 | 188,064 | 226,389 | 522,247 |
The costs associated with the Unit Bonus Plan are as given in the following table.
| Unit Bonus Plan MUSD |
2018 | 2017 |
|---|---|---|
| 2014 | – | 1.5 |
| 2015 | 3.4 | 1.9 |
| 2016 | 2.1 | 2.4 |
| 2017 | 2.9 | 1.7 |
| 2018 | 1.9 | – |
| 10.3 | 7.5 |
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 2018 amounted to MUSD 8.3 (MUSD 9.7). The provision is calculated based on Lundin Petroleum's share price at the balance sheet date. The closing share price at 31 December 2018 was SEK 221.40.
The 2014–2018 AGMs resolved a long-term performance based incentive plan in respect of Group management and a number of key employees.
The 2018 plan is effective from 1 July 2018 and the 2018 award has been accounted for from the second half of 2018. The awards made in respect of 2018 vest over three years from 1 July 2018 subject to certain performance conditions being met. Each award was fair valued at the date of grant at SEK 167.10 using an option pricing model.
The 2017 plan is effective from 1 July 2017 and vests 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 vests 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 was effective from 1 July 2015 and vested on 30 June 2018. The 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 employed by IPC following the IPC spin-off have been pro-rated until the spin-off date 24 April 2017. Based on the performance conditions of the 2015 plan, the 2015 plan vested in full in 2018 with Lundin Petroleum's total shareholder return (TSR) ranking well above the upper quartile level as 3rd of 16 peers. The TSR movements of peers that were taken over were measured by the acquiring companies post acquisition.
The 2014 plan was effective from 1 July 2014 and vested on 30 June 2017. The 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 81.40 using an option pricing model. Awards given to employees employed by IPC following the IPC spin-off have been pro-rated until the spin-off date 24 April 2017. Based on the performance conditions of the 2014 plan, the 2014 plan vested in full in 2017 with Lundin Petroleum's total shareholder return (TSR) ranking well above the upper quartile level as 3rd of 16 peers. The TSR movements of peers that were taken over were measured by the acquiring companies post acquisition.
The following table shows the number of units issued under the LTIPs, the amount outstanding as at 31 December 2018 and the year in which the awards will vest.
| Plan | |||||
|---|---|---|---|---|---|
| Performance Based Incentive Plan | 2015 | 2016 | 2017 | 2018 | Total |
| Outstanding at the beginning of the period | 646,503 | 406,902 | 355,954 | – | 1,409,359 |
| Awarded during the period | – | – | – | 278,917 | 278,917 |
| Forfeited during the period 1 | 2,791 | 2,441 | – | – | 5,232 |
| Exercised during the period | -649,294 | – | – | – | -649,294 |
| Outstanding at the end of the period | – | 409,343 | 355,954 | 278,917 | 1,044,214 |
| Vesting date | |||||
| 30 June 2019 | – | 409,343 | – | – | 409,343 |
| 30 June 2020 | – | – | 355,954 | – | 355,954 |
| 30 June 2021 | – | – | – | 278,917 | 278,917 |
| Outstanding at the end of the period | – | 409,343 | 355,954 | 278,917 | 1,044,214 |
1 The increase in outstanding awards reported as forfeited during the period relates to an adjustment for the reported number on this line in 2017.
The costs associated with the Performance Based Incentive Plan are as given in the following table.
| Performance Based Incentive Plan MUSD |
2018 | 2017 |
|---|---|---|
| 2014 | – | 0.8 |
| 2015 | 0.6 | 1.5 |
| 2016 | 1.3 | 1.4 |
| 2017 | 1.4 | 0.7 |
| 2018 | 0.7 | – |
| 4.0 | 4.4 |
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 2018 amounted to MUSD 6.0 (MUSD 7.3). The effect on equity is calculated based on the fair value at date of grant.
| TUSD | 2018 | 2017 |
|---|---|---|
| PwC | ||
| Audit fees | 448 | 501 |
| Out of which to PricewaterhouseCoopers AB | 201 | 242 |
| Audit related | 33 | 44 |
| Out of which to PricewaterhouseCoopers AB | 23 | 20 |
| Tax advisory services | 45 | 23 |
| Out of which to PricewaterhouseCoopers AB | – | – |
| Other fees | 69 | 18 |
| Out of which to PricewaterhouseCoopers AB | 55 | 7 |
| Total PwC | 595 | 586 |
| Out of which to PricewaterhouseCoopers AB | 279 | 269 |
| Remuneration to other auditors than PwC | 65 | 79 |
| Total audit fees excluding fees for IPC spin-off | 660 | 665 |
| Out of which to PricewaterhouseCoopers AB | 279 | 269 |
| Fees PwC for IPC spin-off | – | 471 |
| Out of which to PricewaterhouseCoopers AB | – | – |
| Total audit fees | 660 | 1,136 |
| Out of which to PricewaterhouseCoopers AB | 279 | 269 |
Audit fees include the review of the 2018 half year report. Audit related costs include special assignments such as licence audits and PSC audits.
In January 2019, Lundin Petroleum entered into a sales and purchase agreement involving the acquisition of Lime Petroleum's 30 percent working interest in each of PL338C and PL338E and 20 percent working interest in PL815, which contain the Rolvsnes oil discovery and Goddo prospect. The transaction will increase the Company's working interest in each of PL338C and PL338E to 80 percent and in PL815 to 60 percent. The transaction involves a cash consideration payable to Lime Petroleum of MUSD 43 and a contingent payment of an additional MUSD 2 which potentially becomes payable 12 months after the completion date of the transaction. The transaction is subject to customary government approvals.
In February 2019, the drilling of the exploration wells Gjøkåsen Shallow in PL857, Pointer/Setter in PL767 and Froskelår Main in PL869 was completed. For more information on the results of these wells, see pages 45–46 of the Directors' 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 1,657.8 (MSEK 46,648.6) for the year. The net result for the year included MSEK 1,812.4 (MSEK 238.6) fi nancial income as a result of received dividends from a subsidiary. The net result for the comparative period also included MSEK 46,542.9 fi nancial income as a result of an internal restructuring prior to the IPC spin-off in 2017. The result excluding these fi nancial income items amounts to MSEK -154.6 (MSEK -132.9).
The net result included general and administrative expenses of MSEK 180.9 (MSEK 146.7) and net fi nance income of MSEK 5.3 (MSEK 4.4) when excluding the fi nance income items as mentioned above.
Pledged assets of MSEK 55,118.9 (MSEK 55,118.9) relate to the carrying value of the pledge of the shares in respect of the reserve-based credit 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.
The Swedish Prosecution Authority issued a notifi cation of a corporate fi ne and forfeiture of economic benefi ts against Lundin Petroleum in relation to past operations in Sudan from 1997 to 2003. The notifi cation indicated that the Prosecutor might seek a corporate fi ne of MSEK 3 and forfeiture of economic benefi ts from the alleged offense in the amount of MSEK 3,282, based on the profi t of the sale of the Block 5A asset in 2003 of MSEK 720. Any potential corporate fi ne or forfeiture would only be imposed after the conclusion of a trial, should one occur. The investigation is in its ninth year and Lundin Petroleum remains convinced that there are absolutely no grounds for any allegations of wrongdoing by any Company representative and the Company will fi rmly contest any corporate fi ne or forfeiture of economic benefi ts. The Company considers this to be a contingent liability and therefore no provision has been recognised.
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 58–63.
for the Financial Year Ended 31 December
| Expressed in MSEK | Note | 2018 | 2017 |
|---|---|---|---|
| Revenue | 21.0 | 9.4 | |
| General and administration expenses | -180.9 | -146.7 | |
| Operating loss | -159.9 | -137.3 | |
| Result from fi nancial investments | |||
| Finance income | 1 | 1,818.1 | 46,786.4 |
| Finance cost | 2 | -0,4 | -0.5 |
| 1,817.7 | 46,785.9 | ||
| Profi t/loss before tax | 1,657.8 | 46,648.6 | |
| Income tax | 3 | – | – |
| Net result | 1,657.8 | 46,648.6 |
| Expressed in MSEK | 2018 | 2017 |
|---|---|---|
| Net result | 1,657.8 | 46,648.6 |
| Other comprehensive income | – | – |
| Total comprehensive income | 1,657.8 | 46,648.6 |
| Attributable to: | ||
| Shareholders of the Parent Company | 1,657.8 | 46,648.6 |
| 1,657.8 | 46,648.6 |
| ASSETS | |
|---|---|
| Non-current assets | |
| Shares in subsidiaries 55,118.9 |
55,118.9 |
| Other tangible fi xed assets 9 0.4 |
– |
| Total non-current assets 55,119.3 |
55,118.9 |
| Current assets | |
| Prepaid expenses and accrued income 1.8 |
1.5 |
| Other receivables 4 3.6 |
6.0 |
| Cash and cash equivalents 29.5 |
4.8 |
| Total current assets 34.9 |
12.3 |
| TOTAL ASSETS 55,154.2 |
55,131.2 |
| 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 6,479.7 |
6,599.2 |
| Retained earnings 46,118.5 |
824.0 |
| Net result 1,657.8 |
46,648.6 |
| Total unrestricted equity 54,256.0 |
54,071.8 |
| Total equity 55,120.8 |
54,936.6 |
| Non-current liabilities | |
| Provisions 0.7 |
0.6 |
| Total non-current liabilities 0,7 |
0.6 |
| Current liabilities | |
| Trade payables 5.8 |
3.0 |
| Payables to Group companies 21.5 |
181.9 |
| Accrued expenses and prepaid income 5 3.4 |
8.7 |
| Other liabilities 2.0 |
0.4 |
| Total current liabilities 32.7 |
194.0 |
| TOTAL EQUITY AND LIABILITIES 55,154.2 |
55,131.2 |
for the Financial Year Ended 31 December
| Expressed in MSEK | 2018 | 2017 |
|---|---|---|
| Cash fl ow from operations | ||
| Net result | 1,657.8 | 46,648.6 |
| Adjustment for | ||
| Foreign currency exchange loss | -5.7 | -1.6 |
| Internal restructuring | – | -46,606.6 |
| Other | 0.9 | – |
| Changes in working capital: | ||
| Changes in current assets | 2.1 | 13.2 |
| Changes in current liabilities | -162.0 | 176.0 |
| Total cash fl ow from operations activities | 1,493.1 | 229.6 |
| Cash fl ow from investing activities | ||
| Investments in other fi xed assets | -0.4 | – |
| Total cash fl ow from investing activities | -0.4 | – |
| Cash fl ow from fi nancing activities | ||
| Dividends paid | -1,354.1 | – |
| Purchase of own shares | -119.5 | -229.6 |
| Total cash fl ow from fi nancing activities | -1,473.6 | -229.6 |
| Change in cash and cash equivalents | 19.1 | – |
| Cash and cash equivalents at the beginning of the year | 4.8 | 3.2 |
| Currency exchange difference in cash and cash equivalents | 5.6 | 1.6 |
| Cash and cash equivalents at the end of the year | 29.5 | 4.8 |
| Restricted Equity | Unrestricted Equity | |||||
|---|---|---|---|---|---|---|
| Expressed in MSEK | Share capital |
Statutory reserve |
Other reserves |
Retained earnings |
Total | Total equity |
| Balance at 1 January 2017 | 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 |
| Distribution of IPC assets | – | – | – | -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 |
| Total comprehensive income | – | – | – | 1,657.8 | 1,657.8 | 1,657.8 |
| Transactions with owners | ||||||
| Purchase of own shares | – | – | -119.5 | – | -119.5 | -119.5 |
| Cash distributions | – | – | – | -1,354.1 | -1,354.1 | -1,354.1 |
| Total transactions with owners | – | – | -119.5 | -1,354.1 | -1,473.6 | -1,473.6 |
| Balance at 31 December 2018 | 3.5 | 861.3 | 6,479.7 | 47,776.3 | 54.256.0 | 55.120.8 |
of the Parent Company
| MSEK | 2018 | 2017 |
|---|---|---|
| Result on internal restructuring | – | 46,542.9 |
| Dividend | 1,812.4 | 238.6 |
| Guarantee fees | – | 3.3 |
| Foreign exchange gain | 5.7 | 1.6 |
| 1,818.1 | 46,786.4 |
The result on the internal restructuring in 2017 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 | 2018 | 2017 |
|---|---|---|
| Interest expenses Group | – | 0.5 |
| Other | 0.4 | – |
| 0.4 | 0.5 |
| MSEK | 2018 | 2017 |
|---|---|---|
| Net result before tax | 1,657.8 | 46,648.6 |
| Tax calculated at the corporate tax rate in Sweden 22% (22%) |
-364.7 | -10,262.7 |
| Tax effect of received dividend | 398.7 | 12,076.9 |
| Tax effect of expenses non-deductible for tax purposes |
-3.6 | -1,775.7 |
| Increase unrecorded tax losses | -30.4 | -38.5 |
| – | – |
| MSEK | 31 December 2018 |
31 December 2017 |
|---|---|---|
| Due from Group companies | 0.2 | 0.7 |
| VAT receivable | 1.2 | 1.2 |
| Other | 2.2 | 4.1 |
| 3.6 | 6.0 |
| MSEK | 31 December 2018 |
31 December 2017 |
|---|---|---|
| Social security costs | 1.1 | 1.5 |
| Directors fees | 0.6 | 1.3 |
| Audit fees | 1.1 | 0.6 |
| Outside services | 0.6 | 5.3 |
| 3.4 | 8.7 |
Pledged assets relate to the carrying value of the pledge of the shares in respect of the reserve-based credit facility entered into by the wholly-owned subsidiary Lundin Petroleum Holding BV, see Note 24 in the notes to the fi nancial statements of the Group.
| MSEK | 2018 | 2017 |
|---|---|---|
| PwC | ||
| Audit fees | 1.8 | 2.1 |
| Audit related | 0.1 | 0.1 |
| Other fees | 0.5 | – |
| 2.4 | 2.2 |
There has been no remuneration to any auditors other than PricewaterhouseCoopers AB.
The 2019 Annual General Meeting has an unrestricted equity at its disposal of MSEK 54,256.0, including the net result for the year of MSEK 1,657.8.
In accordance with the updated dividend policy, the Board of Directors propose that the Annual General Meeting resolves on a dividend for 2018 of USD 1.48 per share, corresponding to USD 500 million (rounded off), to be paid in quarterly instalments of USD 0.37 per share, corresponding to USD 125 million (rounded off). Before payment, each quarterly dividend of USD 0.37 per share shall be converted into a SEK amount, and paid out in SEK, based on the USD to SEK exchange rate published by Sweden's central bank (Riksbanken) four business days prior to each record date (rounded off to the nearest whole SEK 0.01 per share). The fi nal USD equivalent amount received by the shareholders may therefore slightly differ depending on what the USD to SEK exchange rate is on the date of the dividend payment. The SEK amount per share to be distributed each quarter will be announced in a press release four business days prior to each record date.
The fi rst dividend payment is expected to be paid around 5 April 2019, with an expected record date of 2 April 2019 and expected ex-dividend date of 1 April 2019. The second dividend payment is expected to be paid around 8 July 2019, with an expected record date of 3 July 2019 and expected ex-dividend date of 2 July 2019. The third dividend payment is expected to be paid around 7 October 2019, with an expected record date of 2 October 2019 and an expected ex-dividend date of 1 October 2019. The fourth dividend payment is expected to be paid around 9 January 2020, with an expected record date of 3 January 2020 and an expected ex-dividend date of 2 January 2020.
In order to comply with Swedish company law, a maximum total SEK amount shall be pre-determined to ensure that the dividend distributed does not exceed the available distributable reserves of the Company and such maximum amount for the 2018 dividend has been set to a cap of SEK 7.665 billion (i.e., SEK 1.916 billion per quarter). If the total dividend would exceed the cap of SEK 7.665 billion, the dividend will be automatically adjusted downwards so that the total dividend corresponds to the cap of SEK 7.665 billion.
Based on the above, the Board of Directors propose that the Annual General Meeting dispose of the unrestricted equity as follows:
| MSEK | |
|---|---|
| The Board of Directors proposes that the shareholders are paid a dividend of USD 1.48 per share 1 | 4,666.0 |
| Brought forward | 49,590.0 |
| Unrestricted equity | 54,256.0 |
1 The amount is based on the USD to SEK exchange rate published by Sweden's central bank (Riksbanken) as at 25 February 2019. The amount is based on the number of shares in circulation on 25 February 2019 and the total dividend amount may change by the record dates as a result of repurchases of own shares or as a result of issue of new shares. The dividend is USD denominated, fl uctuations in the USD to SEK exchange rate between 25 February 2019 and approval of the dividend proposal by the Annual General Meeting will have an impact on the total dividend amount reported in SEK. If the dividend proposal is approved by the Annual General Meeting, the dividend will be recorded as a liability in USD on the date of the Annual General Meeting and the SEK equivalent of the USD liability will fl uctuate until the fourth tranche is converted from USD to SEK.
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.
| MSEK | Registration number |
Registered offi ce | Total number of shares issued |
Percentage owned |
Nominal value per share |
Book amount 31 Dec 2018 |
|---|---|---|---|---|---|---|
| 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 1 March 2019, the Board of Directors and the President of Lundin Petroleum AB have adopted this annual report for the fi nancial year ended 31 December 2018.
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, 1 March 2019
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
Torstein Sanness Board Member
Grace Reksten Skaugen Board Member
Jakob Thomasen Board Member
Cecilia Vieweg Board Member
Our audit report was issued on March 4, 2019
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 2018. The annual accounts and consolidated accounts of the company are included on pages 40–95 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 2018 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 2018 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.
Therefore, we 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 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 primarily have been located in Norway during the fi nancial year 2018. 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 on two occasions during 2018 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, 2018 and after the year-end audit of the fi nancial year 2018.
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. 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.
Recoverability of the carrying value of oil and gas properties and goodwill
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 5,341 (MUSD 4,937) as per 31 December 2018.
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 non-producing 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, current 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 is fundamental to the impairment assessment of oil and gas properties, but is also an indicator of the future potential of the Group's performance.
Following the analysis of impairment indicators management concluded that there were no 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 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 2018.
For non-producing fi elds the company has written off MUSD 53 during the year as exploration costs.
Refer to pages 48–50 in the Directors' report, page 59-60 and 63 in the Accounting Policies and note 10 in the fi nancial statements for more information.
We obtained management's impairment indicator assessment and impairment test as per 31 December 2018 for producing fi elds and the technical goodwill related to the Edvard Grieg cash generating unit. There was signifi cant headroom in the goodwill impairment test mainly as a result of an upward revision in reserves and improved price assumptions. No impairment indicators were identifi ed for producing fi eld, and consequently our procedures were limited to audit procedures on management's impairment indicator assessment for producing fi elds and assessing changes in signifi cant assumptions in the goodwill impairment test.
As part of our internal controls work, we evaluated and challenged management's assessment and controls over determining the impairment indicators and the process by which this was performed.
Our internal controls testing supported management's conclusion that no impairment indicators are triggering the need for impairment tests for the Company's producing oil and gas assets as per 31 December 2018. In respect of the impairment model applied by management for goodwill impairment testing, 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 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. Our audit work included but was not limited to:
For non-producing oil and gas properties we obtained a listing of capitalized exploration expenditures by fi eld area cost centre basis (fi eld) as of 31 December 2018. We tested Management's internal controls for assessing continued capitalisation of non-producing oil and gas properties. Furthermore, we tested the mathematical accuracy of this listing and reconciled the listing to the general ledger. We then assessed and challenged the continued capitalization of exploration expenditures by assessing the underlying documentation prepared by management for each of the fi elds and discussing 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, publicly available information, progress reporting in the joint venture, future plans and/or well commitments.
| Key audit matter | How our audit addressed the Key audit matter |
|---|---|
| Recognition and valuation of current taxes and deferred taxes 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 2018 the current and deferred income tax expense amounted to MUSD 1,026 (MUSD 501) of which MUSD 935 (MUSD 502) related to a deferred tax expense. The Group has recognised a net deferred tax liability of MUSD 2,103 at December 31, 2018 (MUSD 1,302) 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. Refer to pages 49–50 in the Directors' report, pages 62–63 in the Accounting Policies and note 7 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 controls over the detailed tax calculation, 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 mathematical accuracy of the tax calculations and formulas applied. We reconciled book and tax positions as of Dec 31, 2018 and Dec 31, 2017 used in the calculation to underlying documentation. Furthermore, we tested the reconciliation of the effective rate to underlying documentation. Uncertain tax positions were examined based on the application of tax regulations and by reviewing any correspondence with tax authorities, documentation provided by the Company supporting their position and legal opinion by their advisors. |
| Estimation of decommissioning and site restoration provisions The Group has recognised site restoration provisions in the amount of MUSD 490 as of December 31, 2018 (MUSD 415). 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 50 in the Directors' report, pages 61 and 63 in the Accounting Policies and note 19 in the fi nancial statements for more information. |
We critically assessed management's annual review of site restoration provisions recorded. The provisions contains estimates from both operated assets and non-operated assets. 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. In addition, for non-operated assets we have assessed the competence 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. |
This document also contains other information than the annual accounts and consolidated accounts and is found on pages 1–21 and 101–107. The Board of Directors and the Chief Executive Offi cer 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 Chief Executive Offi cer 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 Chief Executive Offi cer 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 Chief Executive Offi cer 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 Chief Executive Offi cer intend 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 Director's and the Chief Executive Offi cer of Lundin Petroleum AB (publ) for the year 2018 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 Director's and the Chief Executive Offi cer 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.
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' 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 Chief Executive Offi cer 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:
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, 4 March 2019
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. Lundin Petroleum believes that that the alternative performance measures provide useful supplement information to management, investors, security analysts and other stakeholders and are meant to provide an enhanced insight into the fi nancial development of Lundin Petroleum's business operations and to improve comparability between periods. Reconciliations of relevant alternative performance measures are provided on the following page. Defi nitions of the performance measures are provided under the key ratio defi nitions below.
| Financial data from continuing operations MUSD |
2018 | 2017 | 2016 | 2015 | 2014 |
|---|---|---|---|---|---|
| Revenue and other income | 2,617.4 | 1,997.0 | 950.0 | 380.3 | 627.2 |
| EBITDA1 | 1,916.2 | 1,501.5 | 752.5 | 246.3 | 570.9 |
| Net result | 222.1 | 380.9 | -399.3 | -679.7 | -414.8 |
| Operating cash fl ow1 | 1,847.8 | 1,530.0 | 857.9 | 558.1 | 1,046.9 |
| Free cash fl ow | 663,0 | 203.7 | -328.2 | -1,035.2 | -1,205.5 |
| Data per share from continuing operations USD |
|||||
| Shareholders' equity per share | -1,13 | -1.03 | -0.70 | -1.61 | 1.40 |
| Operating cash fl ow per share | 5.46 | 4.50 | 2.63 | 1.81 | 3.39 |
| Cash fl ow from operations per share | 5.07 | 3.82 | 2.05 | 0.77 | 1.43 |
| Earnings per share | 0.66 | 1.13 | -0.79 | -2.18 | -1.33 |
| Earnings per share fully diluted | 0.66 | 1.13 | -0.79 | -2.18 | -1.33 |
| EBITDA per share | 5.65 | 4.41 | 2.31 | 0.80 | 1.85 |
| EBITDA per share fully diluted | 5.64 | 4.40 | 2.30 | 0.79 | 1.84 |
| Dividend per share | 0.45 | 1.21 | – | – | – |
| Number of shares issued at year end | 340,386,445 | 340,386,445 | 340,386,445 | 311,070,330 | 311,070,330 |
| Number of shares in circulation at year end | 338,513,135 | 339,153,135 | 340,386,445 | 309,070,330 | 309,070,330 |
| Weighted average number of shares for the year | 338,592,250 | 340,237,772 | 325,808,486 | 309,070,330 | 309,170,986 |
| Weighted average number of shares for the year fully diluted |
339,513,634 | 341,380,316 | 326,738,233 | 310,019,890 | 309,475,038 |
| Share price | |||||
| Share price in SEK | 221.40 | 187.80 | 198.10 | 122.60 | 112.40 |
| Share price in USD 2 | 24.72 | 22.88 | 21.86 | 14.52 | 14.53 |
| Key ratios from continuing operations (%) | |||||
| Return on equity 3 | – | – | – | – | -48 |
| Return on capital employed | 47 | 22 | -9 | -19 | -8 |
| Net debt/equity ratio 3 | – | – | – | – | 605 |
| Net debt/EBITDA ratio 4 | 1.8 | 2.6 | 5.4 | 15.4 | 4.6 |
| Equity ratio | -7 | -6 | -17 | -10 | 9 |
| Share of risk capital | 29 | 17 | -3 | 1 | 28 |
| Interest coverage ratio | 17 | 6 | -2 | -8 | -10 |
| Operating cash fl ow/interest ratio | 21 | 12 | 5 | 7 | 45 |
| Yield | 2 | 5 | 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 Share price at period end in USD is calculated based on quoted share price in SEK and applicable SEK/USD exchange rate as per period end.
3 As the equity at 31 December 2018, 31 December 2017, 31 December 2016 and 31 December 2015 is negative, these ratios have not been calculated.
4 Net debt/EBITDA ratio is calculated using the EBITDA of the last four quarters.
| EBITDA MUSD |
2018 | 2017 | 2016 | 2015 | 2014 |
|---|---|---|---|---|---|
| Operating profi t | 1,402.4 | 812.4 | -244.7 | -588.7 | -193.9 |
| Add: depletion of oil and gas properties | 458.0 | 568.4 | 386.2 | 159.1 | 88.5 |
| Add: exploration costs | 53.2 | 73.1 | 101.9 | 146.5 | 272.2 |
| Add: impairment costs of oil and gas properties | – | 30.6 | 506.1 | 526.0 | 400.7 |
| Add: loss from sale of assets | – | 14.4 | – | – | – |
| Add: depreciation of other tangible assets | 2.6 | 2.6 | 3.0 | 3.4 | 3.4 |
| EBITDA | 1,916.2 | 1,501.5 | 752.5 | 246.3 | 570.9 |
| Operating cash fl ow MUSD |
|||||
| Revenue and other income | 2,617.4 | 1,997.0 | 950.0 | 380.3 | 627.2 |
| Minus: production costs | -145.4 | -164.2 | -168.4 | -104.6 | -11.3 |
| Minus: purchase of crude oil from third parties | -533.8 | -303.3 | -2.1 | – | – |
| Minus: current taxes | -90.4 | 0.5 | 78.4 | 282.4 | 431.0 |
| Operating cash fl ow | 1,847.8 | 1,530.0 | 857.9 | 558.1 | 1,046.9 |
| Free cash fl ow MUSD |
|||||
| Cash fl ows from operating activities | 1,718.3 | 1,299.3 | 668.7 | 238.0 | 442.1 |
| Minus: cash fl ows from investing activities | -1,055.3 | -1,095.6 | -996.9 | -1,273.2 | -1,647.6 |
| Free cash fl ow | 663.0 | 203.7 | -328.2 | -1,035.2 | -1,205.5 |
| Net debt MUSD |
|||||
| Bank loans | 3,465.0 | 3,955.0 | 4,145.0 | 3,858.0 | 2,690.0 |
| Minus: cash and cash equivalents | -66.8 | -71.4 | -69.5 | -71,9 | -80,5 |
Net debt 3,398.2 3,883.6 4,075.5 3,786.1 2,609.5
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 and other income less production costs less purchase of crude oil from third parties and less current taxes.
Cash fl ow from operating activities less cash fl ow from investing activities in accordance with the consolidated statement of cash fl ow.
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.
EBITDA divided by the weighted average number of shares for the year after considering any dilution effect.
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.
Bank loan less cash and cash equivalents divided by EBITDA.
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 | 2018 | 2017 | 2016 | 2015 | 2014 |
|---|---|---|---|---|---|
| Revenue from own production | 2,071.8 | 1,654.8 | 973.8 | 347.6 | 591.1 |
| Revenue from third party activities | 536.1 | 303.5 | 2.1 | – | – |
| Other income | 9.5 | 38.7 | -25.9 | 32.7 | 36.1 |
| Production costs | -145.4 | -164.2 | -168.4 | -104.6 | -11.3 |
| Depletion and decommissioning costs | -458.0 | -567.3 | -386.2 | -159.1 | -88.5 |
| Exploration costs | -53.2 | -73.1 | -101.9 | -146.5 | -272.2 |
| Impairment costs of oil and gas properties | – | -30.6 | -506.1 | -526.0 | -400.7 |
| Loss from sale of assets | – | -14.4 | – | – | – |
| Other cost of sales | -533.8 | -303.3 | -2.1 | – | – |
| Gross profi t/loss | 1,427.0 | 844.1 | -214.7 | -555.9 | -145.5 |
| General, administration and depreciation expenses | -24.6 | -31.7 | -30.0 | -32.8 | -48.4 |
| Operating profi t/loss | 1,402.4 | 812.4 | -244.7 | -588.7 | -193.9 |
| Net fi nancial items | -153.2 | 70.1 | -218.8 | -670.9 | -480.0 |
| Share in result of associated company | -1.3 | -0.4 | – | – | – |
| Profi t/loss before tax | 1,247.9 | 882.1 | -463.5 | -1,259.6 | -673.9 |
| Income tax | -1,025.8 | -501.2 | 64.2 | 579.9 | 259.1 |
| Net result from continuing operations | 222.1 | 380.9 | -399.3 | -679.7 | -414.8 |
| Net result from discontinued operations | – | 46.5 | -100.0 | -186.6 | -17.1 |
| Net result | 222.1 | 427.4 | -499.3 | -866.3 | -431.9 |
| Net result attributable to the shareholders | |||||
| of the Parent Company: | 222.1 | 431.2 | -356.7 | -861.7 | -427.2 |
| Net result attributable to non-controlling interest: | – | -3.8 | -142.6 | -4.6 | -4.7 |
| Net result | 222.1 | 427.4 | -499.3 | -866.3 | -431.9 |
| Balance sheet summary MUSD |
2018 | 2017 | 2016 | 2015 | 2014 |
|---|---|---|---|---|---|
| Tangible fi xed assets | 5,354.7 | 4,950.3 | 4,542.5 | 4,219.7 | 4,382.9 |
| Other non-current assets | 131.2 | 161.3 | 168.0 | 24.1 | 49.9 |
| Current assets | 356.6 | 417.2 | 491.6 | 541.5 | 659.2 |
| Total assets | 5,842.5 | 5,528.8 | 5,202.1 | 4,785.3 | 5,092.0 |
| Shareholders' equity | -384.0 | -350.8 | -238.6 | -498.2 | 431.5 |
| Non-controlling interest | – | – | -113.6 | 24.1 | 34.2 |
| Total equity | -384.0 | -350.8 | -352.2 | -474.1 | 465.7 |
| Non-current provisions | 2,657.0 | 1,725.9 | 1,119.1 | 970.5 | 1,295.2 |
| Non-current liabilities | 3,262.0 | 3,880.0 | 4,082.1 | 3,867.0 | 2,683.1 |
| Current liabilities | 307.5 | 273.7 | 353.1 | 421.5 | 648.0 |
| Total shareholders'equity and liabilities | 5,842.5 | 5,528.8 | 5,202.1 | 4,785.3 | 5,092.0 |
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 2018 | 695.7 | 183.6 |
| Changes during the year | ||
| Revisions | 29.7 | 21.9 |
| Extensions and new projects 3 | 17.8 | -12.2 |
| Production | -27.4 | -15.8 |
| 31 December 2018 | 715.8 1 | 177.5 |
1 The year end 2018 2P oil reserves reported include 17.9 MMbbl of NGL's.
2 The factor of 6,000 is used by the Company to convert one scf to one boe.
3 Extensions and new projects include new fi elds but also new improved oil recovery (IOR) projects on existing fi elds. In 2018, the Johan Sverdrup water alternating gas (WAG) project was promoted to reserves representing an increase in recoverable oil, but a decrease in recoverable gas.
| Proved plus probable plus possible reserves (3P) from continuing operations |
Norway oil reserves MMbbl |
Norway gas reserves Bn scf 2 |
|---|---|---|
| 1 January 2018 | 856.3 | 235.6 |
| Changes during the year | ||
| Revisions | 10.5 | 22.3 |
| Extensions and new projects 3 | 23.5 | -14.3 |
| Production | -27.4 | -15.8 |
| 31 December 2018 | 862.9 1 | 227.8 |
1 The year end 2018 3P oil reserves reported include 22.0 MMbbl of NGL's.
2 The factor of 6,000 is used by the Company to convert one scf to one boe.
3 Extensions and new projects include new fi elds but also new improved oil recovery (IOR) projects on existing fi elds. In 2018, the Johan Sverdrup water alternating gas (WAG) project was promoted to reserves representing an increase in recoverable oil, but a decrease in recoverable gas.
Lundin Petroleum estimates 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 |
| Mbopd | Thousand barrels of oil 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 |
| 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 2019 | Three month report (January–March 2019) |
|---|---|
| · 31 July 2019 | Six month report (January–June 2019) |
| · 31 October 2019 | Nine month report (January–September 2019) |
| · 31 January 2020 | 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 Friday 29 March 2019 at 13.00 (Swedish time). Location: Vinterträdgården, Grand Hôtel, Södra Blasieholmshamnen 8 in Stockholm.
Shareholders wishing to attend the meeting shall:
When registering please indicate your name, social security number/company registration number, registered shareholding, address and day time telephone number.
Shareholders whose shares are registered in the name of a nominee must temporarily register, through the nominee, the shares in their own names in order to be entitled to attend the Annual General Meeting. Since the record date is on Saturday 23 March 2019, such registration must be effected by Friday 22 March 2019, at the latest.
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 CET on 6 March 2019.
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.
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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.
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 W lundin-petroleum.com
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