Annual Report • Apr 12, 2017
Annual Report
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| Our business model | 2 |
|---|---|
| Looking back 2016 | 4 |
| Looking forward 2017 | 5 |
| CEO review | 6 |
| Chairman's statement Sustainable growth |
8 10 |
| Oil market | 12 |
| Share and shareholders | 14 |
| Operations | |
| COO overview | 16 |
| Production, reserves and resources | 18 |
| Norway | 22 |
| Malaysia | 30 |
| Continental Europe | 32 |
| IPC Spin-off | 34 |
| Risk | |
| Risk management | 36 |
| Responsibility | |
| VP Corporate Responsibility overview | 42 |
| People | 44 |
| Health and safety | 46 |
| Environment | 47 |
| Ethical business conduct | 48 |
| Governance | |
| Corporate governance report 2016 | 50 |
| Financial Report | |
| Contents of financial report | 71 |
| CFO overview | 72 |
| Additional Information | |
| Key financial data | 129 |
| Key ratio definitions | 130 |
| Five year financial data | 131 |
| Reserve quantity information | 132 |
| Definitions and abbreviations | 133 |
| HSE indicator data | 134 |
| Share data | 135 |
| Shareholder information | 136 |
References to "Lundin Petroleum" or "the
Company" pertain to the corporate group in which Lundin Petroleum AB (publ) (company registration number 556610–8055) is the Parent Company or to Lundin Petroleum AB (publ), depending on the
References to "International Petroleum Corporation" or "the IPC assets" pertain to the spinoff of the Company's assets in Malaysia, France and which was approved by the Extraordinary General Meeting held on 22 March 2017.
Lundin Petroleum achieved record high production in 2016, largely due to the robust performance of the operated Edvard Grieg field, while at the same time significantly reducing the cash operating costs.
| » Production | page 18 |
|---|---|
| » Edvard Grieg | page 24 |
Lundin Petroleum contributes to finding solutions for a more energy efficient and low carbon society. In 2016 we managed to reduce our carbon emission intensity level below the industry average in Norway.
| » Sustainable growth | page 10 | |
|---|---|---|
| » Environment | page 47 |
In 2016, significant cost reductions were achieved on the Johan Sverdrup project in addition to increased Phase 1 and 2 production capacities and an increase in resources. The project remains on schedule to start production in late 2019.
» Johan Sverdrup page 25
We continue to believe that our organic growth strategy is the best way to create long-term sustainable value. Our exploration programme for 2017 is primarily focused on the southern Barents Sea and includes some high impact exploration targets, in our search for the "next elephant".
| » Southern Barents Sea | page 28 |
|---|---|
| » Searching for the next elepant | page 29 |
| · Record high production and record low cash operating costs | page 18 |
|---|---|
| · Reserves replacement ratio of 208% | page 19 |
| · Successful appraisal well on Alta discovery | page 28 |
| · Significant success in 23rd licensing round in Norway | page 23 |
| · Value accretive acquisition of an extra 15% interest in Edvard Grieg | page 24 |
| · New USD 5.0 billion reserve-based lending facility signed | page 72 |
| · Improved KPIs for health and safety | page 46 |
Lundin Petroleum is the leading independent oil and gas company in Europe with a strategic focus on Norway.
Lundin Petroleum seeks to generate sustainable long-term value in all stages of the upstream oil and gas value chain. Lundin Petroleum has developed the capacity and competence to take exploration success through to the production phase and we retain our standing in the industry as one of the strongest players to capitalise on further growth.
Lundin Petroleum's business model is to generate sustainable value throughout the value chain
Lundin Petroleum focuses on building core exploration areas and on assembling integrated teams of geoscientists and technical experts that have a creative and visionary approach to finding oil and gas resources. Lundin Petroleum will focus its near-term exploration and appraisal activity in the southern Barents Sea, appraising the Alta and Gohta discoveries and exploring some high impact exploration targets.
Following exploration and appraisal, the strategy is to convert discoveries into reserves and production. After a development plan has been approved, construction of facilities can start, to which wells and infrastructure are connected so that production can begin. As a partner, Lundin Petroleum is involved in the ongoing construction of oil and gas production facilities on the giant Johan Sverdrup project in Norway.
The production phase is defined as everything from extraction and processing to delivering the oil or gas for sale. Lundin Petroleum significantly increased its production in 2016, due to the ramp-up of production from its Edvard Grieg facility and strong ongoing performance at the Alvheim area in Norway and the Bertam field in Malaysia.
Discovering, developing and producing oil and gas resources creates long-term sustainable value for Lundin Petroleum's shareholders and society as a whole.
Our vision is to grow a profitable upstream exploration and production company, focused on core areas in a safe and environmentally responsible manner for the long-term benefit of our shareholders and society.
| Financial performance | 2016 | 2015 |
|---|---|---|
| Average Brent oil price | USD 43.7/boe | USD 52.4/boe |
| Cash operating costs | USD 7.8/boe | USD 11.6/boe |
| EBITDA | MUSD 902.6 | MUSD 384.7 |
| Operating cash flow | MUSD 1,010.8 | MUSD 699.6 |
| Sustainability performance | 2016 | 2015 |
|---|---|---|
| Fatalities | 1 | 0 |
| Oil spills | 0 | 0 |
| LTI rate | 0.67 | 1.76 |
1 excluding IPC assets
We have seen record production levels achieved with over 72,000 boepd produced for the year at a record low cash operating cost of USD 7.80 per barrel
With 2016 now behind us we can confidently say that it is mission accomplished. 2016 has been an outstanding year for Lundin Petroleum. We have seen record production levels achieved with over 72,000 boepd produced for the year at a record low cash operating cost of USD 7.80 per barrel. This is primarily on the back of the excellent performance of the Edvard Grieg field that came onstream in November 2015, in addition to the continued robust performance from our core producing assets that have delivered ahead of expectation. However, our net result for the year was impacted by a non-cash after tax impairment charge of MUSD 548.6 following the decision taken to remove the booked contingent resources associated with discoveries in Russia and in Malaysia. This impairment charge does not impact the cash flow generation of the Company.
We have seen the reserves in Edvard Grieg increasing from the original PDO estimate of 186 MMboe to 223 MMboe and we all know that big fields tend to get bigger. In February 2017, we commenced drilling of a further appraisal well which has the potential to increase reserves.
The year was further marked by the acquisition of an additional 15 percent equity in Edvard Grieg from Statoil. This transaction not only increased our production and reserves but also strengthened our financial position further by improving an already very solid liquidity position following the signing of the USD 5.0 billion reserve-based lending facility earlier in 2016.
At the same time, our largest development project Johan Sverdrup continues to deliver good news with lower project costs, higher increased production capacity and a reserves increase when compared to the original PDO estimates.
We have also seen our southern Barents Sea exploration strategy unfolding with the highly anticipated 23rd licensing round awards. We were very pleased to be one of the most successful companies in this 23rd round and our ongoing 2017 exploration activity has the potential to add significant resources.
Over the years, Norway has become the principal focus area for the Company with the majority of its reserves, resources and production. The logical next step to provide more visibility and renewed attention to our non-Norwegian assets is to spin-off these assets into the new independent company International Petroleum Corporation (IPC). Strategically, Lundin Petroleum becomes a fully Norway focused company with continued great opportunities in terms of organic growth and new development projects. At the same time, IPC will have a wellestablished production and cash flow base to grow from with an acquisition and organic growth led strategy. The timing for the spin-off could not be better considering the cyclic nature of our business. I am also pleased to see Mike Nicholson take the position as CEO for IPC and I am convinced that he and his team will do a great job by growing this exciting new company into a significant E&P player.
I am convinced that what lies ahead of us will be as equally exciting as 2016. In 2017 we will continue to see our production increasing while on the project development side, we will have the most active year ever with Johan Sverdrup Phase 1 project execution. It will also be the year when the concept will be selected for Phase 2 of the Johan Sverdrup project and we progress towards the execution phase.
In parallel, we will be drilling some world class exploration targets in the southern Barents Sea while continuing to work on an appraisal programme in our Alta and Gohta discoveries. Work towards development concept selection studies for Alta, Gohta and Luno II discoveries will be a priority.
With delivery of our committed projects we will see our production level reach in excess of 120,000 boepd by the time Johan Sverdrup Phase 1 comes onstream. By the time Johan Sverdrup Phase 2 reaches plateau our production will reach in excess of 150,000 boepd. We also expect that we will do better with new developments in the pipeline and the new resources we will discover in the years to come.
Our health, safety and environmental track record for 2016 has also been solid and we will continue to keep a strong focus on HSE excellence as the Company grows.
Such great results would not be possible without the enthusiasm, professionalism and entrepreneurship from my colleagues and the management team. My first year as the new CEO of Lundin Petroleum has been a very rewarding one and it is all down to the great team work and team spirit that exists within the Company.
To you, fellow shareholders, the Board, and the Lundin Petroleum team, I thank you for your continued support.
Yours Sincerely,
Alex Schneiter President and CEO
Lundin Petroleum is now in a stronger position than ever to pursue further organic growth in Norway
2016 was truly a record breaking year for Lundin Petroleum. The excellent operational performance across all assets generated a record high production at record low cash operating costs and on top of that Lundin Petroleum's share price hit a record high in December 2016. Development of our key Johan Sverdrup project has also progressed well during the year and this cornerstone asset will assure strong production growth for Lundin Petroleum in years to come.
If 2016 was an extremely eventful year, rest assured that 2017 will be even more exciting. Early in the year, we announced the spin-off of Lundin Petroleum's non-Norwegian assets into a new company, with a name that reflects our entrepreneurial legacy that has led to our success today.
More than 30 years ago a small Canadian listed company called International Petroleum Corporation came into existence as a result of a consolidation of three even smaller publicly listed companies. Its only producing asset at the time was a gas condensate field in the United Arab Emirates. International Petroleum Corporation had big ambitions and soon began to acquire a substantial acreage position in Europe, Africa, the Middle East and South East Asia and at one point had operations in 12 countries with production in Oman and UK. In 1998, International Petroleum Corporation merged with the Swedish listed company Sands Petroleum and the new company was renamed Lundin Oil. In 2001, a decision was taken by the Board of Directors to sell Lundin Oil and the shareholders were offered one share of Lundin Petroleum for each share in Lundin Oil in addition to SEK 36.50 per share in cash. Lundin Petroleum had no production in 2001 but like its predecessors, it had big ambitions.
More information on Corporate Governance can be found on pages 50–70
Today Lundin Petroleum is one of the main operators and largest licence holders on the Norwegian Continental Shelf with a year end market capitalisation of more than SEK 67 billion and a share price that reached SEK 200 in December 2016, which is a 65 fold increase relative to the share price in 2001. Norway has over the years clearly become the Company's focus, with 96 percent of the reserves in Norway, and to give renewed attention to the non-Norwegian assets, the Board of Directors proposed earlier this year to spin-off these assets into a new company. Honouring our heritage, it was named International Petroleum Corporation (IPC). Following the spin-off, the IPC shares will be distributed, on a pro-rata basis, to Lundin Petroleum shareholders.
While the new IPC will seek growth opportunities across the world, Lundin Petroleum is very well positioned to continue its organic growth success in Norway. The Company stands to increase its reserve base as a result of the high exploration success rate in the southern Barents Sea and is also in a very good financial position thanks to strong production, the refinancing of the USD 5.0 billion
reserve-based lending facility and the recent recovery of the oil price. OPEC discipline will be a key factor in keeping the oil price in the USD 55 to 60 range. So far it seems that the production cuts are achieving the desired effect of reducing the stock surplus and Lundin Petroleum is now in a stronger position than ever to capture the benefits of an upturn in oil markets as we pursue further organic growth in Norway.
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This kind of success would not have been possible without the skilled, dedicated and enthusiastic people that make up the Company. I would like to take this opportunity to thank my fellow Board members, Group management and all employees for your tremendous contribution and you, fellow shareholders, for your continued support. I look forward to continuing the journey with you all for the exciting times that lie ahead.
Ian H. Lundin Chairman of the Board
In November 2016, Alex Schneiter and I were interviewed by the Swedish International Prosecution Office and were international humanitarian law in Sudan during the period 1997 to 2003, when we were active in an area called Block 5A. We are cooperating with the investigation, which has been ongoing for nearly seven years, and that we hope is now in its
I remain convinced, even more so after the recent interviews, that there are no legal grounds for any allegations of were a force for good in Sudan and encourage you to visit our dedicated website www.lundinhistoryinsudan.com which provides a detailed account of both our operations and contributions in the region.
Lundin Petroleum is built on tremendous success in Norway and we will continue to operate with the highest standards of professional and responsible conduct in order to create long-term sustainable value for our shareholders and society as a whole. I would like to express my sincere thanks to all our stakeholders for your continued support in Lundin Petroleum
Ian H. Lundin Chairman of the Board
Oil and gas products are fundamental to modern societies and are present in many aspects of our daily life. Oil continues to be the fuel of choice for power and transportation as well as a component for asphalt, pharmaceuticals, plastics and many synthetic products and consumer goods. Oil and gas provide nearly 60 percent of the world's energy supply and will continue to make up a large part of the demand for decades to come. The International Energy Agency projects the global energy demand will grow by 30 percent by 2040 and all types of energy will therefore have an important role to play.
Climate change is one of the greatest challenges of our time. Equally important is the need to ensure access to energy for continued economic development across the world that maintains and improves quality of life for all. Since oil and gas will continue to be a part of the future energy mix and underpin social and economic development, the oil and gas industry must also be part of the solution for making global energy systems sustainable for society and future generations.
Action against climate change and efforts to reduce greenhouse gas emissions do not rule out the use of oil and gas but it does require a change in the way we explore and develop it. Through the development of carbon mitigating technology and improved emission management throughout the energy value chain, oil and gas can remain part of the energy system while contributing to meet the ambitious carbon emission reduction targets the world has agreed in the Paris Agreement.
The challenge that lies ahead is to continue to develop and produce oil and gas in the most carbon efficient way possible. With a strategic focus on Norway, Lundin Petroleum operates in a country with world-leading environmental legislation and standards and with the highest carbon tax and one of the lowest carbon intensity levels in the global oil and gas industry. Since 2011, the emissions per barrel produced in Norway have been almost half as carbon intensive as the global average.
This means that we operate in a context that challenges us to continuously reduce our carbon emissions, both as a way of minimising our carbon footprint and ensuring that our asset base is robust and sustainable to meet a low carbon future. In 2016, Lundin Petroleum significantly reduced its own carbon emissions and we are now operating with a lower carbon intensity level than the industry average in Norway.
The high environmental and climate standards in Norway have encouraged the development of low-emission technologies for the oil and gas industry. Our key projects Edvard Grieg and Johan Sverdrup demonstrate how innovative technical solutions can lead to increased energy efficiency and a significant reduction in carbon emissions.
The Edvard Grieg platform was constructed using the Best Available Technique principle (BAT) which was applied in the three most carbon emitting processes: flaring, power generation and energy management. The nearby Johan Sverdrup field, which is expected to start production in late 2019, will receive power from shore from its inception and as a result, offshore emissions are estimated to be reduced by 80 to 90 percent compared with a standard development.
In addition to seeking carbon efficiency in our operations, we also take an active part in industry initiatives that seek to contribute to future low-carbon energy systems.
The oil and gas industry in Norway continuously strives to find solutions to address climate change and in August 2016 announced a co-ordinated and comprehensive roadmap to reduce greenhouse gas emissions. The road map establishes
the Norwegian oil and gas industry's ambitions to implement reduction measures from 2020 which correspond cumulatively to 2.5 million tonnes of carbon emissions by 2030, representing a significant step towards a more carbon efficient future.
This climate initiative marks a change of pace in terms of climate work. Lundin Norway has participated in the initiative from the start and will continue to contribute to its progress to ensure that the Norwegian continental shelf remains a world leader in developing and producing low carbon energy.
With the benefit of hindsight it seems obvious now that the drop in oil prices below USD 30 per barrel in January 2016 was unsustainable. The failure of OPEC to agree on output levels in November 2015 was casting a dark shadow over oil markets during 2016. Saudi Arabia in particular showed that it was not prepared to blink in its battle to retain market share relative to other higher cost producers. Saudi Arabia would no longer act in isolation as the swing producer to bring oil markets back into balance without the support of other large producers.
That firm Saudi policy started to bear fruit during 2016 with dramatic falls witnessed in the onshore US rig counts reaching record lows whilst shale production volumes fell by more than 1 million barrels per day from their peak levels. Many players announced in parallel they had shelved or deferred plans for taking higher cost projects forward.
Uncertainties did however continue through 2016 on the supply side with concerns focusing on returning Iranian and Libyan crude volumes following the easing of sanctions which appeared to grow faster than many market commentators expected. In addition, a slowing of growth in China was impacting the
demand side. That coupled with Saudi Arabia producing at record high levels and continued strong Russian production meant that the rebalancing process that was expected to commence in the second half of 2016 was deferred into 2017.
With average oil prices in 2016 down a further USD 9 per barrel from a low base in 2015, all eyes were on the OPEC meeting in late 2016. Would key producers, including Russia, adopt a new role and jointly share the burden to agree to production restraint and thereby set in motion a clearer path to rebalancing the stock overhang that had been accumulated in recent years?
The agreement to freeze OPEC production levels at 32.5 million bopd with the added restraint from other key producers gave a welcomed boost of confidence to the market and caused oil prices to rise by close to 20 percent. Attention now turns to output compliance levels and US shale production growth to ultimately determine the path forward for a medium-term to longer-term recovery in oil prices.
The other big uncertainty is the impact of the massive contraction in upstream investment seen in recent years. We
believe this may be greater than currently anticipated when one factors in underlying field declines.
Looking positively at this challenging time, the oil price shock has caused a dramatic rethink in how we can deliver value for all of our stakeholders and reset cost levels to a more sustainable basis. Significant cost inflation had beset the industry when prices stood above USD 100 per barrel. New technology and standardisation will be the key to driving productivity improvements. Some players who lost their way and added unnecessary standards and complexity during the good times are changing their ways in a move to lower the breakeven for projects going forward and that should benefit the industry as a whole.
For Lundin Petroleum, 2016 was an outstanding year with an excellent operational performance across all assets driving the Company to outperform and achieving record high production. The market environment has allowed Lundin Petroleum to capture large cost savings of around 30 percent on our key Johan Sverdrup project. In the medium-term our production will grow from 72,600 boepd in 2016 to over 150,000 boepd
when Johan Sverdrup reaches production plateau. In addition our cash operating costs will fall to below USD 5 per barrel over the same period, allowing us to generate significant free cash flow. When we combine this with our close to USD 1 billion of spare liquidity headroom, the Company is in a stronger position than ever to capture the benefits of an upturn in oil markets as we pursue further organic growth from appraising our existing discoveries and in our search for new exploration discoveries.
The Lundin Petroleum share is listed on the Large Cap list of NASDAQ Stockholm and is part of the OMX 30 index. Lundin Petroleum's share price increased by 61.6 percent during 2016, significantly outperforming both the OMX 30 index, which increased by 3.7 percent, and the USD denominated S&P Global Oil Index which increased by 24.8 percent. Since inception of the listing of Lundin Petroleum's shares in September 2001, the share price has achieved a compounded annual return up to 31 December 2016 of 31.4 percent excluding dividends.
Lundin Petroleum's market capitalisation as at 31 December 2016 was SEK 67,431 million which made Lundin Petroleum the largest independent E&P company in Europe by market capitalisation.
During 2016, a total of 301 million shares were traded on NASDAQ Stockholm to a value of approximately SEK 41.91 billion, representing an average daily trading volume of approximately 1.2 million shares per trading day. The share trading turnover during 2016 equated to approximately 92 percent of the average number of shares in issue during 2016 and approximately 1.7 times the number of shares in free float.
The registered share capital as at 31 December 2016 amounted to SEK 3,478,713 represented by 340,386,445 shares with a quota value of SEK 0.01 each (rounded off), representing one vote each. All outstanding shares are common shares and carry equal rights to participation in Lundin Petroleum's assets and earnings.
The Annual General Meeting (AGM) of Lundin Petroleum held on 12 May 2016 resolved to authorise the Board of Directors
to purchase and sell Lundin Petroleum shares up to 5 percent of the total amount of shares in issue until the next AGM. The purpose of the authorisation is to provide the Board of Directors with a means to optimise Lundin Petroleum's capital structure and to secure Lundin Petroleum's exposure in relation to its long-term incentive programmes. As per the resolutions of an Extraordinary General Meeting of Lundin Petroleum held on 30 May 2016, Lundin Petroleum issued 29,316,115 shares to Statoil and transferred 2,000,000 treasury shares to Statoil as a consideration for acquiring Statoil's 15 percent working interest in the Edvard Grieg field, in addition to receiving approximately SEK 544 million in cash. Lundin Petroleum held no treasury shares as at 31 December 2016.
At the 2016 AGM, it was resolved that the Board of Directors is authorised to issue no more than 34 million new shares, without the application of the shareholders' pre-emption rights, in order to enable the Company to raise capital for the Company's business operations and business acquisitions. If the authorisation is fully utilised the dilution effect on the share capital will amount to approximately 9.1 percent after the new issue.
Lundin Petroleum's primary objective is to add value to the shareholders, employees and society through profitable operations and growth. This will be achieved by increased reserves, developing discoveries and thereby increasing production and ultimately cash flow and operating income. This added value will be expressed partly by a long-term increase in the share price and dividends.
The size of any dividend would have to be determined by Lundin Petroleum's financial position and the possibilities for growth through profitable investments. Dividends will be paid when Lundin Petroleum generates sufficient cash flow from operations to maintain long-term financial strength and flexibility. With the substantial increase in Lundin Petroleum's production profile over the next years, driven by the Edvard Grieg and the Johan Sverdrup fields in Norway, over time the total return to shareholders is expected to partially transfer from an increase in share price to dividends received.
Lundin Petroleum had 32,726 shareholders as at 31 December 2016. The proportion of shares held by Swedish retail investors amounted to 9 percent. The top 10 shareholder list excludes shareholdings through nominee accounts.
| The 10 largest shareholders | Number | |
|---|---|---|
| as at 31 December 2016 | of shares | % |
| Nemesia S.à.r.l.1 | 87,187,538 | 25.61 |
| Statoil ASA | 68,417,676 | 20.07 |
| Landor Participations Inc.2 | 10,638,956 | 3.13 |
| Swedbank Robur fonder | 7,235,542 | 2.13 |
| Nordea fonder | 3,082,145 | 0.91 |
| Fjärde AP-fonden | 2,231,731 | 0.66 |
| Handelsbanken fonder | 2,064,689 | 0.61 |
| SPP Fonder | 1,966,292 | 0.58 |
| SEB | 1,828,638 | 0.54 |
| C. Ashley Heppenstall | 1,391,283 | 0.41 |
| Other shareholders | 154,341,955 | 45.35 |
| Total | 340,386,445 | 100% |
1 An investment company wholly owned by a Lundin family trust. 2 An investment company wholly owned by a trust whose settler is
Ian H. Lundin.
The above list only includes institutional shareholders who hold the shares directly as reported by Euroclear Sweden.
Statoil announced on 14 January 2016 the acquisition of 37,101,561 shares in Lundin Petroleum, corresponding to 11.93 percent. On 30 June 2016, on completion of the acquisition of a 15 percent additional working interest in the Edvard Grieg field, Statoil received 31,316,115 additional shares thus taking Statoil's total shareholding up to 68,417,676, representing 20.07 percent of the shares in issue.
| Size categories | Number of shareholders |
Percentage of shares, % |
|---|---|---|
| 1–500 | 24,111 | 1.04 |
| 501–1,000 | 3,718 | 0.90 |
| 1,001–10,000 | 4,016 | 3.58 |
| 10,001–50,000 | 541 | 3.49 |
| 50,001–100,000 | 103 | 2.18 |
| 100,001–500,000 | 160 | 10.38 |
| 500,001– | 77 | 78.43 |
| Total | 32,726 | 100 |
| 31 Dec 2016 | 31 Dec 2015 | |
|---|---|---|
| Number of shares issued | 340,386,445 | 311,070,330 |
| Number of shares owned by Lundin Petroleum |
– | 2,000,000 |
| Number of shares in circulation | 340,386,445 | 309,070,330 |
Source: Euroclear Sweden, December 2016
Lundin Petroleum has now reached a level of market capitalisation which makes the Lundin Petroleum share investable for even the larger US investment funds. Over recent years, Lundin Petroleum has stepped up its investor marketing in the US, both on the east coast and on the west coast. With a growing market capitalisation, and with total US shareholding being at only 6 percent, the US marketing efforts will be intensified during 2017 as Lundin Petroleum is gaining access to a larger sphere of US investment funds.
Shareholder Structure – Geographical
Source: IPREO, November 2016
In September 2016, Lundin Petroleum established (ADR) programme in the United States.
ADRs are depositary receipts traded in the United States over-the-counter market (OTC). Each ADR
Deutsche Bank is acting as the depositary bank for this ADR programme.
More information on Lundin Petroleum's ADR Programme can be found on
16 Lundin Petroleum Annual Report 2016
We met or exceeded all our key operational targets, driven by exceptional facilities and reservoir performance
Nick Walker Chief Operating Officer
2016 was an outstanding year for Lundin Petroleum with delivery on all our operational objectives. We met or exceeded all our key targets, driven by exceptional facilities and reservoir performance. We continued our strong production growth trajectory underpinned by a series of major development projects, more than doubling production over 2015 while at the same time significantly reducing our cash operating costs. We also continued to grow our reserves, replacing more than two times what we produced.
Our flagship operated Edvard Grieg field started production at the end of 2015 and very quickly achieved world class facilities uptime. With new wells progressively being brought on through the year production ramped up to exit 2016 at maximum facilities capacity levels of 100,000 boepd. Well results on the western flank of the field yielded increased reserves and this will be followed up with appraisal in 2017 with the potential to add significant volumes, supporting the trend of big fields getting bigger. The first year of Edvard Grieg performance has exceeded expectations and puts us in great shape for 2017.
The giant Johan Sverdrup project is progressing really well and keeps getting better and better. Phase 1 of the development is progressing on schedule with all elements of the project under construction, costs have come down by 30 percent in US dollar terms since PDO approval, and facilities capacity and reserves have both increased. The concept selection for Phase 2 of the development was made in early 2017. When Phase 1 starts up in late 2019 we will see our net production exceed 120,000 boepd and then grow to over 150,000 boepd at full field plateau levels.
We have continued to adapt our business to the current oil price environment, focusing spend on strategic activities and relentlessly challenging our cost base, achieving significant savings. Our quality assets have allowed us to drive down cash operating costs year-over-year. 2016 cash operating costs were one third less than 2015, at just under USD 8 per barrel. We will see a further reduction in 2017 and when Johan Sverdrup comes onstream we will be below USD 5 per barrel. These stellar cost metrics put us in great shape to generate significant cash flow as our production ramps up.
Our strategy of value creation through organic growth has been highly successful and we continue to believe this is the best way to create long-term sustainable shareholder value. We have built a really exciting exploration position in the southern Barents Sea focussed on three high impact trends with multibillion barrel potential. We will again be amongst the most active explorers in the area with a rig drilling through the year. At the Loppa High area we continue to have success with the appraisal of the significant Alta and Gohta oil discoveries and the Neiden oil discovery made at the end of 2016 proves the northern extension of the trend which has lots of additional prospectivity. Our recent Filicudi oil discovery proves a new play with significant follow-on prospectivity, with further exploration drilling being planned for 2017. We continue to build our position in the area with awards in the 23rd licensing round, picking up interests in two giant multi-billion barrel licences in the southeastern Barents Sea, the first of which will be drilled in 2017.
Delivery of our committed projects gives us a growth profile that will see us double production from current levels when Johan Sverdrup reaches plateau. We are hopeful that the southern Barents Sea will emerge as the next producing hub for Lundin Petroleum and continue our strong growth trajectory.
These outstanding results are a reflection of the skill and motivation of the world class team we have at Lundin Petroleum. Looking forward the focus is to keep on delivering what we say we will do and we have already made a great start to 2017.
Lundin Petroleum Annual Report 2016 17
A strong production performance in 2016 saw production levels exceed guidance and achieve record levels for the Company
During 2016, Lundin Petroleum produced 26.6 million barrels of oil equivalent (MMboe) at an average rate of 72,600 barrels of oil equivalent per day (boepd) which is 4 percent above the mid-point of the original guidance of 65,000 to 75,000 boepd and in line with the increased guidance issued in October 2016 of 70,000 to 75,000 boepd. These results are due to strong facilities and reservoir performance. Edvard Grieg came onstream at the end of 2015, quickly achieving stable operations, and during 2016 new wells were progressively brought online with production levels reaching gross maximum facilities capacity of 100,000 boepd towards the year end. Exiting the year, Edvard Grieg represents approximately two thirds of the Company's total production.
Lundin Petroleum's production forecast for 2017 is in the range of 70,000 to 80,000 boepd (excluding the IPC assets). The increase compared to 2016 represents a full year at maximum facilities design capacity level for the Edvard Grieg field partially offset by natural declines in the other areas. Continued development drilling at Edvard Grieg will allow the field to stay at field capacity rates into 2020 and with upside in the southwest area of the field offering the opportunity to extend this further. The Ivar Aasen field, which is produced through the Edvard Grieg facilities, was brought online at the end of 2016.
The giant Johan Sverdrup field is planned to start production in late 2019 and is expected to increase Lundin Petroleum's net production levels to above 120,000 boepd and then grow to over 150,000 boepd at full field plateau levels. This excludes any contribution from the significant contingent resource base, or any contribution from exploration wells that Lundin Petroleum is planning to drill.
1 excluding IPC assets
Upward revisions of Lundin Petroleum's reserves have replaced more than two times production
| Reserves Summary | MMboe |
|---|---|
| Reserves end 2015 | 685.3 |
| 2016 Production | -26.6 |
| Sales/Acquisitions | +29.5 |
| Revisions | +55.3 |
| Reserves end 2016 | 743.5 |
| Reserves replacement ratio | 208% |
Lundin Petroleum had 743.5 MMboe of certified reserves at the end of 2016 of which 96 percent relate to Norway. Approximately 55 MMboe of additional reserves were added in 2016, resulting in a reserves replacement ratio of over 200 percent. In addition, approximately 29 MMboe of reserves were added during the year through the acquisition of an additional 15 percent working interest in Edvard Grieg. The reserves to production ratio at the end of 2016 stands at 28 years, which is well above industry norms.
The main reason for the reserves increase relates to Lundin Petroleum's two biggest assets, Edvard Grieg and Johan Sverdrup. The reserves increase on Edvard Grieg is driven by drilling results which indicate more oil-in-place in the western flank of the field than originally foreseen. The upgrade of reserves in the Johan Sverdrup field reflects better understanding of the reservoir, in particular the waterflood performance characteristics following the acquisition and evaluation of additional core data. Further reserves increases have been attributed to the Alvheim field, as a result of the identification of further infill drilling targets, and also at the Bertam field, due to reservoir outperformance.
96 percent of the 743.5 MMboe of reserves is related to oil and natural gas liquids (NGL). Lundin Petroleum quotes all of its reserves in working interest barrels of oil equivalent. All reserves are independently audited by ERC Equipoise Ltd. (ERCE).
Unless otherwise stated, all reserves estimates in this Annual Report are the aggregate of "Proved Reserves" and "Probable Reserves", together also known as "2P Reserves".
Reserves quantity information and definitions can be found on pages 132–133.
1 excluding IPC assets
Lundin Petroleum has a number of discovered oil and gas resources which are classified as contingent resources. Contingent resources are known oil and gas resources not yet classified as reserves due to one or more contingencies. Work is ongoing to remove these contingencies and to mature contingent resources into reserves and ultimately production.
Lundin Petroleum had 267 MMboe of contingent resources at year end 2016 of which Norway represents 93 percent and with the contingent resource position in Norway growing by 47 MMboe during the year.
The majority of the contingent resource additions are associated with the Johan Sverdrup field. Contingent resources have been added from the Neiden discovery in the southern Barents Sea as well as from re-assessing the resource potential within the fields in the Paris Basin. Further contingent resources have been added from newly identified infill drilling targets on the Alvheim and Volund fields.
There has been a further rationalisation of the contingent resource portfolio during 2016. Lundin Petroleum decided to remove from its contingent resources the Sabah and Tembakau gas discoveries in Malaysia and the Morskaya oil discovery in the Russian Caspian Sea. The net effect of these changes is a 31 percent reduction of the contingent resources from end of 2015.
Contingent Resources Unless otherwise stated, all contingent resource estimates in this Annual Report are unrisked best estimate.
Resource definitions can be found on page 133.
Having first class people to access world class exploration acreage is essential to our success
Lundin Petroleum's business model is to grow organically through exploration. This means to identify and mature exploration targets, drill exploration wells, appraise discoveries, develop and finally produce, thereby creating long-term sustainable value for our shareholders. To be successful with this strategy, having first class people to access world class exploration acreage is essential. In 2016, Lundin Petroleum focussed its exploration activities on Norway.
Lundin Petroleum only discloses prospective resource estimates for those prospects that will be drilled in the following year. However, many more prospects and leads have been identified from the large exploration licence portfolio and are being matured to be drilled in future years.
In Norway, Lundin Petroleum has grown to become one of the largest operated acreage holders and has been the most successful explorer in the past 10 years. By the end of 2016, Lundin Petroleum had drilled a total of 84 exploration and appraisal wells, resulting in a cumulative finding cost after tax of USD 0.7 per barrel.
In 2017 Lundin Petroleum will again be one of the most active exploration and appraisal drillers in Norway with a rig drilling through the year. The 2017 exploration programme includes five exploration wells, three on the Loppa High in the southern Barents Sea, one on new highly prospective acreage awarded in the 23rd licensing round in the southeastern Barents Sea and one well in the North Sea. Appraisal wells will also be drilled on the Alta and Gohta oil discoveries in the southern Barents Sea with two further appraisal wells on the Utsira High.
Over the course of the last two years, Lundin Norway's geophysicists have worked with the geoscience company CGG to develop a completely new method of acquiring seismic data. The method is called TopSeis and it will provide a significantly better image of the subsurface. TopSeis will be particularly beneficial for relatively shallow reservoirs, such as in the southern Barents Sea. The method basically involves two seismic vessels operating in tandem. The signal sources of one boat are placed directly above the streamers, rather than the normal position in the front. To achieve this, the streamers must be pulled at a sufficiently deep position in the water so that the vessel with the streamer can sail over them without conflict with the cables. Previously, such an operation was considered impossible. TopSeis provides much greater signal reflection than is the case in conventional acquisition, and the subsurface is illuminated with 10 to 15 times more signal energy. The result is a detailed and quantitative depiction of the reservoirs. The results from testing TopSeis are now so convincing that a large fullscale survey will be acquired in the southern Barents Sea over the Alta, Gohta and Filicudi areas in 2017.
"
2016 was an outstanding year for the Company with Lundin Norway establishing itself as a leading operator on the Norwegian Continental Shelf
2016 was an outstanding year of performance from the Norwegian assets with net production at an all-time high of 59,300 boepd, which is an increase of 180 percent on 2015. The cash operating costs of USD 7 per barrel were also at an all-time low. At year end 2016 the reserves had increased to 714 MMboe with a reserves replacement ratio of 242 percent.
Notwithstanding the significant production levels that the Company is now achieving, the organic growth strategy remains core to Lundin Petroleum with continuous access to new exploration acreage being key to the Company's long-term success. 2016 was a pivotal year in terms of new exploration acreage and the Company was awarded four licences in the 2015 APA round and five highly prospective licences in the southern Barents Sea in the 23rd licensing round. Two of the blocks awarded in the 23rd licensing round are in the southeastern Barents Sea with both licences containing multi-billion barrels of unrisked prospective resource potential.
· Gross contingent resources 216–584 MMboe · Two appraisal wells and 3D seismic in 2017 · Planning for extended well tests in 2018
| Norway Key Data | 2016 | 2015 |
|---|---|---|
| Reserves (MMboe) | 714 | 654 |
| Contingent resources (MMboe) | 249 | 202 |
| Average net production per day (Mboepd) | 59 | 21 |
| Net turnover (MUSD) | 946 | 376 |
| Sales price achieved (USD/boe) | 40 | 52 |
| Cash operating costs (USD/boe) | 7 | 11 |
| Operational cash flow contribution (USD/boe) | 40 | 77 |
| 1. Utsira High – North Sea | ||||
|---|---|---|---|---|
| Edvard Grieg Field - PL338 (WI 65%) | Johan Sverdrup Field (WI 22.6%) | Utsira High Exploration | ||
| · Production start 2015 · Net remaining reserves 127 MMboe · 2016 net production 42,000 boepd · Additional 15% interest acquired in 2016 · Development drilling ongoing · Appraisal of Edvard Grieg SW in 2017 · Ivar Aasen unit (WI 1.385%) development completed – first production December 2016 |
· Discovered in 2010 (PL501) and in 2011 (PL265) · 23 wells and 7 sidetracks drilled during appraisal · PDO approved in August 2015 · Net reserves 551 MMboe · Major contracts for Phase 1 awarded · Facilities construction and development drilling ongoing and according to schedule · Phase 2 concept selection in early 2017 · Phase 1 production expected late 2019 |
· Luno II discovery in PL359 in 2013 gross contingent resources 27–71 MMboe · Luno II North discovery in PL359 in 2015 gross contingent resources 12–26 MMboe · Rolvsnes discovery in PL338C in 2015 gross contingent resources 3–16 MMboe |
||
| 2. Alvheim Area – North Sea | ||||
| Alvheim Field (WI 15%) | Volund Field (WI 35%) | Bøyla Field (WI 15%) | ||
| · Production start 2008 · Net remaining reserves 19 MMboe · 2016 net production 10,000 boepd · Infill drilling in 2017 · Viper/Kobra development completed – first production November 2016 · 15% ownership of the Alvheim FPSO |
· Production start 2010 · Net remaining reserves 8 MMboe · 2016 net production 2,700 boepd · Exploration well on Volund West in 2017 |
· Production start 2015 · Net reserves 2 MMboe · 2015 net production 1,700 boepd |
||
| 3. Loppa High – Southern Barents Sea | ||||
| Gohta and Alta Discoveries PL492 and PL609 (WI 40%) |
Loppa High Exploration | Southeastern Barents Sea Exploration | ||
| · Gohta and Alta discoveries in 2013 and 2014 · Three appraisal wells drilled |
· Neiden discovery in PL609 in 2016 gross resources 25–60 MMboe |
· One exploration well during 2017 – Korpfjell prospect in PL859 (WI 15%) |
· Filicudi discovery in PL533 in February 2017
gross resources 35–100 MMboe · Remaining exploration wells for 2017: – Børselv prospect in PL609 (WI 40%) – Hufsa prospect in PL533 (WI 35%)
Since 2007 Lundin Petroleum has discovered close to 3 billion barrels of gross recoverable reserves and resources in the area and further prospects are being matured for drilling in the years to come
The Utsira High holds the Edvard Grieg and Johan Sverdrup fields and represents the majority of Lundin Petroleum's asset base.
The area covering the Johan Sverdrup, Edvard Grieg, Ivar Aasen and Luno II fields spans 1,600 km2 and lies approximately 150 km offshore from Stavanger on the west coast of Norway. Exploration in the area began in the 1960's but not until 2007 was the breakthrough made by Lundin Petroleum with its Edvard Grieg discovery which unlocked the geological setting at the Utsira High and ultimately led to the discovery of Johan Sverdrup.
Production from the Edvard Grieg field commenced in November 2015 and the field achieved facility design capacity production levels of 100,000 boepd towards the end of 2016. The field achieved excellent results during its first year of full production with both production and the platform uptime being ahead of forecast. The PDO included a total of 14 development wells to be drilled and as of April 2017 a total of seven wells have been drilled and completed with development drilling continuing into 2018. The western flank of the field has proven to contain thicker reservoir sands than originally estimated which has resulted in the gross ultimate recoverable reserves having increased to 223 MMboe which is a 20 percent increase on the PDO reserves estimate. In 2017 a further five development wells are planned to be drilled to facilitate continuous high production rates for at least the next couple of years. In addition to the development drilling an appraisal well was drilled in the first quarter of 2017 targeting further resources in the southwestern part of the field. Strong operating performance resulted in cash operating costs for 2016 below USD 7.2 per barrel.
The Ivar Aasen field (1.385%) commenced production in December 2016 and will be ramping up production during 2017. The Ivar Aasen field produces to the Edvard Grieg platform and is contributing to lowering the cash operating costs per barrel on the Edvard Grieg platform.
Lundin Petroleum is continuing to assess the Luno II and Rolvsnes discoveries just south of the Edvard Greig field for potential tie-backs to the Edvard Grieg platform. Concept development engineering studies are ongoing on Luno II. The Rolvsnes discovery requires an appraisal well and testing, which is being considered for 2018, before the potential of the discovery can be determined. Success on appraisal of Rolvsnes would provide encouragement for the potential of the Goddo prospect just to the southeast of Rolvsnes.
During challenging periods successful companies are those which can embrace the situation and see it as a time of opportunity. This is exactly what Lundin Petroleum managed to achieve when acquiring Statoil's 15 percent interest in the Edvard Grieg field in exchange for newly issued shares.
This increases Lundin Petroleum's exposure to a world class asset and further consolidates the Company's position on the Utsira High, adding significant reserves, production and cash flow in the heart of the Company's core area in Norway.
· Gross capex: NOK 97 billion (123.2 1) nominal
· Gross capex: NOK 40–55 billion (85 1) real 2016
PDO values
1
The Johan Sverdrup field is located on the Utsira High in the central part of the Norwegian North Sea, approximately 20 km east of the Edvard Grieg field and approximately 150 km from the west coast of Norway. Lundin Petroleum discovered the Johan Sverdrup field in 2010 and following an extensive appraisal campaign, totalling 23 wells and seven side-tracks, the field has been successfully delineated with an exceptional reservoir quality in relatively homogeneous sandstone spanning an area of approximately 200 km2 . The PDO was approved in mid-2015. Statoil is the operator of Johan Sverdrup and estimates the field to contain gross reserves in the range of 2.0 to 3.0 billion boe. Lundin Petroleum has booked 551 MMboe of net reserves and an additional 47 MMboe of net contingent resources.
The construction of the facilities is progressing on schedule and 2017 will be a peak year of activity with work ongoing at 22 construction sites around the world. The contract awards have occurred at an opportune time given the deflationary cost environment within the oil and gas service sector. This has resulted in a gross Phase 1 reduction of capital expenditures of NOK 26 billion to NOK 97 billion (nominal) at a project exchange rate of 6 NOK per USD, which represents a 21 percent saving. In addition to this material saving there remain significant contingencies included in the cost estimates. Lundin Petroleum
has also locked-in significant currency savings from the weakening NOK with approximately 75 percent of the NOK denominated capital expenditure hedged at an average rate of approximately 8.3 NOK to the USD.
The Phase 1 development consists of four fixed platform installations at the field centre with dedicated export oil and gas pipelines to the Mongstad and Kårstø oil and gas terminals located on the west coast of Norway. The Phase 1 production capacity is 440,000 bopd with gas in addition. Pre-drilling of the wells for Phase 1 commenced in 2016 with eight drilled. Drilling of water injection wells commenced in early 2017. The first of four jackets will be installed during the summer of 2017 with the installation of the riser and drilling platforms scheduled for 2018 and the processing and living quarter platforms in 2019. Production for Phase 1 is scheduled to commence late in 2019.
The concept selection for Phase 2 of the development was made in early 2017 and involves an additional processing platform at the field centre to provide additional capacity taking the total to 660,000 bopd with gas in addition. Phase 2 will also involve additional drilling and subsea facilities. Production from Phase 2 is scheduled to commence in 2022. Due to favourable market conditions and optimisation of the project scope, gross Phase 2 development costs have been reduced from NOK 85 billion to between NOK 40 and 55 billion.
The Alvheim, Volund and Bøyla fields are located in the Alvheim area in the central part of the North Sea with production starting from these fields in 2008, 2010 and 2015 respectively. Collectively these fields are Lundin Petroleum's second largest production hub.
The Alvheim area is estimated to hold gross ultimate recoverable reserves of 472 MMboe which is 215 MMboe more than was estimated in the PDO for these three fields. During 2016 three additional infill wells were put into production with excellent production rates resulting in a combined gross production of 85,700 boepd for 2016.
There is a long track record of identifying infill drilling opportunities in the Alvheim area through the use of 4D seismic and pilot holes from planned development wells. New infill drilling opportunities continue to be matured. During 2017 four infill wells are planned to be drilled in addition to one exploration well on the Volund West prospect. Through a combination of keeping the facilities full with ongoing infill drilling and strong operating performance has resulted in cash operating costs for 2016 below USD 5 per barrel.
Non-operated Lundin Petroleum Licences
Fields/discoveries
0 KM 10
Caterpillar
Bøyla
Lundin Petroleum's three key assets, the Johan Sverdrup field, the Edvard Grieg field and the fields in the Alvheim area have all grown in reserves over time. It is a well-known industry trend that the big fields tend to get bigger, a trend observed on almost all big fields on the Norwegian Continental Shelf. Reserves in the Alvheim area have grown by 83 percent compared with the estimates in the PDO. The Edvard Grieg and Johan Sverdrup fields, which are both much younger fields relative to the Alvheim area, have added reserves and resources by 36 percent and 16 percent respectively compared to the PDO estimates.
The ability to grow reserves through time comes from an improved understanding of the subsurface, utilising new technology such as seismic and a continuous value driven investment approach which improves the recovery factors. The fact that both Edvard Grieg and Johan Sverdrup are at the early stage in their life cycle provides future opportunities to add even more reserves as the subsurface understanding of these fields improves.
Lundin Petroleum Annual Report 2016 27
The ability to grow reserves through time comes from an improved understanding of the subsurface, utilising new technology and a continuous value driven investment approach
The southern Barents Sea is one of Lundin Petroleum's core areas on the Norwegian Continental Shelf. Having started to build an acreage position in this region in 2007, Lundin Petroleum now has 18 licences and three significant discoveries, Alta, Gohta and Filicudi, which makes Lundin Petroleum along with Statoil the biggest player in the southern Barents Sea. The Company's exploration position in the southern Barents Sea is focused on three high impact trends with multi-billion barrel potential.
A majority of Lundin Petroleum's acreage in the southern Barents Sea covers the highly prospective Loppa High, with contingent and prospective resource potential of over 1 billion boe. The Alta discovery was successfully appraised in 2016 and late in the year the Neiden oil discovery was announced, proving the extension of the carbonate reservoir play to the north.
Both the Alta and the Gohta discoveries will be further appraised in 2017 to better define the resources within the current resource range estimate of 216 to 584 MMboe for the two discoveries. Contingent on the results of the wells, extended well tests are being planned on each accumulation for 2018, which will provide the reservoir understanding to commence development studies.
Drilling of the large Børselv prospect, just to the north of Neiden, is being planned for 2017 and there is significant additional prospectivity along trend which will be matured during the year. Lundin Petroleum continues to build its acreage position in the play with the awards of blocks PL609C and PL851 in the 23rd licensing round and PL902 in the 2016 APA round as well as concluding deals for interests in PL715.
In 2016, Lundin Petroleum proved yet another oil trend in the southern Barents Sea with the Filicudi discovery in PL533, with a gross resource estimate of between 35 and 100 MMboe. The Filicudi discovery is on trend with the Johan Castberg discovery with similar sandstone reservoir intervals. Multiple additional prospects have been identified on the Filicudi trend with a prospective resource potential on Lundin Petroleum acreage in PL533 of up to 700 million boe. Additional exploration drilling is being planned in 2017 on the Filicudi trend.
(1) Gross contingent plus resource potential (2) Gross contingent resources
We continue to believe that our strategy of value creation through organic growth is the best way to create long-term sustainable value. We have a strong track record of adding value through the drill bit having made a series of significant discoveries over the years and we aim to continue that trend, searching for the "next elephant".
The southern Barents Sea is one of the most attractive exploration plays in the world today with over 1 billion boe discovered recently and with estimates of yet to find resources close to 9 billion boe. The area is an emerging producing region, with current production from the Snøhvit and Goliat fields and with some large oil discoveries, including the Lundin Petroleum operated Alta and Gohta accumulations, likely to progress towards development.
Southern Barents Sea - Three high impact exploration trends Lundin Petroleum's prospect portfolio in the southern Barents Sea has multi-billion barrel potential. We will again be one of the most active explorers in Norway during 2017, with a rig working all year in the southern Barents Sea drilling a series of high impact exploration trends that includes some very large and exciting prospects. The potential of the area is enormous and we are hopeful it will extend Lundin Petroleum's strong production growth profile beyond the levels
The third trend is in the southeastern Barents Sea where Lundin Petroleum was awarded two highly prospective licences in 2016, PL857 and PL859, located close to the Russian maritime border.
The two licences contain prospects which have multi-billion barrel unrisked prospective resource potential. The first of these, the Korpfjell prospect in PL859, will be drilled by the operator Statoil in the summer of 2017.
Further exploration drilling is expected to take place during 2018 with a likely multi-well campaign.
Outstanding performance from the Bertam field facilities with an uptime of 99 percent and production ahead of forecast
| Malaysia Key Data | 2016 | 2015 |
|---|---|---|
| Reserves (MMboe) | 10 | 11 |
| Average net production per day (Mboepd) | 9 | 5 |
| Net turnover (MUSD) | 126 | 71 |
| Sales price achieved (USD/boe) | 45 | 49 |
| Cash operating costs (USD/boe) | 23 | 24 |
| Operational cash flow contribution (USD/boe) | 16 | 16 |
| Peninsular Malaysia | Sabah |
|---|---|
| · Bertam field on Block PM307 (WI 75%) – Net reserves 10 MMboe – First oil in April 2015 – A15 development well completed in 2016 · PM328 (WI 35%) – 3D seismic in 2016 |
· SB303 Gas Holding Area (WI 55%) |
The Bertam oil field is located on Block PM307, offshore Peninsular Malaysia, and has since the start-up in 2015 delivered outstanding operational performance. Production for 2016 was ahead of forecast and an excellent facilities uptime of 99 percent was achieved.
The Bertam field has been producing from 11 wells since 2015 and an additional development well in the eastern extension of the reservoir was successfully put into production in June 2016. Overall field performance has been better than forecast and due to the excellent reservoir performance on the Bertam field since production start-up, the gross ultimate recoverable reserves have been increased from 16.9 MMboe to 19.6 MMboe.
Block PM308A and PM319 were relinquished during 2016. Lundin Petroleum further decided to remove the Tembakau gas discovery on PM307 from its contingent resources, and the net contingent resources removed amounted to 28.9 MMboe.
Lundin Petroleum completed the drilling of three independent exploration prospects on Block SB307/308 in 2016 but none of these contained oil or gas in any commercial volumes.
In 2016, Lundin Petroleum removed the Tarap, Cempulut and Berangan gas discoveries on SB303 from its contingent resources and the net contingent resources removed amounted to 31.8 MMboe.
Early in 2017, Lundin Petroleum announced the spin-off of its non-Norwegian assets into the newly formed company called International Petroleum Corporation (IPC). For more information on the spinoff, see the IPC Spin-off section on pages 34–35.
The mature assets in France and the Netherlands continue to provide steady production and cash flow
| France Key Data | 2016 | 2015 |
|---|---|---|
| Reserves (MMboe) | 18 | 19 |
| Average production per day (Mboepd), net | 3 | 3 |
| Net turnover (MUSD) | 42 | 52 |
| Sales price achieved (USD/boe) | 44 | 52 |
| Cash operating costs (USD/boe) | 24 | 25 |
| Operational cash flow contribution (USD/boe) | 22 | 27 |
| Netherlands Key Data | 2016 | 2015 |
|---|---|---|
| Reserves (MMboe) | 2 | 2 |
| Average production per day (Mboepd), net | 2 | 2 |
| Net turnover (MUSD) | 17 | 26 |
| Sales price achieved (USD/boe) | 27 | 39 |
| Cash operating costs (USD/boe) | 17 | 19 |
| Operational cash flow contribution (USD/boe) | 17 | 20 |
The mature assets in France and the Netherlands continue to provide steady production and cash flow. The nature of these assets provides for low decline, stable and predictable production with strong leverage to oil and gas prices through low taxes.
The French assets consist of mature onshore oil producing fields in the Paris Basin, operated by Lundin Petroleum, and mature onshore oil producing fields in the Aquitaine Basin, operated by Vermilion. The assets in the Netherlands consist of mature onshore and offshore gas producing fields, operated by Vermilion, Engie, Oranje-Nassau Energie and Total.
In 2014, Lundin Petroleum successfully completed the Grandville re-development in the Paris Basin and commenced infill drilling on the Vert La Gravelle re-development with two wells completed in 2015. The remaining five infill wells have been postponed until the oil price recovers.
The gas production in the Netherlands during 2016 was better than expected due to good production performance from certain new wells coming onstream. During 2017, one offshore development well and one onshore exploration well are planned.
Early in 2017, Lundin Petroleum announced the spinoff of its non-Norwegian assets into the newly formed company called International Petroleum Corporation (IPC). For more information on the spin-off, see the IPC Spin-off section on pages 34–35.
In early 2017, Lundin Petroleum announced that its Board of Directors proposed to spin-off the assets in Malaysia, France and the Netherlands into the newly formed company International Petroleum Corporation (IPC) and to distribute the IPC shares, on a pro-rata basis, to Lundin Petroleum shareholders.
The distribution is made in a tax efficient manner in accordance with the "Lex-ASEA rules", implying that no immediate taxation will arise to shareholders in Sweden. IPC has applied to the Toronto Stock Exchange to list its shares following the distribution on such exchange under the ticker IPCO, and also intends to list its shares on a recognised Swedish stock exchange.
The Board of Directors and management of the Company routinely review and assess strategic alternatives available to the Company to enhance shareholder value. As part of that review, the Board of Directors and management concluded that given ongoing developments and successes with the Company's assets in Norway, the other international producing assets, held within a separate and independent entity, would benefit from enhanced strategic flexibility and management focus, as well as be ascribed increased focus, visibility, and value from investors.
With a renewed strategy and focus, the Company believes that IPC can be built into a leading international independent oil and gas company, focused on the production and development of high quality assets around the world. The Company believes an independent IPC will be well positioned to pursue both organic and inorganic growth opportunities over time. The significant cash flows generated from IPC's long-lived assets will provide financial capacity to pursue this strategy.
With the spin-off, Lundin Petroleum will become fully focused on Norway, which I am convinced will serve to further crystallise the value of our high-growth asset portfolio in the North Sea and the southern Barents Sea
The spin-off will allow Lundin Petroleum's management to solely focus on maximising shareholder value from its Norwegian portfolio which has continuously grown in size and value since Lundin Petroleum entered Norway in 2004. Lundin Petroleum's strong liquidity position of USD 1 billion of headroom coupled with its operating cashflow generation allows the Company to retain all external bank debt and still be able to fully fund its committed capital expenditure up to Johan Sverdrup first oil in late 2019.
The Lundin Family remains committed to the success of IPC, and entities related to the Lundin Family will continue to be the largest shareholders of IPC following the completion of the spin-off.
Listing of IPC's shares on the TSX and a recognised Swedish stock exchange will be subject to IPC fulfilling the requirements of the respective exchange. There can be no assurance that the shares will be accepted for listing on either of the TSX or a Swedish exchange.
An Extraordinary General Meeting was convened on 22 March 2017 and resolved to approve the Board of Director's proposal on distribution of shares in International Petroleum Corporation to the shareholders of Lundin Petroleum.
The EGM documents as well as more information on the spin-off can be found on www.lundin-petroleum.com
Risk management creates value by enabling management to effectively identify, mitigate and monitor potential events affecting our business and the environment in which we operate
Today's business landscape is dynamic, fluid and often characterised by rapid change, regional differences and cultural contrasts that lead to significant business risks. The oil and gas industry has numerous operational, financial, external and strategic risks, which even the combination of robust processes, experience, knowledge and careful evaluation may not be fully able to eliminate or which are beyond the Company's control.
Risk management creates value by enabling management to deal effectively with potential events in the Company's operations and its business environment. Risk management is a process driven by the Company's Board of Directors to encourage foresight, pro-activeness and informed decision making. Risk management brings together the assessment and review of possible events and scenarios resulting in an increased awareness throughout the Company and gives management the ability to take informed and robust decisions internally to face the challenges of the business environment and encourage and maintain a proactive risk management. Lundin Petroleum bases its risk approach on COSO 2013 in order to have a robust risk assessment methodology which cover all aspects of the Company's operations, not only financial reporting.
Risk identification and assessment is based on the achievement of business objectives. A proper risk assessment forms a basis for highlighting which risks should be prioritised by local and Group management.
As part of the risk identification and assessment process in each area of operations, Lundin Petroleum reviews and analyses the risks that affect the business. The Company identifies strategic, operational, financial and external risks affecting its activities and this identification involves an analysis of interrelated internal and external factors. The risks are assessed on a quarterly basis, through a standardised methodology based on likelihood and impact. Regular reviews are conducted to focus on which risks may be reduced or eliminated.
After identifying and assessing the significance of risks and opportunities, management also considers control measures. The prioritisation of control measures is based on high risks that could affect the business.
Controlling risk through effective management is achieved by creating a mandate and commitment to risk at all levels of the business. Risk mitigation is an integral and continual part of the control activities and decision making within Lundin Petroleum.
The Company's policies and procedures are robust allowing for the establishment of clear responsibilities and business principals to reduce risk exposure. Controlling risk may also involve risk acceptance, avoidance, or transferring the impact and management of the risk to a third-party by, for example, purchasing insurance or having risk transferred by contract.
Lundin Petroleum has identified the following high inherent risks relative to the Company's performance and reputation highlighted in four risk categories: strategic, operational, financial and external risks. These risks are presented in the following section, but other risks could also exist or arise.
Monitoring risk is an important part of the continuous risk management process. It involves local operational accountability and clear responsibility for continuous identification of risks by risk owners.
The Company provides oversight through regular risk reporting which enables the continual review of factors such as:
Lundin Petroleum follows a "Three lines of defence" approach, which gives the Company a systematic and disciplined methodology to improve the effectiveness of risk management and the internal control processes. This is further described in the Internal Control and Audit section on pages 68–69.
| Operational Risk | ||
|---|---|---|
| Risk Area | Description | Response |
| Major Operational Incidents | The possibility that a major operational incident could occur affects all oil and gas operations. The drilling and production operations will never be completely risk free and the potential for incidents, although reduced, will remain. |
Lundin Petroleum has competent and focused Health, Safety and Environmental (HSE) teams and HSE is prioritised by management. HSE management systems are in place to avoid major operational incidents and the Company promotes active management and reporting on HSE, which is a priority area both for Lundin Petroleum and its contractors, suppliers and partners. For more information, see Responsibility on pages 42–49. |
| Asset Integrity | The risk that physical assets and pipelines are affected by corrosion or are unreliable, leading to liability or loss exposure. |
Diligent operations management and effective maintenance, inspection and corrosion management planning is in place to ensure that the assets remain reliable. This coupled with having new assets, good technical integrity and a focus on safety and regulatory compliance mitigates this risk. |
| Asset Management and Cost Control |
Drilling and development projects can experience cost overruns and delays, leading to declines in revenue. Idle rigs, failure of critical equipment or insufficient planning may adversely affect cash flow levels to varying degrees. |
Internal processes are in place to ensure that reasonable cost levels are achieved relative to business plans. All development projects must pass through the Lundin Petroleum value creation process that requires approval from the Investment Committee, and approval from the Board for significant investment decisions. Effective procurement and contractual terms enable good cost and schedule control management in the operations. |
| Current and future production concentrated to a few fields |
A significant proportion of the Company's current production comes from the Edvard Grieg field. This concentration increases the sensitivity to serious technical issues or any long term production shutdowns. |
Lundin Petroleum has highly competent and motivated operational teams. In addition, the Company has entered into a "loss of production" insurance, reducing the impact of any unexpected long-term shutdowns on the Edvard Grieg field. |
| The Ability to Increase Reserves |
An inability to secure permit licences and partnerships in strategic areas of exploration, and consequently failure to bring this into resources and reserves. |
The ability to increase reserves is controlled by the Company's ability to analyse subsurface data, select and acquire suitable licences, generate prospects and by having a proactive risk approach with its partners. |
| Delay in delivery of the Johan Sverdrup field |
A delay in delivery of the Johan Sverdrup project is a risk that would impact the Company's costs and production forecasts. |
The use of effective peer review with partners and the efficient execution of the project work to date decrease the risk of delay in the Johan Sverdrup field. Due to current market conditions the current cost estimates have been significantly reduced from the plan for development and operations. |
| Decommissioning | The Company needs to comply with the terms and conditions of its own and partner operated projects. Decommissioning at the end of a field's economic life may result in liability, substantial abandonment and reclamation costs. This remains an industry risk with environmental and regulatory challenges to manage. |
Lundin Petroleum considers the risk of decommissioning within the asset life-cycle process. Major business and technical assumptions underlying decommissioning estimates are reviewed annually for each development project and operated and non-operated assets. Decommissioning liabilities and specific requirements are addressed by the operations and coordinated by Group management. |
| Financial Risk | ||
|---|---|---|
| Risk Area | Description | Response |
| Financial Reporting | Material misstatements in financial reporting could lead to regulatory action, legal liability, and loss of shareholder confidence damaging the Company's reputation. |
Lundin Petroleum has a formal monthly management reporting process to review and control the financial reporting. The internal control system for financial reporting operates to provide reasonable assurance against material misstatement or loss. Internal and external audits provide verification in the financial reporting and risk monitoring process. |
| Reserves and Resource Calculations |
Estimates of economically recoverable oil and gas reserves and the future net cash flows of the reservoir performance are based upon a number of factors and assumptions. Since the calculations are based on variable factors this leads to a risk of uncertainty. This is also viewed by the Company as an operational risk. |
Reserves and resource calculations undergo a comprehensive internal peer review process and adhere to industry standards. All reserves are independently audited as part of the annual reserves audit process. For more information, see Production, Reserves and Resources on pages 18–21. |
| Investment Oversight | The risk that investments or expenditures are not in line with approvals from the Lundin Petroleum Investment Committee, could have an impact on budget and lead to overspending. |
To mitigate the risk of investment oversight, Lundin Petroleum, through the annual budget and supplementary budget approval process and its Authorisation Policy, has implemented a rigorous continual process of oversight of all expenditures. This process ensures that expenditures are in line with approvals from the Investment Committee. |
| Capital Requirements | The Company's future capital requirements depend on many factors, including whether the Company's cash flow from operations is sufficient to fund the Company's business plans. The Company may need additional funds in the longer term in order to further develop exploration and development programmes or to acquire assets or shares of other companies. |
There is an active and continuous process of monitoring of liquidity and financing arrangements in place. The Johan Sverdrup development project requires significant capital expenditures, which Lundin Petroleum has secured through its financing and the additional 15 percent interest acquired in the Edvard Grieg field. This provides the necessary flexibility to fund the ongoing development, exploration and appraisal programmes, including the Johan Sverdrup development. The net debt position of Lundin Petroleum is reported on a regular basis. |
| Fraud, Bribery and Corruption |
The risk of fraud, bribery and corruption, if ignored, can slowly drain assets or severely impact short- and long-term growth plans. |
The control environment of the Company encompasses the "tone at the top" provided by the Board and Group management. A consistent application of Lundin Petroleum's Code of Conduct, together with its Anti-Corruption policy, Anti Fraud policy, Authorisation Policy and procedures clearly define responsibility within the internal control environment and minimises the risk. To further mitigate this risk the Company has entered into a fraud insurance. |
| Interest and Currency | The Company is exposed to market fluctuations in foreign exchange rates due to the fact that the financial statements of the Group are reported in USD. The uncertainty in future interest rates and currency risk could have an impact on the Company's earnings. |
The Company's exposure to interest rate and currency risk is continuously assessed and monitored. Lundin Petroleum uses hedging instruments to manage this risk. |
| External Risk | ||
|---|---|---|
| Risk Area | Description | Response |
| Market Oil Price | The price of oil and gas is affected by global growth and the economic drivers of supply and demand. Market conditions may also impair the liquidity situation of contractors and consequently their ability to meet its obligations towards Lundin Petroleum. This may in turn impact both project timelines and cost. |
Lundin Petroleum's policy is to have financial flexibility in place to deal with sustained periods of low oil prices. In addition, Lundin Petroleum actively reviews the contractor base and their position of liquidity. |
| Availability of Drilling Equipment and Access |
The market uncertainty in the oil and gas price may affect contractors or sub-contractors stability and consequently the availability of services and equipment. |
The Company manages this risk by having a long-term outlook on drilling and services needs and by reviewing contractual commitments on a regular basis. |
| Changes to Laws and Regulations |
There can be no assurance that legislation that directly or indirectly regulates or affects the oil and gas industry will not be changed in a manner that will adversely affect the Company. Changes to laws and regulations may lead to negative consequences such as, but not limited to, the expropriation of property, cancellation of or modification of contract rights, and uncertainty in taxation. |
The Company strives to ensure comprehensive interpretation and compliance with regulations that may impact the business. Lundin Petroleum designs its controls in a way that compliments its business. Ongoing monitoring is necessary to ensure the controls can be sustained and properly mitigate the risk to an acceptable tolerance. |
| Regulatory Investigations and Litigation |
Regulatory investigations or third party claims cannot be predicted with certainty and may adversely affect the reputation of the Company. |
Lundin Petroleum complies with all applicable laws and regulations and acts in an ethical manner, consistent with its Code of Conduct, and in a preventive manner to manage any allegations or uncertainties that could lead to claims. When necessary, the Company retains external counsel and advisors to assist with regulatory investigations or claims. |
| Security | Security is an important risk area for the oil and gas industry and includes potential threats such as terrorist or other attacks on people or physical assets. |
The Company regularly monitors and assesses security risks in order to ensure that high awareness and an effective security risk management is in place. With a majority of its operations on the Norwegian Continental Shelf, exposure to such security issues are assigned a lower risk ranking by the Company but we are nonetheless attentive to potential risks that can arise within the industry. |
| Information Security | The increased vulnerability of information to cyber threats or malware attacks enhances the risk to system security potentially affecting people's data privacy as well as the critical systems related to the assets. |
The Company's networks are constantly monitored to avoid and swiftly remedy any external attacks. Through information system control mechanisms such as firewalls and procedures, Lundin Petroleum manages this risk to maintain a unified and resilient internal network. |
| External Risk (continued) |
||
|---|---|---|
| Risk Area Stakeholder Engagement |
Description Inadequate stakeholder engagement can affect Lundin Petroleum's reputation and impact the ability to identify business opportunities. In addition, despite the Company's commitment to all stakeholders, some individuals or groups may directly or indirectly impact the business through lobbying or demonstration activities. |
Response As highlighted in Lundin Petroleum's Sustainability Report, the Company engages at various levels with stakeholders to ensure their understanding of the Company's presence and operations. Lundin Petroleum's aim is to explore for and produce oil and gas in an economically, socially and environmentally responsible way for the benefit of all its stakeholders and society as a whole. Lundin Petroleum is a participant of the UN Global Compact to further confirm the Company's commitment to ethical business conduct. Lundin Petroleum also supports social investment through the Lundin Foundation by contributing to sustainable development projects. For more information see Lundin Petroleum's Sustainability Report 2016. |
| Climate Change | There is a potential exposure from climate change, including stricter regulation on emissions or imposition of mandatory technology in Lundin Petroleum's operations. |
In the face of technological and regulatory requirements stemming from climate change, Lundin Petroleum reviews its environmental requirements and emission reduction measures in development projects and discloses its operational greenhouse gas emissions. |
| Strategic Risk | ||
|---|---|---|
| Risk Area | Description | Response |
| Creating Shareholder Value | The risk that Lundin Petroleum's strategy will fall short of creating shareholder value which could affect the market position of the Company. |
Throughout all stages of the business cycle, Lundin Petroleum seeks to generate shareholder value by proactively investing in exploration to organically grow the reserve base, exploiting the existing asset base and acquiring new or disposing of reserves. Lundin Petroleum's business model clearly defines the vision and strategy of the Company. |
| Economic Value of the Asset Portfolio |
Ineffective management may lead to a failure to understand and unlock the full value of an asset which could negatively impact shareholder value. |
Lundin Petroleum continually reviews the economic value of the asset portfolio in order to ensure that the value of each asset within the existing portfolio is well understood, communicated and fully reflected within the share price. |
| Ineffective Communication | A strategy that is ineffective and inefficiently communicated or executed may lead to not only a loss of investor confidence and a reduction in the share price, but also affect employee and partner confidence in the Company. |
Lundin Petroleum has strong communication channels coupled with effective leadership, in order to maintain creativity and an entrepreneurial spirit which helps to ensure that the entire organisation works towards the same goal. |
More information on Internal Control and i Audit can be found on pages 68–69
The health and safety of our people is our highest priority
Christine Batruch Vice President Corporate Responsibility
2016 was an exceptional year for Lundin Petroleum in many respects, including from a Corporate Responsibility perspective. For the first time we published a standalone Sustainability Report. Our Corporate Responsibility work has been reflected in our Annual Reports from the start, but publishing a Sustainability Report based on the Global Reporting Initiative G4 Guidelines brought the active participation of everyone in the Company, from our Board of Directors, our corporate and country based management to our operational staff.
Thanks to our Sustainability Report, Lundin Petroleum's Corporate Responsibility work can now be measured against our peers, leading to a more constructive dialogue with our stakeholders. I recall in particular the very stimulating discussions I had with students at the Stockholm School of Economics CSR week when I presented our Sustainability Report and the process we had followed to produce it. We also had in-depth discussions about our sustainability work with banks at the start of the year when Lundin Petroleum secured the USD 5.0 billion reserve-based lending facility.
2016 was also an exceptional year from a global sustainability perspective. The year culminated with the Paris Agreement entering into force, marking a turning point in the global understanding of the climate change issue and the challenge it represents. Working closely with the oil and gas industry, we are ready to contribute to finding solutions for a more energy efficient and low carbon society. This commitment is also part of our ongoing efforts to lower our carbon intensity levels, a target that we achieved in 2016.
In addition to the projects on environmental preservation that we initiated a few years ago in partnership with the Lundin Foundation, we decided in 2016 to address one of the most important social issues currently facing Europe. Pilot projects aimed at assisting the integration of refugees and migrants into the workforce were launched in Norway and Sweden and early indications show that these projects are reaching their targets. We look forward to expanding this work in 2017.
The health and safety of our people is our highest priority. Our focus on health, safety and the environment (HSE) resulted in better Key Performance Indicators for 2016 compared to previous years. In February 2016, a fatal accident occurred on the Bertam field in Malaysia and we regret the tragic loss of one of our sub-contractors, an event which has left a mark on us all.
In 2017, we will continue to place emphasis on a strong HSE culture, thoroughly preparing our activities so as to prevent incidents and have the ability to respond to any potential unexpected situations.
You will find further information on Lundin Petroleum's performance and management approach on environmental, governance and social issues in the following section and in our 2016 Sustainability Report.
Environment 0 recordable oil spills
Uphold health and safety
Focus on carbon efficiency
Minimise environmental impact
Promote ethical conduct
Read more about Lundin Petroleum's performance and management approach on environmental, governance and social issues in the Sustainability Report available on www.lundin-petroleum.com
The challenging oil market environment that has dominated over the past two years has had a major impact on the oil and gas industry. A continuation of low oil prices have led to a significant underinvestment in the offshore industry and reduced activity levels which have meant some difficult years for the many oil and gas companies, suppliers and contractors operating across the world.
Lundin Petroleum has adapted to the higher pressure on the industry through a continued focus on cost efficiency and operational excellence and as a result was one of the few oil and gas companies to increase its employee base in Norway in 2016.
Maintaining an inclusive working environment and a focus on high performance has been the key to our success in attracting and retaining the best possible talent in the industry over the years. We will continue to build on this base of world class employees through our commitment to develop and invest in them as we believe that our people are our greatest single asset and the foundation for our future success.
Our outstanding performance would not be possible without the great team work and team spirit that exists within Lundin Petroleum
At year end 2016, Lundin Petroleum had a total of 542 employees directly employed by the Group in seven different countries. During 2016, the work force increased in Norway, the organisation in Malaysia was restructured to adapt to the reduced level of activities and the divestment of the Indonesian assets was finalised.
Lundin Petroleum also employs a large number of consultants and contractors who provide services for and on behalf of Lundin Petroleum. In 2016, a total of 74 consultants were engaged for services related to exploration, project development and other operational activities.
We value an open and inclusive working environment and strive to maintain a competent, engaged and experienced workforce. Acting locally and thinking globally is a guiding principle in our approach to the selection, recruitment and management of our employee base, by ensuring that all employment opportunities are offered on the basis of skills and experience.
We recruit based on qualifications and irrespective of gender, ethnicity, religion, disability etc. We are committed to promote equal opportunity and do not accept any kind of discrimination.
Wherever we operate, we actively strive to employ locally so that we can benefit from the local knowledge and experience, while contributing to enhanced expertise within the host country. Our employees are provided with the necessary skills, knowledge and motivation to be successful in their work and for the ongoing success of the Company, which is proven by its strong results and low levels of employee turnover compared to industry norms.
At year end 2016, a total of 29 different nationalities were employed throughout Lundin Petroleum's global operations. Women represented 34 percent of the total workforce and 20 percent of the managerial positions. The proportion of women in Lundin Petroleum's Board of Directors was 38 percent.
The health and safety of the people working for us is our highest priority. Our commitment is to provide a safe working environment not only for our employees, but also for contractors and others who could potentially be exposed to risks due to our activities.
We operate in an industry exposed to safety risks and accidents can potentially occur anywhere and at any time. We rely on competent and dedicated employees and contractors as well as rigorous planning to prevent accidents and ill health. In each new phase of operations we identify, analyse and aim to mitigate all potential risks.
We also test and review our emergency preparedness in operations on an ongoing basis and hold regular emergency response exercises locally, together with external emergency preparedness organisations. Internal HSE audits are also conducted in order to identify and mitigate potential safety issues and ensure that sound HSE practices are in place. Safety is a joint responsibility and we expect the same commitment from our contractors, suppliers and partners as we do from our employees.
In 2016, we achieved a Lost Time Incident Rate (LTIR) for Lundin Petroleum's employees and contractors of 0.67 per million hours worked and a Total Recordable Incident Rate (TRIR) of 2.34 per million hours worked. This is an improvement compared to 2015 and attest to our focus on safety at a time of high operational activity.
Despite our strong performance, a fatal accident occurred in Malaysia in 2016. We tragically lost one of our sub-contractors working for the FOS Leo supply vessel on the Bertam field, offshore Malaysia. In-depth investigations into the accident were conducted both by local management and third parties with a view to fully understand the circumstances of the accident and ensure preventive measures are in place to avoid such accidents in the future. A comprehensive HSE programme was developed to improve control of work and safety leadership and will continue to be implemented throughout 2017.
Environmental responsibility starts with understanding the environmental context in which we operate. Before any exploration, development or production activities begin Lundin Petroleum uses existing environmental baseline studies or perform its own baseline or impact assessments. As a result, operational plans may be modified in order to avoid an environmental impact, for example by drilling a deviated well, changing the anchor pattern of the rig or bringing drill cuttings to shore. Drilling activities only commence after an environmental permit has been obtained from national authorities.
Respecting our environment is an essential part of the planning phase and we have robust systems in place to ensure that risks are properly assessed and that competence and capacity exist to prevent and, if need be, manage oil spills. In addition to national arrangements, Lundin Petroleum has a contract with Oil Spill Response (OSRL), the world's largest oil spill preparedness and response organisation, to cover its worldwide activities and ensure an effective response anywhere in the world.
Lundin Petroleum's operations are located on the Norwegian Continental Shelf, the area in the world with the lowest carbon intensity levels in the industry over the past ten years and with the highest carbon taxes. Our work to include climate change considerations in operational activities and in the selection of installation designs, products and equipment has therefore been a way of minimising both our carbon footprint and our costs.
In 2016, Lundin Petroleum significantly reduced its greenhouse gas emissions compared to 2015 (emissions data is published in the Sustainability Report 2016) which means we are now operating with a lower intensity level than the industry average.
In addition to seeking carbon efficiency in our operations, we take an active part in discussions on climate change. Through engagement with environmental organisations and other stakeholders, we stay informed of the latest developments on international climate policy. As part of our risk management, we analyse upcoming climate policy measures and how they will affect the energy market and take this into account in our strategic planning to make sure that our asset base is robust and sustainable, taking into account both climate risks and opportunities. In addition, Lundin Norway is part of the Norwegian Oil & Gas Association's (NOROG) working group on climate change and its roadmap to 2030 and 2050, which outlines the Norwegian oil and gas industry's commitment to contribute to a future low carbon society.
We are committed to operate according to the highest level of ethical standards and we believe that the rule of law and transparency are essential in order to ensure that our activities benefit society as a whole.
As part of our commitment to good governance, we track internal corruption potential through our financial and Corporate Responsibility reviews and audits. While our internal processes ensure that we have a low exposure to corruption, the issue is highlighted in our risk reviews. We monitor corruption trends through Transparency International's Corruption Index, media and NGO reports, as well as progress made through legislative developments and law enforcement. Our business partners and contractors are expected to abide by our anti-corruption principles.
As in previous years, there were no cases of suspected or actual corruption throughout the Group in 2016.
One of the means of receiving information regarding potential or actual cases of corruption is through our Whistleblowing policy and procedure. In the course of 2016, the whistleblowing procedure was invoked once, by a former employee, regarding an internal process. A thorough review was undertaken which confirmed that Lundin Petroleum followed industry and regulatory standards.
The disclosure of payments made to governments is a way to honour Lundin Petroleum's commitment to contribute to the economic and social development of our host countries.
The Extractive Industries Transparency Initiative (EITI), which reconciles government disclosure of cash flows from the extractive industry with the disclosure of payments made by the industry to the government, is a meaningful initiative for the industry and natural resource rich countries. Since 2009, Lundin Petroleum has consistently reported payments made to governments in EITI compliant countries within the Group. See also the Lundin Petroleum report of payments to governments on www.lundin-petroleum.com
Promoting good governance and requiring high standards of ethical business conduct throughout our value chain is of the highest importance to Lundin Petroleum since we believe that joint industry efforts are most effective in addressing anti-corruption. Lundin Petroleum has implemented expectations of ethical business conduct in contractual clauses and in its Contractor Declaration.
Lundin Petroleum also supports and participates in a number of international initiatives to actively promote ethical standards:
Lundin Petroleum is committed to ensure that respect for human rights is upheld throughout its business activities. Lundin Petroleum's assets are focused in Norway which means that we operate in a low risk environment with respect to human rights. We are nonetheless attentive to potential risks that can arise within the industry.
Lundin Petroleum adheres to all applicable national and local legislation and follows the principles for business and human rights embodied in international initiatives such as the UN Global Compact and the UN Guiding Principles on Business and Human Rights. We have a human rights due diligence
process in place for our operations in order to identify, assess and determine measures to prevent or mitigate potential human rights risks. Our human rights screenings, which review potential human rights issues in relation to planned or existing activities, have found no salient human rights issues in 2016 in relation to our operations.
Lundin Petroleum seeks to contribute to promoting human rights in the industry by engaging on the issue with partners and by requiring contractors and suppliers to sign Lundin Petroleum's Contractor Declaration, which outlines the commitment to respect human rights and to observe the highest standards of ethical business conduct.
The Lundin Foundation, founded in 2005, is a globally recognised leader in impact investments. Through our partnership with the Lundin Foundation, we support innovative solutions to key economic, social and environmental challenges which are relevant to the energy sector and to our operations. In the first years of the partnership, which was initiated in 2013, we focused on projects in Malaysia and Indonesia that aimed to increase access to renewable energy, improve biodiversity conservation and promote sustainable fisheries.
With Lundin Petroleum's operational focus shifting to Norway, the strategy has been revised to better reflect our geographical footprint. In 2016, we identified projects in Norway and Sweden which aim at supporting the increasing refugee and migrant population in these countries to improve their professional skills, start or expand businesses and enhance their employability. Lundin Petroleum also supports a project in the north of Norway that aims to encourage entrepreneurship and innovation in the area.
More information on Lundin Foundation projects can be found in the 2016 Sustainability Report.
The year 2016 was extremely successful for Lundin Petroleum. Our development projects progressed according to plan and we achieved our highest ever production rate as a result of the outstanding performance of our assets, in particular the Edvard Grieg field offshore Norway, as well as record low cash operating costs. This kind of success would not be possible without the skilled, dedicated and enthusiastic people that make up the Company and I would like to thank my fellow Board members, Group management and all staff for their tremendous contribution. To me, it is clear that the Company's robust corporate governance framework has also played an important role in supporting us achieve these operational successes. We apply our governance policies and procedures across all levels of the organisation to ensure that we duly monitor our projects, assess risks and opportunities and make necessary improvements as and when needed. Clearly this approach is bearing fruit.
During the year, the Board maintained its focus on closely monitoring the major Johan Sverdrup development project and projected expenditure. 2017 will be the most active year in the development of this enormous project and will require continued supervision and controls to make sure we have sufficient funding capacity to meet our commitments.
The Board further considered several opportunities to maximise shareholder value, including the Edvard Grieg transaction with Statoil, which enabled us to acquire an additional 15 percent interest in this world class asset and to thereby bring additional liquidity to the operations. The recently announced spin-off of Lundin Petroleum's Malaysian, French and Dutch assets into International Petroleum Corporation is another major example, which we believe will unlock previously unrecognised shareholder value and will create another exciting oil and gas company. The spin-off is a major undertaking and thanks to our people and high quality assets, combined with well-established governance policies, procedures and practices, I am convinced that the transition will be smooth.
I very much look forward to seeing the new Norway focused Lundin Petroleum continue its success story and it goes without saying that, as part of our core values, we will remain committed to operating in a responsible, transparent and sustainable manner for the benefit of all our shareholders and other stakeholders, whilst applying the highest standards of corporate governance.
Ian H. Lundin Chairman of the Board
Lundin Petroleum AB (publ), company registration number 556610-8055, has its corporate head office at Hovslagargatan 5, 111 48 Stockholm, Sweden and the registered seat of the Board of Directors is Stockholm, Sweden.
The Company's website is www.lundin-petroleum.com.
This Corporate Governance Report has been prepared in accordance with the Swedish Accounts Act (SFS 1995:1554) and the Code of Corporate Governance (Code of Governance) and deviations from the Code of Governance in 2016 Committee, as further described in the schedule on page 54, and in respect of Board member attendance at the Extraordinary General Meeting (EGM) held on 30 May 2016, as described under EGM 2016 on page 55.
The President and CEO Alex Schneiter appointed as a new Board member at the AGM on 12 May 2016. Issuing new shares and selling the Company's treasury shares as part of the transaction to acquire from Statoil ASA an additional interest of 15 percent in the Edvard Grieg field offshore Norway. Revising the Company's corporate governance practices following significant regulatory changes as a result of the EU Market Abuse Regulation and Audit Reform.
Maintaining a focus on effective governance practices and internal controls in a volatile oil price environment with significant committed development expenditure.
Lundin Petroleum is an independent Swedish oil and gas exploration and production company. After completion of the spin-off of its Malaysian, French and Dutch assets into International Petroleum Corporation through a dividend distribution, which was approved by an EGM held on 22 March 2017, its core area of business will be Norway. The ultimate parent company of the Group is the Swedish public limited liability company Lundin Petroleum AB (publ) and the Norwegian operations are conducted through its subsidiary Lundin Norway AS. In 2016, Lundin Petroleum employed worldwide approximately 542 highly experienced oil and gas professionals.
Lundin Petroleum maintains an exploration focus seeking to generate long-term value for all shareholders, as well as other stakeholders, and has, since its creation in 2001, been guided by general principles of corporate governance to:
Lundin Petroleum adheres to principles of corporate governance found in both internal and external rules and regulations. As a Swedish public limited company listed on NASDAQ Stockholm, Lundin Petroleum is subject to the Swedish Companies Act and the Annual Accounts Act, as well as the Rule Book
for Issuers of NASDAQ Stockholm, which can be found on www.nasdaqomxnordic.com. In addition, the Company abides by principles of corporate governance found in a number of internal and external documents.
The Code of Governance is based on the tradition of selfregulation and acts as a complement to the corporate governance rules contained in the Swedish Companies Act, the Annual Accounts Act, EU rules and other regulations such as the Rule Book for Issuers and good practice on the securities market. A revised Code of Governance applies as of 1 December 2016 and this Corporate Governance report has been prepared in accordance with the principles included therein (as applicable). The Code of Governance can be found on www.bolagsstyrning.se.
The Code of Governance is based on the "comply or explain principle", which entails that a company may choose to apply another solution than the one provided by the Code of Governance if it finds an alternative solution more appropriate in a particular case. The company must however explain why it did not comply with the rule in question and describe the company's preferred solution, as well as the reasons for it. Lundin Petroleum reports two deviations from the Code of Governance in 2016. Firstly in respect of the composition of the Nomination Committee, as further detailed in the schedule on page 54, and secondly, in respect of Board member attendance at the EGM held on 30 May 2016, as described under EGM 2016 on page 55. Furthermore, there were no infringements of applicable stock exchange rules during the year, nor any breaches of good practice on the securities market.
In June 2010, the Swedish International Public Prosecution Office commenced an investigation into alleged complicity in violations of international humanitarian law in Sudan during 1997–2003. The Company has cooperated extensively and proactively with the Prosecution Office by providing information regarding its operations in Block 5A in Sudan during the relevant time period. Ian H. Lundin and Alex Schneiter have been interviewed by the Prosecution Office and were notified of the suspicions that are the basis for the investigation. This is a normal part of Swedish legal procedure for any investigation and no charges have been brought, nor does this mean that charges will be brought. As repeatedly stated, Lundin Petroleum categorically refutes all allegations of wrongdoing and is cooperating with the Prosecution Office's investigation. Lundin Petroleum strongly believes that it was a force for good in Sudan and that its activities contributed to the improvement of the lives of the people of Sudan.
Lundin Petroleum's Articles of Association form the basis of the governance of the Company's operations. They set forth the Company's name, the seat of the Board, the object of the business activities, the shares and share capital of the Company and contain rules with respect to Shareholders' Meetings. The Articles of Association do not contain any limitations as to how many votes each shareholder may cast at Shareholders' Meetings, nor any provisions regarding the appointment and dismissal of Board members or amendments to the Articles of Association.
The Articles of Association 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 benefit of all stakeholders, including shareholders, employees, business partners, host and home governments and local communities. The Company applies the same standards to its activities worldwide to satisfy both its commercial and ethical requirements and strives to continuously improve its performance and to act in accordance with good oilfield practice and high standards of corporate citizenship. The Code of Conduct is an integral part of the Company's contracting procedures and any violations of the Code of Conduct will be the subject of an inquiry and appropriate remedial measures. Performance under the Code of Conduct is assessed on an annual basis by the Board.
The Code of Conduct is available on the Company's website.
While the Code of Conduct provides Lundin Petroleum's ethical framework, dedicated Group policies, procedures and guidelines have been developed to outline specific rules and controls. The policies, guidelines and procedures cover areas such as Operations, Accounting and Finance, Health and Safety, Environment, Anti-Corruption, Human Rights, Stakeholder Relations, Legal, Information Systems, Insurance & Risk Management, Human Resources, Inside Information and Corporate Communications and are continuously reviewed and updated as and when required.
In addition, Lundin Petroleum has a dedicated Health, Safety and Environment (HSE) Management System (Green Book), modelled after the ISO 14001 standard, which gives guidance to management, employees and contractors regarding the Company's intentions and expectations in HSE matters. The Green Book serves to ensure that all operations meet Lundin Petroleum's legal and ethical obligations, responsibilities and commitments within the HSE field.
Corporate Responsibility (CR) and HSE policies are available on the Company's website.
Lundin Petroleum's Rules of Procedure of the Board
The Rules of Procedure of the Board contain the fundamental rules regarding the division of duties between the Board, the Committees, the Chairman of the Board and the Chief Executive Officer (CEO). The Rules of Procedure also include instructions to the CEO, instructions for the financial reporting to the Board and the terms of reference of the Board Committees and the Investment Committee. The Rules of Procedure are approved annually by the Board.
The object of Lundin Petroleum's business is to explore for, develop and produce oil and gas and to develop other energy resources, as laid down in the Articles of Association. The Company aims to create value for its shareholders through exploration and organic growth, while operating in an economically, socially and environmentally responsible way for the benefit of all stakeholders. To achieve this value creation, Lundin Petroleum applies a governance structure that favours straightforward decision making processes, with easy access to relevant decision makers, while nonetheless providing the necessary checks and balances for the control of the activities, both operationally and financially.
The shares of Lundin Petroleum are listed on the Large Cap list of NASDAQ Stockholm. 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. This authorisation was not used in 2016.
An EGM of Lundin Petroleum was held on 30 May 2016 to approve the acquisition of an additional 15 percent working interest in the Edvard Grieg field, offshore Norway, and associated interests, from Statoil ASA (Statoil). As a part of the transaction, the Company issued in total 29,316,115 shares and transferred 2 million treasury shares to Statoil, and also received a cash consideration of approximately MSEK 544. Lundin Petroleum held no treasury shares as per 31 December 2016.
Lundin Petroleum had at the end of 2016 a total of 32,726 shareholders listed with Euroclear Sweden, which represents a decrease of 4,528 shareholders compared to 2015, i.e. a decrease of approximately 12 percent. As at 31 December 2016, the major shareholders of the Company, which held more than ten percent of the shares and votes, were Nemesia S.à.r.l., an investment company wholly owned by a Lundin family trust, which held 25.6 percent of the shares. In addition, Landor Participations Inc., an investment company wholly owned by a trust whose settler is Ian H. Lundin, held 3.1 percent of the shares. Furthermore, Statoil announced on 14 January 2016 that it had acquired 37,101,561 shares, representing 11.9 percent of the shares of the Company and, on 30 June 2016, upon the completion of the Edvard Grieg transaction, received 31,316,115 additional shares, thus taking Statoil's total shareholding up to 68,417,676, representing 20.1 percent of the shares in issue.
Further information regarding the shares and shareholders of Lundin Petroleum in 2016, as well as the Company's dividend policy, can be found on pages 14–15.
The Nomination Committee is formed in accordance with the Company's Nomination Committee Process, which the shareholders approved at the 2014 AGM as applicable for all future AGMs, until a change is proposed by a Nomination Committee. According to the Process, the Company shall invite four of the larger shareholders of the Company based on shareholdings as per 1 August each year to form the Nomination Committee, however, the members are, regardless of how they are appointed, required to promote the interests of all shareholders of the Company.
The tasks of the Nomination Committee include making recommendations to the AGM regarding the election of the Chairman of the AGM, election of Board members and the Chairman of the Board, remuneration of the Chairman and other Board members, including remuneration for Board Committee work, election of the statutory auditor and remuneration of the statutory auditor. Shareholders may submit proposals to the Nomination Committee by e-mail to [email protected].
The Nomination Committee for the 2017 AGM consists of members appointed by three of the larger shareholders of the Company based on shareholdings as per 1 August 2016. The names of the members were announced and posted on the Company's website on 26 October 2016, i.e. within the timeframe of six months before the AGM as prescribed by the Code of Governance. Statoil, as one of the larger shareholders of the Company, was invited to join but declined the invitation.
The Nomination Committee has held three meetings during its mandate and informal contacts have taken place between such meetings. To prepare the Nomination Committee for its tasks and duties and to familiarise the members with the Company, the Chairman of the Board, Ian H. Lundin, who is also a member of the Nomination Committee, commented at the meetings on the Company's business operations and future outlook, as well as on the oil and gas industry in general.
The full Nomination Committee report, including the final proposals to the 2017 AGM, are published on the Company's website together with the notice of the 2017 AGM.
| Nomination Committee for the 2017 AGM | ||||||
|---|---|---|---|---|---|---|
| Member | Appointed by | Meeting attendance |
Shares represented as at 1 Aug 2016 |
Shares represented as at 31 Dec 2016 |
Independent of the Company and Group management |
Independent of the Company's major shareholders |
| Åsa Nisell | Swedbank Robur fonder | 3/3 | 2.2 percent | 2.1 percent | Yes | Yes |
| Hans Ek | SEB Investment Management |
3/3 | 0.6 percent | 0.5 percent | Yes | Yes |
| Ian H. Lundin | Nemesia S.à.r.l and Landor Participations Inc., also non-executive Chairman of the Board of Lundin Petroleum |
3/3 | 28.7 percent | 28.7 percent | Yes | No1 |
| Magnus Unger | Non-executive Board member of Lundin Petroleum who acts as the Chairman of the Nomination Committee |
3/3 | – | – | Yes | Yes |
| Total 31.5 percent | Total 31.3 percent |
–Members of the Nomination Committee, who are not members of the Company's Board, met and had discussions with one current Board member, Peggy Bruzelius, to discuss the work and functioning of the Board, and also met with the new proposed Board member Jakob Thomasen.
–The Nomination Committee fulfills the independence requirements of the Code of Governance and no member of Group management is a member of the Committee.
1 For details, see schedule on pages 66–67.
The 2017 AGM will be held on 4 May 2017 at 1 p.m. in Vinterträdgården at the 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 27 April 2017 and must notify the Company of their intention to attend the AGM no later than 27 April 2017. 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.
The Shareholders' Meeting is the highest decision-making body of Lundin Petroleum where the shareholders exercise their voting rights and influence the business of the Company. Shareholders may request that a specific issue be included in the agenda provided such request reaches the Board in due time. The AGM is 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, however usually four weeks, before the AGM. At the AGM, the shareholders decide on a number of key issues regarding the governance of the Company, such as election of the members of the Board and the statutory auditor, the remuneration of the Board, management and the statutory auditor, including approval of the Policy on Remuneration, discharge of the Board members and the CEO from liability and the adoption of the annual accounts and appropriation of the Company's result. Extraordinary General Meetings are held as and when required for the operations of the Company.
Resolutions at Shareholders' Meetings generally require a simple majority to pass, unless the Swedish Companies Act requires a higher proportion of shares represented and votes cast at the Meeting. The results of each Shareholders' Meeting are press released promptly after the Shareholders' Meeting and the approved minutes are published on the Company's website at the latest two weeks after the Shareholders' Meeting.
The 2016 AGM was held on 12 May 2016 at Grand Hôtel in Stockholm. The AGM was attended by 589 shareholders, personally or by proxy, representing 60.4 percent of the share capital. The Chairman of the Board, all of the Board members and the CEO were present, as well as the Company's auditor and all of the members of the Nomination Committee for the 2016 AGM. The members of the Nomination Committee for the 2016 AGM were Åsa Nisell (Swedbank Robur fonder), Ulrika Danielson (Andra AP-fonden) and Knut Gezelius (SKAGEN Funds), Ian H. Lundin (Lorito Holdings (Guernsey) Ltd., Zebra Holdings and Investment (Guernsey) Ltd., which have since transferred their shareholdings to Nemesia S.à.r.l., and Landor Participations Inc., as well as non-executive Chairman of the Board of Lundin Petroleum) and Magnus Unger (non-executive Board member of Lundin Petroleum and Chairman of the Nomination Committee). All proceedings were simultaneously translated from Swedish to English and from English to Swedish and all AGM materials were provided both in Swedish and English.
The resolutions passed by the 2016 AGM include:
administration of the Company's business for 2015. · Adoption of the Company's income statement and balance sheet and the consolidated income statement and balance sheet and deciding that no dividend was to be declared for 2015.
· Re-election of the registered accounting firm PricewaterhouseCoopers AB as the Company's statutory auditor until the 2017 AGM, authorised public accountant Johan Rippe being the designated auditor in charge.
An electronic system with voting devices was used for the two last items requiring a qualified majority. The minutes of the 2016 AGM and all AGM materials, in Swedish and English, are available on the Company's website, together with the CEO's address to the AGM.
An EGM was held on 30 May 2016 in Stockholm in respect of the acquisition of an additional 15 percent interest in the Edvard Grieg field offshore Norway, and associated interests, from Statoil. The EGM resolved, in accordance with the Board of Directors' proposals:
The Chairman of the Board and the CEO, who is also a Board member, attended the EGM, which was held approximately two weeks after the AGM. However, a quorum of Board members was not present as required by Code of Governance rule 1.2. The notice of the EGM had been issued before the AGM and the proposed transaction had also been presented at the AGM, and it was therefore considered sufficient that the Chairman of the Board and the CEO represent the Board at the EGM.
The transaction was completed on 30 June 2016 and as a result, Statoil now owns 68,417,676 shares of Lundin Petroleum, representing 20.1 percent of the Company shares. The total dilution effect of the share issue to Statoil was approximately 8.6 percent of the number of shares in the Company.
Lundin Petroleum's statutory auditor audits annually the Company's financial statements, the consolidated financial statements, the Board's and the CEO's administration of the Company's affairs and reports on the Corporate Governance Report. The auditor also performs a review of the Company's half year report and issues a statement regarding the Company's compliance with the Policy on Remuneration approved by the AGM. The Board of Directors meets at least once a year with the auditor without any member of Group management present at the meeting. In addition, the auditor participates regularly in Audit Committee meetings, in particular in connection with the Company's half year and year end reports. Group entities outside of Sweden are audited in accordance with local rules and regulations.
At the 2016 AGM, the audit firm PricewaterhouseCoopers AB was re-elected as the auditor of the Company for a period of one year until the 2017 AGM. The auditor in charge is the authorised public accountant Johan Rippe.
The auditor's fees are described in the notes to the financial statements, see Note 26 on page 117 and Note 7 on page 122. 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.
5
Lundin Petroleum's independent qualified reserves auditor certifies 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 Production, Reserves and Resources section on pages 18–21.
The Board of Directors of Lundin Petroleum is responsible for the organisation of the Company and management of the Company's operations. The Board is to manage the Company's affairs in the interests of the Company and all shareholders with the aim of creating long-term shareholder value. To achieve this, the Board should at all times have an appropriate and diverse composition considering the current and expected development of the operations, with Board members from a wide range of backgrounds that possess both individually and collectively the necessary experience and expertise. The Code of Governance recommends that an even gender distribution should be pursued.
The Board of Lundin Petroleum shall, according to the Articles of Association, consist of a minimum of three and a maximum of ten directors with a maximum of three deputies, and the AGM decides the final number each year. The Board members are elected for a period of one year.
The Nomination Committee for the 2016 AGM considered that a Board size of eight members would be appropriate taking into account the nature, size, complexity and geographical scope of the Company's business. The 2016 AGM approved the proposal and re-elected Peggy Bruzelius, C. Ashley Heppenstall, Ian H. Lundin, also Chairman of the Board, Lukas H. Lundin, Grace Reksten Skaugen, Magnus Unger and Cecilia Vieweg as Board members, and elected the Company's CEO Alex Schneiter as a new Board member, for a period until the 2017 AGM. William A. Rand had declined re-election. There are no deputy members and no members appointed by employee organisations. In addition, the Board is supported by a corporate secretary who is not a Board member. The appointed corporate secretary is Henrika Frykman, the Company's Vice President Legal.
The Nomination Committee considered that the Board as proposed and elected by the 2016 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 in Norway and internationally and in particular in relation to Lundin Petroleum's core areas of operations, public company financial matters, Swedish practice and compliance matters and CR/HSE
· Statutory meeting following the AGM to confirm Board fees, committee compensation, signatory powers, appointment of CR/HSE Board representative and Corporate Secretary and adoption ot the Rules of Procedure
matters. Gender balance was also specifically discussed and the Nomination Committee noted that 37.5 percent of the Board members are women and that the Company has thus met since 2015 the recommendation of the Swedish Corporate Governance Board, that larger listed Swedish companies should strive to achieve 35 percent female Board representation by 2017.
The Nomination Committee also considered the independence of each proposed Board member and determined that the composition of the proposed Board met the independence requirements of the Code of Governance both in respect of independence towards the Company and Group management and towards the Company's major shareholders. The independence of each Board member is presented in the schedule on pages 66–67.
In addition to applicable rules and regulations such as the Swedish Companies Act and the Code of Governance, the Board is guided by the Rules of Procedure, which set out how the Board is to conduct its work. The Chairman of the Board, Ian H. Lundin, is responsible for ensuring that the Board's work is well organised and conducted in an efficient manner. He upholds the reporting instructions for management, as drawn up by the CEO and as approved by the Board, however, he does not take part in the day-to-day decision-making concerning the operations of the Company. The Chairman maintains close contacts with the CEO to ensure the Board is at all times sufficiently informed of the Company's operations and financial status, and to provide support to the CEO in his tasks and duties. The Chairman further meets, at various occasions during the year, shareholders of the Company to discuss shareholder questions and ownership
issues in general, as well as other Company stakeholders. In addition, the Chairman actively promotes the Company and its interests in the various operational locations and in respect of potential new business opportunities.
In addition to the statutory meeting following the AGM, the Board normally holds at least six ordinary meetings per calendar year to ensure all areas of responsibility are duly addressed and that adequate focus is placed on strategic and important issues. At the meetings, the CEO reports on the status of the business, prospects and the financial situation of the Company. The Board also receives management updates and presentations on the business and operations of the Company, financial status, CR/HSE matters, insurance and risk management, legal questions and investor relations matters, to enable the Board to duly monitor the Company's operations and financial position. Furthermore, the Board receives regular reports from the Company's Audit Committee, Compensation Committee and the CR/HSE Board representative on issues delegated to, or considered by, the Committees and the CR/HSE Board representative. A monthly operational report is also circulated to the Board members.
During 2016, 15 Board meetings were held, including the statutory meeting. To continue developing the Board's knowledge of the Company and its operations, at least one Board meeting per year is held in an operational location and is combined with visits to the operations, industry partners and other business interests. In September 2016, the Board visited the Norwegian operations and an executive session with Group management was held in connection with the Board meeting.
Ian H. Lundin Chairman since 2002 Director since 2001 Member of the Nomination Committee Member of the Compensation Committee
Peggy Bruzelius Director since 2013 Chair of the Audit Committee
C. Ashley Heppenstall Director since 2001 Member of the Audit Committee
Lukas H. Lundin Director since 2001
At the executive session, an overview of the Company's general strategy and operations was given, as well as a financial update discussing the Company's current and future financing needs and hedging strategy, and an investor relations and valuation update. In-depth operations reviews were given regarding the Group's exploration and development activities, with a continued focus on the Norwegian operations. The executive session was followed by a site visit to the Leiv Eriksson rig and a tour of the Snøhvit field LNG facilities. Group management also attended a number of Board meetings during the year to present and report on specific questions.
A formal review of the work of the Board was conducted in November 2016 through a questionnaire submitted to all Board members, with the objective of ensuring that the Board functions in an efficient manner and to enable the Board to strengthen its focus on matters which may be raised. The topics considered included several aspects of the Board's structure, work, meetings and general issues such as support and information given to the Board.
Individual feedback from all Board members was received and the overall conclusions were very positive and showed that the structure and composition of the Board is appropriate and that the Board members have diverse qualifications with relevant operational and corporate experience, which enables the Board to function as an effective governing body. Board members considered that they continuously increase their knowledge of the Company and that individual contributions and overall effectiveness do not correlate with length of service or age,
and hence, that no term limits should be implemented. The Board Committees' duties and decision-making powers within the Board are clear and the Committees report to the Board in an appropriate manner. There are sufficient Board meetings, which are well planned and prepared and enable the Board to effectively monitor the Company's activities and performance. Site visits to the operational areas were considered necessary and valuable, and the monthly operational reports summarising the activities and main events of each month were good and succinct. The staff and related support to the Board, including Board and Committee materials, were also considered very good. Individual suggestions received included that more time should be given to discussions regarding the Company's overall strategy rather than very detailed operational matters. The results and conclusions of the review were presented to the Nomination Committee.
The remuneration of the Chairman and other Board members follows the resolution adopted by the AGM. The Board members, with the exception of the CEO, are not employed by the Company, do not receive any salary from the Company and are not eligible for participation in the Company's incentive programmes.
At the 2016 AGM, the Chairman was awarded an amount of SEK 1,050,000 and each other Board member, with the exception of the CEO, an amount of SEK 500,000. The AGM further decided to award SEK 100,000 for each ordinary Board Committee assignment and SEK 150,000 for each assignment as Committee Chairman, however, limited to a total of SEK 900,000 for Committee work.
More information on the Board members can be found on i pages 66–67 and on www.lundin-petroleum.com
Alex Schneiter Director since 2016 President and CEO
Grace Reksten Skaugen Director since 2015 CR/HSE Board representative Member of the Compensation Committee
Magnus Unger Director since 2001 Chairman of the Nomination Committee Member of the Audit Committee
Cecilia Vieweg Director since 2013 Chair of the Compensation Committee
In addition to the topics covered by the Board as per its yearly work cycle, the following significant matters were addressed by the Board during the year.
The 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 of Directors is detailed further in the schedule on pages 66–67 and in the notes to the financial statements, see Note 24 on pages 114–115.
To maximise the efficiency of the Board's work and to ensure a thorough review of specific issues, the Board has established a Compensation Committee and an Audit Committee and has appointed a CR/HSE Board representative. The tasks and responsibilities of the Committees are detailed in the terms of reference of each Committee, which are annually adopted as part of the Rules of Procedure of the Board. Minutes are kept at Committee meetings and matters discussed are reported to the Board. In addition, informal contacts take place between ordinary meetings as and when required by the operations.
The Compensation Committee assists the Board in Group management remuneration matters and receives information and prepares the Board's and the AGM's decisions on matters relating to the principles of remuneration, remunerations and other terms of employment of Group management. The objective of the Committee in determining compensation for Group management is to provide a compensation package that is based on market conditions, is competitive and takes into account the scope and responsibilities associated with the position, as well as the skills, experience and performance of the individual. The Committee's tasks also include monitoring and evaluating programmes for variable remuneration, the application of the Policy on Remuneration as well as the current remuneration structures and levels in the Company. In addition, the Compensation Committee may request advice and assistance of external reward consultants. For further information regarding Group remuneration matters, see the remuneration section of this report on pages 63–65.
The Audit Committee assists the Board in ensuring that the Company's financial reports are prepared in accordance with International Financial Reporting Standards (IFRS), the Swedish Annual Accounts Act and accounting practices applicable to a company incorporated in Sweden and listed on NASDAQ Stockholm. The Audit Committee itself does not perform audit work, however, it supervises the Company's financial reporting and gives recommendations and proposals to ensure the reliability of the reporting. The Committee also supervises the efficiency of the Company's financial internal controls, internal audit and risk management in relation to the financial reporting and provides support to the Board in the decision making processes regarding such matters. The Committee monitors the audit of the Company's financial 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 first and third quarter interim financial statements on behalf of the Board. The Audit Committee also regularly liaises with the Group's statutory auditor as part of the annual audit process and reviews the audit fees and the auditor's independence and impartiality. The Audit Committee further assists the Company's Nomination Committee in the preparation of proposals for the election of the statutory auditor at the AGM.
The Board has a leadership and supervisory role in all CR/ HSE matters within the Group and appoints yearly one non-executive Director to act as the CR/HSE Board representative. The tasks of the CR/HSE Board representative include to liaise with Group management regarding CR/HSE related matters and to regularly report on such matters to the Board of Directors. The current CR/HSE Board representative is Grace Reksten Skaugen. More information about the Company's CR/HSE activities can be found in the Responsibility section on pages 42–49.
Management structure
The Company's CEO, Alex Schneiter, is responsible for the management of the day-to-day operations of Lundin Petroleum. He is appointed by, and reports to, the Board. He in turn appoints the other members of Group management, who assist the CEO in his functions and duties, and in the implementation of decisions taken and instructions given by the Board, with the aim of ensuring that the Company meets its strategic objectives and continues to deliver responsible growth and long-term shareholder value.
Lundin Petroleum's Group and local management consists of highly experienced individuals with worldwide oil and gas experience. As a result of the announced spin-off of the Company's non-Norwegian business, several management changes occurred. Following the spin-off, Group and local management comprises, in addition to the CEO:
Prior to the spin-off, Mike Nicholson was the Company's CFO and Teitur Poulsen was the Vice President Corporate Planning and Investor Relations. Jeffrey Fountain was Vice President Legal and Christophe Nerguararian was Vice President Corporate Finance.
| Audit Committee 2016 | ||||
|---|---|---|---|---|
| Members | Meeting attendance |
Audit Committee work during the year | Other requirements | |
| Peggy Bruzelius, Chair William A. Rand1 C. Ashley Heppenstall1 Magnus Unger |
6/6 3/3 3/3 6/6 |
–Assessment of the 2015 year end report and the 2016 half year report for completeness and accuracy and recommendation for approval to the Board. –Assessment and approval of the first and third quarter reports 2016 on behalf of the Board. –Evaluation of accounting issues in relation to the assessment of the financial reports. –Follow-up and evaluation of the results of the internal audit and risk management of the Group. –Three meetings with the statutory auditor to discuss the financial reporting, internal controls, risk management, etc. –Evaluation of the audit performance and the independence and impartiality of the statutory auditor. –Review and approval of statutory auditor's fees. –Assisting the Nomination Committee in its work to propose a statutory auditor for election at the 2017 AGM. |
–The composition and the members of the Audit Committee fulfil the requirements of the Swedish Companies Act. – The Audit Committee members have extensive experience in financial, accounting and audit matters. Peggy Bruzelius' current and previous assignments include high level management positions in financial institutions and companies and she has chaired Audit Committees of other companies. Magnus Unger has previously been a member of the Company's Audit Committee and C. Ashley Heppenstall is the Company's previous CFO and CEO, and both have extensive knowledge of financial matters. |
|
| Compensation Committee 2016 | ||||
| Members | Meeting attendance |
Compensation Committee work during the year | Other requirements | |
| Cecilia Vieweg, Chair William A. Rand2 Grace Reksten Skaugen2 Ian H. Lundin |
2/2 0/0 2/2 2/2 |
–Review of and strengthening the Performance Management Process through several work sessions and ongoing reviews across the year. –Review of the performance of the CEO and Group management as per the Performance Management Process. –Preparing a report regarding the Board's evaluation of remuneration in 2015. –Continuous monitoring and evaluation of remuneration structures, levels, programmes and the Policy on Remuneration. –Preparing a proposal for the 2016 Policy on Remuneration for Board and AGM approval. –Consultation and meetings with Company stakeholders, including institutional investors, regarding the proposed LTIP 2016. – Preparing a proposal for LTIP 2016 for Board and AGM approval through several work sessions and preparation discussions. –Preparing a proposal for remuneration and other terms of employment for the CEO for Board approval. –Review of the CEO's proposals for remuneration and other terms of employment of the other members of Group management for Board approval. –Review and approval of the CEO's proposals for the principles of compensation of other employees. –Review and approval of the CEO's proposals for 2016 LTIP awards. –Undertaking a remuneration benchmark study and various contacts and ongoing reviews in relation thereto across the year. – Frequent contacts, ongoing dialogue and decisions by email outside of formal meetings to provide oversight and approvals for remuneration and severance terms as presented by Group management. |
–The composition of the Compensation Committee fulfils the independence requirements of the Code of Governance. |
1 William A. Rand was a member of the Audit Committee until 12 May 2016 and C. Ashley Heppenstall is a member of the Audit Committee as of 12 May 2016.
2 William A. Rand was a member of the Compensation Committee until 12 May 2016 and Grace Reksten Skaugen is a member of the Compensation Committee as of 12 May 2016.
Group management
Alex Schneiter President and Chief Executive Officer
Nick Walker Chief Operating Officer
Teitur Poulsen Chief Financial Officer
The tasks of the CEO and the division of duties between the Board and the CEO are defined in the Rules of Procedure and the Board's instructions to the CEO. In addition to the overall management of the Company, the CEO's tasks include ensuring that the Board receives all relevant information regarding the Company's operations, including profit trends, financial position and liquidity, as well as information regarding important events such as significant disputes, agreements and developments in important business relations. The CEO is also responsible for preparing the required information for Board decisions and for ensuring that the Company complies with applicable legislation, securities regulations and other rules such as the Code of Governance. Furthermore, the CEO maintains regular contacts with the Company's stakeholders, including shareholders, the financial markets, business partners and public authorities. To fulfil his duties, the CEO works closely with the Chairman of the Board to discuss the Company's operations, financial status, 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 all Group policies, procedures and guidelines in a professional, efficient and responsible manner. Regular management meetings are held to discuss all commercial, technical, CR/HSE, financial, legal and other issues within the Group to ensure the established short- and long-term business objectives and goals will be met. A detailed weekly operations report is further circulated to Group management summarising the operational events, highlights and issues of the week in question. Group management also travels frequently to oversee the ongoing operations, seek new business opportunities and meet with various stakeholders, including business partners, suppliers and contractors, government representatives and financial institutions. In addition, Group management liaises continuously with the Board, and in particular the Board Committees and the CR/HSE Board representative, in respect of ongoing matters and issues that may arise, and meets with the Board at least once a year at the executive session held in connection with a Board meeting in one of the operational locations.
The Company's Investment Committee, which consists of the CEO, CFO and COO, assists the Board in discharging its responsibilities in overseeing the Company's investment portfolio. The role of the Investment Committee is to determine that the Company has a clearly articulated investment policy, to develop, review and recommend to the Board investment strategies and guidelines in line with the Company's overall policy, to review and approve investment transactions and to monitor compliance with investment strategies and guidelines. The responsibilities and duties include considering annual budgets, supplementary budget approvals, investment proposals, commitments, relinquishment of licences, disposal of assets and performing other investment related functions as the Board may designate. The Investment Committee has regularly scheduled meetings and meets more frequently if required by the operations.
More information on Group management i can be found on www.lundin-petroleum.com
Christine Batruch Vice President Corporate Responsibility
Henrika Frykman Vice President Legal
Lundin Petroleum aims to offer all employees compensation packages that are competitive and in line with market conditions. These packages are designed to ensure that the Group can recruit, motivate and retain highly skilled individuals and reward performance that enhances shareholder value.
The Group's compensation packages consist of four elements, being (i) base salary; (ii) yearly variable salary; (iii) long-term incentive plan (LTIP); and (iv) other benefits. As part of the yearly assessment process, a Performance Management Process has been established to align individual and team performance to the strategic and operational goals and objectives of the overall business. Individual performance measures are formally agreed and key elements of variable remuneration are clearly linked to the achievement of such stated and agreed performance measures.
To ensure compensation packages within the Group remain competitive and in line with market conditions, the Compensation Committee undertakes yearly benchmarking studies. For each study, a peer group of international oil and gas companies of similar size and operational reach is selected, against which the Group's remuneration practices are measured. The levels of base salary, yearly variable salary and long-term incentives are set at the median level, however, in the event of exceptional performance, deviations may be authorised. As the Group continuously competes with the peer group to retain and attract the very best talent in the market, both at operational and executive level, it is considered important that the Group's compensation packages are determined primarily by reference to the remuneration practices within this peer group.
The remuneration of Group management follows the principles that are applicable to all employees, however, these principles must be approved by the shareholders at the AGM. The Compensation Committee therefore prepares yearly for approval by the Board and for submission for final approval to the AGM, a Policy on Remuneration for Group management. Based on the approved Policy on Remuneration, the Compensation Committee subsequently proposes to the Board for approval the remuneration and other terms of employment of the CEO. The CEO, in turn, proposes to the Compensation Committee, for approval by the Board, the remuneration and other terms of employment of the other members of Group management.
The 2016 AGM resolved to approve a performance based LTIP 2016, that follows the same principles as the previously approved LTIPs 2014 and 2015, for Group management and a number of key employees of Lundin Petroleum, which gives the participants the possibility to receive shares in Lundin Petroleum subject to the fulfilment of a performance condition under a three year performance period commencing on 1 July 2016 and expiring on 1 July 2019. 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 2016 and the total LTIP award made in respect of 2016 was 530,503.
The Board of Directors may reduce (including reduce to zero) the allotment of performance shares at its discretion, should it consider the underlying performance not to be reflected in the outcome of the performance condition, for example, in light of operating cash flow, reserves and HSE performance. The participants will not be entitled to transfer, pledge or dispose of the LTIP awards or any rights or obligations under LTIP 2016, 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 2016 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 2016, the Compensation Committee undertook on behalf of the Board a review of the work and performance of Group management, including the CEO. The results were presented to the Board, together with proposals regarding the compensation of the CEO and other Group management. Neither the CEO nor other Group management were present at the Board meetings when such discussions took place.
The tasks of the Compensation Committee also include monitoring and evaluating the general application of the Policy on Remuneration, as approved by the AGM, and the Compensation Committee prepares in connection therewith a yearly report, for approval by the Board, on the application of the Policy on Remuneration and the evaluation of remuneration of Group management. As part of its review process, the statutory auditor of the Company also verifies on a yearly basis whether the Company has complied with the Policy on Remuneration. Both reports are available on the Company's website.
In this Policy on Remuneration, the term "Group Management" refers to the President and Chief Executive Officer, the Chief Operating Officer, the Chief Financial Officer and Vice President level employees. Group Management will be comprised of seven executives in 2016. 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 conflict of interest regarding other assignments that such consultants may have for the Company and Group Management.
There are four key elements to the remuneration of the Group management: a) base salary; b) yearly variable salary; c) long-term incentive plan; and d) other benefits.
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,
For information regarding the Board's proposal for remuneration to Group management to the 2017 AGM, including a similar LTIP as approved by the 2014, 2015 and 2016 AGMs, see the Directors' report, pages 82–83. as well as the skills, experience and performance of the executive. The executive's base salary, as well as the other elements of the executive's remuneration, shall be reviewed annually to ensure that such remuneration remains competitive and in line with market conditions. As part of this assessment process, the Compensation Committee undertakes yearly benchmarking studies in respect of the Company's remuneration policy and practices.
The Company considers that yearly variable salary is an important part of the executive's remuneration package where associated performance targets reflect the key drivers for value creation and growth in shareholder value. Through its Performance Management Process, the Company sets predetermined and measurable performance criteria for each executive, aimed at promoting longterm value creation for the Company's shareholders.
The yearly variable salary shall, in the normal course of business, be based upon a predetermined limit, being within the range of one to twelve monthly salaries (if any). However, the Compensation Committee may recommend to the Board of Directors for approval yearly variable salary outside of this range in circumstances or in respect of performance which the Compensation Committee considers to be exceptional.
The cost of yearly variable salary for 2016 is estimated to range between no payout at minimum level and MSEK 23.0 (excluding social costs) at maximum level, based on the current composition of Group Management.
The Company believes that it is appropriate to structure its longterm incentive plans (LTIP) to align Group Management's incentives with shareholder interests. Remuneration which is linked to the share price results in a greater personal commitment to the Company. Therefore, the Board believes that the Company's LTIP for Group Management should be related to the Company's share price.
Information on the principal conditions of the proposed 2016 LTIP for Group Management, which follows the same principles as the LTIP approved by the 2014 and 2015 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 2016 LTIP is estimated to range between no cost at minimum level and MSEK 52.7 (excluding social costs) at maximum level, based on the current composition of Group Management.
Other benefits shall be based on market terms and shall facilitate the discharge of each executive's duties. Such benefits include statutory pension benefits comprising a defined contribution scheme with premiums calculated on the full base salary. The pension contributions in relation to the base salary are dependent upon the age of the executive.
A mutual notice period of between one and twelve months applies between the Company and executives, depending on the duration of the employment with the Company. In addition, severance terms are incorporated into the employment contracts for executives that give rise to compensation, up to two years' base salary, in the event of termination of employment due to a change of control of the Company. The Board of Directors is further authorised, in individual cases, to approve severance arrangements, in addition to the notice periods and the severance arrangements in respect of a change of control of the Company, where employment is terminated by the Company without cause, or otherwise in circumstances at the discretion of the Board. Such severance arrangements may provide for the payment of up to one year's base salary; no other benefits shall be included. Severance payments in aggregate (i.e. for notice periods and severance arrangements) shall be limited to a maximum of two years' base salary.
In addition to Board of Directors' fees resolved by the Annual General Meeting, remuneration as per prevailing market conditions may be paid to members of the Board of Directors 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 specific case.
Remunerations outstanding to Group Management comprise awards granted under the Company's previous LTIP programs and include 13,464 unit bonus awards under the 2013 Unit Bonus Plan, 212,308 LTIP Awards under the 2014 Performance Based Incentive Plan and 303,883 LTIP Awards under the 2015 Performance Based Incentive Plan. Further information about these plans is available in note 24 on pages 114–115.
The 2015 Policy on for Remuneration authorises the Board of Directors to deviate from the Policy in case of special circumstances in a specific case. The 2015 Policy on Remuneration did not comprise remuneration to members of the Board of Directors for work performed outside the directorship and to enable such payments, two deviations were approved for consultancy fees paid to two members of the Board of Directors, one being the Company's former Chief Executive Officer. The Board considered that special circumstances warranted the deviations as the Company may thereby draw on these Directors' experience and skills for specific projects and assignments. Further information regarding these deviations can be found in note 24 on pages 114–115.
| Name | Ian H. Lundin | Alex Schneiter | Peggy Bruzelius | C. Ashley Heppenstall |
|---|---|---|---|---|
| Function | Chairman (since 2002) | President & Chief Executive Officer, Director |
Director | Director |
| Elected | 2001 | 2016 | 2013 | 2001 |
| Born | 1960 | 1962 | 1949 | 1962 |
| Education | Bachelor of Science degree in Petroleum Engineering from the University of Tulsa. |
Graduate from the University of Geneva with a degree in Geology and a Masters degree in Geophysics. |
Master of Science (Econom ics and Business) from the Stockholm School of Economics. |
Bachelor of Science degree in Mathematics from the University of Durham. |
| Experience | Ian H. Lundin was previously CEO of International Petroleum Corp. during 1989–1998, of Lundin Oil AB during 1998–2001 and of Lundin Petroleum during 2001–2002. |
Alex Schneiter has worked with public companies where the Lundin family has a major shareholding since 1993 and was COO of Lundin Petroleum during 2001–2015 and is the Company's CEO since 2015. |
Peggy Bruzelius has worked as Managing Director of ABB Financial Services AB and has headed the asset management division of Skandinaviska Enskilda Banken AB. |
C. Ashley Heppenstall has worked with public companies where the Lundin family has a major shareholding since 1993. He was CFO of Lundin Oil AB during 1998–2001 and of Lundin Petroleum during 2001–2002 and was CEO of Lundin Petroleum during 2002–2015. |
| Other board duties | Chairman of the board of Etrion Corporation and member of the board of Bukowski Auktioner AB. |
– | Chair of the board of Lancelot Asset Management AB, member of the board of Diageo PLC, Akzo Nobel NV and Skandia Liv. |
Chairman of the board of Etrion Corporation and Africa Energy Corp. and member of the board of ShaMaran Petroleum Corp., Lundin Gold Inc., Filo Mining Corp. and Gateway Storage Company Limited. |
| Shares in Lundin Petroleum (as at 31 December 2016) |
Nil1 | 223,133 | 8,000 | 1,391,283 |
| Board Attendance | 15/15 | 7/72 | 14/15 | 15/15 |
| Audit Committee Attendance |
– | – | 6/6 | 3/34 |
| Compensation Committee Attendance |
2/2 | – | – | – |
| Remuneration for Board and Committee work |
SEK 1,150,000 | Nil | SEK 650,000 | SEK 550,000 |
| Remuneration for special assignments outside the directorship |
SEK 1,500,000 | Nil | Nil | SEK 5,208,300 |
| Independent of the Company and the Group management |
Yes | No3 | Yes | No5 |
| Independent of the Company's major shareholders |
No1 | Yes | Yes | No5 |
1 Ian H. Lundin is the settler of a trust that owns Landor Participations Inc., an investment company that holds 10,638,956 shares in the Company, and is a member of the Lundin family that holds, through a family trust, Nemesia S.à.r.l. which holds 87,187,538 shares in the Company.
2 Alex Schneiter is a member of the Board of Directors since 12 May 2016.
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 | Magnus Unger | Cecilia Vieweg |
|---|---|---|---|
| Director | Director, CR/HSE representative | Director | Director |
| 2001 | 2015 | 2001 | 2013 |
| 1958 | 1953 | 1942 | 1955 |
| Graduate from the New Mexico Institute of Mining, Technology and Engineering. |
MBA from the BI Norwegian School of Management, Bachelor of Science (Honours Physics) and Doctorate in laser physics from Imperial College of Science and Technology at the University of London. |
MBA from the Stockholm School of Economics. |
Master of Law from the University of Lund. |
| Lukas H. Lundin has held several key positions within companies where the Lundin family has a major shareholding. |
Grace Reksten Skaugen has been a director of Corporate Finance with SEB Enskilda Securities in Oslo and has worked in several roles within private equity and venture capital in Oslo and London. She is currently a member of HSBC European Senior Advisory Council and Norway country advisor to Proventus AB. |
Magnus Unger was an Executive Vice President within the Atlas Copco group during 1988–1992. |
Cecilia Vieweg was General Counsel and member of the Executive Management of AB Electrolux from 1999–2016. She previously worked as legal advisor in senior positions within the AB Volvo Group and as a lawyer in private practice. |
| Chairman of the board of Lundin Mining Corp., Denison Mines Corp., Lucara Diamond Corp., NGEx Resources Inc., Lundin Gold Inc., Filo Mining Corp. and Lundin Foundation, member of the board of Bukowski Auktioner AB. |
Chair of the board of NAXS Nordic Access Buyout A/S, Deputy Chair of the board of Orkla ASA and member of the board of Investor AB and Euronav NV, founder and Chair of the Norwegian Institute of Directors and council member of the International Institute for Strategic Studies in London. |
– | – |
| 788,3316 | – | 250,000 | 3,500 |
| 15/15 | 14/15 | 15/15 | 14/15 |
| – | – | 6/6 | – |
| – | 2/2 | – | 2/2 |
| SEK 500,000 | SEK 550,000 | SEK 600,000 | SEK 650,000 |
| Nil | Nil | SEK 150,000 | Nil |
| Yes | Yes | Yes | Yes |
| No6 | Yes | Yes | Yes |
4 C. Ashley Heppenstall is a member of the Audit Committee as of 12 May 2016.
5 C. Ashley Heppenstall is in the Nomination Committee's and the Company's opinion not deemed independent of the Company and the Group management since he was the President and CEO of Lundin Petroleum until 2015, and not of the Company's major shareholders since he is a director of companies in which entities associated with the Lundin family hold ten percent or more of the share capital and voting rights.
6 Lukas H. Lundin is a member of the Lundin family that holds, through a family trust, Nemesia S.à.r.l., which holds 87,187,538 shares in the Company.
William A. Rand declined re-election at the AGM on 12 May 2016. During the period 1 January to 12 May 2016, he attended six out of eight Board meetings held and all three Audit Committee meetings held. For additional information regarding William A. Rand, please see the Company's Annual Report 2015, and for remuneration paid to him, please refer to Note 24 on pages 114–115.
The objective for internal control over financial reporting is to provide reliable and relevant information in compliance with applicable laws and regulations
The responsibility of the Board of Directors for internal control over financial reporting is regulated by the Swedish Companies Act, the Swedish Annual Accounts Act and the Swedish Code of Governance. The information in this report is limited to internal control regarding financial reporting and describes how internal control over the financial reporting is organised, but does not comment on its effectiveness.
An internal control system for financial reporting can only provide reasonable and not absolute assurance against material misstatement or loss, and is designed to manage rather than eliminate the risk of failure to achieve the financial reporting objectives.
Lundin Petroleum's internal control system for financial reporting consists of five key objectives, as described below and in the section on risk management on pages 36–41. The key objectives are based on the principles of the Committee of Sponsoring Organisation (COSO) that set out the guiding principles of internal control. The internal control of financial reporting is a continuous evaluation of the risks and control activities within the Company. The evaluation work is an ongoing process that involves internal and external benchmarking.
joint operating arrangements. One joint operating partner is appointed to be the operator and is responsible for managing the operations, including the joint operating partners. Joint operating partners have audit rights over the joint operations to ensure that accounting procedures are followed and costs operating agreement.
The control environment of Lundin Petroleum encompasses the "tone at the top" provided by the Board and it influences the Company's governance processes and the risk and control consciousness of its employees. The Board is responsible for ensuring that the Company has an adequate internal control system. The Audit Committee assists the Board to ensure that the Company has formalised routines that support the principles for financial reporting and internal controls, and that the Company's financial reports are produced in accordance with legislation, applicable accounting standards and other requirements for listed companies.
By setting the objectives for the Company, the Board provides the management with the ability to set up the strategy and the performance goals for the Company. The internal control processes are structured accordingly to identify risk events that could arise in the context of financial reporting, compliance and the Company's operational objectives.
When risks are identified and evaluated, control activities are implemented to minimise the risks in the financial reporting process. Conclusions of the risk assessment are reported to the Group Risk Manager, Group management and the Board through the Audit Committee. Identified risk areas are mitigated through business processes with incorporated risk management, policies and procedures, segregation of duties and delegation of authority.
The Group management presents recommendations to the Board, which then provides direction to ensure there is a programme to select and develop control activities that contribute to mitigate risks to acceptable levels. The Investment Committee oversees the Company's investment decisions through the annual budget process, supplementary budget requests submitted during the year and makes recommendations to the Board as required. The finance department of each company within the
Group is responsible for the regular analysis of the financial results and for reporting thereon to the finance department at Group level. The Company also selects and develops general control activities with the support of information systems improvement and development of control activities following a "Three lines of defence" approach.
The Company communicates financial information internally, including objectives and responsibilities for internal control, which are necessary to support the functioning of internal controls. Communicating relevant information throughout all levels of the Company in a complete, correct and timely manner is an important part of the financial internal control framework. Internal policies and procedures relating to the financial reporting, such as the Authorisation Policy, the Company Accounting Principles Manual and the Finance and Accounting Manual, are updated and communicated on a regular basis to all involved employees and are accessible through the information system network.
The Board's measures for monitoring that the internal control related to financial reporting and reporting to the Board function adequately include among others; ensuring that relevant internal policies and procedures are in place and are respected, that regular meetings are held with Group management to follow-up on the financial status and activities of the Company, that internal and external audits are performed, that audit reports are reviewed and followedup on, that continuous reporting is made to the Board and that the financial reporting is prepared in accordance with applicable rules and regulations and show a true and fair view of the financial status of the Company. These measures are implemented and continuously monitored under the direction of the Audit Committee, with the assistance of Group management at all levels of the Company, including the Company's CFO. In this respect, the Internal Audit and the Company's finance department monitor financial compliance with internal policies, procedures and other corporate policy documents. The Audit Committee monitors the efficiency of the internal auditing, internal control and financial reporting, reviews all interim and annual financial reports and reports regularly thereon to the Board.
Internal Audit provides independent and objective appraisal of the control environment thereby adding value to the organisation through a continuous improvement process. The Internal Audit is concerned with the adequacy and effectiveness of systems of control and whether they are managed, maintained, complied with and function effectively. The Group Internal Audit Manager has a primary reporting line to Lundin Petroleum's Audit Committee.
Internal Audit performs regular audits according to a risk based internal audit plan which is approved by the Audit Committee twice per year. In addition, the Internal Audit coordinates and monitors joint operating audits that are undertaken by Lundin Petroleum.
Further, an important activity carried out by Internal Audit is to follow-up on the results of the previous years' internal audits and risk assessments to ensure that the appropriate corrective measures have been implemented.
Stockholm, 30 March 2017
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 2016 on pages 50–69 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 sufficient 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, 31 March 2017
PricewaterhouseCoopers AB
Johan Rippe Johan Malmqvist Lead Partner
Authorised Public Accountant Authorised Public Accountant
| CFO overview | 72 |
|---|---|
| Directors' report | 73 |
| Consolidated income statement | 84 |
| Consolidated statement of comprehensive income | 85 |
| Consolidated balance sheet | 86 |
| Consolidated statement of cash flow | 87 |
| Consolidated statement of changes in equity | 88 |
| Accounting policies | 89 |
| Notes to the financial statements of the Group | 95 |
| - Note 1 – Revenue | 95 |
| - Note 2 – Production costs | 95 |
| - Note 3 – Segment information | 95 |
| - Note 4 – Finance income | 97 |
| - Note 5 – Finance costs | 98 |
| - Note 6 – Income tax | 98 |
| - Note 7 – Oil and gas properties | 100 |
| - Note 8 – Other tangible assets | 102 |
| - Note 9 – Goodwill | 102 |
| - Note 10 – Financial assets | 102 |
| - Note 10.1 – Other shares and participations | 103 |
| - Note 10.2 – Other financial assets | 103 |
| - Note 11 – Inventories | 103 |
| - Note 12 – Trade and other receivables | 104 |
| - Note 13 – Cash and cash equivalents | 104 |
| - Note 14 – Equity | 104 |
| - Note 14.1 – Share capital and share premium | 104 |
| - Note 14.2 – Other reserves | 105 |
| - Note 14.3 –Earnings per share | 105 |
| - Note 15 – Financial liabilities | 105 |
| - Note 16 – Provisions | 105 |
| - Note 17 – Trade and other payables | 106 |
|---|---|
| - Note 18 – Financial assets and liabilities | 107 |
| - Note 19 – Financial risks, sensitivity analysis and | |
| derivative instruments | 109 |
| - Note 20 – Pledged assets | 112 |
| - Note 21 – Contingent liabilities and assets | 112 |
| - Note 22 – Related party transactions | 113 |
| - Note 23 – Average number of employees | 113 |
| - Note 24 – Remuneration to the Board of Directors, | |
| Group management and other employees | 114 |
| - Note 25 – Long-term incentive plans | 116 |
| - Note 26 – Remuneration to the Group's auditors | 117 |
| - Note 27 – Subsequent events | 117 |
| Annual accounts of the Parent Company | 118 |
| Parent Company income statement | 119 |
| Parent Company comprehensive income statement | 119 |
| Parent Company balance sheet | 120 |
| Parent Company statement of cash flow | 121 |
| Parent Company statement of changes in equity | 121 |
| Notes to the financial statements of the Parent Company 122 | |
| - Note 1 – Finance income | 122 |
| - Note 2 – Finance costs | 122 |
| - Note 3 – Income taxes | 122 |
| - Note 4 – Other receivables | 122 |
| - Note 5 – Accrued expenses and prepaid income | 122 |
| - Note 6 – Pledged assets, contingent liabilities and assets 122 | |
| - Note 7 – Remuneration to the auditor | 122 |
| - Note 8 – Proposed Disposition of Unappropriated | |
| Earnings | 122 |
| - Note 9 – Shares in subsidiaries | 123 |
| Board assurance | 124 |
| Auditor's report | 125 |
Oil prices fell by a further 17 percent during 2016. This continued weakness increased the challenge faced by all industry participants as they wrestled to cope with a third year of decline. Every management team and board was focused on delivering operational performance, reducing costs and ensuring that sufficient financial headroom was in place to sustain this prolonged downturn.
Lundin Petroleum rose to this challenge on all fronts, delivering world class performance from each of our core producing assets. This allowed us to generate in excess of USD 1 billion of operating cash flow, our first pillar of financial strength.
Cost levels continued to fall significantly on our dominant Johan Sverdrup growth project, with total reductions achieved amounting to 30 percent from the time when the PDO was submitted in February 2015 including currency savings. This is material for Lundin Petroleum, as every dollar saved not only adds value but improves our liquidity position, given that we are not in a cash tax paying position in Norway as a result of the significant capital we have invested in our growth projects.
Our cash operating costs fell to record low levels below USD 8 per barrel driven by a record high production for the year of 72,600 boepd.
The world class nature of our projects shone through when we concluded the refinancing of our reserve-based lending facility, the second pillar of our financial strength, with the support
As we look back on a tough year for the industry, we have a great sense of satisfaction having achieved record high production, record low cash operating costs and adding significant liquidity headroom. We can now look forward with a great sense of hope as we expect to deliver even more in 2017
from our broad international banking group. The refinancing was signed in late January 2016 when oil prices were below USD 30 per barrel. Total commitments under the facility stand at USD 5.0 billion and we exited 2016 with spare liquidity headroom of USD 1 billion to fund our growth projects.
The acquisition of an additional 15 percent interest in the Edvard Grieg field from Statoil during the year further solidified the cash flow generation of the Company and was highly value accretive.
Having delivered improved financial strength, Lundin Petroleum finds itself in the enviable position of being able to fully fund our growth projects down to oil prices of around USD 40 per barrel and to consider returning money to our shareholders should oil prices recover on a sustained basis above USD 60 per barrel, prior to the start-up of Johan Sverdrup.
This is a remarkable transformation and facilitated our plan to crystallise value for all our shareholders with the spin-off of our non-Norwegian assets.
As we look back on a tough year for the industry we have a great sense of satisfaction having achieved record high production, record low cash operating costs and adding significant liquidity headroom. We can now look forward with a great sense of hope as we expect to deliver even more in 2017. Lundin Petroleum retains its standing in the industry as one of the strongest players to capitalise on further growth.
The address of Lundin Petroleum AB's registered office is Hovslagargatan 5, Stockholm, Sweden.
The main business of Lundin Petroleum is the exploration for, the development of, and the production of oil and gas. Lundin Petroleum maintains a portfolio of oil and gas production assets
and development projects in various countries with exposure to exploration opportunities.
The Group does not carry out any significant research and development. The Group maintains branches in some areas of operation. The Parent Company has no foreign branches.
On 28 April 2016, Lundin Petroleum completed the sale of its Indonesia business, including the non-operated Singa gas field.
The transaction to acquire an additional 15 percent working interest in the Edvard Grieg field and interests in the associated pipeline assets from Statoil ASA with an effective date of 1 January 2016, completed on 30 June 2016. In consideration for the acquisition of the assets, Lundin Petroleum issued 27,580,806 new shares in Lundin Petroleum AB based upon an agreed share price of SEK 138 per share and a SEK/USD exchange rate of 8.098, which equated to a consideration of MUSD 470.0 as at 1 January 2016. The transaction was accounted for at closing in accordance with IFRS3 Business Combinations as required by the amended IFRS11 Joint Arrangements which provides guidance on the accounting for acquisitions of interests in joint operations in which the activity constitutes a business. The production and financial results from the additional working interest are being reflected from 1 July 2016.
A summary of the net assets acquired at closing is shown in the table below:
| Expressed in MUSD | 30 June 2016 |
|---|---|
| Assets | |
| Oil and gas properties | 456.1 |
| Goodwill | 128.1 |
| Cash | 25.9 |
| Total Assets Acquired | 610.1 |
| Liabilities | |
| Deferred tax | 111.0 |
| Site restoration provision | 24.2 |
| Working capital | 10.4 |
| Total Liabilities Acquired | 145.6 |
| Net Assets Acquired 1 | 464.5 |
¹ In addition, MUSD 5.5 of interest was expensed.
In accordance with the Norwegian Petroleum Tax Act, the consideration paid is on an after tax basis and the remaining tax balances were transferred from Statoil ASA to Lundin Petroleum. Lundin Petroleum is therefore not entitled to a tax deduction for the consideration paid over and above the tax values transferred. In accordance with IAS12 Income Taxes, a deferred tax liability for an amount of MUSD 128.1 was recognised on the difference between the assigned fair values and the related tax base as at 30 June 2016, and the offsetting accounting entry is to goodwill. The goodwill forms part of the impairment testing of the Edvard Grieg field going forward.
In addition, Lundin Petroleum transferred 2 million treasury shares and issued 1,735,309 new shares to Statoil ASA in exchange for a cash consideration of MSEK 544.1 (MUSD 64.1).
Lundin Petroleum is an independent oil and gas exploration and production company with a principal focus on operations in Norway. In 2016, Lundin Petroleum had a portfolio of assets in Norway, Malaysia, France, the Netherlands and Russia. Norway represents the majority of Lundin Petroleum's operational activities with production for the financial year 2016 accounting for 82 percent of total production and with 96 percent of Lundin Petroleum's total reserves as at 31 December 2016.
Lundin Petroleum has 743.5 million barrels of oil equivalent (MMboe) of proved plus probable reserves as at 31 December 2016 as certified by an independent third party. Lundin Petroleum also has a number of discovered oil and gas resources which classify as contingent resources and are not yet classified as reserves. The best estimate contingent resources net to Lundin Petroleum amount to 267 MMboe as at 31 December 2016.
Production for the year amounted to 72,600 barrels of oil equivalent per day (boepd) (compared to 32,300 boepd for 2015) and was thus in the upper end of the original production guidance of 65,000 to 75,000 boepd for the year and at the midpoint of the revised 2016 guidance of 70,000 to 75,000 boepd. The actual production was comprised as follows:
| Production in Mboepd | 2016 | 2015 |
|---|---|---|
| Crude oil | ||
| Norway | 53.2 | 18.6 |
| France | 2.6 | 2.7 |
| Malaysia | 8.6 | 5.5 |
| Total crude oil production | 64.4 | 26.8 |
| Gas | ||
| Norway | 6.1 | 2.1 |
| Netherlands | 1.6 | 1.8 |
| Indonesia | 0.5 | 1.6 |
| Total gas production | 8.2 | 5.5 |
| Total production | ||
| Quantity in Mboe | 26,559.6 | 11,790.3 |
| Quantity in Mboepd | 72.6 | 32.3 |
| Production in Mboepd |
WI1 | 2016 | 2015 |
|---|---|---|---|
| Edvard Grieg | 65%2 | 42.0 | 1.4 |
| Alvheim | 15% | 10.0 | 7.8 |
| Volund | 35% | 2.7 | 4.9 |
| Bøyla | 15% | 1.7 | 2.1 |
| Brynhild | 90% | 2.6 | 4.2 |
| Gaupe | 40% | 0.3 | 0.3 |
| Quantity in Mboepd | 59.3 | 20.7 |
1 Lundin Petroleum's working interest (WI)
2 WI 50% up to 30 June 2016
Production from the Edvard Grieg field during the year was higher than forecast at 42,000 boepd due to better reservoir performance and uptime than forecast. During the fourth quarter of 2016 a fourth production well was successfully drilled and came onstream at planned production rates in December 2016, thus allowing the field to reach its facilities design capacity levels of 100,000 boepd gross. The production capacity from the first three wells has exceeded expectations and the reservoir pressure depletion rate has been more favourable than anticipated.
The first two water injection wells have also been successfully drilled during the year, with both wells encountering better than expected reservoir sands and pressure communication with the production wells. Both water injection wells are injecting at planned rates. The facilities uptime has also been exceptional with an average facilities uptime of 97 percent for the year. During the fourth quarter of 2016 the Edvard Grieg field was shut-in for a limited period for the tie-in of the Ivar Aasen field. The tie-in operation was successfully carried out in November 2016 and the Edvard Grieg platform commenced processing Ivar Aasen hydrocarbons on 24th December 2016.
The two water injection wells which have been drilled during the year have proven additional oil reserves in the western flank of the Edvard Grieg field. The first water injection well, which was drilled in the northwestern part of the field, encountered the top reservoir 23 metres shallow to prognosis with a 26 metres gross oil column. The second water injection well, drilled 1.4 km southwest of the first water injection well, also found the top reservoir shallow to prognosis by 13 metres with a 5 metres gross oil column. The results from these two water injection wells indicate more oil-in-place in the western flank of the field than originally foreseen and has resulted in the field's estimated gross ultimate recoverable reserves increasing by 17 MMboe with the field's total ultimate recoverable reserves increasing to 223 MMboe as at year end 2016, which is a 20 percent increase on the original PDO reserves estimate. In addition to the reserves upgrade from the two water injection wells a new appraisal well will be drilled during the first half of 2017 in the southwestern part of the field to target additional gross unrisked resources of up to 30 MMboe.
The fifth production well was brought on line in early 2017 and a sixth well is currently being drilled with a total of 14 development wells scheduled to be drilled as part of the Edvard Grieg development plan with drilling operations expected to continue into 2018. The total operating cost for the Edvard Grieg field was USD 7.20 per barrel during the year.
In May 2016, Lundin Petroleum announced that it had entered into an agreement to acquire an additional 15 percent working interest in the Edvard Grieg field from Statoil ASA. The effective date of the transaction is 1 January 2016 and the transaction completed on 30 June 2016. As a result of this transaction, Lundin Petroleum increased its reserves by 29.5 MMboe. The additional production from this transaction has been accounted for from 1 July 2016. For more information, see the Changes in the Group section above.
Production from the Alvheim area during the year was better than forecast due to better than expected reservoir performance as well as a higher than expected Alvheim FPSO production efficiency of 97 percent, excluding planned shutdown of the Sage gas terminal in the United Kingdom. During August 2016, the terminal was shutdown for planned maintenance for 14 days and consequently the Alvheim FPSO was shut-in during this period. The total operating cost for the Alvheim area was USD 5.10 per barrel during the year. The Alvheim area partners signed a new contract for the Transocean Arctic rig which commenced an infill drilling campaign in the Alvheim area in December 2016.
Net production from the Alvheim field during the year was better than forecast at 10,000 boepd. The reservoir performance continues to be excellent with the most recent infill well, the B5 three-branched production well, as well as the Viper and Kobra wells, which came onstream in November 2016, all producing significantly ahead of expectation. The gas processing capacity on the Alvheim FPSO has resulted in certain wells having been production constrained during the year, however this constraint has been alleviated through an upgrade of the Alvheim FPSO gas export compressor, resulting in increased gas handling capacity. Two infill wells are planned to be drilled at Alvheim during 2017 with production startup of these wells expected in 2018.
The Volund field net production during the year was below forecast at 2,700 boepd. Further infill opportunities have been identified on the Volund field and during the year the top holes of two infill wells were successfully drilled by the Transocean Winner rig before it went off hire at the end of July. These two wells will be completed by the Transocean Arctic rig which
commenced the drilling of the first infill well in December 2016 with an expected production start-up in the second half of 2017. One exploration well is planned in 2017 targeting the Volund West prospect.
The Bøyla field net production during the year was slightly ahead of forecast at 1,700 boepd due to good reservoir performance with lower water cut in the wells than expected.
Net production from the Brynhild field during the year was lower than forecast at 2,600 boepd due to a temporary lower well capacity than forecast due to the water injection system being unavailable since August 2016. The water injection system recommenced in early 2017 following repair of the pump. The Brynhild field achieved an uptime of 65 percent for the year, excluding the planned outage earlier this year. The Haewene Brim FPSO was shut-in for 20 days during the fourth quarter 2016 to undergo planned integrity and inspection work.
Despite no remaining reserves being attributed to the Gaupe field, the field is producing intermittently subject to favourable economic conditions and achieved net production of 300 boepd during the year.
The Ivar Aasen field commenced production on 24 December 2016 and is currently producing from five wells. The field is expected to ramp-up production in accordance with the commercial arrangement with its host platform, Edvard Grieg, during 2017.
The Johan Sverdrup project is progressing on schedule with a majority of Phase 1 contracts now awarded, resulting in estimated total project costs being reduced compared to the original estimates. Phase 1 construction work commenced in 2015 with total project completion remaining on schedule.
Construction of three steel jackets has commenced at the Kværner yard on the west coast of Norway and of one jacket at the Dragados yard in Spain. Construction of the drilling platform and living quarters, through EPC contracts, is underway in Norway by Aibel and Kværner/KBR respectively and construction of the riser platform and processing platform commenced at Samsung Heavy Industries in Korea during the third quarter 2016 with Aker Solutions being contracted for the procurement and engineering of the riser platform and processing platform. In addition civil engineering works are underway on the onshore power system at Haugsneset in
| Licence | Field | WI | Operator | PDO Approval | Estimated gross reserves |
Production start achieved/expected |
Gross plateau production rate expected |
|---|---|---|---|---|---|---|---|
| Ivar Aasen Unit |
Ivar Aasen | 1.385% Aker BP | May 2013 | 175 MMboe | Production start December 2016 |
67 Mboepd | |
| Johan Sverdrup Unit |
Johan Sverdrup | 22.6% | Statoil | August 2015 | 2.0–3.0 billion boe | Late 2019 | 660 Mbopd |
Norway. The pre-drilling of development wells commenced in March 2016 with eight development wells being completed to date ahead of schedule.
The contract for the heavy lift installations for three of the topsides has been awarded to Allseas. Odfjell Drilling has been awarded contracts for drilling of the wells. Rosenberg WorleyParsons has been awarded the contracts for the construction of the three bridges linking the platforms and for the construction of two flare booms. In October 2016 the contract for modification work at the Mongstad oil terminal was awarded to Aker Solutions.
At the time of submitting the Phase 1 PDO in February 2015, the capital expenditure for Phase 1 was estimated at gross NOK 123 billion (nominal). With most of the major contracts now awarded, the latest cost estimate, as released by Statoil in early 2017, has been reduced to NOK 97 billion (nominal), a reduction of approximately 21 percent. This is based on a fixed project exchange rate of NOK 6 per USD and excludes additional foreign exchange rate savings in US dollar terms. The Phase 1 development is scheduled to start production in late 2019. The original gross production capacity for Phase 1 was estimated at 315,000 to 380,000 bopd. However, debottlenecking measures have concluded that the design processing capacity for Phase 1 will increase to 440,000 bopd with gas processing capacity in addition .
The PDO for Phase 1 also outlines certain concepts for the full field development involving an expected full field gross plateau production level of 660,000 bopd. Statoil provided an update on resources in early 2017 with gross resources increasing to between 2.0 and 3.0 billion boe with 95 percent of the resources being oil.
Statoil revised down the full field development costs (Phase 1 and Phase 2) from the previous total of NOK 207 billion to between NOK 137 and 152 billion (real 2016), due to market savings relating to Phase 1 and optimisation of the Phase 2 facilities concept. In the first quarter 2017, the Johan Sverdrup partnership decided to proceed with concept selection (DG2) for Phase 2 which is expected to start production in 2022.
During the year Lundin Petroleum successfully completed the drilling and testing of the Alta-3 appraisal well 7220/11-3A, which was a re-entry well from the suspended 7220/11-3 well drilled in 2015. The objective of the Alta-3 re-entry was to deepen the well to further assess the quality of the Permian carbonate reservoirs through water injection tests as well as to conduct a production test in the shallower gas zone. Two injection tests in the carbonate reservoir below the oil-water contact proved good to very good reservoir quality in the Falk and Ørn formations, respectively. A production test in the gas zone in the Lower Triassic reservoir section produced a maximum of 21 million cubic feet of gas per day through a 64/64 inch choke.
The original Alta-3 well encountered a gross hydrocarbon column of 120 metres and all three Alta wells drilled to date have proven pressure communication.
During the year Lundin Petroleum entered into a rig contract with Ocean Rig for the charter of the Leiv Eiriksson semisubmersible rig for an extended appraisal and exploration campaign in the southern Barents Sea. The contract for the rig is flexible and encompasses multiple well-slot options which can be called at Lundin Petroleum's election and the rig will carry out all of Lundin Petroleum operated wells in the southern Barents Sea for the 2017 drilling campaign.
The 2017 appraisal programme will consist of four appraisal wells with one well being drilled on the western flank of the Edvard Grieg field in PL338 (WI 65%) targeting gross resources of 30 MMboe and one well appraising a northern extension of the Johan Sverdrup field. The remaining two wells will appraise the Alta/Gohta discoveries on the Loppa High in the southern Barents Sea.
In January 2016, the Lorry well in PL700 in the Norwegian Sea which was spudded in November 2015 was announced as dry. The well failed to encounter the prognosed reservoir.
In March 2016, the Fosen well in PL544 in the North Sea was announced as dry. The well, which was drilled just south of Luno II, encountered a 160 metres reservoir section but was water-wet with oil shows.
In November 2016 Lundin Petroleum announced a discovery on the Neiden prospect in PL609 in the southern Barents Sea. The well, which was drilled approximately 60 km northeast of the Alta discovery, encountered a Permian carbonate reservoir with a 31 metres hydrocarbon column of which 21 metres were oil and 10 metres gas. The discovery is estimated to contain between 25 and 60 MMboe of gross resources.
Lundin Petroleum will drill five exploration wells offshore Norway in 2017. Four of the 2017 exploration wells will be drilled in the Barents Sea with the first well on the Filicudi prospect in PL533 (WI 35%) already announced as a discovery with a gross resource estimate of between 35 and 100 MMboe. Three further wells are planned to be drilled in the southern Barents Sea with one well targeting the Børselv prospect in PL609 (WI 40%) located on-trend north of the Alta and Neiden discoveries, which is subject to partner approval. The second
| Licence | Operator | WI | Well | Spud Date | Status |
|---|---|---|---|---|---|
| PL609 | Lundin Petroleum | 40% | Re-enter 7220/11-3 (Alta-3) |
July 2016 | Completed September 2016 |
| Licence | Well | Spud Date | Target | WI | Operator | Result |
|---|---|---|---|---|---|---|
| Utsira High | ||||||
| PL544 | 16/4-10 | January | Fosen | 40% | Lundin Petroleum | Dry |
| Southern Barents Sea | ||||||
| PL609 | Re-enter 7220/6-2-R | October | Neiden | 40% | Lundin Petroleum | Oil and gas discovery |
| PL533 | 7219/12-1 | November | Filicudi | 35% | Lundin Petroleum | Oil and gas discovery |
well will be targeting one segment of the shallower horizons within the multi-billion barrel gross prospective resource Korpfjell prospect in PL859 (WI 15%) in the eastern Barents Sea. The third well will be targeting the Hufsa prospect in PL533 along trend with the Filicudi discovery, which is subject to partner approval.
Additionally, one well will be drilled west of the Volund field in PL150 (WI 35%).
In January 2016, the Ministry of Petroleum and Energy announced the licence awards in the 2015 APA licensing round. Lundin Petroleum was awarded four licences of which two as operator in PL815 and PL830 (both with WI 40%) in addition to two non-operated working interests in PL678SB and PL831 (both with WI 20%).
In May 2016 the licence awards in the 23rd licensing round in the southern Barents Sea were announced and Lundin Petroleum was awarded five licences of which three as operator. Lundin Petroleum was awarded two operated licences, PL851 and PL609C (both with WI 40%) in the Loppa High area, one operated licence, PL853 (WI 60%) in the Hoop area and two non-operated licences, PL857 and PL859 (WI 20% and 15% respectively) in the southeastern Barents Sea.
During the year, Lundin Petroleum relinquished PL438, PL519, PL544, PL555, PL631, PL673, PL674, PL708, PL741 and PL779.
In January 2017, the Ministry of Petroleum and Energy announced the licence awards in the 2016 APA licensing round. Lundin Petroleum was awarded four licences, of which two as operator in PL902 (WI 50%) and PL886 (WI 40%) in addition to two non-operated working interests in PL896 and PL869 (both with WI 20%).
| Malaysia |
|---|
| ---------- |
| Production in Mboepd | WI | 2016 | 2015 |
|---|---|---|---|
| Bertam | 75% | 8.6 | 5.5 |
Net production from the Bertam field on Block PM307 (WI 75%) during the year was ahead of forecast at 8,600 boepd with an uptime of 99 percent. The Bertam field has been producing from 11 wells as of mid-October 2015 with one additional well, the A15 well, commencing production in June 2016. The A15 well results were in line with expectations with production being constrained by facilities limitations. Overall field performance is better than forecast due to better than expected reservoir performance and this outperformance has been partially offset by the shut-in of two production wells during the year in relation to replacement of downhole electrical submersible pumps and for production shut-ins due to rig moves. The West Prospero drilling rig came off contract towards the end of May 2016. Due to the excellent reservoir performance on Bertam since production startup, the gross ultimate recoverable reserves have been increased from 16.9 MMboe to 19.6 MMboe.
At year end 2016 Lundin Petroleum decided to remove the booked contingent resources associated with the Tembakau gas discovery on PM307 from its books. The net contingent resources removed amounted to 28.9 MMboe. For more information, see the Financial Review section.
During 2016, Lundin Petroleum relinquished PM308A and PM319.
Lundin Petroleum completed the drilling of the Imbok well on Block SB307/308 (WI 65%) in early January 2016. The well encountered only oil shows in Miocene sands and was plugged and abandoned as dry. Following the Imbok well, the rig was moved to drill the Bambazon prospect, also on Block SB307/308, which encountered 15 metres of net reservoir pay with oil shows. However, no moveable oil was recovered from sampling and the well was plugged and abandoned as dry. The West Prospero rig subsequently moved to the Maligan prospect on Block SB307/308 and whilst gas shows were encountered, the well was plugged and abandoned as dry.
At year end 2016 Lundin Petroleum decided to remove the booked contingent resources associated with the gas discoveries on SB303 (WI 55%) from its books. The net contingent resources removed amounted to 31.8 MMboe.
Lundin Petroleum signed a farm-out agreement with Dyas in December 2015 whereby Lundin Petroleum has transferred a 20 percent working interest in Block SB307/308 (WI 65% after farm-out) and a 20 percent working interest in Block SB303 (WI 55% after farm-out), located offshore Sabah, East Malaysia. In addition, Dyas acquired from Lundin Petroleum a 15 percent working interest in Block PM328 (WI 35% after farm-out), located offshore Peninsular Malaysia.
Lundin Petroleum announced on 22 January 2016 that it had entered into an agreement to sell the FPSO Bertam to M3nergy Investment Ltd (M3nergy), a wholly owned subsidiary of M3nergy Berhad of Malaysia. The transaction was subject to M3nergy securing financing within a certain timeframe. However, M3nergy was unable to secure the required financing and the agreement to sell the FPSO was subsequently terminated.
| Production in Mboepd | WI | 2016 | 2015 |
|---|---|---|---|
| Singa | 25.9% | 0.5 | 1.6 |
In April 2016, Lundin Petroleum completed the sale of the business in Indonesia to PT Medco Energi Internasional TBK for a cash consideration of MUSD 22, with an effective date of 1 October 2015. The Indonesian assets sold to Medco include the non-operated interest in the producing Singa gas field. Lundin Petroleum may become entitled to certain contingent payments in respect of the future production from the Singa gas field. Lundin Petroleum ceased reporting the production contribution from Singa as of 28 April 2016.
| Production in Mboepd | WI | 2016 | 2015 |
|---|---|---|---|
| France | |||
| – Paris Basin | 100%1 | 2.2 | 2.3 |
| – Aquitaine | 50% | 0.4 | 0.4 |
| Netherlands | Various | 1.6 | 1.8 |
| 4.2 | 4.5 |
1 Working interest in the Dommartin Lettree field 42.5 percent
Net production during the year from France was slightly above forecast at 2,600 boepd. Good production performance has been achieved from the Vert La Gravelle field (WI 100%) in the Paris Basin and the fields in the Aquitaine Basin have also performed well during the year.
Net production for the year from the Netherlands was ahead of forecast at 1,600 boepd.
The Langezwaag-3 (WI 7.75%) well, on the Gorredijk licence, was drilled during the third quarter 2016 and put on production in November 2016.
The drilling of the K5-F3 development well has been completed and the well was put on production in the third quarter of
In 2017, the planned activity involves the drilling of the A6 development well on the offshore E17a-A field (WI 1.2%) and the Nieuwehorne-1 exploration well in the onshore Gorredijk licence (WI 7.75%).
During 2016, the exploration area of the Lagansky block surrounding the Morskaya field (WI 70%) was relinquished.
At year end 2016, Lundin Petroleum decided to remove the booked contingent resources associated with the Morskaya oil discovery from its books. The net contingent resources removed amounted to 110.1 MMboe. For more information, see the Financial Review section.
During the year, Lundin Petroleum recorded five incidents among contractors, resulting in a year to date Lost Time Incident Rate (LTIR) of 0.67 per million hours worked and a Total Recordable Incident Rate (TRIR) of 2.34, a clear improvement over 2015 with an LTIR of 1.76 and a TRIR of 3.71. In February 2016, a tragic fatal accident took place offshore Malaysia when a contractor undertook repair work on the FPSO export hose. A thorough investigation was undertaken and follow-up measures were implemented. Two minor lost time incidents were recorded in France in February and April 2016 and two restricted work incidents in France and Norway in November.
In May 2016, Lundin Petroleum issued its first sustainability report based on the Global Reporting Initiative, GRI G4 guidance, providing more qualitative and quantitative sustainability data. This report is available on www.lundin-petroleum.com.
In June 2016, Lundin Petroleum reported to the Carbon Disclosure Project (CDP) on its climate change strategy and 2015 emissions performance.
The net result for the financial year ended 31 December 2016 amounted to MUSD -499.3 (MUSD -866.3). The loss for the year was mainly driven by an after tax impairment charge of MUSD 548.6. The net result attributable to shareholders of the Parent Company for the year amounted to MUSD -356.7 (MUSD -861.7) representing earnings per share of USD -1.09 (USD -2.79).
Earnings before interest, tax, depletion and amortisation (EBITDA) for the year amounted to MUSD 902.6 (MUSD 384.7) representing EBITDA per share of USD 2.77 (USD 1.24). Operating cash flow for the year amounted to MUSD 1,010.8 (MUSD 699.6) representing operating cash flow per share of USD 3.10 (USD 2.26).
Revenue for the year amounted to MUSD 1,159.9 (MUSD 569.3) and was comprised of net sales of oil and gas, change in under/ over lift position and other revenue as detailed in Note 1.
Net sales of oil and gas for the year amounted to MUSD 1,166.5 (MUSD 521.0). The average price achieved by Lundin Petroleum for a barrel of oil equivalent amounted to USD 42.40 (USD 50.71) and is detailed in the following table. The average Dated Brent price for the year amounted to USD 43.73 (USD 52.39) per barrel.
Net sales of oil and gas for the year are detailed in Note 3 and were comprised as follows:
| Sales | ||
|---|---|---|
| Average price per boe expressed in USD | 2016 | 2015 |
| Crude oil sales | ||
| Norway | ||
| – Quantity in Mboe | 20,654.5 | 5,939.4 |
| – Average price per boe | 43.61 | 52.97 |
| France | ||
| – Quantity in Mboe | 907.0 | 971.4 |
| – Average price per boe | 43.98 | 52.07 |
| Netherlands | ||
| – Quantity in Mboe | 1.2 | 1.2 |
| – Average price per boe | 33.54 | 50.20 |
| Malaysia | ||
| – Quantity in Mboe | 2,787.8 | 1,455.6 |
| – Average price per boe | 45.13 | 48.92 |
| Total crude oil sales | ||
| – Quantity in Mboe | 24,350.5 | 8,367.6 |
| – Average price per boe | 43.80 | 52.16 |
| Sales | ||
| Average price per boe expressed in USD | 2016 | 2015 |
| Gas and NGL sales | ||
| Norway | ||
| – Quantity in Mboe | 2,352.1 | 745.7 |
| – Average price per boe | 30.94 | 44.21 |
| Netherlands | ||
| – Quantity in Mboe | 580.4 | 633.3 |
| – Average price per boe | 27.04 | 38.88 |
| Indonesia | ||
| – Quantity in Mboe | 178.2 | 527.7 |
| – Average price per boe | 52.02 | 50.99 |
timing differences. Permanent differences arise as a result of paying royalties in kind as well as the effects from production sharing agreements. Timing differences can arise due to under/ over lift of entitlement, inventory, storage and pipeline balances effects.
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
The change in under/over lift position amounted to a charge of MUSD 28.9 (credit of MUSD 25.6) in the year due to the timing of the cargo liftings compared to production.
Other revenue amounted to MUSD 22.3 (MUSD 22.7) for the year and included Bertam FPSO lease income, a quality differential compensation on Alvheim blended crude, tariff income from France and the Netherlands and income for maintaining strategic inventory levels in France.
Production costs including inventory movements for the year amounted to MUSD 227.5 (MUSD 150.3) and are detailed in the table below.
| Production costs | 2016 | 2015 |
|---|---|---|
| Cost of operations | ||
| – In MUSD | 166.0 | 121.1 |
| – In USD per boe | 6.25 | 10.27 |
| Tariff and transportation expenses | ||
| – In MUSD | 37.9 | 11.8 |
| – In USD per boe | 1.43 | 1.00 |
| Royalty and direct production taxes | ||
| – In MUSD | 3.3 | 3.5 |
| – In USD per boe | 0.12 | 0.29 |
| Cash operating costs | ||
| – In MUSD | 207.2 | 136.4 |
| – In USD per boe | 7.80 | 11.56 |
| Change in inventory position | ||
| – In MUSD | -1.8 | -12.6 |
| – In USD per boe | -0.07 | -1.07 |
| Other | ||
| – In MUSD | 22.1 | 26.5 |
| – In USD per boe | 0.83 | 2.25 |
| Total production costs | ||
| – In MUSD | 227.5 | 150.3 |
| – In USD per boe | 8.56 | 12.74 |
Note: USD per boe is calculated by dividing the cost by total production volume for the year.
The table above excludes 47,449 barrels of crude oil purchased from outside of the Group by Lundin Petroleum Marketing SA and sold to the market.
– Quantity in Mboe 3,110.7 1,906.7 – Average price per boe 31.42 44.31
– Quantity in Mboe 27,461.2 10,274.3 – Average price per boe 42.40 50.71
Total gas and NGL sales
Total sales
The total cost of operations for the year was MUSD 166.0 (MUSD 121.1). The increase compared to the same period last year is mainly due to the contribution of the Edvard Grieg field which commenced production in November 2015. The total cost of operations excluding operational projects amounted to MUSD 151.7 (MUSD 102.7).
The cost of operations per barrel for the year amounted to USD 6.25 (USD 10.27) including operational projects and USD 5.71 (USD 8.71) excluding operational projects. This was below guidance given at the third quarter of USD 6.50 including operational projects and USD 5.85 excluding operational.
Tariff and transportation expenses for the year amounted to MUSD 37.9 (MUSD 11.8). The increase compared to the same period last year is mainly due the impact of the Edvard Grieg field.
Other costs amounted to MUSD 22.1 (MUSD 26.5) and mainly related to the operating cost share arrangement on the Brynhild field whereby the amount of operating cost varies with the oil price until mid-2017. This arrangement is being markedto-market against the oil price curve and due to the low oil price curve at the end of 2015 an asset was recognised as at 31 December 2015. This asset is being charged to the income statement over the remaining term of the arrangement.
Depletion and decommissioning costs amounted to MUSD 471.4 (MUSD 260.6) and are detailed in Note 3. The depletion costs associated with oil and gas properties amounted to MUSD 473.9 (MUSD 258.0) at an average rate of USD 17.84 (USD 21.88) per barrel. The higher depletion costs for the year compared to last year are due to the depletion charge associated with the Edvard Grieg field, partly offset by a lower Brynhild field depletion rate following the impairment of the carrying value at the end of 2015. Decommissioning costs released to the income statement in the year amounted to MUSD 2.5 (MUSD 2.6 charge) and related to the reduction in the site restoration estimate for the Gaupe field, Norway.
Depreciation of other assets amounted to MUSD 31.1 (MUSD 23.7) for the year and related to the Bertam FPSO which was depreciated from April 2015.
Exploration costs expensed in the income statement for the year amounted to MUSD 116.1 (MUSD 184.1) and are detailed in Note 3. Exploration and appraisal costs are capitalised as they are incurred. When exploration drilling is unsuccessful, the capitalised costs are expensed. All capitalised exploration costs are reviewed on a regular basis and are expensed where their recoverability is considered highly uncertain.
During the year, exploration costs relating to Norway of MUSD 101.9 were expensed and mainly related to the
uncommercial exploration wells that were drilled in PL700 (Lorry), PL544 (Fosen) and PL609 (Neiden). In addition, exploration costs were expensed relating to Malaysia of MUSD 13.1 following the drilling of the unsuccessful Bambazon and Maligan wells in SB307/308.
Non-cash impairment costs charged to the income statement for the year amounted to MUSD 632.1 (MUSD 737.0) following a decision to remove the contingent resources associated with the gas discoveries in the Sabah region offshore East Malaysia and the Tembakau gas discovery in PM307 offshore Peninsular Malaysia, as well as the Morskaya oil discovery in the Russian Caspian Sea. Management deems that it is unlikely that any of these discoveries will be developed in the foreseeable future. A pre-tax impairment cost of MUSD 506.1 was charged to the income statement in respect of Russia with a deferred tax credit of MUSD 83.5, giving a net after tax charge of MUSD 422.6. The impairment cost for Malaysia charged to the income statement was MUSD 126.0 with no associated tax credit.
Other cost of sales for the year amounted to MUSD 2.1 (MUSD –) and related to the purchase of crude oil from a third party and marketed by the Group along with its own crude.
Sale of assets amounted to a charge of MUSD 3.5 (MUSD –) for the year. The reported charge related to the disposal of the Indonesian business which completed on 28 April 2016. The effective date of the deal was 1 October 2015 for a cash consideration of MUSD 22.
The general administrative and depreciation expenses for the year amounted to MUSD 31.9 (MUSD 39.5) which included a charge of MUSD 4.6 (MUSD 7.1) in relation to the Group's longterm incentive plans (LTIP), see Note 25. Fixed asset depreciation expenses for the year amounted to MUSD 4.3 (MUSD 5.2).
Finance income for the year amounted to MUSD 22.6 (MUSD 7.4) and is detailed in Note 4.
The net foreign currency exchange gain for the year amounted to MUSD 15.0 (loss of MUSD 507.3). 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 operational expenditure amounts against the US Dollar and for the year, the net realised exchange loss on settled foreign exchange hedges amounted to MUSD 29.1 (MUSD 132.7).
Finance costs for the year amounted to MUSD 225.4 (MUSD 617.9) and are detailed in Note 5.
Interest expenses for the year amounted to MUSD 137.3 (MUSD 71.4) and represented the portion of interest charged to the income statement. An additional amount of interest of MUSD 23.4 (MUSD 40.2) associated with the funding of the Norwegian development projects was capitalised in the year. The total interest expense has increased compared to last year mainly due to the increased borrowings to fund the capital expenditure. The result on interest rate hedge settlements amounted to a loss of MUSD 19.5 (MUSD 6.9) and increased compared to last year due to the higher fixed interest rate that was hedged in 2016 compared to 2015.
The amortisation of the deferred financing fees amounted to MUSD 43.2 (MUSD 12.4) for the year and related to the expensing of the fees incurred in establishing the new group financing facility and the Norwegian exploration refund facility over the period of usage of the facilities. In addition, the unamortised portion of the capitalised financing fees incurred in establishing the previous financing facilities and the short term revolving credit facility were expensed during the second quarter of 2016 and amounted to MUSD 22.3.
The overall tax credit for the year amounted to MUSD 59.3 (MUSD 570.1).
The current tax credit for the year amounted to MUSD 80.6 (MUSD 280.6) which included MUSD 78.9 (MUSD 283.3) relating to the tax refund on Norwegian exploration and appraisal expenditure.
The deferred tax charge for the year amounted to MUSD 21.3 (credit of MUSD 289.5) and included a deferred tax charge of MUSD 98.5 relating to Norway, primarily on the difference in depletion for tax and accounting purposes. A deferred tax credit of MUSD 83.5 in relation to the Russian impairment charge was also recognised in the fourth quarter of 2016.
The Group operates in various countries and fiscal regimes where corporate income tax rates are different from the regulations in Sweden. Corporate income tax rates for the Group vary between 20 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 impairment charges and Malaysian exploration costs, 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 -142.6 loss (loss of MUSD -4.6) and related mainly to the non-controlling interest's share in a Russian subsidiary which is fully consolidated. The net result for the year included the impairment of the Morskaya oil discovery in the Russian Caspian Sea.
Oil and gas properties amounted to MUSD 4,376.4 (MUSD 4,015.4) and are detailed in Note 7.
Development and exploration and appraisal expenditure incurred for the year was as follows:
| in MUSD | 2016 | 2015 |
|---|---|---|
| Norway | 877.1 | 880.7 |
| Malaysia | 15.2 | 130.1 |
| France | 2.8 | 16.9 |
| Netherlands | 2.5 | 2.7 |
| Indonesia | 0.1 | -1.1 |
| 897.7 | 1,029.3 |
An amount of MUSD 877.1 (MUSD 880.7) of development expenditure was incurred in Norway during the year, primarily on the Johan Sverdrup and Edvard Grieg field developments. In Malaysia, MUSD 15.2 (MUSD 130.1) was incurred during the year primarily on the Bertam field A15 development well.
| 158.4 | 413.8 | |
|---|---|---|
| Netherlands | 0.1 | 1.5 |
| Indonesia | 0.3 | 3.1 |
| Russia | 1.4 | 5.3 |
| France | 0.3 | 0.4 |
| Malaysia | 14.2 | 33.3 |
| Norway | 142.1 | 370.2 |
| in MUSD | 2016 | 2015 |
Exploration and appraisal expenditure of MUSD 142.1 (MUSD 370.2) was incurred in Norway during the year, primarily on the Neiden in PL609 and the Filicudi in PL533 exploration wells in the fourth quarter of 2016, the Alta-3 appraisal well in PL609, the Fosen well in PL544 and the Lorry well in PL700. In Malaysia, MUSD 14.2 (MUSD 33.3) was incurred during the year mainly on the Bambazon and Maligan wells in SB307/308.
In addition, MUSD 456.1 was added to the oil and gas properties at 30 June 2016 and related to the additional 15 percent of the Edvard Grieg field acquired from Statoil.
Other tangible fixed assets amounted to MUSD 166.1 (MUSD 204.3) and included the accounting book value of the Bertam FPSO.
Goodwill associated with the accounting for the Edvard Grieg transaction amounted to MUSD 128.1 (MUSD –) and is described in the section Edvard Grieg transaction, see pages 73–74.
Financial assets amounted to MUSD 9.4 (MUSD 10.7) and are detailed in Note 10. Other shares and participations amounted to MUSD 8.9 (MUSD 4.1) and related to the shares held in ShaMaran Petroleum which are reported at market value with
any change in value being recorded in other comprehensive income.
Deferred tax assets amounted to MUSD 13.5 (MUSD 13.4) and are mainly related to Malaysia following the impairment of the Bertam field at year end 2015 resulting in the depreciable tax pool value being higher than the accounting book value.
Derivative instruments amounted to MUSD 17.0 (MUSD –) and related to the marked-to-market gain on the outstanding interest rate hedge contracts due to be settled after twelve months.
Inventories amounted to MUSD 54.9 (MUSD 45.6) and included both hydrocarbon inventories and well and operational supplies mainly held in Norway and Malaysia.
Trade and other receivables amounted to MUSD 288.9 (MUSD 159.3) and are detailed in Note 12. Trade receivables, which are all current, amounted to MUSD 193.4 (MUSD 35.2). Underlift amounted to MUSD 28.9 (MUSD 26.5) and was mainly attributable to a net underlift position on the Norwegian producing fields, Edvard Grieg and Brynhild. Joint operations debtors relating to various joint venture receivables amounted to MUSD 31.2 (MUSD 48.4). Prepaid expenses and accrued income amounted to MUSD 29.4 (MUSD 29.5) and represented prepaid operational and insurance expenditure. Brynhild operating cost share amounted to MUSD 3.0 (MUSD 14.7) and related to marked-to-market valuation of the arrangement where the share of the Brynhild field operating cost varies with the oil price. Other current assets amounted to MUSD 3.0 (MUSD 5.0) and included VAT and other miscellaneous receivable balances.
Derivative instruments amounted to MUSD 0.8 (MUSD –) and related to the marked-to-market gain on outstanding interest rate hedge contracts due to be settled within twelve months.
Current tax assets amounted to MUSD 77.5 (MUSD 264.7) of which MUSD 76.9 related to the Norwegian corporate tax refund in respect of 2016 which will be received in the fourth quarter of 2017.
Cash and cash equivalents amounted to MUSD 69.5 (MUSD 71.9). Cash balances are held to meet ongoing operational funding requirements.
Financial liabilities amounted to MUSD 4,048.3 (MUSD 3,834.8) and are detailed in Note 15. Bank loans amounted to MUSD 4,145.0 (MUSD 3,858.0) and related to the outstanding loan under the Group's reserve-based lending facility. Capitalised financing fees relating to the establishment costs of the financing facilities amounted to MUSD 96.7 (MUSD 23.2) and are being amortised over the period of usage of the financing facilities.
Provisions amounted to MUSD 420.0 (MUSD 379.9) and are detailed in Note 16. The provision for site restoration amounted to MUSD 407.1 (MUSD 368.2) and related to future decommissioning obligations. The provision has increased during the year due to additions relating to the Norwegian development projects and by MUSD 24.2 relating to the additional 15 percent of the Edvard Grieg field acquired at 30 June 2016. Farm-in payment amounted to MUSD 5.5 (MUSD 4.6) and related to a provision for payments towards historic costs based on production milestones on the Bertam field, Malaysia.
Deferred tax liabilities amounted to MUSD 669.3 (MUSD 542.6) of which MUSD 621.3 (MUSD 407.9) related to Norway and included a net deferred tax liability of MUSD 111.0 related to the additional 15 percent of Edvard Grieg. 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 29.8 (MUSD 48.4) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts due to be settled after twelve months.
Other non-current liabilities amounted to MUSD 33.8 (MUSD 32.2) and related to the full consolidation of a subsidiary in which the non-controlling interest entity has made funding advances in relation to LLC PetroResurs, Russia.
Trade and other payables amounted to MUSD 308.4 (MUSD 349.9) and are detailed in Note 17. Overlift amounted to MUSD 29.9 (MUSD –) and was mainly attributable to a net overlift position on the Greater Alvheim area producing fields. Joint operations creditors and accrued expenses amounted to MUSD 238.8 (MUSD 271.5) and related mainly to the development and drilling activity in Norway. Other accrued expenses amounted to MUSD 16.9 (MUSD 23.7) and other current liabilities amounted to MUSD 9.5 (MUSD 11.4).
Derivative instruments amounted to MUSD 37.6 (MUSD 66.1) and related to the marked-to-market loss on outstanding interest rate and currency hedge contracts due to be settled within twelve months.
Current provisions amounted to MUSD 6.9 (MUSD 4.8) and related to the current portion of the provision for Lundin Petroleum's Unit Bonus Plan.
The Annual General Meeting will be held in Stockholm on 4 May 2017.
The intention of the Board of Directors is to propose to the 2017 AGM the adoption of a Policy on Remuneration for 2017 that follows in essence the same principles as applied in 2016 and that contains similar elements of remuneration for Group management as the 2016 Policy on Remuneration being base salary, yearly variable salary, Long-term Incentive Plan (LTIP) and other benefits.
The Board will propose that the AGM also resolve on a longterm, performance-based incentive plan in respect of Group management and a number of key employees of Lundin Petroleum, which follows the same principles as LTIP 2014, LTIP 2015 and LTIP 2016 approved by the 2014 AGM, the 2015 AGM and the AGM 2016 respectively. LTIP 2017 gives the participants the possibility to receive shares in Lundin Petroleum subject to the fulfilment of a performance condition under a three year performance period commencing on 1 July 2017 and expiring on 1 July 2020. The performance condition is based on the share price growth and dividends (Total Shareholder Return) of the Lundin Petroleum share compared to the Total Shareholder Return of a peer group of companies. At the beginning of the performance period, the participants will be granted awards free of charge which, provided that the performance condition is met, entitle the participant to be allotted free of charge shares in Lundin Petroleum at the end of the performance period.
The number of performance shares that may be allotted to each participant is limited to a value of three times his/ her annual gross base salary for 2017. The total number of performance shares that may be allotted under LTIP 2017 is 465,000, corresponding to approximately 0.1 percent of the total number of outstanding shares in Lundin Petroleum. The Board of Directors may reduce (including reduce to zero) allotment of performance shares at its discretion, should it consider the underlying performance not to be reflected in the outcome of the performance condition, for example, in light of operating cash flow, reserves, and health and safety performance.
The participants will not be entitled to transfer, pledge or dispose of the LTIP awards or any rights or obligations under LTIP 2017, 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 financial exposure related to LTIP 2017. 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 specific case.
For a detailed description of the Policy on Remuneration applied in 2016, see the Corporate Governance report on pages 64–65. The remuneration to Board and Group management is detailed in Notes 24 and 25.
For the AGM resolution on the authorisation to issue new shares, see pages 14–15, Share and Shareholders.
The Board of Directors propose that no dividend be paid for the year. For details of the dividend policy, see pages 14–15, Share and Shareholders.
The Board of Directors propose that the unrestricted equity of the Parent Company of MSEK 11,348.1, including the net result for the year of MSEK -103.3 be brought forward.
At the 2017 AGM, all the current members of the Board of Directors will be proposed for re-election, except Magnus Unger who has declined to stand for re-election. Jakob Thomasen will be proposed for election as a new member of the Board of Directors.
The result of the Group's operations and financial position at the end of the financial year are shown in the following income statement, statement of comprehensive income, balance sheet, statement of cash flow, statement of changes in equity and related notes, which are presented in US Dollars.
The Parent Company's income statement, balance sheet, statement of cash flow, statement of changes in equity and related notes presented in Swedish Krona can be found on pages 118–123.
Subsequent events are detailed in Note 27.
Lundin Petroleum has issued a Corporate Governance report which is separate from the Financial Statements. The Corporate Governance report is included in this document, on pages 50–70.
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 | 2016 | 2015 |
|---|---|---|---|
| Revenue | 1 | 1,159.9 | 569.3 |
| Cost of sales | |||
| Production costs | 2 | -227.5 | -150.3 |
| Depletion and decommissioning costs | 7 | -471.4 | -260.6 |
| Depreciation of other assets | 8 | -31.1 | -23.7 |
| Exploration costs | 7 | -116.1 | -184.1 |
| Impairment costs of oil and gas properties | 7 | -632.1 | -737.0 |
| Other cost of sales | 3 | -2.1 | – |
| Gross profit/loss | -320.4 | -786.4 | |
| Sale of assets | -3.5 | – | |
| General, administration and depreciation expenses | -31.9 | -39.5 | |
| Operating profit/loss | -355.8 | -825.9 | |
| Result from financial investments | |||
| Finance income | 4 | 22.6 | 7.4 |
| Finance costs | 5 | -225.4 | -617.9 |
| -202.8 | -610.5 | ||
| Profit/loss before tax | -558.6 | -1,436.4 | |
| Income tax | 6 | 59.3 | 570.1 |
| Net result | -499.3 | -866.3 | |
| Attributable to: | |||
| Shareholders of the Parent Company | -356.7 | -861.7 | |
| Non-controlling interest | -142.6 | -4.6 | |
| -499.3 | -866.3 | ||
| Earnings per share – USD1 | 14.3 | -1.09 | -2.79 |
| Earnings per share fully diluted – USD1 | 14.3 | -1.09 | -2.79 |
1 Based on net result attributable to shareholders of the Parent Company.
for the Financial Year Ended 31 December
| Expressed in MUSD | 2016 | 2015 |
|---|---|---|
| Net result | -499.3 | -866.3 |
| Items that may be subsequently reclassified to profit or loss | ||
| Exchange differences foreign operations | 13.8 | -81.7 |
| Cash flow hedges | 64.3 | 6.9 |
| Available-for-sale financial assets | 5.3 | -3.7 |
| Other comprehensive income | 83.4 | -78.5 |
| Total comprehensive income | -415.9 | -944.8 |
| Attributable to: | ||
| Shareholders of the Parent Company | -278.2 | -934.8 |
| Non-controlling interest | -137.7 | -10.0 |
| -415.9 | -944.8 |
for the Financial Year Ended 31 December
| ASSETS Non-current assets Oil and gas properties 7 4,376.4 Other tangible fixed assets 8 166.1 Goodwill 9 128.1 Financial assets 10 9.4 Deferred tax assets 6 13.5 Derivative instruments 18 17.0 Total non-current assets 4,710.5 Current assets Inventories 11 54.9 Trade and other receivables 12 288.9 Derivative instruments 18 0.8 Current tax assets 6 77.5 Cash and cash equivalents 13 69.5 Total current assets 491.6 TOTAL ASSETS 5,202.1 EQUITY AND LIABILITIES Equity Share capital 14.1 0.5 Additional paid in capital 14.1 979.1 Other reserves 14.2 -430.8 |
2015 |
|---|---|
| 4,015.4 | |
| 204.3 | |
| – | |
| 10.7 | |
| 13.4 | |
| – | |
| 4,243.8 | |
| 45.6 | |
| 159.3 | |
| – | |
| 264.7 | |
| 71.9 | |
| 541.5 | |
| 4,785.3 | |
| 0.5 | |
| 445.0 | |
| -509.3 | |
| Retained earnings -430.7 |
427.3 |
| Net result -356.7 |
-861.7 |
| Shareholders' equity -238.6 |
-498.2 |
| Non-controlling interest -113.6 |
24.1 |
| Total equity -352.2 |
-474.1 |
| Liabilities | |
| Non-current liabilities | |
| Financial liabilities 15 4,048.3 |
3,834.8 |
| Provisions 16 420.0 |
379.9 |
| Deferred tax liabilities 6 669.3 |
542.6 |
| Derivative instruments 18 29.8 |
48.4 |
| Other non-current liabilities 33.8 |
32.2 |
| Total non-current liabilities 5,201.2 |
4,837.9 |
| Current liabilities | |
| Trade and other payables 17 308.4 |
349.9 |
| Derivative instruments 18 37.6 |
66.1 |
| Current tax liabilities 6 0.2 |
0.7 |
| Provisions 16 6.9 |
4.8 |
| Total current liabilities 353.1 |
421.5 |
| Total liabilities 5,554.3 |
5,259.4 |
| TOTAL EQUITY AND LIABILITIES 5,202.1 |
4,785.3 |
for the Financial Year Ended 31 December
| Expressed in MUSD | 2016 | 2015 |
|---|---|---|
| Cash flow from operations | ||
| Net result | -499.3 | -866.3 |
| Adjustments for: | ||
| Exploration costs | 116.1 | 184.1 |
| Depletion, depreciation and amortisation | 509.2 | 286.9 |
| Impairment of oil and gas properties | 632.1 | 737.0 |
| Current tax | -80.6 | -280.6 |
| Deferred tax | 21.3 | -289.5 |
| Long-term incentive plans | 15.6 | 15.2 |
| Foreign currency exchange gain/loss | -44.1 | 374.6 |
| Interest expense | 137.3 | 71.3 |
| Capitalised financing fees | 43.2 | 12.4 |
| Other | 21.3 | 28.5 |
| Interest received | 2.3 | 6.1 |
| Interest paid | -153.7 | -110.1 |
| Income taxes paid/received | 278.4 | 335.6 |
| Changes in working capital: | ||
| Changes in inventories | -13.0 | -4.0 |
| Changes in underlift position | -2.4 | -22.9 |
| Changes in receivables | 156.5 | -21.4 |
| Changes in overlift position | 29.9 | – |
| Changes in liabilities | -391.9 | -145.4 |
| Total cash flows from operating activities | 778.2 | 311.5 |
| Cash flows from investing activities | ||
| Investment in oil and gas properties | -1,055.7 | -1,443.3 |
| Investment in other fixed assets | 0.6 | -36.0 |
| Investment in subsidiaries | – | -0.1 |
| Investment in other shares and participations1 | 25.8 | -3.7 |
| Decommissioning costs paid | -10.7 | -10.6 |
| Disposal of subsidiary2 | 23.7 | – |
| Other | – | -0.5 |
| Total cash flows from investing activities | -1,016.3 | -1,494.2 |
| Cash flows from financing activities | ||
| Changes in long-term liabilities | 288.7 | 1,171.0 |
| Financing fees paid | -114.3 | -3.3 |
| Issuance of shares/Sale of treasury shares3 | 64.1 | – |
| Total cash flows from financing activities | 238.5 | 1,167.7 |
| Changes in cash and cash equivalents | 0.4 | -15.0 |
| Cash and cash equivalents at the beginning of the year | 71.9 | 80.5 |
| Currency exchange difference in cash and cash equivalents | -2.8 | 6.4 |
| Cash and cash equivalents at the end of the year | 69.5 | 71.9 |
1 Cash received on closing of the Edvard Grieg transaction with Statoil ASA.
² Cash received on the sale of the Indonesian business on closing including settlement of net working capital.
3 Cash received on the additional sale of newly issued and treasury shares to Statoil ASA.
The effects of currency exchange differences due to the translation of foreign group companies have been excluded as these effects do not affect the cash flow. Cash and cash equivalents comprise cash and short-term deposits maturing within less than three months.
for the Financial Year Ended 31 December
| Attributable to owners of the Parent Company | |||||||
|---|---|---|---|---|---|---|---|
| Expressed in MUSD | Share capital1 |
Additional paid-in capital |
Other reserves2 |
Retained earnings |
Total | Non controlling interest |
Total equity |
| Balance at 1 January 2015 | 0.5 | 445.0 | -436.2 | 422.2 | 431.5 | 34.2 | 465.7 |
| Comprehensive income | |||||||
| Net result | – | – | – | -861.7 | -861.7 | -4.6 | -866.3 |
| Currency translation difference | – | – | -76.3 | – | -76.3 | -5.4 | -81.7 |
| Cash flow hedges | – | – | 6.9 | – | 6.9 | – | 6.9 |
| Available-for-sale financial assets | – | – | -3.7 | – | -3.7 | – | -3.7 |
| Total comprehensive income | – | – | -73.1 | -861.7 | -934.8 | -10.0 | -944.8 |
| Transactions with owners | |||||||
| Investment in subsidiaries | – | – | – | – | – | -0.1 | -0.1 |
| Value of employee services | – | – | – | 5.1 | 5.1 | – | 5.1 |
| Total transactions with owners | – | – | – | 5.1 | 5.1 | -0.1 | 5.0 |
| Balance at 31 December 2015 | 0.5 | 445.0 | -509.3 | -434.4 | -498.2 | 24.1 | -474.1 |
| Comprehensive income | |||||||
| Net result | – | – | – | -356.7 | -356.7 | -142.6 | -499.3 |
| Currency translation difference | – | – | 8.9 | – | 8.9 | 4.9 | 13.8 |
| Cash flow hedges | – | – | 64.3 | – | 64.3 | – | 64.3 |
| Available-for-sale financial assets | – | – | 5.3 | – | 5.3 | – | 5.3 |
| Total comprehensive income | – | – | 78.5 | -356.7 | -278.2 | -137.7 | -415.9 |
| Transactions with owners | |||||||
| Share issuance | 0.0 | 534.1 | – | – | 534.1 | – | 534.1 |
| Value of employee services | – | – | – | 3.7 | 3.7 | – | 3.7 |
| Total transactions with owners | 0.0 | 534.1 | – | 3.7 | 537.8 | – | 537.8 |
| Balance at 31 December 2016 | 0.5 | 979.1 | -430.8 | -787.4 | -238.6 | -113.6 | -352.2 |
1 Lundin Petroleum AB's issued share capital described in detail in Note 14.1.
2 Other reserves are described in detail in Note 14.2.
Lundin Petroleum's annual report has been prepared in accordance with prevailing International Financial Reporting Standards (IFRS) and International Financial Reporting Interpretation Committee (IFRIC) interpretations adopted by the EU Commission and the Swedish Annual Accounts Act (1995:1554). In addition, RFR 1 "Supplementary Rules for Groups" has been applied as issued by the Swedish Financial Reporting Board. The Parent Company applies the same accounting policies as the Group, except as specified in the Parent Company accounting policies on page 118.
The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates and also requires management to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed under the headline "Critical accounting estimates and judgements". The consolidated financial statements have been prepared under the historical cost convention, as modified by the revaluation of available for sale financial assets and financial assets and liabilities (including derivative instruments) at fair value through other comprehensive income.
As from 1 January 2016, Lundin Petroleum has applied the following new accounting standards: Annual Improvements to IFRSs - 2012–2014 Improvements Cycle.
The adoption of these amendments did not have any impact on the consolidated financial statements of the Group.
The Group has not adopted the following standards and interpretations that are not mandatory for the financial year 2016.
IFRS 9 Financial instruments, the standard addresses the classification, measurement and recognition of financial assets and financial liabilities. Effective from 1 January 2018.
IFRS 15 Revenue from contract with customers, the standard addresses revenue recognition and establishes principles for reporting useful information to users of financial statements. Effective from 1 January 2018.
The Group is currently assessing the potential effect on the Group's consolidated financial statements of the standards not yet applicable. At this stage of analysis, the Group does not expect the impact on its consolidated financial statements to be material.
IFRS 16 Leases, this standard will replace IAS 17 "Leases" and requires assets and liabilities arising from all leases, with some exceptions, to be recognised on the balance sheet. Effective from 1 January 2019.
The Group is yet to assess the full impact of this standard.
Subsidiaries are all entities over which the Group has control. The Group controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing the Group's control. Subsidiaries are fully consolidated from the date on which control is transferred to the Group and are de-consolidated from the date that control ceases.
The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair values of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.
The non-controlling interest in a subsidiary represents the portion of the subsidiary not owned by the Group. The equity of the subsidiary relating to the non-controlling shareholders is shown as a separate item within equity for the Group. The Group recognises any non-controlling interest on an acquisitionby-acquisition basis, either at fair value or at the non-controlling interest's proportionate share of the recognised amounts of the acquiree's identifiable net assets.
Inter-company transactions, balances, income and expenses on transactions between group companies are eliminated. Profits 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 financial 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.
Investments where the shareholding is less than 20 percent of the voting rights are treated as available for sale financial assets. If the value of these assets has declined significantly or has lasted for a longer period, the cumulative loss is removed from equity and an impairment charge is recognised in the income statement. Dividends received attributable to these assets are recognised in the income statement as part of net financial items.
Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates (functional currency). The consolidated financial statements are presented in US Dollars, which is the currency the Group has elected to use as the presentation currency.
Monetary assets and liabilities denominated in foreign currencies are translated at the rates of exchange prevailing at the balance sheet date and foreign exchange currency differences are recognised in the income statement. Transactions in foreign currencies are translated at exchange rates prevailing at the transaction date. Exchange differences are included in finance income/costs in the income statement except deferred exchange differences on qualifying cash flow hedges which are recorded in other comprehensive income.
The balance sheets and income statements of foreign Group companies are translated for consolidation purposes using the current rate method. All assets and liabilities are translated at the balance sheet date rates of exchange, whereas the income statements are translated at average rates of exchange for the year, except for transactions where it is more relevant to use the rate of the day of the transaction. The translation differences which arise are recorded directly in the foreign currency translation reserve within other comprehensive income. Upon disposal of a foreign operation, the translation differences relating to that operation will be transferred from equity to the income statement and included in the result on sale. Translation differences arising from net investments in subsidiaries, used for financing exploration activities, are recorded directly in other comprehensive income.
For the preparation of the annual financial statements, the following currency exchange rates have been used.
| 31 December 2016 | 31 December 2015 | ||
|---|---|---|---|
| Average | Period end | Average Period end | |
| 8.4014 | 8.6200 | 8.0637 | 8.8090 |
| 0.9037 | 0.9487 | 0.9012 | 0.9185 |
| 8.5610 | 9.0622 | 8.4303 | 8.4408 |
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 field area cost centre basis.
Costs directly associated with an exploration well are capitalised. If it is determined that a commercial discovery has not been achieved, these exploration costs are charged to the income statement. During the exploration and development phases, no depletion is charged. The field will be transferred from the non-production cost pool to the production cost pool within oil and gas properties once production commences, and accounted for as a producing asset. Routine maintenance and repair costs for producing assets are expensed as production costs when they occur.
Net capitalised costs to reporting date, together with anticipated future capital costs for the development of the proved and probable reserves determined at the balance sheet date price levels, are depleted based on the year's production in relation to estimated total proved and probable reserves of oil and gas, in accordance with the unit of production method. Depletion of a field area is charged to the income statement through cost of sales once production commences.
Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and governmental regulations. Proved reserves can be categorised as developed or undeveloped. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimates.
Probable reserves are those unproved reserves which analysis of geological and engineering data indicate are less likely to be recovered than Proved reserves but more certain to be recovered than Possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50 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 deficit is included in the income statement.
Impairment tests are performed annually or when there are facts and circumstances that suggest that the carrying value of an asset capitalised costs within each field area less any provision for site restoration costs, royalties and deferred
production or revenue related taxes is higher than the anticipated future net cash flow from oil and gas reserves attributable to the Group's interest in the related field areas. Capitalised costs cannot be carried unless those costs can be supported by future cash flows from that asset. Provision is made for any impairment, where the net carrying value, according to the above, exceeds the recoverable amount, which is the higher of value in use and fair value less costs to sell, determined through estimated future discounted net cash flows using prices and cost levels used by Group management in their internal forecasting. If there is no decision to continue with a field specific exploration programme, the costs will be expensed at the time the decision is made.
Other tangible assets are stated at cost less accumulated depreciation. Depreciation is based on cost and is calculated on a straight line basis over the estimated economic life of 20 years for real estate and three to five years for office equipment and other assets. The FPSO located on the Bertam field, Malaysia, is being depreciated over the committed contract term.
Additional costs to existing assets are included in the assets' net book value or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. The net book value of any replaced parts is written off. Other additional expenses are deemed to be repair and maintenance costs and are charged to the income statement when they are incurred.
The net book value is written down immediately to its recoverable amount when the net book value is higher. The recoverable amount is the higher of an asset's fair value less cost to sell and value in use.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred and the fair value of noncontrolling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net assets acquired, the difference is recognised in profit 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 flows to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. When the recoverable amount is less than the carrying value an impairment loss is recognised with the expensed charge to the income statement. If indications exist that previously recognised impairment losses no longer exist or are decreased, the recoverable amount is estimated. When a previously recognised impairment loss is reversed the carrying amount of the asset is increased to the estimated recoverable amount but the increased carrying amount may not exceed the carrying amount after depreciation that would have been determined had no impairment loss been recognised for the asset in prior years.
Assets and liabilities are recognised initially at fair value plus transaction costs and subsequently measured at amortised cost unless stated otherwise. Financial assets are derecognised when the rights to receive cash flows from the investments have expired, or have been transferred and the Group has transferred substantially all risks and rewards of ownership.
Lundin Petroleum recognises the following financial assets and liabilities:
The Group has only cash flow hedges which qualify for hedge accounting. The effective portion of changes in the fair value of derivatives that qualify as cash flow hedges are recognised in other comprehensive income. The gain or loss relating to the ineffective portion is recognised immediately in the income statement. Amounts accumulated in other comprehensive income are transferred to the income statement in the period when the hedged item will affect the income statement. When a hedging instrument no longer meets the requirements for hedge accounting, expires or is sold, any accumulated gain or loss recognised in other comprehensive income remains in shareholders' equity until the forecast transaction no longer is expected to occur, at which point it is transferred to the income statement.
Inventories of consumable well supplies are stated at the lower of cost and net realisable value, cost being determined on a weighted average cost basis. Net realisable value is the estimated selling price in the ordinary course of business, less applicable variable selling expenses. Inventories of hydrocarbons are stated at the lower of cost and net realisable value. Under or overlifted positions of hydrocarbons are valued at market prices prevailing at the balance sheet date. An underlift of production from a field is included in the current receivables and valued at the reporting date spot price or prevailing contract price and an overlift of production from a field is included in the current liabilities and valued at the reporting date spot price or prevailing contract price.
Cash and cash equivalents include cash at bank, cash in hand and interest bearing securities with original maturities of three months or less.
Share capital consists of the registered share capital for the Parent Company. Share issue costs associated with the issuance of new equity are treated as a direct reduction of proceeds. Excess contribution in relation to the issuance of shares is accounted for in the item additional paid-in-capital.
Where any Group company purchases the Company's equity share capital (treasury shares), the consideration paid, including any directly attributable incremental costs (net of income taxes) is deducted from equity attributable to the Company's equity holders until these shares are cancelled or sold. Where these shares are subsequently sold, any consideration received, net of any directly attributable incremental transaction costs and related income tax effects, is included in equity attributable to the Company's equity holders.
The change in fair value of other shares and participations is accounted for in the available for sale reserve. Upon the realisation of a change in value, the change in fair value recorded will be transferred to the income statement. The change in fair value of hedging instruments which qualify for hedge accounting is accounted for in the hedge reserve. Upon
settlement of the hedge instrument, the hedged item will be transferred to the income statement. The currency translation reserve contains unrealised translation differences due to the conversion of the functional currencies into the presentation currency.
Retained earnings contain the accumulated results attributable to the shareholders of the Parent Company.
A provision is reported when the Company has a legal or constructive obligation as a consequence of an event and when it is more likely than not that an outflow of resources is required to settle the obligation and a reliable estimate can be made of the amount.
Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a discount rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to passage of time is recognised as finance costs.
On fields where the Group is required to contribute to site restoration costs, a provision is recorded to recognise the future commitment. An asset is created, as part of the oil and gas property, to represent the discounted value of the anticipated site restoration liability and depleted over the life of the field on a unit of production basis. The corresponding accounting entry to the creation of the asset recognises the discounted value of the future liability. The discount applied to the anticipated site restoration liability is subsequently released over the life of the field and is charged to financial expenses. Changes in site restoration costs and reserves are treated prospectively and consistent with the treatment applied upon initial recognition.
Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortised costs using the effective interest method, with interest expense recognised on an effective yield basis.
The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or a shorter period where appropriate.
Revenues from the sale of oil and gas are recognised in the income statement net of royalties taken in kind. Sales of oil and gas are recognised upon delivery of products and customer acceptance or on performance of services. Incidental revenues from the production of oil and gas are offset against capitalised costs of the related cost centre until quantities of proved 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 reflected through the change in under/ overlift position as part of revenue.
Service income, generated by providing technical and management services to joint operations, is recognised as other income. The fiscal regime in the area of operations defines whether royalties are payable in cash or in kind. Royalties payable in cash are accrued in the accounting period in which the liability arises. Royalties taken in kind are subtracted from production for the period to which they relate.
Borrowing costs attributable to the acquisition, construction or production of qualifying assets are added to the cost of those assets. Qualifying assets are assets that take a substantial period of time to complete for their intended use or sale. Investment income earned on the temporary investment of specific borrowings pending to be used for the qualifying asset, is deducted from the borrowing costs eligible for capitalisation.
This applies on the interest on borrowings to finance fields under development which is capitalised within oil and gas properties until production commences. All other borrowing costs are recognised in the income statement in the period in which they occur. Interest on borrowings to finance the acquisition of producing oil and gas properties is charged to the income statement as incurred.
Short-term employee benefits such as salaries, social premiums and holiday pay, are expensed when incurred.
Pensions are the most common long-term employee benefits. The pension schemes are funded through payments to insurance companies. The Group's pension obligations consist mainly of defined contribution plans. A defined contribution plan is a pension plan under which the Group pays fixed contributions. The Group has no further payment obligations once the contributions have been paid. The contributions are recognised as an expense when they are due.
The Group has one obligation under a defined benefit plan. The relating liability recognised in the balance sheet is valued at the discounted estimated future cash outflows as calculated by an external actuarial expert. Actuarial gains and losses are recognised in other comprehensive income. The Group does not have any designated plan assets.
Cash-settled share-based payments are recognised in the income statement as expenses during the vesting period and as a liability in relation to the long-term incentive plan. The liability is measured at fair value and revalued using the Black & Scholes pricing model at each balance sheet date and at the date of settlement, with any change in fair value recognised in the income statement for the period. Equity-settled sharebased payments are recognised in the income statement as expenses during the vesting period and as equity in the Balance Sheet. The option is measured at fair value at the date of grant using an options pricing model and is charged to the income statement over the vesting period without revaluation of the value of the option.
The components of tax are current and deferred. Tax is recognised in the income statement, except to the extent that it relates to items recognised in other comprehensive income or directly in equity, in which case it is matched.
Current tax is tax that is to be paid or received for the year in question and also includes adjustments of current tax attributable to previous periods.
Deferred income tax is a non-cash charge provided, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying values. Temporary differences can occur, for example, where investment expenditure is capitalised for accounting purposes but the tax deduction is accelerated, or where site restoration costs are provided for in the financial statements but not deductible for tax purposes until they are actually incurred. However, the deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit nor loss. Deferred income tax is provided on temporary differences arising on investments in subsidiaries and associates, except where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the temporary difference will not reverse in the foreseeable future. Deferred income tax is determined using tax rates (and laws) that have
been enacted or substantively enacted by the balance sheet date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled. Deferred income tax assets are recognised to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilised.
Deferred tax assets are offset against deferred tax liabilities in the balance sheet where they relate to the same jurisdiction.
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker being Group management, which, due to the unique nature of each country's operations, commercial terms or fiscal environment, is at a country level. Information for segments is only disclosed when applicable. Segmental information is presented in Note 3, Note 6 and Note 7.
The management of Lundin Petroleum has to make estimates and judgements when preparing the financial statements of the Group. Uncertainties in the estimates and judgements could have an impact on the carrying amount of assets and liabilities and the Group's result. The most important estimates and judgements in relation thereto are:
Estimates of oil and gas reserves are used in the calculations for impairment tests and accounting for depletion and site restoration. Standard recognised evaluation techniques are used to estimate the proved and probable reserves. These techniques take into account the future level of development required to produce the reserves. An independent reserves auditor reviews these estimates, see page 132 Reserve Quantity Information. Changes in estimates of oil and gas reserves, resulting in different future production profiles, will affect the discounted cash flows used in impairment testing, the anticipated date of site decommissioning and restoration and the depletion charges in accordance with the unit of production method. Changes in estimates in oil and gas reserves could for example result from additional drilling, observation of long-term reservoir performance or changes in economic factors such as oil price and inflation rates.
Information about the carrying amounts of the oil and gas properties and the amounts charged to income, including depletion, exploration costs, and impairment costs is presented in Note 7.
Key assumptions in the impairment models relate to prices and costs that are based on forward curves and the long-term corporate assumptions. Lundin Petroleum carried out its annual impairment tests in conjunction with the annual reserves
audit process. The calculation of the impairment requires the use of estimates. For the purpose of determining an eventual impairment the assumptions that management uses to estimate the future cash flows for value-in-use are future oil and gas prices and expected production volumes. These assumptions and judgements of management that are based on them are subject to change as new information becomes available. Changes in economic conditions can also affect the rate used to discount future cash flow estimates and the discount rate applied is reviewed throughout the year. Goodwill relating to acquisitions of oil and gas properties forms part of the impairment testing of oil and gas properties.
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 7.
Amounts used in recording a provision for site restoration are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to the site decommissioning and restoration can be different. To reflect the effects due to changes in legislation, requirements and technology and price levels, the carrying amounts of site restoration provisions are reviewed on a regular basis.
The effects of changes in estimates do not give rise to prior year adjustments and are treated prospectively over the estimated remaining commercial reserves of each field. While the Group uses its best estimates and judgement, actual results could differ from these estimates.
Information about the carrying amounts of the Provision for site restoration is presented in Note 16.
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 profits 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 profits.
All events up to the date when the financial statements were authorised for issue and which have a material effect in the financial statements have been disclosed. Subsequent events are presented in Note 27.
of the Group
| MUSD | 2016 | 2015 |
|---|---|---|
| Crude oil | 1,068.8 | 436.5 |
| Condensate | 14.7 | 0.6 |
| Gas | 83.0 | 83.9 |
| Net sales of oil and gas | 1,166.5 | 521.0 |
| Change in under/over lift position | -28.9 | 25.6 |
| Other revenue | 22.3 | 22.7 |
| 1,159.9 | 569.3 |
For further information on revenue, see the Directors Report on page 79.
| MUSD | 2016 | 2015 |
|---|---|---|
| Cost of operations | 166.0 | 121.1 |
| Tariff and transportation expenses | 37.9 | 11.8 |
| Direct production taxes | 3.3 | 3.5 |
| Change in inventory position | -1.8 | -12.6 |
| Other production costs | 22.1 | 26.5 |
| 227.5 | 150.3 |
For further information on production costs, see the Directors Report on pages 79–80.
The Group operates within several geographical areas. Operating segments are reported at country level which is consistent with the internal reporting provided to Group management.
The following tables present segment information regarding; revenue, production costs, exploration costs, impairment costs of oil and gas properties, gross profit/loss and certain asset and liability information regarding the Group's business segments. In addition segment information is reported in Note 6 and 7.
Revenues are derived from various external customers. There were no intercompany sales or purchases in the year or in the previous year other than to Lundin Petroleum Marketing SA which performs trading activities for Norway, 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 50 percent of the total revenue is contracted with one customer. The Parent Company is included in Other in the table below.
| MUSD | 2016 | 2015 |
|---|---|---|
| Norway | ||
| Crude oil | 901.0 | 314.6 |
| Condensate | 14.3 | – |
| Gas | 58.5 | 33.0 |
| Net sales of oil and gas | 973.8 | 347.6 |
| Change in under/over lift position | -29.1 | 25.9 |
| Other revenue | 1.5 | 2.0 |
| Revenue | 946.2 | 375.5 |
| Production costs | -168.4 | -104.5 |
| Depletion and decommissioning costs | -386.2 | -158.9 |
| Exploration costs | -101.9 | -146.5 |
| Impairment costs of oil and gas properties | – | -526.0 |
| Gross profit/loss | 289.7 | -560.4 |
| MUSD | 2016 | 2015 |
|---|---|---|
| France | ||
| Crude oil | 39.9 | 50.6 |
| Net sales of oil and gas | 39.9 | 50.6 |
| Change in under/over lift position | 0.4 | -0.2 |
| Other revenue | 1.2 | 1.5 |
| Revenue | 41.5 | 51.9 |
| Production costs | -20.5 | -25.1 |
| Depletion and decommissioning costs | -14.4 | -15.5 |
| Exploration costs | -0.1 | -0.6 |
| Gross profit/loss | 6.5 | 10.7 |
| Netherlands | ||
| Crude oil | – | 0.1 |
| Condensate | 0.4 | 0.6 |
| Gas | 15.2 | 24.0 |
| Net sales of oil and gas | 15.6 | 24.7 |
| Change in under/over lift position | -0.2 | -0.1 |
| Other revenue | 1.7 | 1.8 |
| Revenue | 17.1 | 26.4 |
| Production costs | -9.9 | -12.0 |
| Depletion and decommissioning costs | -9.7 | -10.7 |
| Exploration costs | -1.3 | -0.7 |
| Gross profit/loss | -3.8 | 3.0 |
| Malaysia | ||
| Crude oil | 125.8 | 71.2 |
| Net sales of oil and gas | 125.8 | 71.2 |
| Other revenue | 15.1 | 10.8 |
| Revenue | 140.9 | 82.0 |
| Production costs | -27.3 | -4.4 |
| Depletion and decommissioning costs | -61.1 | -66.4 |
| Depreciation of other assets | -31.1 | -23.7 |
| Exploration costs | -13.1 | -36.3 |
| Impairment costs of oil and gas properties | -126.0 | -191.8 |
| Gross profit/loss | -117.7 | -240.6 |
| Indonesia | ||
| Gas | 9.3 | 26.9 |
| Net sales of oil and gas | 9.3 | 26.9 |
| Other revenue | – | – |
| Revenue | 9.3 | 26.9 |
| Production costs | -1.4 | -4.3 |
| Depletion and decommissioning costs | – | -9.1 |
| Exploration costs | -0.3 | – |
| Impairment costs of oil and gas properties | – | -19.2 |
| Gross profit/loss | 7.6 | -5.7 |
| Other | ||
| Crude oil | 2.1 | – |
| Net sales of oil and gas | 2.1 | – |
| Other revenue | 2.8 | 6.6 |
| Revenue | 4.9 | 6.6 |
| Production costs | 0.6 | – |
| Impairment costs of oil and gas properties1 | -506.1 | – |
| Other cost of sales | -2.1 | – |
| Gross profit/loss | -502.7 | 6.6 |
1 The impairment costs of oil and gas properties relates to Russia.
| MUSD | 2016 | 2015 |
|---|---|---|
| Total | ||
| Crude oil | 1,068.8 | 436.5 |
| Condensate | 14.7 | 0.6 |
| Gas | 83.0 | 83.9 |
| Net sales of oil and gas | 1,166.5 | 521.0 |
| Change in under/over lift position | -28.9 | 25.6 |
| Other revenue | 22.3 | 22.7 |
| Revenue | 1,159.9 | 569.3 |
| Production costs | -227.5 | -150.3 |
| Depletion and decommissioning costs | -471.4 | -260.6 |
| Depreciation of other assets | -31.1 | -23.7 |
| Exploration costs | -116.1 | -184.1 |
| Impairment costs of oil and gas properties | -632.1 | -737.0 |
| Other cost of sales | -2.1 | – |
| Gross profit/loss | -320.4 | -786.4 |
| Assets | Equity and Liabilities | |||
|---|---|---|---|---|
| MUSD | 2016 | 2015 | 2016 | 2015 |
| Norway | 4,608.4 | 3,429.0 | 4,291.8 | 3,212.8 |
| France | 220.8 | 217.4 | 121.7 | 120.3 |
| Netherlands | 75.0 | 83.2 | 45.1 | 50.7 |
| Malaysia | 343.6 | 572.0 | 466.0 | 536.0 |
| Indonesia | 6.8 | 38.9 | 195.2 | 220.9 |
| Russia | 0.7 | 491.0 | 372.2 | 441.5 |
| Sweden | 2.6 | 2.1 | 7.5 | 12.7 |
| Corporate | 4,225.0 | 3,370.3 | 4,335.3 | 4,073.1 |
| Other | 162.1 | 67.4 | 162.4 | 77.4 |
| Intercompany balance elimination | -4,442.9 | -3,486.0 | -4,442.9 | -3,486.0 |
| Assets/liabilities per country | 5,202.1 | 4,785.3 | 5,554.3 | 5,259.4 |
| Shareholders' equity | N/A | N/A | -238.6 | -498.2 |
| Non-controlling interest | N/A | N/A | -113.6 | 24.1 |
| Total equity for the Group | N/A | N/A | -352.2 | -474.1 |
| Total consolidated | 5,202.1 | 4,785.3 | 5,202.1 | 4,785.3 |
For detailed information of the oil and gas properties per country, see also Note 7.
For further information on revenue, production costs, depletion and decommissioning costs, exploration costs, impairment costs of oil and gas properties, see the Directors Report on pages 79–80.
| MUSD | 2016 | 2015 |
|---|---|---|
| Foreign currency exchange gain, net | 15.0 | – |
| Interest income | 2.3 | 6.1 |
| Guarantee fees | 0.4 | 0.7 |
| Other | 4.9 | 0.6 |
| 22.6 | 7.4 |
| MUSD | 2016 | 2015 |
|---|---|---|
| Interest expense | 137.3 | 71.4 |
| Foreign currency exchange loss, net | – | 507.3 |
| Result on interest rate hedge settlement | 19.5 | 6.9 |
| Unwinding of site restoration discount | 15.2 | 10.0 |
| Amortisation of deferred financing fees | 43.2 | 12.4 |
| Loan facility commitment fees | 9.3 | 7.7 |
| Other | 0.9 | 2.2 |
| 225.4 | 617.9 |
During 2016, MUSD 23.4 (MUSD 40.2) of interest was capitalised relating to development projects.
Exchange rate variations result primarily from fluctuations in the value of the USD currency against a pool of currencies which includes, amongst others, EUR, NOK and the Russian Rouble (RUR). Lundin Petroleum has USD denominated debt recorded in subsidiaries using a functional currency other than USD. For further information on the foreign exchange movement, see the Directors Report on page 80.
| Total tax | -59.3 | -570.1 |
|---|---|---|
| 21.3 | -289.5 | |
| Malaysia | 0.5 | -12.2 |
| Russia | -83.5 | -0.2 |
| Indonesia | 3.8 | 6.6 |
| Netherlands | -0.9 | 4.8 |
| France | 2.9 | 7.2 |
| Norway | 98.5 | -295.7 |
| Deferred tax | ||
| -80.6 | -280.6 | |
| Other | 0.4 | 0.8 |
| Russia | 0.1 | 0.2 |
| Netherlands | -2.2 | 1.7 |
| Norway | -78.9 | -283.3 |
| Current tax | ||
| Tax charge MUSD |
2016 | 2015 |
For further information on income taxes, see the Directors Report on page 81.
The tax on the Group's profit before tax differs from the theoretical amount that would arise using the tax rate of Sweden as follows:
| MUSD | 2016 | 2015 |
|---|---|---|
| Loss before tax | -558.6 | -1,436.4 |
| Tax calculated at the corporate tax rate in Sweden 22% (22%) | 122.9 | 316.0 |
| Effect of foreign tax rates | -61.0 | 417.1 |
| Tax effect of expenses non-deductible for tax purposes | -136.1 | -235.3 |
| Tax effect of uplift on expenses | 152.0 | 99.9 |
| Tax effect of income not subject to tax | -0.6 | – |
| Tax effect of utilisation of unrecorded tax losses | 8.3 | 9.8 |
| Tax effect of creation of unrecorded tax losses | -24.4 | -32.9 |
| Adjustments to prior year tax assessments | -1.8 | -4.5 |
| Tax credit | 59.3 | 570.1 |
The tax rate in Norway is 78 percent and is the primary reason for the effect of foreign tax rates in 2016 in the table above. The effect of non deductible expenses mainly relates to non deductible financial expenses in Norway and to non deductible exploration expenditures in Malaysia. The uplift on expenses relates to uplift on development expenses for oil and gas assets in Norway.
There is no tax charge/credit relating to components of other comprehensive income.
| Corporation tax liability - current and deferred MUSD |
Current | Deferred | |||
|---|---|---|---|---|---|
| 2016 | 2015 | 2016 | 2015 | ||
| Norway | – | – | 621.3 | 407.9 | |
| France | – | – | 50.0 | 47.6 | |
| Netherlands | – | 0.4 | -2.0 | -1.6 | |
| Indonesia | – | – | – | 3.5 | |
| Russia | 0.2 | 0.3 | – | 85.2 | |
| Total tax liability | 0.2 | 0.7 | 669.3 | 542.6 |
There is also a tax receivable of MUSD 77.5 (MUSD 264.7) mainly related to Norway reported in current tax assets as at 31 December 2016.
For further information on tax liabilities, see the Directors Report on page 82.
Specification of deferred tax assets and tax liabilities 1
| MUSD | 2016 | 2015 |
|---|---|---|
| Deferred tax assets | ||
| Unused tax loss carry forwards | 708.6 | 508.0 |
| Other deductible temporary differences | 9.6 | 8.2 |
| 718.2 | 516.2 | |
| Deferred tax liabilities | ||
| Accelerated allowances | 1,371.1 | 955.4 |
| Brynhild operating cost share | 1.6 | 14.6 |
| Deferred tax on excess values | 1.1 | 75.3 |
| Other taxable temporary differences | 0.2 | 0.1 |
| 1,374.0 | 1,045.4 |
1 The specification of deferred tax assets and tax liabilities does not agree to the face of the balance sheet due to the netting off of balances in the balance sheet when they relate to the same jurisdiction.
The deferred tax asset is primarily relating to tax loss carried forwards in Norway for an amount of MUSD 320.7 (MUSD 283.9) and unused uplift carry forward in Norway of MUSD 374.3 (MUSD 215.3). Deferred tax assets in relation to tax loss carried forwards are only recognised in so far that there is a reasonable certainty as to the timing and the extent of their realisation.
The deferred tax liability arises mainly on accelerated allowances, being the difference between the book and the tax value of oil and gas properties primarily 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 211 (MUSD 196). The tax losses can be carried forward and utilised for up to 9 years. A deferred tax asset of MUSD 53 (MUSD 48) relating to the tax loss carry forwards has not been recognised as at 31 December 2016 due to the uncertainty as to the timing and the extent of the tax loss carry forward utilisation. This treatment is consistent with the comparative year's accounts.
The Group also has Swedish tax loss carry forwards of approximately MUSD 47 (MUSD 39). 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.
| MUSD | 31 December 2016 |
31 December 2015 |
|---|---|---|
| Production cost pools | 2,641.8 | 2,369.3 |
| Non-production cost pools | 1,734.6 | 1,646.1 |
| 4,376.4 | 4,015.4 |
| Cost | ||||||
|---|---|---|---|---|---|---|
| 1 January | 3,567.1 | 312.7 | 126.0 | 64.4 | 412.1 | 4,482.3 |
| Additions | 664.4 | 2.8 | 2.5 | 0.1 | 15.2 | 685.0 |
| Change in estimates | 10.9 | 0.8 | -4.0 | – | -4.1 | 3.6 |
| Disposal | – | – | – | -64.5 | – | -64.5 |
| Reclassifications | 43.8 | – | -1.3 | – | 0.5 | 43.0 |
| Currency translation difference | 65.4 | -10.0 | -4.0 | – | 0.1 | 51.5 |
| 31 December | 4,351.6 | 306.3 | 119.2 | – | 423.8 | 5,200.9 |
| Depletion | ||||||
| 1 January | -1,600.1 | -132.6 | -101.2 | -46.8 | -232.3 | -2,113.0 |
| Depletion charge for the year | -388.7 | -14.4 | -9.7 | – | -61.1 | -473.9 |
| Impairment | – | – | – | – | – | – |
| Disinvestments | – | – | – | 46.8 | – | 46.8 |
| Currency translation difference | -27.4 | 4.8 | 3.6 | – | – | -19.0 |
| 31 December | -2,016.2 | -142.2 | -107.3 | – | -293.4 | -2,559.1 |
| Net book value | 2,335.4 | 164.1 | 11.9 | – | 130.4 | 2,641.8 |
| MUSD | Norway | France | Netherlands | Indonesia | Malaysia | Total |
|---|---|---|---|---|---|---|
| Cost | ||||||
| 1 January | 1,896.6 | 332.9 | 133.0 | 65.5 | – | 2,428.0 |
| Additions | 181.1 | 16.9 | 2.3 | -1.1 | 132.0 | 331.2 |
| Change in estimates | 57.6 | -2.6 | 4.0 | – | 11.9 | 70.9 |
| Reclassifications | 1,743.9 | – | – | – | 268.2 | 2,012.1 |
| Currency translation difference | -312.1 | -34.5 | -13.3 | – | – | -359.9 |
| 31 December | 3,567.1 | 312.7 | 126.0 | 64.4 | 412.1 | 4,482.3 |
| Depletion | ||||||
| 1 January | -1,104.1 | -130.7 | -100.6 | -37.7 | – | -1,373.1 |
| Depletion charge for the year | -156.3 | -15.5 | -10.7 | -9.1 | -66.4 | -258.0 |
| Impairment | -526.0 | – | – | – | -165.9 | -691.9 |
| Currency translation difference | 186.3 | 13.6 | 10.1 | – | – | 210.0 |
| 31 December | -1,600.1 | -132.6 | -101.2 | -46.8 | -232.3 | -2,113.0 |
| Net book value | 1,967.0 | 180.1 | 24.8 | 17.6 | 179.8 | 2,369.3 |
| MUSD | Norway | France | Netherlands | Indonesia | Russia | Malaysia | Other | Total |
|---|---|---|---|---|---|---|---|---|
| 1 January | 1,020.6 | 6.9 | 6.6 | – | 490.2 | 121.8 | – | 1,646.1 |
| Additions | 834.3 | 0.3 | 0.7 | 0.3 | 1.5 | 14.1 | -0.6 | 850.6 |
| Expensed Exploration costs | -101.9 | -0.1 | -1.3 | -0.3 | – | -13.1 | 0.6 | -116.1 |
| Impairment | – | – | – | – | -506.1 | -122.3 | – | -628.4 |
| Change in estimates | 6.3 | – | – | – | – | – | – | 6.3 |
| Reclassifications | -43.8 | – | 1.3 | – | – | -0.5 | – | -43.0 |
| Currency translation difference | 5.1 | -0.2 | -0.2 | – | 14.4 | – | – | 19.1 |
| 31 December | 1,720.6 | 6.9 | 7.1 | – | – | – | – | 1,734.6 |
| MUSD | Norway | France | Netherlands | Indonesia | Russia | Malaysia | Total |
|---|---|---|---|---|---|---|---|
| 1 January | 2,168.0 | 8.0 | 6.2 | 16.1 | 500.9 | 428.5 | 3,127.7 |
| Additions | 1,109.0 | 0.4 | 1.9 | 3.1 | 5.3 | 23.5 | 1,143.2 |
| Expensed Exploration costs | -146.5 | -0.6 | -0.7 | – | – | -36.3 | -184.1 |
| Impairment | – | – | – | -19.2 | – | -25.9 | -45.1 |
| Change in estimates | 56.7 | – | – | – | – | – | 56.7 |
| Reclassifications | -1,743.9 | – | – | – | – | -268.2 | -2,012.1 |
| Currency translation difference | -422.7 | -0.9 | -0.8 | – | -16.0 | 0.2 | -440.2 |
| 31 December | 1,020.6 | 6.9 | 6.6 | – | 490.2 | 121.8 | 1,646.1 |
In 2015, the reclassification from Non-production cost pools to Production cost pools mainly related to the Edvard Grieg field, Norway, which commenced production in November 2015 and to the Bertam field, Malaysia, which commenced production in April 2015.
Lundin Petroleum carried out its impairment testing at 31 December 2016 on an asset basis in conjunction with the annual reserves audit process. Lundin Petroleum used the oil price forward curve at the year end as a basis for its price forecast, a future cost inflation factor of 2% (2%) per annum and a discount rate of 8% (8%) to calculate the future post-tax cash flows.
Non-cash impairment costs charged to the income statement for the year amounted to MUSD 632.1 (MUSD 737.0) following a decision to remove the contingent resources associated with the gas discoveries in the Sabah area offshore East Malaysia and the Tembakau gas discovery in PM307 offshore Peninsular Malaysia, as well as the Morskaya oil discovery in the Russian Caspian Sea. Management deems that it is unlikely that any of these discoveries will be developed in the foreseeable future. A pre-tax impairment cost of MUSD 506.1 was charged to the income statement in respect of Russia with a deferred tax credit of MUSD 83.5, giving a net after tax charge of MUSD 422.6. The impairment cost for Malaysia charged to the income statement was MUSD 122.3 with no associated tax credit. In addition, inventory well supplies in Malaysia were impaired for an amount of MUSD 3.7 in 2016. For further information on impairment, see the Directors Report on page 80.
During 2016, MUSD 23.4 (MUSD 40.2) of capitalised interest costs were added to oil and gas properties and relate to Norwegian and Malaysian development projects. The interest rate for capitalised borrowing costs is calculated at the external facility borrowing rate of LIBOR plus a margin of 3.00% per annum, increased to 3.15 % from February 2016 (margin of 2.75% per annum up to June 2015 and 3.00% per annum from June 2015).
The Group participates in joint operations with third parties in oil and gas exploration activities. The Group is contractually committed under various concession agreements to complete certain exploration programmes. The commitments as at 31 December 2016 are estimated to be MUSD 51.1 (MUSD 211.1) of which third parties who are joint operations partners will contribute approximately MUSD 32.8 (MUSD 128.5).
| 2016 | 2015 | |||||||
|---|---|---|---|---|---|---|---|---|
| Real | Real | |||||||
| MUSD | FPSO | estate | Other | Total | FPSO | estate | Other | Total |
| Cost | ||||||||
| 1 January | 207.2 | 11.2 | 46.5 | 264.9 | 178.9 | 11.2 | 40.8 | 230.9 |
| Additions | -1.7 | – | 1.3 | -0.4 | 30.8 | – | 5.3 | 36.1 |
| Disposals | – | – | -11.5 | -11.5 | – | – | -0.5 | -0.5 |
| Reclassification | – | – | – | – | – | – | 4.5 | 4.5 |
| Currency translation difference | -0.7 | – | 0.2 | -0.5 | -2.5 | – | -3.6 | -6.1 |
| 31 December | 204.8 | 11.2 | 36.5 | 252.5 | 207.2 | 11.2 | 46.5 | 264.9 |
| Depreciation | ||||||||
| 1 January | -23.7 | -1.7 | -35.2 | -60.6 | – | -1.6 | -29.0 | -30.6 |
| Disposals | – | – | 9.4 | 9.4 | – | – | 0.5 | 0.5 |
| Depreciation charge for the year | -31.1 | -0.1 | -4.2 | -35.4 | -23.7 | -0.1 | -5.1 | -28.9 |
| Reclassification | – | – | 0.2 | 0.2 | – | – | -4.1 | -4.1 |
| Currency translation difference | – | – | – | – | – | – | 2.5 | 2.5 |
| 31 December | -54.8 | -1.8 | -29.8 | -86.4 | -23.7 | -1.7 | -35.2 | -60.6 |
| Net book value | 150.0 | 9.4 | 6.7 | 166.1 | 183.5 | 9.5 | 11.3 | 204.3 |
The depreciation charge for the year is based on cost and an estimated useful life of 3 to 5 years for office equipment and other assets. Real estate is depreciated using an estimated useful life of 20 years and taking into account its residual value. Depreciation is included within the general, administration and depreciation line in the income statement. The FPSO located on the Bertam field, Malaysia, is being depreciated over the committed contract term and included in the depreciation of other assets line in the income statement.
| MUSD | 31 December 2016 |
31 December 2015 |
|---|---|---|
| 1 January | – | – |
| Additions | 128.1 | – |
| 31 December | 128.1 | – |
The Group's goodwill arose from the acquisition of a further 15 percent interest in the Edvard Grieg field in 2016. Goodwill was included in the Group's impairment testing as per 31 December 2016 and will be tested for impairment annually as part of the annual impairment testing of oil and gas properties.
For further information on goodwill, see Changes in the Group presented in the Directors Report on pages 73–74.
| MUSD | 31 December 2016 |
31 December 2015 |
|---|---|---|
| Other shares and participations | 8.9 | 4.1 |
| Brynhild operating cost share | – | 5.5 |
| Other | 0.5 | 1.1 |
| 9.4 | 10.7 |
| 31 December 2015 | ||||
|---|---|---|---|---|
| Number of shares | Share % | Book amount MUSD |
Book amount MUSD |
|
| ShaMaran Petroleum Corp. | 103,784,842 | 5.8 % | 8.9 | 4.1 |
| 8.9 | 4.1 |
The investment in ShaMaran Petroleum Corp. (ShaMaran) was booked at the fair value of the shares at the date of acquisition and under accounting rules, subsequent movements in the fair value of the shares is being recorded in the consolidated statement of comprehensive income.
The fair value of ShaMaran is calculated using the quoted share price at the Toronto Stock Exchange at the balance sheet date and is detailed below.
| ShaMaran Petroleum Corp. MUSD |
2016 | 2015 |
|---|---|---|
| 1 January | 4.1 | 4.7 |
| Additions | – | 4.2 |
| Fair value movement | 5.2 | -3.7 |
| Currency translation difference | -0.4 | -1.1 |
| 31 December | 8.9 | 4.1 |
See Subsequent events detailed in Note 27.
| MUSD | 31 December 2016 |
31 December 2015 |
|---|---|---|
| Brynhild operating cost share | – | 5.5 |
| Other | 0.5 | 1.1 |
| 0.5 | 6.6 |
The Brynhild operating cost share related to the long-term portion of the mark-to-market valuation of the Brynhild operating cost share arrangement where the share of the operating cost varies with the oil price. The arrangement ends in mid-2017 and the short-term portion is reflected in Note 12.
| MUSD | 31 December 2016 |
31 December 2015 |
|---|---|---|
| Hydrocarbon stocks | 17.1 | 15.5 |
| Drilling equipment and consumable materials | 37.8 | 30.1 |
| 54.9 | 45.6 |
| MUSD | 31 December 2016 |
31 December 2015 |
|---|---|---|
| Trade receivables | 193.4 | 35.2 |
| Underlift | 28.9 | 26.5 |
| Joint operations debtors | 31.2 | 48.4 |
| Prepaid expenses and accrued income | 29.4 | 29.5 |
| Brynhild operating cost share | 3.0 | 14.7 |
| Other | 3.0 | 5.0 |
| 288.9 | 159.3 |
The trade receivables relate mainly to hydrocarbon sales to a limited number of independent customers from whom there is no recent history of default. The trade receivables balance is current and the provision for bad debt is nil.
The Brynhild operating cost share relates to the short-term portion of the mark-to-market valuation of the Brynhild operating cost share arrangement where the share of the operating cost varies with the oil price.
Cash and cash equivalents include only cash at hand or on bank. No short term deposits are held as at 31 December 2016.
| Share capital | Additional paid in capital | ||||
|---|---|---|---|---|---|
| MUSD | Number of shares |
Par value MSEK |
Par value MUSD |
MSEK | MUSD |
| 31 December 2015 | 311,070,330 | 3.2 | 0.5 | 4,810.5 | 445.0 |
| Share issuance Treasury shares transferred |
29,316,115 – |
0.3 – |
0.0 – |
4,242.2 291.3 |
499.8 34.3 |
| Total share issuance increase | 29,316,115 | 0.3 | 0.0 | 4,533.5 | 534.1 |
| 31 December 2016 | 340,386,445 | 3.5 | 0.5 | 9,344.0 | 979.1 |
In 2016, Lundin Petroleum AB issued 27,580,806 new shares to Statoil ASA as part of the Edvard Grieg transaction. In addition, the Company also issued 1,735,309 new shares and transferred 2 million treasury shares held to Statoil ASA in exchange for a cash consideration of MSEK 544.1 based upon a share price of SEK 145.66 per share. These three share transactions increased the share capital/premium of the Company by an amount of MSEK 4,533.8.
| MUSD | Available-for sale reserve |
Hedge reserve | Currency translation reserve |
Total |
|---|---|---|---|---|
| 1 January 2015 | -6.5 | -147.9 | -281.8 | -436.2 |
| Total comprehensive income | -3.7 | 6.9 | -76.3 | -73.1 |
| 31 December 2015 | -10.2 | -141.0 | -358.1 | -509.3 |
| Total comprehensive income | 5.3 | 64.3 | 8.9 | 78.5 |
| 31 December 2016 | -4.9 | -76.7 | -349.2 | -430.8 |
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.
| 2016 | 2015 | |
|---|---|---|
| Net result attributable to shareholders of the Parent Company, USD | -356,739,927 | -861,764,755 |
| Weighted average number of shares for the year | 325,808,486 | 309,070,330 |
| Earnings per share, USD | -1.09 | -2.79 |
| Weighted average diluted number of shares for the year | 326,738,233 | 310,019,890 |
| Earnings per share fully diluted, USD | -1.09 | -2.79 |
| MUSD | 31 December 2016 |
31 December 2015 |
|---|---|---|
| Bank loans | 4,145.0 | 3,858.0 |
| Capitalised financing fees | -96.7 | -23.2 |
| 4,048.3 | 3,834.8 |
Capitalised financing fees amounted to MUSD 96.7 (MUSD 23.2) and related to the establishment costs of the external credit facility. The capitalised financing fees are being amortised over the duration of the credit facility.
For further information, see Note 18.
| MUSD | Site Restoration |
LTIP | Farm in payment |
Pension provision |
Other | Total |
|---|---|---|---|---|---|---|
| 1 January 2016 | 368.2 | 7.0 | 4.6 | 1.2 | 3.7 | 384.7 |
| Additions | 24.2 | 10.4 | – | 0.1 | 0.7 | 35.4 |
| Changes in estimates | 7.4 | – | 0.5 | – | – | 7.9 |
| Payments | -10.7 | -7.3 | – | -0.1 | -0.2 | -18.3 |
| Unwinding of discount | 15.2 | – | – | – | – | 15.2 |
| Reclassification | – | – | – | – | -0.6 | -0.6 |
| Currency translation difference | 2.8 | – | -0.1 | – | -0.1 | 2.6 |
| 31 December 2016 | 407.1 | 10.1 | 5.0 | 1.2 | 3.5 | 426.9 |
| Non-current | 407.1 | 3.2 | 5.0 | 1.2 | 3.5 | 420.0 |
| Current | – | 6.9 | – | – | – | 6.9 |
| Total | 407.1 | 10.1 | 5.0 | 1.2 | 3.5 | 426.9 |
| Site | Farm in | Pension | ||||
|---|---|---|---|---|---|---|
| MUSD | Restoration | LTIP | payment | provision | Other | Total |
| 1 January 2015 | 274.1 | 6.7 | 56.0 | 1.2 | 3.4 | 341.4 |
| Additions | – | 7.3 | – | – | 1.2 | 8.5 |
| Changes in estimates | 127.6 | – | -9.0 | -0.1 | – | 118.5 |
| Payments | -10.6 | -5.9 | -34.8 | -0.1 | -0.5 | -51.9 |
| Unwinding of discount | 12.7 | – | – | – | – | 12.7 |
| Currency translation difference | -35.6 | -1.1 | -7.6 | 0.2 | -0.4 | -44.5 |
| 31 December 2015 | 368.2 | 7.0 | 4.6 | 1.2 | 3.7 | 384.7 |
| Non-current | 368.2 | 2.2 | 4.6 | 1.2 | 3.7 | 379.9 |
| Current | – | 4.8 | – | – | – | 4.8 |
| Total | 368.2 | 7.0 | 4.6 | 1.2 | 3.7 | 384.7 |
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 changes in estimates in 2016 mainly relates to the liability associated with Norwegian development projects and the additions to the additional 15 percent of the Edvard Grieg field acquired in 2016. Based on the estimates used in calculating the site restoration provision as at 31 December 2016, approximately 70 percent of the total amount is expected to be settled after more than 15 years.
For more information on the Group's LTIP, see Note 25.
The farm in payment provision mainly relates to a payment for historic costs on Block PM307 in Malaysia payable on reaching certain production milestones.
In May 2002, the Compensation Committee recommended to the Board of Directors, and the Board of Directors approved, a pension to be paid to Adolf H. Lundin upon his resignation as Chairman of the Board of Directors and his appointment as Honorary Chairman. It was further agreed that upon the death of Adolf H. Lundin, the monthly payments would be paid to his wife, Eva Lundin, for the duration of her life.
Pension payments totalling an annual amount of TCHF 138 (TUSD 135) are payable to Eva Lundin. The Company may, at its option, buy out the obligation to make the pension payments through a lump sum payment in the amount of TCHF 1,800 (TUSD 1,767).
| MUSD | 31 December 2016 |
31 December 2015 |
|---|---|---|
| Trade payables | 13.3 | 23.1 |
| Overlift | 29.9 | – |
| Deferred revenue | – | 20.2 |
| Joint operations creditors and accrued expenses | 238.8 | 271.5 |
| Other accrued expenses | 16.9 | 23.7 |
| Other | 9.5 | 11.4 |
| 308.4 | 349.9 |
The accounting policies for financial assets and liabilities have been applied to the line items below:
| Total | Loan receivables and other receivables at amortised cost |
Financial assets at amortised cost |
Assets at fair value in OCI 2 |
Fair value recognised in profit/loss |
Derivatives used for hedging |
|---|---|---|---|---|---|
| 8.9 | – | – | 8.9 | – | – |
| 0.5 | – | 0.5 | – | – | – |
| 17.8 | – | – | – | – | 17.8 |
| 31.2 | 31.2 | – | – | – | – |
| 305.8 | 276.9 | – | – | 28.9 | – |
| 69.5 | 69.5 | – | – | – | – |
| 433.7 | 377.6 | 0.5 | 8.9 | 28.9 | 17.8 |
| 31 December 2016 MUSD |
Total | Other liabilities at amortised cost |
Financial liabilities at amortised cost |
Fair value recognised in profit/loss |
Derivatives used for hedging |
|---|---|---|---|---|---|
| Financial liabilities | 4,048.3 | – | 4,048.3 | – | – |
| Other non-current liabilities | 33.8 | 33.8 | – | – | – |
| Derivative instruments | 67.4 | – | – | – | 67.4 |
| Joint operations creditors | 238.8 | 238.8 | – | – | – |
| Other current liabilities | 52.9 | 23.0 | – | 29.9 | – |
| 4,441.2 | 295.6 | 4,048.3 | 29.9 | 67.4 |
| 31 December 2015 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 profit/loss |
Derivatives used for hedging |
|---|---|---|---|---|---|---|
| Other shares and participations | 4.1 | – | – | 4.1 | – | – |
| Other non-current financial assets | 6.6 | – | 1.1 | – | 5.5 | – |
| Joint operations debtors | 48.4 | 48.4 | – | – | – | – |
| Other current receivables1 | 346.1 | 319.6 | – | – | 26.5 | – |
| Cash and cash equivalents | 71.9 | 71.9 | ||||
| 477.1 | 439.9 | 1.1 | 4.1 | 32.0 | – |
| 31 December 2015 MUSD |
Total | Other liabilities at amortised cost |
Financial liabilities at amortised cost |
Fair value recognised in profit/loss |
Derivatives used for hedging |
|---|---|---|---|---|---|
| Financial liabilities | 3,834.8 | – | 3,834.8 | – | – |
| Other non-current liabilities | 32.2 | 32.2 | – | – | – |
| Derivative instruments | 114.5 | – | – | – | 114.5 |
| Joint operations creditors | 271.5 | 271.5 | – | – | – |
| Other current liabilities | 55.4 | 55.4 | – | – | – |
| 4,308.4 | 359.1 | 3,834.8 | – | 114.5 |
1 Prepayments are not included in other current assets, as prepayments are not deemed to be financial instruments.
Other comprehensive income.
The fair value of loan receivables and other receivables is a fair approximation of the book value.
For financial 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, financial assets and liabilities measured at fair value can be detailed as follows:
| 31 December 2016 MUSD |
Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Other shares and participations | 8.9 | – | – |
| Derivative instruments – non-current | – | 17.0 | – |
| Derivative instruments – current | – | 0.8 | – |
| Underlift | 28.9 | – | – |
| 37.8 | 17.8 | – | |
| Liabilities | |||
| Derivative instruments - non current | – | 29.8 | – |
| Derivative instruments - current | – | 37.6 | – |
| Overlift | 29.9 | – | – |
| 29.9 | 67.4 | – | |
| 31 December 2015 |
| MUSD | Level 1 | Level 2 | Level 3 |
|---|---|---|---|
| Assets | |||
| Other shares and participations | 4.1 | – | – |
| Underlift | 26.5 | – | – |
| 30.6 | – | – | |
| Liabilities | |||
| Derivative instruments – non-current | – | 48.4 | – |
| Derivative instruments – current | – | 66.1 | – |
| – | 114.5 | – |
The outstanding derivative instruments can be specified as follows:
| Fair value of outstanding derivative instruments in the balance sheet |
31 December 2016 | 31 December 2015 | |||
|---|---|---|---|---|---|
| MUSD | Assets | Liabilities | Assets | Liabilities | |
| Interest rate swap | 17.8 | 31.6 | – | 43.9 | |
| Currency hedge | – | 35.8 | – | 70.6 | |
| Total | 17.8 | 67.4 | – | 114.5 | |
| Non-current | 17.0 | 29.8 | – | 48.4 | |
| Current | 0.8 | 37.6 | – | 66.1 | |
| Total | 17.8 | 67.4 | – | 114.5 |
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 2016 amounted to a net liability of MUSD 13.8 (MUSD 43.9).
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 2016 amounted to a net liability of MUSD 35.8 (MUSD 70.6).
For risks in the financial reporting, see the section Internal Control and Audit in the Corporate Governance report on pages 68–69 and Risk Management on pages 36–41 for more information.
As an international oil and gas exploration and production company operating globally, Lundin Petroleum is exposed to financial risks such as currency risk, interest rate risk, credit risks, liquidity risks as well as the risk related to the fluctuation in the oil price. The Group seeks to control these risks through sound management practice and the use of internationally accepted financial instruments, such as oil price, interest rate and foreign exchange hedges. Lundin Petroleum uses financial instruments solely for the purpose of minimising risks in the Group's business.
For further information on risks in the financial reporting, see the section Internal Control and Audit in the Corporate Governance report on pages 68–69 and Risk Management on pages 36–41.
The Group's objectives when managing capital are to safeguard the Group's ability to continue as a going concern and to meet its committed work programme requirements in order to create shareholder value. The Group may put in place new credit facilities, repay debt, or other such restructuring activities as appropriate. Group management continuously monitors and manages the Group's net debt position in order to assess the requirement for changes to the capital structure to meet the objectives and to maintain flexibility. Lundin Petroleum is not subject to any externally imposed capital requirements.
No significant changes were made in the objectives, policies or processes during 2016.
Lundin Petroleum monitors capital on the basis of net debt. Net debt is calculated as bank loans as shown in the balance sheet less cash and cash equivalents.
| MUSD | 31 December 2016 | 31 December 2015 |
|---|---|---|
| Bank loans | 4,145.0 | 3,858.0 |
| Cash and cash equivalents | -69.5 | -71.9 |
| Net debt | 4,075.5 | 3,786.1 |
The increase in net debt compared to 2015 is mainly due to the funding of the Group's development activities.
Interest rate risk is the risk to the earnings due to uncertain future interest rates.
Lundin Petroleum is exposed to interest rate risk through the credit facility, see also Liquidity risk below. The interest rate for capitalised borrowing costs is calculated at the external facility borrowing rate of LIBOR plus a margin of 3.00% per annum, increased to 3.15 % from February 2016 (margin of 2.75% per annum up to June 2015 and 3.00% per annum from June 2015). Lundin Petroleum will assess the benefits of interest rate hedging on borrowings on a continuous basis. If the hedging contract provides a reduction in the interest rate risk at a price that is deemed acceptable to the Group, then Lundin Petroleum may choose to enter into an interest rate hedge.
The total interest expense for 2016 amounted to MUSD 160.7 which included MUSD 23.4 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 21.8, taking into account the Group's interest rate hedges for 2016.
The Group has entered into interest rate hedging as follows:
| Borrowings MUSD |
Fixing of floating LIBOR Rate per annum |
Settlement period |
|---|---|---|
| 2,000 | 1.94% | Jan 2017 – Dec 2017 |
| 2,000 | 2.02% | Jan 2018 – Dec 2018 |
| 2,000 | 1.18% | Jan 2019 – Dec 2019 |
See Subsequent events detailed in Note 27.
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 fluctuations of these currencies against the US Dollar.
Lundin Petroleum's policy on the currency rate hedging is, in case of currency exposure, to consider setting the rate of exchange for known costs in non-US Dollar currencies to US Dollars in advance so that future US Dollar cost levels can be forecasted with a reasonable degree of certainty. The Group will take into account the current rates of exchange and market expectations in comparison to historic trends and volatility in making the decision to hedge.
The Group has entered into currency hedging contracts fixing the rate of exchange from US Dollar into Norwegian Krone to meet Norwegian Krone operational requirements as summarised in the table below.
| Buy | Sell | Average contractual exchange rate |
Settlement period |
|---|---|---|---|
| MNOK 3,492.6 | MUSD 423.6 | NOK 8.25:USD 1 | Jan 2017 – Dec 2017 |
| MNOK 3,493.0 | MUSD 424.2 | NOK 8.23:USD 1 | Jan 2018 – Dec 2018 |
| MNOK 1,672.4 | MUSD 200.4 | NOK 8.35:USD 1 | Jan 2019 – Dec 2019 |
Under IAS 39, subject to hedge effectiveness testing, all of the hedges are treated as effective and changes to the fair value are reflected in other comprehensive income. At 31 December 2016, a net current liability of MUSD 36.8 (MUSD 66.1) and a net non-current liability of MUSD 12.8 (MUSD 48.4) 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 profit through the conversion of the income statements of the Group's subsidiaries from functional currency to the presentation currency US Dollar for the year ended 31 December 2016.
| Operating result in the financial statements, MUSD | -355.8 | -355.8 | |
|---|---|---|---|
| Shift of currency exchange rates | Average rate 2016 | 10% USD weakening | 10% USD strengthening |
| EUR/USD | 0.9037 | 0.8215 | 0.9940 |
| SEK/USD | 8.5610 | 7.7827 | 9.4171 |
| NOK/USD | 8.4014 | 7.6376 | 9.2415 |
| RUR/USD | 67.0692 | 60.9720 | 73.7761 |
| CHF/USD | 0.9855 | 0.8959 | 1.0841 |
| Total effect on operating result, MUSD | -64.2 | 64.2 |
The foreign currency risk to the Group's income and equity from conversion exposure is not hedged.
As described in the Directors' report on page 80, 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 10.9 (MUSD 50.7 loss) reported foreign exchange gain in the income statement.
Price of oil and gas are affected by the normal economic drivers of supply and demand as well as the financial investors and market uncertainty. Factors that influence these include operational decisions, natural disasters, economic conditions, political instability or conflicts or actions by major oil exporting countries. Price fluctuations can affect Lundin Petroleum's financial position.
The table below summarises the effect that a change in the oil price would have had on the net result and equity at 31 December 2016:
| Net result in the financial statements, MUSD | -499.3 | -499.3 |
|---|---|---|
| Possible shift | -10% | 10% |
| Total effect on net result, MUSD | -20.9 | 20.9 |
The impact on the net result from a change in oil price is reduced due to the 78 percent tax rate in Norway.
Lundin Petroleum's policy is to adopt a flexible approach towards oil price hedging, based on an assessment of the benefits of the hedge contract in specific circumstances. Based on analysis of the circumstances, Lundin Petroleum will assess the benefits of forward hedging monthly sales contracts for the purpose of establishing cash flow. If it believes that the hedging contract will provide an enhanced cash flow then it may choose to enter into an oil price hedge.
For the year ended 31 December 2016, the Group did not enter into oil price hedging contracts and there are no oil price hedging contracts outstanding as at 31 December 2016.
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 2016, the Group's trade receivables amounted to MUSD 193.4 (MUSD 35.2). There is no recent history of default. Other longterm and short-term receivables are considered recoverable and no provision for bad debt was accounted for as at 31 December 2016. Cash and cash equivalents are maintained with banks having strong long-term credit ratings.
Liquidity risk is defined as the risk that the Group could not be able to settle or meet its obligations on time or at a reasonable price. Group treasury is responsible for liquidity, funding as well as settlement management. In addition, liquidity and funding risks and related processes and policies are overseen by Group management.
In February 2016, Lundin Petroleum replaced its existing USD 4.0 billion lending facility, which was due to reduce in availability from June 2016 and mature in 2019, with a committed seven year senior secured reserve-based lending facility of up to USD 5.0 billion, with an initial committed amount of USD 4.3 billion. The committed amount has subsequently been increased to USD 5.0 billion. The facility is secured against certain cash flows generated by the Group. The amount available under the facility is recalculated every six months based upon the calculated cash flow generated by certain producing fields and fields under development at an oil price and economic assumptions agreed with the banking syndicate providing the facility.
The facility agreement provides that an "event of default" occurs where the Group does not comply with certain material covenants or where certain events occur as specified in the agreement, as are customary in financing agreements of this size and nature. If such an event of default occurs and subject to any applicable cure periods, the external lenders may take certain specified actions to enforce their security, including accelerating the repayment of outstanding amounts under the credit facility.
In April 2015, Lundin Petroleum entered into a NOK 4.5 billion Norwegian exploration refund facility with ten international banks. The facility was secured against the tax refunds generated from Lundin Norway's exploration and appraisal activities on the Norwegian Continental Shelf and extended until the end of 2016. Following the receipt of the 2014 Norwegian exploration tax refund in December 2015, the facility size was reduced to NOK 2.15 billion. As at 31 December 2016, the facility was cancelled after the outstanding balance was repaid in November 2016 from the 2015 exploration tax refund receipt.
In addition, in March 2016, Lundin Petroleum entered into a six month revolving credit facility of MUSD 300 with the option to extend by a further three months. Following the increased commitments under the Group's USD 5.0 billion reserve-based lending facility and the completion of the Edvard Grieg transaction, the facility was cancelled effective 30 June 2016.
Lundin Petroleum has, through its subsidiary Lundin Malaysia BV, entered into Production Sharing Contracts (PSC) with Petroliam Nasional Berhad, the oil and gas company of the Government of Malaysia (Petronas). Bank guarantees have been issued in support of the work commitments and other related costs in relation to certain of these PSCs and the outstanding amount of the bank guarantees at 31 December 2016 was MUSD 10.3.
The table below analyses the Group's financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet date to the contractual maturity date. Loan repayments are made based upon a net present value calculation of the assets' future cash flows. No loan repayments are currently forecast under this calculation.
| MUSD | 31 December 2016 | 31 December 2015 |
|---|---|---|
| Non-current | ||
| Repayment within 1–2 years: | ||
| – Derivative instruments | 29.8 | 42.5 |
| Repayment within 2–5 years: | ||
| – Bank loans | 1,132.9 | 3,858.0 |
| – Derivative instruments | – | 5.9 |
| Repayment after 5 years: | ||
| – Bank loans | 3,012.1 | – |
| – Derivative instruments | – | – |
| – Other non-current liabilities | 33.8 | 32.2 |
| 4,208.6 | 3,938.6 | |
| Current | ||
| Repayment within 6 months: | ||
| – Trade payables | 13.3 | 23.1 |
| – Overlift | 29.9 | – |
| – Tax liabilities | 0.2 | 0.7 |
| – Joint operations creditors | 238.8 | 271.5 |
| – Other current liabilities | 9.5 | 11.4 |
| – Derivative instruments | 19.5 | 18.1 |
| Repayment after 6 months: | ||
| – Derivative instruments | 18.1 | 48.0 |
| 329.3 | 372.8 |
In February 2016, Lundin Petroleum replaced its existing USD 4.0 billion lending facility with a committed seven year senior secured reservebased lending facility of USD 5.0 billion. The facility is secured by a pledge over the shares of certain Group companies and a charge over some of the bank accounts of the pledged companies. The pledged assets at 31 December 2016 amounted to MUSD 743.8 (MUSD 422.9) and represented the accounting value of net assets of the Group companies whose shares are pledged as described in the Parent Company section below.
In April 2016, Lundin Petroleum completed the sale of its oil and gas assets in Indonesia, including Lundin Petroleum's 25.88 percent interest in the Lematang PSC in respect of the Singa field, to PT Medco Energi Internasional TBK ("Medco"). Medco has agreed to pay a deferred consideration to Lundin Petroleum related to the Singa field of 35 percent of certain cash flows generated during the extension period commencing April 2017.
Lundin Petroleum recognises the following related parties: associated companies, jointly controlled entities, key management personnel and members of their close family or other parties that are partly, directly or indirectly, controlled by key management personnel or of its family or of any individual that controls, or has joint control or significant influence over the entity.
During the year, the Group has entered into transactions with related parties on a commercial basis as shown below:
| MUSD | 2016 | 2015 |
|---|---|---|
| Sale of oil and related products | 155.0 | – |
| Sale of services | 0.3 | 0.5 |
| Purchase of services | -0.4 | -0.2 |
Since 30 June 2016, being the date Statoil ASA's holding in Lundin Petroleum increased to 20.1 percent, the Group has sold oil and related products to the Statoil group on an arm's-length basis amounting to MUSD 155.0.
The related party transactions concern other parties that are controlled by key management personnel. Key management personnel include members of the Board of directors and Group management. The remuneration to the Board of directors and Group management is disclosed in Note 24.
| 2016 | 2015 | |||
|---|---|---|---|---|
| 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 | 344 | 258 | 338 | 254 |
| Malaysia | 105 | 66 | 123 | 81 |
| France | 48 | 40 | 48 | 39 |
| Netherlands | 6 | 4 | 7 | 4 |
| Russia | 16 | 10 | 17 | 9 |
| Switzerland | 45 | 26 | 44 | 27 |
| Indonesia | – | – | 10 | 5 |
| Total subsidiaries abroad | 564 | 404 | 587 | 419 |
| Total Group | 566 | 405 | 589 | 420 |
| 2016 | 2015 | |||
|---|---|---|---|---|
| Board members and Group management | Total at year end |
of which men | Total at year end |
of which men |
| Parent Company in Sweden | ||||
| Board members1 | 7 | 4 | 8 | 5 |
| Subsidiaries abroad | ||||
| Group management | 7 | 6 | 6 | 5 |
| Total Group | 14 | 10 | 14 | 10 |
1 Alex Schneiter, Chief Executive Officer (CEO) and Board Member is only included in Group management.
| 2016 | 2015 | |||
|---|---|---|---|---|
| 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 | 582 | 116 | 573 | 87 |
| Employees | 308 | 157 | 258 | 139 |
| Subsidiaries abroad | ||||
| Group management | 4,857 | 340 | 7,015 | 492 |
| Other employees | 85,240 | 22,567 | 97,834 | 23,647 |
| Total Group | 90,987 | 23,180 | 105,680 | 24,365 |
| of which pension costs | 8,664 | 9,539 |
| Salaries and other remuneration for the Board members and Group management TUSD |
Fixed Board remuneration/ fixed salary and other benefits1 |
Short-term variable salary2 |
Unit bonus plan |
Remuneration for committee work |
Remuneration for work outside of directorship |
Pension | Total 2016 |
|---|---|---|---|---|---|---|---|
| Parent Company in Sweden | |||||||
| Board members | |||||||
| Ian H. Lundin | 123 | – | – | 12 | 175 | – | 310 |
| Peggy Bruzelius | 58 | – | – | 17 | – | – | 75 |
| C. Ashley Heppenstall | 58 | – | – | 6 | 608 | – | 672 |
| Lukas H. Lundin | 58 | – | – | – | – | – | 58 |
| William A. Rand | 29 | – | – | 12 | – | – | 41 |
| Grace Reksten Skaugen | 58 | – | – | 6 | – | – | 64 |
| Magnus Unger | 58 | – | – | 12 | 18 | – | 88 |
| Cecilia Vieweg | 58 | – | – | 17 | – | – | 75 |
| Total Board members | 500 | – | – | 82 | 801 | – | 1,383 |
| Subsidiaries abroad | |||||||
| Group management | |||||||
| A. Schneiter | 810 | 386 | – | – | – | 162 | 1,358 |
| Other3 | 2,742 | 880 | 246 | – | – | 438 | 4,306 |
| Total Group management | 3,552 | 1,266 | 246 | – | – | 600 | 5,664 |
1 Other benefits include school fees and health insurance for Group management.
2 The bonus awarded and paid in 2016 relates to the assessment made by the Compensation Committee in January 2016, considering the employees'
contributions to the results of the Group in 2015. 3 Comprises six persons (Chief Financial Officer, Chief Operating Officer, Vice President Corporate Responsibility, Vice President Legal, Vice President Corporate Planning and Investor Relations, Vice President Corporate Finance).
Note: In 2015, the remaining entitlement under the phantom option plan was paid to the Group management. No performance based incentive plan vested in 2016.
| Salaries and other remuneration for the Board members and Group management TUSD |
Fixed Board remuneration/ fixed salary and other benefits1 |
Short-term variable salary2 |
Unit bonus plan |
Phantom option plan |
Remuneration for committee work |
Remuneration for work outside of directorship3 |
Pension | Total 2015 |
|---|---|---|---|---|---|---|---|---|
| Parent Company in Sweden | ||||||||
| Board members | ||||||||
| Ian H. Lundin | 124 | – | – | – | 6 | 178 | – | 308 |
| Peggy Bruzelius | 59 | – | – | – | 15 | – | – | 74 |
| C. Ashley Heppenstall | 10 | – | – | – | – | – | – | 10 |
| Asbjørn Larsen | 30 | – | – | – | 6 | – | – | 36 |
| Lukas H. Lundin | 59 | – | – | – | – | – | – | 59 |
| William A. Rand | 59 | – | – | – | 27 | – | – | 86 |
| Grace Skaugen | 30 | – | – | – | – | – | – | 30 |
| Magnus Unger | 59 | – | – | – | 12 | 18 | – | 89 |
| Cecilia Vieweg | 59 | – | – | – | 18 | – | – | 77 |
| Total Board members | 489 | – | – | – | 84 | 196 | – | 769 |
| Subsidiaries abroad | ||||||||
| Group management | ||||||||
| C. Ashley Heppenstall4 | 1,879 | 698 | – | 12,200 | – | – | 137 | 14,914 |
| A. Schneiter4 | 718 | 499 | – | 8,946 | – | – | 166 | 10,329 |
| Other5 | 2,103 | 1,152 | 371 | 5,693 | – | – | 345 | 9,664 |
| Total Group management | 4,700 | 2,349 | 371 | 26,839 | – | – | 648 | 34,907 |
1 Other benefits include school fees and health insurance for Group management.
2 The bonus awarded and paid in 2015 relates to the assessment made by the Compensation Committee in January 2015, considering the employees'
contributions to the results of the Group in 2014. 3 The remuneration relates to work performed outside the scope of normal Board duties undertaken by Board members on behalf of the Group. The 2015 Policy on Remuneration referred only to Group management remuneration and did not refer to consultancy fees to members of the Board of Directors. The remuneration paid to the Chairman Ian H. Lundin was approved by the 2014 and 2015 AGMs. The Board authorised a permitted deviation from the 2015 Policy on Remuneration for the payment of such remuneration to Magnus Unger. In addition, the Board approved, as a
permitted deviation from the 2015 Policy on Remuneration, a consultancy agreement with C. Ashley Heppenstall, effective as of 1 January 2016. 4 C. Ashley Heppenstall left the role of CEO at the end of September 2015 and was replaced by Alex Schneiter in October 2015. 5 Comprises six persons (Chief Operating Officer, Chief Financial Officer, Vice President Corporate Responsibility, Vice President Legal, Vice President Corporate Planning and Investor Relations and former Senior Vice President Development).
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 defined as annual base salary and short-term variable salary and is capped at approximately TCHF 846 (TUSD 858). The normal retirement age for the CEO is 65 years.
A mutual termination period of between one month and twelve months applies between the Company and Group management, depending on the duration of the employment with the Company. In addition, severance terms are incorporated into the employment contracts for executives that give rise to compensation, up to two years' base salary, in the event of termination of employment due to a change of control of the Company. The Board of Directors is further authorised, in individual cases, to approve severance arrangements, in addition to the notice periods and the severance arrangements in respect of a change of control of the Company, where employment is terminated by the Company without cause, or otherwise in circumstances at the discretion of the Board. Such severance arrangements may provide for the payment of up to one year's base salary; no other benefits shall be included. Severance payments in aggregate (i.e. for notice periods and severance arrangements) shall be limited to a maximum of two years' base salary.
See pages 63–65 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 2016.
The Company maintains the long-term incentive plans (LTIP) described below.
In 2008, Lundin Petroleum implemented a LTIP scheme consisting of a Unit Bonus Plan which provides for an annual grant of units that will lead to a cash payment at vesting. The LTIP has a three year duration whereby the initial grant of units vested equally in three tranches: one third after one year; one third after two years; and the final third after three years. The cash payment is conditional upon the holder of the units remaining an employee of the Group at the time of payment. The share price for determining the cash payment at the end of each vesting period will be the average of the Lundin Petroleum closing share price for the period five trading days prior to and following the actual vesting date. The exercise price at vesting date 31 May 2016 was SEK 151.35.
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 2016 and the year in which the units will vest.
| Plan | |||||
|---|---|---|---|---|---|
| Unit Bonus Plan | 2013 | 2014 | 2015 | 2016 | Total |
| Outstanding at the beginning of the period | 132,836 | 247,306 | 438,732 | – | 818,874 |
| Awarded during the period | – | – | – | 360,099 | 360,099 |
| Forfeited during the period | – | -7,128 | -14,928 | – | -22,056 |
| Exercised during the period | -132,836 | -122,745 | -145,876 | – | -401,457 |
| Outstanding at the end of the period | – | 117,433 | 277,928 | 360,099 | 755,460 |
| Vesting date | |||||
| 31 May 2017 | – | 117,433 | 138,964 | 120,033 | 376,430 |
| 31 May 2018 | – | – | 138,964 | 120,033 | 258,997 |
| 31 May 2019 | – | – | – | 120,033 | 120,033 |
| Outstanding at the end of the period | – | 117,433 | 277,928 | 360,099 | 755,460 |
The costs associated with the unit bonus plans are as given in the following table.
| Unit Bonus Plan MUSD |
2016 | 2015 |
|---|---|---|
| 2012 | – | 1.5 |
| 2013 | 2.0 | 1.5 |
| 2014 | 2.0 | 2.0 |
| 2015 | 3.6 | 2.0 |
| 2016 | 2.5 | – |
| 10.1 | 7.0 |
LTIP awards are recognised in the financial statements pro rata over their vesting period. The total carrying amount for the provision for the Unit Bonus Plan including social costs at 31 December 2016 amounted to MUSD 10.1 (MUSD 7.0). The provision is calculated based on Lundin Petroleum's share price at the balance sheet date. The closing share price at 31 December 2016 was SEK 198.10.
The 2014, 2015 and 2016 AGMs resolved a long-term performance based incentive plan in respect of Group management and a number of key employees.
The 2016 plan is effective from 1 July 2016 and the 2016 award has been accounted for from the second half of 2016. The total outstanding awards made in respect of 2016 are 512,595 which vest over three years from 1 July 2016 subject to certain performance conditions being met. Each award was fair valued at the date of grant at SEK 89.30 using an option pricing model.
The 2015 plan is effective from 1 July 2015 and the total outstanding number of awards made in respect of 2015 are 684,372 which vest over three years from 1 July 2015 subject to certain performance conditions being met. Each award was fair valued at the date of grant at SEK 91.40 using an option pricing model.
The 2014 plan is effective from 1 July 2014 and the total outstanding number of awards made in respect of 2014 are 602,554 which vest over three years from 1 July 2014 subject to certain performance conditions being met. Each award was fair valued at the date of grant at SEK 81.40 using an option pricing model.
The costs associated with the long-term performance based incentive plans are as given in the following table.
| Performance Based Incentive Plan MUSD |
2016 | 2015 |
|---|---|---|
| 2014 | 1.5 | 4.1 |
| 2015 | 1.9 | 3.0 |
| 2016 | 0.9 | – |
| 4.3 | 7.1 |
| TUSD | 2016 | 2015 |
|---|---|---|
| PwC | ||
| Audit fees | 830 | 887 |
| Audit related | 84 | 88 |
| Tax advisory services | 24 | 29 |
| Other fees | 36 | 30 |
| Total PwC | 974 | 1,034 |
| Remuneration to other auditors than PwC | 41 | 34 |
| Total | 1,015 | 1,068 |
Audit fees include the review of the 2016 half year report. Audit related costs include special assignments such as licence audits and PSC audits.
In January 2017, Lundin Petroleum acquired a further 17.8 million shares in ShaMaran Petroleum as part of the private placement of 360 million shares by the company at CAD 0.10 per share.
In February 2017, Lundin Petroleum announced that its Board of Directors has proposed to spin-off its assets in Malaysia, France and the Netherlands (the IPC Assets) into a newly formed company called International Petroleum Corporation (IPC) and to distribute the IPC shares, on a pro-rata basis, to Lundin Petroleum shareholders. The spin-off of the IPC Assets will have an effective date of 1 January 2017, however Lundin Petroleum will account for the production from the IPC Assets up to the date of completion of the spin-off with a net financial settlement at completion to account for the cash generation from the effective date to the completion date. On 22 March 2017, the shareholders of Lundin Petroleum AB approved the transaction at an Extraordinary General Meeting.
In March 2017, Lundin Petroleum announced that IPC has filed a preliminary prospectus with the Alberta Securities Commission (ASC) in Canada.
During the first quarter of 2017, Lundin Petroleum entered into further interest rate swaps as follows:
| Borrowings MUSD |
Fixing of floating LIBOR Rate per annum |
Settlement period |
|---|---|---|
| 750 | 1.05% | Mar 2017 |
| 1,000 | 1.11% | Apr 2017–Dec 2017 |
| 1,000 | 1.58% | Jan 2018–Dec 2018 |
| 1,000 | 1.89% | Jan 2019–Dec 2019 |
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 -103.3 (MSEK -78.1) for the year.
The result included general and administrative expenses of MSEK 106.6 (MSEK 89.6) and net finance costs of MSEK 0.5 (net finance income of MSEK 2.8).
On 30 June 2016, following 2016 EGM resolutions, Lundin Petroleum AB issued 27,580,806 new shares to Statoil ASA as part of the Edvard Grieg transaction. In addition, the Company also issued 1,735,309 new shares and transferred 2 million treasury shares held to Statoil ASA in exchange for a cash consideration of MSEK 544.1 based upon a share price of SEK 145.66 per share. These three share transactions increased the share capital/premium of the Company by an amount of MSEK 4,533.8.
Following the sale of the 2 million treasury shares to Statoil ASA, the Company does not hold any own shares at 31 December 2016.
Pledged assets of MSEK 6,740.3 (MSEK 3,569.7) relate to the accounting value of the pledge of the shares in respect of the financing facility entered into by its fully-owned subsidiary Lundin Petroleum BV, see also Note 20 in the notes to the financial statements of the Group.
In June 2010, the Swedish International Public Prosecution Office commenced an investigation into alleged violations of international humanitarian law in Sudan during 1997–2003. The Company has cooperated extensively and proactively with the Prosecution Office by providing information regarding its operations in Block 5A in Sudan during the relevant time period. Ian H. Lundin and Alex Schneiter have been interviewed by the Prosecution Office and were notified of the suspicions that are the basis for the investigation. This is a normal part of Swedish legal procedure for any investigation and no charges have been brought, nor does this mean that charges will be brought. As repeatedly stated, Lundin Petroleum categorically refutes all allegations of wrongdoing and is cooperating with the Prosecution Office's investigation. Lundin Petroleum strongly believes that it was a force for good in Sudan and that its activities contributed to the improvement of the lives of the people of Sudan.
The financial statements of the Parent Company are prepared in accordance with accounting policies generally accepted in Sweden, applying RFR 2 issued by the Swedish Financial Reporting Board and the Annual Accounts Act (1995: 1554). RFR 2 requires the Parent Company to use similar accounting policies as for the Group, i.e. IFRS to the extent allowed by RFR 2. The Parent Company's accounting policies do not in any material respect deviate from the Group policies, see pages 89–94.
for the Financial Year Ended 31 December
| Expressed in MSEK | Note | 2016 | 2015 |
|---|---|---|---|
| Revenue | 3.8 | 8.7 | |
| General and administration expenses | -106.6 | -89.6 | |
| Operating loss | -102.8 | -80.9 | |
| Result from financial investments | |||
| Finance income | 1 | 3.5 | 4.6 |
| Finance costs | 2 | -4.0 | -1.8 |
| -0.5 | 2.8 | ||
| Loss before tax | -103.3 | -78.1 | |
| Income tax | 3 | – | – |
| Net result | -103.3 | -78.1 |
for the Financial Year Ended 31 December
| Expressed in MSEK | 2016 | 2015 |
|---|---|---|
| Net result | -103.3 | -78.1 |
| Other comprehensive income | – | – |
| Total comprehensive income | -103.3 | -78.1 |
| Attributable to: | ||
| Shareholders of the Parent Company | -103.3 | -78.1 |
| -103.3 | -78.1 |
for the Financial Year Ended 31 December
| Expressed in MSEK | Note | 2016 | 2015 |
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Shares in subsidiaries | 8 | 12,256.6 | 7,871.8 |
| Other tangible fixed assets | – | 0.2 | |
| Total non-current assets | 12,256.6 | 7,872.0 | |
| Current assets | |||
| Prepaid expenses and accrued income | 5.4 | 3.8 | |
| Other receivables | 4 | 15.3 | 13.7 |
| Cash and cash equivalents | 3.2 | 0.4 | |
| Total current assets | 23.9 | 17.9 | |
| TOTAL ASSETS | 12,280.5 | 7,889.9 | |
| EQUITY AND LIABILITIES | |||
| Restricted equity | |||
| Share capital | 3.5 | 3.2 | |
| Statutory reserve | 861.3 | 861.3 | |
| Total restricted equity | 864.8 | 864.5 | |
| Unrestricted equity | |||
| Other reserves | 6,828.8 | 2,295.3 | |
| Retained earnings | 4,622.6 | 4,700.7 | |
| Net result | -103.3 | -78.1 | |
| Total unrestricted equity | 11,348.1 | 6,917.9 | |
| Total equity | 12,212.9 | 7,782.4 | |
| Non-current liabilities | |||
| Provisions | 0.6 | 0.4 | |
| Payables to Group companies | 49.4 | 100.7 | |
| Total non-current liabilities | 50.0 | 101.1 | |
| Current liabilities | |||
| Trade payables | 1.9 | – | |
| Accrued expenses and prepaid income | 5 | 14.4 | 5.2 |
| Other liabilities | 1.3 | 1.2 | |
| Total current liabilities | 17.6 | 6.4 | |
| TOTAL EQUITY AND LIABILITIES | 12,280.5 | 7,889.9 |
for the Financial Year Ended 31 December
| Expressed in MSEK | 2016 | 2015 |
|---|---|---|
| Cash flow from operations | ||
| Net result | -103.3 | -78.1 |
| Adjustment for | ||
| Foreign currency exchange loss | -2.2 | 0.3 |
| Other | 26.8 | – |
| Changes in working capital: | ||
| Changes in current assets | -3.2 | -0.8 |
| Changes in current liabilities | 10.6 | -23.0 |
| Total cash flow from operations activities | -71.3 | -101.6 |
| Cash flow from financing activities | ||
| Changes in long-term liabilities | -467.5 | 100.4 |
| Proceeds from share issues /treasury shares | 544.1 | – |
| Total cash flow from financing activities | 76.6 | 100.4 |
| Change in cash and cash equivalents | 5.3 | -1.2 |
| Cash and cash equivalents at the beginning of the year | 0.4 | 1.8 |
| Currency exchange difference in cash and cash equivalents | -2.5 | -0.2 |
| Cash and cash equivalents at the end of the year | 3.2 | 0.4 |
for the Financial Year Ended 31 December
| Restricted Equity | Unrestricted Equity | |||||
|---|---|---|---|---|---|---|
| Expressed in MSEK | Share capital1 |
Statutory reserve |
Other reserves |
Retained earnings |
Total | Total equity |
| Balance at 1 January 2015 | 3.2 | 861.3 | 2,295.3 | 4,700.7 | 6,996.0 | 7,860.5 |
| Total comprehensive income | – | – | – | -78.1 | -78.1 | -78.1 |
| Balance at 31 December 2015 | 3.2 | 861.3 | 2,295.3 | 4,622.6 | 6,917.9 | 7,782.4 |
| Total comprehensive income | – | – | – | -103.3 | -103.3 | -103.3 |
| Transactions with owners | – | – | – | – | – | – |
| Issuance of shares/sale of treasury shares | 0.31 | – | 4,533.51 | – | 4,533.5 | 4,533.8 |
| Total transactions with owners | 0.3 | – | 4,533.5 | – | 4,533.5 | 4,533.8 |
| Balance at 31 December 2016 | 3.5 | 861.3 | 6,828.8 | 4,519.3 | 11,348.1 | 12,212.9 |
1 In 2016, Lundin Petroleum AB issued 27,580,806 new shares to Statoil ASA as part of the Edvard Grieg transaction. In addition, the Company also issued 1,735,309 new shares and transferred 2 million treasury shares held to Statoil ASA in exchange for a cash consideration of MSEK 544.1 based upon a share price of SEK 145.66 per share. These three share transactions increased the share capital/premium of the Company by an amount of MSEK 4,533.8.
of the Parent Company
| MSEK | 2016 | 2015 |
|---|---|---|
| Guarantee fees | 3.5 | 4.4 |
| Foreign exchange gain | – | 0.2 |
| 3.5 | 4.6 |
| MSEK | 2016 | 2015 |
|---|---|---|
| Interest expenses Group | 1.8 | 1.8 |
| Foreign exchange losses, net | 2.2 | – |
| 4.0 | 1.8 |
| MSEK | 31 December 2016 |
31 December 2015 |
|---|---|---|
| Social security costs | 1.6 | 1.0 |
| Directors fees | 0.5 | 0.6 |
| Audit | 0.8 | 1.0 |
| Outside services | 11.6 | 2.6 |
| 14.4 | 5.2 |
Pledged assets relate to the accounting value of the pledge of the shares in respect of the new financing facility entered into by the fully-owned subsidiary Lundin Petroleum BV, see Note 20 in the notes to the financial statements of the Group.
| MSEK | 2016 | 2015 |
|---|---|---|
| Net result before tax | -103.3 | -78.1 |
| Tax calculated at the corporate tax rate in Sweden 22% (22%) |
22.7 | 17.2 |
| Tax effect of expenses non-deductible for tax purposes |
-1.9 | -2.3 |
| Increase unrecorded tax losses | -20.8 | -14.9 |
| – | – |
| MSEK | 31 December 2016 |
31 December 2015 |
|---|---|---|
| Due from Group companies | 11.7 | 10.9 |
| VAT receivable | 0.7 | 0.9 |
| Other | 2.9 | 1.9 |
| 15.3 | 13.7 |
| MSEK | 2016 | 2015 |
|---|---|---|
| PwC | ||
| Audit fees | 1.6 | 1.7 |
| Audit related | – | – |
| 1.6 | 1.7 |
There has been no remuneration to any auditors other than PwC.
The Board of Directors propose that the unrestricted equity of the Parent Company of MSEK 11,348.1, including the net result for the year of MSEK -103.3 be brought forward.
| Registration | Total number of shares |
Percentage | Nominal value |
Book amount 31 Dec |
Book amount 31 Dec |
||
|---|---|---|---|---|---|---|---|
| MSEK | number | Registered office | issued | owned | per share | 2016 | 2015 |
| Directly owned Lundin Petroleum BV |
27254196 | The Hague, Netherlands | 181 | 100 | EUR 100.00 | 12,256.6 | 7,871.8 |
| Lundin Services Ltd | LL09860 | Labuan, Malaysia | 100 | 100 | USD 0.01 | – | – |
| 12,256.6 | 7,871.8 | ||||||
| Indirectly owned | |||||||
| Lundin Norway AS | 986 209 409 | Lysaker, Norway | 4,930,000 | 100 | NOK 100.00 | ||
| Lundin Netherlands BV | 24106565 | The Hague, Netherlands | 6,000 | 100 | EUR 450.00 | ||
| Lundin Netherlands Facilities BV 27324007 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | |||
| Lundin Holdings SA | 442423448 | Montmirail, France | 1,853,700 | 100 | EUR 10.00 | ||
| - Lundin International SA | 572199164 | Montmirail, France | 1,721,855 | 99.87 | EUR 15.00 | ||
| - Lundin Gascogne SNC | 419619077 | Montmirail, France | 100 | 100 | EUR 152.45 | ||
| Ikdam Production SA | 433912920 | Montmirail, France | 4,000 | 100 | EUR 10.00 | ||
| Lundin SEA Holding BV | 27290568 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Malaysia BV | 27306815 | The Hague, Netherlands | 150,000 | 100 | EUR 1.00 | ||
| - Lundin Indonesia Holding BV | 27290577 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Baronang BV | 27314235 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Cakalang BV | 27314288 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Gurita BV | 27296469 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Rangkas BV (under liquidation) |
27314247 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Cambodia BV (under liquidation) |
27292990 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Russia BV | 27290574 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Lundin Russia Ltd. | 656565-4 | Vancouver, Canada | 55,855,414 | 100 | CAD 1.00 | ||
| - Culmore Holding Ltd | 162316 | Nicosia, Cyprus | 1,002 | 100 | CYP 1.00 | ||
| - Lundin Lagansky BV | 27292984 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| - Mintley Caspian Ltd | 160901 | Nicosia, Cyprus | 5,000 | 70 | CYP 1.00 | ||
| - LLC PetroResurs | 1047796031733 | Moscow, Russia | 1 | 100 | RUR 10,000 | ||
| Lundin Tunisia BV | 27284355 | The Hague, Netherlands | 180 | 100 | EUR 100.00 | ||
| Lundin Marine BV (under liquidation) |
27275508 | The Hague, Netherlands | 180 | 100 | EUR 100.00 | ||
| - Lundin Marine SARL (under liquidation) |
06B090 | Pointe Noire, Congo | 200 | 100 | FCFA 5,000 | ||
| Lundin Petroleum SA | 660.0.330.999-0 | Collonge-Bellerive, Switzerland |
1,000 | 100 | CHF 100.00 | ||
| Jet Arrow SA (under liquidation) |
660.2.774.006-9 | Collonge-Bellerive, Switzerland |
11,000 | 100 | CHF 100.00 | ||
| Lundin Petroleum Marketing SA | 660.6.133.015-6 | Collonge-Bellerive, Switzerland |
1,000 | 100 | CHF 100.00 | ||
| Lundin Services BV | 27260264 | The Hague, Netherlands | 180 | 100 | EUR 100.00 | ||
| Lundin Ventures XVII BV | 53732855 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Ventures XVIII BV | 55709532 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 | ||
| Lundin Ventures XIX BV | 55709362 | The Hague, Netherlands | 18,000 | 100 | EUR 1.00 |
Jet Arrow SA, Lundin Marine BV, Lundin Marine SARL, Lundin Rangkas BV and Lundin Cambodia BV were under liquidation as at 31 December 2016.
Lundin South East Asia BV was liquidated during 2016. Lundin Indonesia Holding BV, Lundin Lematang BV, Lundin Oil & Gas BV, Lundin Cendrawasih VII BV and Lundin South Sokang BV were sold to PT Medco Energi Internasional TBK in April 2016.
As at 30 March 2017, the Board of Directors and the President of Lundin Petroleum AB have adopted this annual report for the financial year ended 31 December 2016.
The Board of Directors and the President & CEO certify that the annual financial report for the Parent Company has been prepared in accordance with generally accepted accounting principles in Sweden and that the consolidated accounts have been prepared in accordance with IFRS as adopted by the EU and give a true and fair view of the financial position and profit of the Company and the Group and provides a fair review of the performance of the Group's and Parent Company's business, and describes the principal risks and uncertainties that the Company and the companies in the Group face.
Stockholm, 30 March 2017
Lundin Petroleum AB (publ) Reg. Nr. 556610-8055
Ian H. Lundin Chairman
Alex Schneiter President & CEO Peggy Bruzelius Board Member
C. Ashley Heppenstall Board Member
Lukas H. Lundin Board Member
Grace Reksten Skaugen Board Member
Magnus Unger Board Member
Cecilia Vieweg Board Member
Our audit report was issued on 31 March 2017
PricewaterhouseCoopers AB
Johan Rippe Authorised Public Accountant Lead Partner
Johan Malmqvist Authorised Public Accountant
To the general meeting of the shareholders of Lundin Petroleum AB (publ), corporate identity number 556610-8055
We have audited the annual accounts and consolidated accounts of Lundin Petroleum AB (publ) for the year 2016. The annual accounts and consolidated accounts of the company are included on pages 71–124 in this document.
In our opinion, the annual accounts and consolidated accounts have been prepared in accordance with the Annual Accounts Act and present fairly, in all material respects, the financial position of parent company as of 31 December 2016 and its financial performance and cash flow for the year then ended in accordance with the Annual Accounts Act. The consolidated accounts have been prepared in accordance with the Annual Accounts Act and present fairly, in all material respects, the financial position of the group as of 31 December 2016 and their financial performance and cash flow for the year then ended in accordance with International Financial Reporting Standards (IFRS), as adopted by the EU, and the Annual Accounts Act. The statutory administration report is consistent with the other parts of the annual accounts and consolidated accounts. We therefore recommend that the general meeting of shareholders adopts the income statement and balance sheet for the parent company and the group.
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 fulfilled our ethical responsibilities in accordance with these requirements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinions.
Lundin Petroleum is an oil and gas company with exploration, development and production activities that, for the financial year 2016, have been located in Norway, Malaysia, France, the Netherlands and Russia. The operations in Norway represented 82% of the group's revenue for the financial year 2016 and 89% of the group's assets as per 31 December 2016. We designed our audit by determining materiality and assessing the risks of material misstatement in the consolidated financial statements. In particular, we considered where the Board of Directors and the President & CEO made subjective judgements; for example, in respect of significant 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 sufficient work to enable us to provide an opinion on the consolidated financial 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 offices. Following the group's organisation certain processes for accounting and financial reporting is 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 specified 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 specified audit procedures in Malaysia, France, the Netherlands and Russia. For entities considered to be of insignificant 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 the finance department from Norway including physical visits to the Norwegian office location.
We have obtained reporting from our component auditors at two occasions in the 2016 financial year 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, 2016 and after the year-end audit of the financial year 2016.
The scope of our audit was influenced by our application of materiality. An audit is designed to obtain reasonable assurance whether the financial 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 influence the economic decisions of users taken on the basis of the financial statements. Based on our professional judgement, we determined certain quantitative thresholds for materiality, including the overall group materiality for the financial statements as a whole. These, together with qualitative considerations, helped us to determine the scope of our audit and the nature, timing and extent of our audit procedures and to evaluate the effect of misstatements, both individually and in aggregate on the financial statements as a whole.
We chose total assets as the quantitative benchmark because, in our view, it is the most relevant benchmark given the current developments in the group with continued exploration and development of oil fields, in combination with the oil price in the year. An additional factor was the impact from variations in foreign exchange rates that does not have an insignificant impact on the group's income. By taking these matters into consideration a revenue or income oriented benchmark is not considered appropriate. Auditing standards specifically acknowledge that an alternative approach to determining materiality may be more appropriate where revenue and income are volatile and not representative of underlying or sustained business performance. By also taking into consideration the external stakeholders' perspective, where the development of the company's assets is a key measure, we have chosen total assets as the most appropriate benchmark.
Key audit matters of the audit are those matters that, in our professional judgment, were of most significance 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.
| Key audit matter | How our audit addressed the Key audit matter |
|---|---|
| Recoverability of the carrying value of oil and gas properties The carrying value of oil and gas properties represents the majority of the assets in the balance sheet in the group and amounted to USD 4,376 million (USD 4,015 million) as per 31 December 2016. The carrying value of oil and gas properties is supported by the |
We have examined management's assessment for determining the impairment indicators and concluded that the oil and gas price outlook together with the production profiles for certain of its oil and gas assets represents an impairment indicator triggering the need for an impairment test. The assumptions that underpin management's calculation of the recoverable amount of oil and gas assets are inherently |
| higher of either value in use calculations, which are based on discounted future cash flow forecasts, or fair value less cost of disposal (recoverable amount). |
judgmental. Our audit work therefore assessed the reasonableness of management's key judgements of the recoverable amount. Specifically our work included, but was not limited to, the following procedures: |
| Management concluded that the oil and gas price outlook together with the updated production profiles as part of the year end reserves process, was considered a trigger for an impairment test for certain of its oil and gas properties. The test, with the aim to assess the recoverability of the carrying value, requires management to exercise significant judgement as described in the Accounting Policies "Critical accounting estimates and judgements" as well as in note 7 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. |
· comparison of management´s short-term oil and gas price assumptions against external oil price forward curves; · comparison of long-term oil and gas price assumptions against views published by brokers, economists, consultancies and respected industry bodies, which provided a range of relevant third-party data points; · agreement of hydrocarbon production profiles and proved and probable reserves to reserve reports prepared by ERC Equipoise Ltd; · verification of estimated future operating costs and capital expenditures by agreement to budgets, Plan for development and operation (PDO) and where applicable, third party data; |
| Management's assessment requires consideration of a number of factors, including but not limited to, the Group's intention to proceed with a future work programme, the success of future |
· recalculation and benchmarking of inflation and discount rates applied; |
· testing of the mathematical accuracy of the model to calculate the recoverable amount.
We obtained the estimation of proved and probable reserves certified 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 capitalised exploration expenditures by field area cost centre basis (field) as of December 31, 2016. We tested the mathematical accuracy of this listing and reconciled the listing to the general ledger. We then assessed and challenged the continued capitalisation of exploration expenditures by reviewing the underlying documentation prepared by management for each of the fields and discussed with management. On a sample basis, we also reconciled and corroborated information provided on expenditures incurred and wells drilled to licence budgets, resource and value estimates, progress reporting in the joint venture, future plans and/or well commitments.
drilling, the size of proved and probable reserves, short and long term oil prices, future costs as well as discount and inflation rates.
The estimation of oil and natural gas reserves is a significant area of judgement due to the technical uncertainty in assessing the estimated quantities. The estimates of proved and probable reserves has a direct impact on depletion charges and forms the basis of the estimation of future planned production applied in the impairment tests of oil and gas properties.
The estimation of reserves are also a fundamental indicator of the future potential of the group's performance and therefore becomes critical information provided in the annual report. The estimates of proved and probable reserves are certified by the group's external reserves auditor, ERC Equipoise Ltd., which is considered to be an expert firm in this area.
Management has incorporated all these judgmental factors in determining the recoverable amount of the assets and compared it with the carrying value. This test has concluded that the carrying value of oil and gas properties associated the Sabah region offshore East Malaysia and the Tembakau gas discovery in PM307 offshore Peninsular Malaysia as well as the Morskaya oil discovery in the Russian Caspian Sea have all been fully impaired with an amount totalling USD 632 million less a corresponding tax credit of USD 83 million.
Refer to pages 80 and 81 in the Directors' report, page 94 in the Accounting Policies and note 7 in the financial statements for more information.
| Key audit matter | How our audit addressed the Key audit matter |
|---|---|
| Recognition and valuation of current taxes and deferred taxes The group has recognised a tax receivable of USD 77 million at December 31, 2016 (USD 261 million) related to the Lundin Norway entity. Under Norwegian Petroleum tax regulations, the Norwegian entity is eligible for cash tax refunds calculated on exploration costs incurred. In addition, the Norwegian entity has material unused tax loss carry forwards as part of the deferred tax position as discussed in note 6 to the financial statements. 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. Refer to pages 81 and 82 in the Directors' report, page 94 in the Accounting Policies and note 6 in the financial statements for more information. |
We obtained the annual tax calculation for the Norwegian entity as prepared by management. The tax calculation is subject to internal controls. We tested management's review control 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 the mathematical accuracy of the tax calculations and formulas applied. We reconciled book and tax positions as of December 31, 2016 and December 31, 2015 used in the calculation to underlying documentation. We examined the application of the tax regulations and considered the classification of costs to assess the entity's calculation of cash tax refund for net loss positions related to exploration costs incurred. 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. |
| Estimation of decommissioning and site restoration provisions The group has recognised site restoration provisions in the amount of USD 407 million as of December 31, 2016 (USD 368 million). The calculation of decommissioning and site restoration provisions requires significant management judgement because of the inherent complexity in estimating future 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 fields on an ongoing basis. This review incorporates the effects of any changes in local regulations, management's expected approach to decommissioning, cost estimates, discount rates, and the effects of changes in exchange rates. Refer to page 82 in the Directors' report, page 94 in the Accounting Policies and note 16 in the financial statements. |
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 field. We tested mathematical accuracy of the calculations and reconciled the calculated site provision liability 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. 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 verified that the accounting records appropriately reflect the external estimates performed. |
| Other Information than the annual accounts and consolidated accounts This document also contains other information than the annual accounts and consolidated accounts and is found on pages 1–70 and 129–137. The Board of Directors and the President & CEO 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. |
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. |
In connection with our audit of the annual accounts and consolidated accounts, our responsibility is to read the information identified above and consider whether the
Responsibilities of the Board of Directors and the President The Board of Directors and the President 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 President 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 President 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 President intends to liquidate the company, to cease operations, or has no realistic alternative but to do so.
The Audit Committee shall, without prejudice to the Board of Director's responsibilities and tasks in general, among other things oversee the company's financial 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 influence 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 Revisorsnämnden's website: www.revisorsinspektionen.se/rn/ showdocument/documents/rev_dok/revisors_ansvar.pdf. This description is part of the auditor´s report.
In addition to our audit of the annual accounts and consolidated accounts, we have also audited the administration of the Board of Directors and the President of Lundin Petroleum AB (publ) for the year 2016 and the proposed appropriations of the company's profit or loss.
We recommend to the general meeting of shareholders that the profit be appropriated in accordance with the proposal in the statutory administration report and that the members of the Board of Directors and the President be discharged from liability for the financial year.
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 fulfilled our ethical responsibilities in accordance with these requirements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinions.
The Board of Directors is responsible for the proposal for appropriations of the company's profit or loss. At the proposal of a dividend, this includes an assessment of whether the dividend is justifiable considering the requirements which the company's and the group's type of operations, size and risks place on the size of the parent company's and the group's equity, consolidation requirements, liquidity and position in general.
The Board of Directors is responsible for the company's organization and the administration of the company's affairs. This includes among other things continuous assessment of the company's and the group's financial situation and ensuring that the company's organization is designed so that the accounting, management of assets and the company's financial affairs otherwise are controlled in a reassuring manner. The President shall manage the ongoing administration according to the Board of Directors' guidelines and instructions and among other matters take measures that are necessary to fulfill 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 President in any material respect:
Our objective concerning the audit of the proposed appropriations of the company's profit 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 profit 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 Revisorsnämnden's website: www.revisorsinspektionen.se/rn/showdocument/documents/rev_ dok/revisors_ansvar.pdf. This description is part of the auditor´s report.
Stockholm, 31 March 2017
PricewaterhouseCoopers AB
Johan Rippe Authorised Public Accountant Lead Partner
Johan Malmqvist Authorised Public Accountant
Lundin Petroleum discloses alternative performance measures as part of its financial statements prepared in accordance with ESMA's (European Securities and Markets Authority) guidelines. Definitions of the performance measures are provided under the key ratio definitions below.
| Financial data | |||||
|---|---|---|---|---|---|
| MUSD | 2016 | 2015 | 2014 | 2013 3 | 2012 |
| Revenue1 | 1,159.9 | 569.3 | 785.2 | 1,132.0 | 1,375.8 |
| EBITDA | 902.6 | 384.7 | 671.3 | 955.7 | 1,144.1 |
| Net result | -499.3 | -866.3 | -431.9 | 72.9 | 103.9 |
| Operating cash flow | 1,010.8 | 699.6 | 1,138.5 | 967.9 | 831.4 |
| Data per share USD |
|||||
| Shareholders' equity per share | -0.70 | -1.61 | 1.40 | 3.90 | 3.81 |
| Operating cash flow per share | 3.10 | 2.26 | 3.68 | 3.12 | 2.68 |
| Cash flow from operations per share | 2.39 | 1.01 | 1.96 | 2.92 | 2.64 |
| Earnings per share | -1.09 | -2.79 | -1.38 | 0.25 | 0.35 |
| Earnings per share fully diluted | -1.09 | -2.79 | -1.38 | 0.25 | 0.35 |
| EBITDA per share | 2.77 | 1.24 | 2.17 | 3.08 | 3.68 |
| Dividend per share | – | – | – | – | – |
| Number of shares issued at year end | 340,386,445 | 311,070,330 | 311,070,330 | 317,910,580 | 317,910,580 |
| Number of shares in circulation at year end | 340,386,445 | 309,070,330 | 309,070,330 | 309,570,330 | 310,542,295 |
| Weighted average number of shares for the year | 325,808,486 | 309,070,330 | 309,170,986 | 310,017,074 | 310,735,227 |
| Weighted average number of shares for the year fully diluted |
326,738,233 | 310,019,890 | 309,475,038 | – | – |
| Share price SEK |
|||||
| Share price | 198.10 | 122.60 | 112.40 | 125.40 | 149.5 |
| Key ratios (%) | |||||
| Return on equity 2 | – | – | -50 | 6 | 9 |
| Return on capital employed | -12 | -26 | -11 | 16 | 35 |
| Net debt/equity ratio 2 | – | – | 605 | 99 | 28 |
| Equity ratio | -7 | -10 | 9 | 29 | 38 |
| Share of risk capital | 6 | 1 | 28 | 53 | 66 |
| Interest coverage ratio | -3 | -11 | -13 | 52 | 75 |
| Operating cash flow/interest ratio | 6 | 9 | 49 | 149 | 119 |
| Yield | n/a | n/a | n/a | n/a | n/a |
1 Following the reclassification of the change in under/over lift from production cost to revenue from 1 January 2013, the comparatives have been restated.
2 As the equity in 2015 and 2016 are negative, these ratios have not been calculated.
3 The comparatives for 2013 have been restated following the adoption of IFRS 11 Joint Arrangements, effective 1 January 2014. No restatement has been made for the year 2012.
Operating EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortisation): Operating profit before depletion of oil and gas properties, exploration costs, impairment costs, depreciation of other tangible assets and gain on sale of assets.
Revenue less production costs and less current taxes.
Cost of operations, tariff and transportation expenses and royalty and direct production taxes.
Shareholders' equity divided by the number of shares in circulation at year end.
Operating cash flow divided by the weighted average number of shares for the year.
Cash flow from operations in accordance with the consolidated statement of cash flow divided by the weighted average number of shares for the year.
NNet result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the year.
Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the year after considering any dilution effect.
EBITDA divided by the weighted average number of shares for the year.
The number of shares at the beginning of the year with changes in the number of shares weighted for the proportion of the year they are in issue.
The number of shares at the beginning of the year with changes in the number of shares weighted for the proportion of the year they are in issue after considering any dilution effect.
Net result divided by average total equity.
Income before tax plus interest expenses plus/less currency exchange differences on financial loans divided by the average capital employed (the average balance sheet total less non-interest bearing liabilities).
Bank loan less cash and cash equivalents divided by shareholders' equity.
Total equity divided by the balance sheet total.
The sum of the total equity and the deferred tax provision divided by the balance sheet total.
Result after financial items plus interest expenses plus/less currency exchange differences on financial 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 financial year.
| Income statement summary | |||||
|---|---|---|---|---|---|
| MUSD | 2016 | 2015 | 2014 | 20131 | 2012 |
| Revenue | 1,159.9 | 569.3 | 785.2 | 1,132.0 | 1,375.8 |
| Production costs | -227.5 | -150.3 | -66.5 | -139.6 | -203.2 |
| Depletion and decommissioning costs | -471.4 | -260.6 | -131.6 | -169.3 | -191.4 |
| Depletion of other assets | -31.1 | -23.7 | – | – | – |
| Exploration costs | -116.1 | -184.1 | -386.4 | -287.8 | -168.4 |
| Impairment costs of oil and gas properties | -632.1 | -737.0 | -400.7 | -123.4 | -237.5 |
| Other cost of sales | -2.1 | – | – | – | – |
| Gross profit/loss | -320.4 | -786.4 | -200.0 | 411.9 | 575.3 |
| Sale of assets | -3.5 | – | – | – | – |
| General, administration and depreciation expenses | -31.9 | -39.5 | -52.2 | -41.2 | -31.8 |
| Operating profit/loss | -355.8 | -825.9 | -252.2 | 370.7 | 543.5 |
| Net financial items | -202.8 | -610.5 | -420.0 | -82.5 | -21.2 |
| Share of result of joint ventures accounted for using the equity method |
– | – | -12.9 | -0.2 | – |
| Profit/loss before tax | -558.6 | -1,436.4 | -685.1 | 288.0 | 522.3 |
| Income tax | 59.3 | 570.1 | 253.2 | -215.1 | -418.4 |
| Net result | -499.3 | -866.3 | -431.9 | 72.9 | 103.9 |
| Net result attributable to the shareholders of the Parent Company: |
-356.7 | -861.7 | -427.2 | 77.6 | 108.2 |
| Net result attributable to non-controlling interest: | -142.6 | -4.6 | -4.7 | -4.7 | -4.3 |
| Net result | -499.3 | -866.3 | -431.9 | 72.9 | 103.9 |
| Balance sheet summary MUSD |
2016 | 2015 | 2014 | 2013 | 2012 |
| Tangible fixed assets | 4,542.5 | 4,219.7 | 4,382.9 | 3,905.8 | 2,913.8 |
| Other non-current assets | 168.0 | 24.1 | 49.9 | 93.6 | 44.1 |
| Current assets | 491.6 | 541.5 | 659.2 | 362.0 | 335.8 |
| Total assets | 5,202.1 | 4,785.3 | 5,092.0 | 4,361.4 | 3,293.7 |
| Shareholders' equity | -238.6 | -498.2 | 431.5 | 1,207.0 | 1,182.4 |
| Non-controlling interest | -113.6 | 24.1 | 34.2 | 59.8 | 67.7 |
| Total equity | -352.2 | -474.1 | 465.7 | 1,266.8 | 1,250.1 |
| Non-current provisions | 1,119.1 | 970.5 | 1,295.2 | 1,345.1 | 1,204.6 |
| Non-current liabilities | 4,082.1 | 3,867.0 | 2,683.1 | 1,264.1 | 406.8 |
| Current liabilities | 353.1 | 421.5 | 648.0 | 485.4 | 432.2 |
| Total shareholders'equity and liabilities | 5,202.1 | 4,785.3 | 5,092.0 | 4,361.4 | 3,293.7 |
1 The comparatives for 2013 have been restated following the adoption of IFRS 11 Joint Arrangements, effective 1 January 2014. No restatement has been made for the year 2012.
| Proved and probable oil reserves | Total MMbbl |
Norway MMbbl |
France MMbbl |
Netherlands MMbbl |
Malaysia MMbbl |
Russia MMbbl |
|---|---|---|---|---|---|---|
| 1 January 2015 | 172.7 | 137.7 | 21.2 | – | 13.8 | – |
| Changes during the year | ||||||
| Acquisitions | – | – | – | – | – | – |
| Sales | – | – | – | – | – | – |
| Revisions | -4.5 | -2.3 | -1.1 | – | -1.1 | – |
| Extensions and discoveries | 498.8 | 498.8 | – | – | – | – |
| Production | -9.8 | -6.8 | -1.0 | – | -2.0 | – |
| 31 December 2015 | 657.2 | 627.4 | 19.1 | – | 10.7 | – |
| 2016 | ||||||
| Changes during the year | ||||||
| Acquisitions | 27.6 | 27.6 | – | – | – | – |
| Sales | – | – | – | – | – | – |
| Revisions | 49.7 | 47.9 | -0.1 | – | 1.9 | – |
| Extensions and discoveries | 1.4 | 1.4 | – | – | – | – |
| Production | -23.9 | -19.9 | -0.9 | – | -3.1 | – |
| 31 December 2016 1 | 712.0 | 684.4 | 18.1 | – | 9.5 | – |
| Proved and probable gas reserves | Total Bn scf 2 |
Norway Bn scf |
Netherlands Bn scf |
Indonesia Bn scf |
|---|---|---|---|---|
| 1 January 2015 | 88.5 | 65.4 | 14.8 | 8.3 |
| Changes during the year | ||||
| Acquisitions | – | – | – | – |
| Sales | -4.8 | – | – | -4.8 |
| Revisions | 11.1 | 10.3 | 0.8 | – |
| Extensions and discoveries | 86.2 | 86.2 | – | – |
| Production | -12.0 | -4.6 | -3.9 | -3.5 |
| 31 December 2015 | 169.0 | 157.3 | 11.7 | – |
| 2016 | ||||
| Changes during the year | ||||
| Acquisitions | 11.1 | 11.1 | – | – |
| Sales | – | – | – | – |
| Revisions | 24.1 | 20.2 | 2.7 | 1.2 |
| Extensions and discoveries | 2.8 | 2.8 | – | – |
| Production | - 17.9 | -13.3 | - 3.4 | - 1.2 |
| 31 December 2016 | 189.1 | 178.1 | 11.0 | – |
1 The year end 2016 Oil reserves reported include 17.0 MMbbl of NGL's relating to Norway.
2 The factor of 6,000 is used by the company to convert one scf to one boe.
| 2P Reserves | ||
|---|---|---|
| Reserves | Proved reserves | Probable reserves |
| Lundin Petroleum calculates reserves and resources according to 2007 Petroleum Resources Management System (PRMS) Guidelines of the Society of Petroleum Engineers (SPE), World Petroleum Congress (WPC), American Association of Petroleum Geologists (AAPG) and Society of Petroleum Evaluation Engineers (SPEE). Lundin Petroleum's reserves are audited by ERC Equipoise Ltd. (ERCE), an independent reserves auditor. Reserves are defined 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 defined 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. |
Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and governmental regulations. Proved reserves can be categorised as developed or undeveloped. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimates. |
Probable reserves are those unproved reserves which analysis of geological and engineering data indicate are less likely to be recovered than Proved reserves but more certain to be recovered than Possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50 percent probability that the actual quantities recovered will equal or exceed the Proved plus Probable reserves (2P) estimate. |
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.
Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and chance of development.
| bbl | Barrel (1 barrel = 159 litres) |
|---|---|
| bcf | Billion cubic feet (1 cubic foot = 0.028 m3 ) |
| Bn | Billion |
| boe | Barrels of oil equivalent |
| boepd | Barrels of oil equivalent per day |
| bopd | Barrels of oil per day |
| Bn boe | Billion barrels of oil equivalent |
| Mbbl | Thousand barrels |
| Mbo | Thousand barrels of oil |
| Mboe | Thousand barrels of oil equivalent |
| Mboepd | Thousand barrels of oil equivalent per day |
| MMbo | Million barrels of oil |
| MMboe | Million barrels of oil equivalent |
| MMbbl | Million barrels |
| MMbpd | Million barrels per day |
| MMbopd | Million barrels of oil per day |
| Mcf | Thousand cubic feet |
| Mcfpd | Thousand cubic feet per day |
| MMscf | Million standard cubic feet |
| MMscfd | Million standard cubic feet per day |
| MMstb | Million stock tank barrels |
| MMbtu | Million British thermal units |
| CHF | Swiss Franc |
|---|---|
| CAD | Canadian Dollar |
| EUR | Euro |
| GBP | British Pound |
| NOK | Norwegian Krone |
| RUR | Russian Rouble |
| SEK | Swedish Krona |
| USD | US Dollar |
| TCHF | Thousand CHF |
| TSEK | Thousand SEK |
| TUSD | Thousand USD |
| MSEK | Million SEK |
| MUSD | Million USD |
For further definitions of oil and gas terms and i measurements, visit www.lundin-petroleum.com
| HSE indicator data | 2016 | 2015 | 2014 | 2013 | 2012 | |
|---|---|---|---|---|---|---|
| Exposure Hours | Employees | 1,115,738 | 1,286,396 | 1,219,744 | 960,508 | 909,196 |
| Contractors | 1,881,461 | 3,841,243 | 4,466,854 | 2,074,824 | 1,561,482 | |
| Total | 2,997,199 | 5,127,639 | 5,686,598 | 3,035,332 | 2,470,678 | |
| Fatalities | Employees | 0 | 0 | 0 | 0 | 0 |
| Contractors | 1 | 0 | 0 | 0 | 0 | |
| Lost Time Incidents1 | Employees | 0 | 1 | 0 | 2 | 2 |
| Contractors | 2 | 8 | 7 | 4 | 5 | |
| Restricted Work Incidents2 | Employees | 0 | 0 | 0 | 0 | 0 |
| Contractors | 2 | 0 | 1 | 0 | 0 | |
| Medical Treatment Incidents3 | Employees | 2 | 1 | 0 | 0 | 1 |
| Contractors | 0 | 9 | 4 | 2 | 0 | |
| Lost Time Incident Rate4 | Employees | 0.00 | 0.80 | 0.00 | 2.10 | 2.20 |
| Contractors | 1.06 | 2.10 | 1.55 | 1.95 | 3.20 | |
| All | 0.67 | 1.76 | 1.23 | 1.98 | 2.83 | |
| Total Recordable Incident Rate4 | Employees | 1.79 | 1.55 | 0.00 | 2.10 | 3.30 |
| Contractors | 2.66 | 4.45 | 2.70 | 2.90 | 3.20 | |
| All | 2.34 | 3.71 | 2.11 | 2.64 | 3.24 | |
| Oil Spills | No. | 0 | 0 | 2 | 0 | 2 |
| Vol. (m3 ) |
0 | 0 | 5.2 | 0 | 4 | |
| Chemical Spills | No. | 2 | 6 | 6 | 7 | 1 |
| Vol. (m3 ) |
65.20 | 59.88 | 45.9 | 59.37 | 1.75 | |
| Hydrocarbon Leaks | No. | 1 | 0 | 0 | 0 | 0 |
| Mass (kg) | 650 | 0 | 0 | 0 | 0 | |
| Near Misses with High Potential | No. | 3 | 6 | 7 | 2 | 5 |
| Non-compliance with Permits/Consents |
No. | 0 | 0 | 0 | 0 | 0 |
1 Lost Time Incident (LTI) is an incident which results in a person having at least one day away from work.
2 Restricted Work Incident (RWI) is an incident which results in keeping a person from performing one or more routine functions.
3 Medical Treatment Incident (MTI) is a work related injury or illness that does not result in a job restriction or days away from work.
4 Lost Time Incident Rate (LTIR) and Total Recordable Incident Rate (TRIR) are calculated per million hours worked.
Since Lundin Petroleum was incorporated in May 2001 and up to 31 December 2016 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:
| · 3 May 2017 | Three month report (January – March 2017) |
|---|---|
| · 2 August 2017 | Six month report (January – June 2017) |
| · 1 November 2017 | Nine month report (January – September 2017) |
| · 7 February 2018 | Year End report 2017 |
The reports are available on www.lundin-petroleum.com in Swedish and English directly after public announcement.
The Annual General Meeting (AGM) is held within six months from the close of the financial year. All shareholders who are registered in the shareholders' register and who have duly notified their intention to attend the AGM may do so and vote in accordance with their level of shareholding. Shareholders may also attend the AGM through a proxy and a shareholder shall in such a case issue a written and dated proxy. A proxy form is available on www.lundin-petroleum.com.
Lundin Petroleum's AGM is to be held on Thursday 4 May 2017 at 13.00 (Swedish time). Location: Vinterträdgården, Grand Hôtel, Södra Blasieholmshamnen 8 in Stockholm.
Shareholders wishing to attend the meeting shall:
· in writing to Lundin Petroleum AB, c/o Computershare AB, P.O. Box 610, SE 182 16 Danderyd, Sweden
When registering please indicate your name, social security number/company registration number, registered shareholding, address and day time telephone number.
Shareholders whose shares are registered in the name of a nominee must temporarily register the shares in their own name in the shareholders' register to be able to attend the meeting and exercise their voting rights. Such registration must be effected by Thursday 27 April 2017.
This information is information that Lundin Petroleum AB is required to make public pursuant to the Securities Markets Act. The information was submitted for publication at 08.00 CEST on 4 April 2017.
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 reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations and assumptions will prove to be correct and such forward-looking statements should not be relied upon. These statements speak only as on the date of the information and the Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, operational risks (including exploration and development risks), productions costs, availability of drilling equipment, reliance on key personnel, reserve estimates, health, safety and environmental issues, legal risks and regulatory changes, competition, geopolitical risk, and financial risks. These risks and uncertainties are described in more detail under the heading "Risks and Risk Management" and elsewhere in the Company's annual report. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. Actual results may differ materially from those expressed or implied by such forward-looking statements. Forwardlooking statements are expressly qualified by this cautionary statement.
Printed by Exakta Print Malmö and Landsten Reklam, Sweden 2017.
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 E [email protected]
W lundin-petroleum.com
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