Annual Report • Dec 31, 2016
Annual Report
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Tullow Oil is a leading independent oil and gas exploration and production company. Our focus is on finding and monetising oil in Africa and South America. Our key activities include targeted exploration and appraisal, selective development projects and growing our high-margin production. We have a prudent financial strategy with diverse sources of funding.
Our portfolio of over 100 licences spans 18 countries and is organised into three Business Delivery Teams. We are headquartered in London and our shares are listed on the London, Irish and Ghana Stock Exchanges.
Each year, Tullow Oil aims to produce an open, transparent and balanced Annual Report which gives an honest portrayal of our performance, strategy and impacts. Disclosure on our sustainability performance and objectives is included in this report and on our website. Each year we try to improve our reporting and we welcome feedback on how well we are doing.
Please give us your feedback: [email protected]
You can find this report and additional information about Tullow Oil on our website www.tullowoil.com
| Our operations | 4 |
|---|---|
| Chairman's statement | 6 |
| Chief Executive's review | 8 |
| Market review | 10 |
| Our business model | 12 |
| Our strategy | 14 |
| Key performance indicators | 16 |
| Creating value | 22 |
| Operations review | 24 |
| Finance & Portfolio Management | 32 |
| Responsible Operations | 38 |
| Governance & Risk Management | 40 |
| Principal risks | 44 |
| Organisation & Culture | 54 |
| Shared Prosperity | 56 |
| Directors' report | 60 |
|---|---|
| Audit Committee report | 69 |
| Nominations Committee report | 74 |
| EHS Committee report | 76 |
| Ethics & Compliance Committee report | 78 |
| Remuneration report | 80 |
| Other statutory information | 101 |
| Statement of Directors' responsibilities | 108 |
|---|---|
| Independent auditor's report for the | |
| Group Financial Statements | 109 |
| Group Financial Statements | 116 |
| Company Financial Statements | 150 |
| Five-year financial summary | 159 |
| Supplementary information | |
| Shareholder information | 160 |
| Licence interests | 161 |
| Commercial reserves and resources | 166 |
| Transparency disclosure | 167 |
| Sustainability data | 172 |
| Tullow Oil plc subsidiaries | 175 |
| Glossary | 177 |
Front Challenger, offloading tanker, and helideck of the TEN FPSO, Prof. John Evans Atta Mills, offshore Ghana
| Our operations | 4 |
|---|---|
| Chairman's statement | 6 |
| Chief Executive's review | 8 |
| Market review | 10 |
| Our business model | 12 |
| Our strategy | 14 |
| Key performance indicators | 16 |
| Creating value | 22 |
| Operations review | 24 |
| Finance & Portfolio Management | 32 |
| Responsible Operations | 38 |
| Governance & Risk Management | 40 |
| Principal risks | 44 |
| Organisation & Culture | 54 |
| Shared Prosperity | 56 |
STRATEGIC REPORT OUR OPERATIONS
Tullow has a balanced portfolio of high-quality producing fields, areas for future development and exciting exploration acreage.
Tullow's key operations are in Africa and South America, which are split into three Business Delivery Teams, as set out below.
The West Africa Business Delivery Team focuses on Tullow's production and development projects in West Africa. Our European production is also managed by this team.
Operations review: West Africa 28
Tullow's portfolio of licences is balanced between exploration, development and production activities.
Our acreage onshore and offshore Africa, and South America includes newly acquired licences in Zambia and Guyana.
Our talented employees and contractors work together across our corporate centre and Business Delivery Teams.
In this high potential region, the Group is progressing onshore exploration and the development of its Uganda and Kenya discoveries.
Operations review: East Africa 29
The New Ventures Business Delivery Team is responsible for Tullow's frontier exploration activity across Africa and South America.
Operations review: New Ventures 31
| Group financial overview | 2016 | 2015 |
|---|---|---|
| Sales revenue (\$m) | 1,270 | 1,607 |
| Pre-tax operating cash flow (\$m) | 774 | 967 |
| Operating loss (\$m) | (755) | (1,094) |
| Net loss after tax (\$m) | (597) | (1,037) |
| Basic (loss) per share (cents) | (65.8) | (113.6) |
During the course of 2016 we have repositioned Tullow Oil for growth. The Company is leaner, more efficient and more effective.
Tullow prides itself on being a resourceful, adaptable, resilient Company. During 2016, these characteristics were tested to the full. The collapse in the oil price that started in mid-2014 continued into 2016. In January 2016, the price of Brent crude fell to \$27 a barrel from a peak of \$115 in 2014, one of the worst downturns in the history of the oil industry. During 2015 we took decisive action in response to the sharp deterioration in the market, reducing our headcount by around 40 per cent, cutting exploration costs, and refocusing our capital expenditure on the TEN Project in Ghana. As we entered 2016, our strategic priorities were clear: maximise cash flow from existing operations; deliver the TEN Project on time and on budget; continue to progress our attractive, low-cost development projects in East Africa; maintain liquidity whilst working towards our long-term goal of reducing debt; pursue monetisation of portfolio options; and position the Company for renewed growth when market conditions improve. I am pleased to report that we have made significant progress on all of these objectives, notwithstanding a major, unforeseeable, setback with the Jubilee FPSO during the course of the year.
West Africa oil production for the year averaged 60,900 boepd, excluding insurance proceeds (2015: 73,400 boepd), despite an unprecedented failure of the main turret bearing on the Jubilee FPSO in February, which temporarily halted production. The response to this emergency, described on page 28, was exemplary, combining technical skill and ingenuity with an absolute commitment to safety and environmental protection.
"The Company has demonstrated technical and operational excellence, delivering TEN on time and on budget, and responding to the unprecedented events on the Jubilee FPSO with speed and skill."
Simon R Thompson Chairman
The speed of response mitigated our losses and reassured our lenders, allowing us to increase the loan facilities available to us. Our insurers have subsequently confirmed insurance cover for cost of repairs and lost production.
Revenues for the year amounted to \$1,270 million (2015: \$1,607 million), underpinned by our longstanding, prudent hedging programme, and continuing tight cost control resulted in a reduction in G&A expenses from \$194 million to \$116 million. Pre-tax operating cash flow amounted to \$774 million (2015: \$967 million), but the Company again reported a net loss after tax of \$597 million (2015: \$1,037 million), largely as a result of non-cash write-offs and impairments relating to the Uganda farm-down, the low oil price and the disposal of non-core assets.
The TEN Project achieved first oil, on time and on budget, in August 2016. This was an outstanding achievement for a complex, \$4 billion, multi-national project, particularly given the uncertainty introduced by the maritime border dispute between Côte d'Ivoire and Ghana, where a decision by the International Tribunal on the Law of the Sea is expected by the end of 2017. The start-up of TEN marks a major inflection point for Tullow. A combination of significantly reduced capital expenditure and increased, high-margin production means that we are now cash flow positive after capex, and can start to steadily pay down debt.
In Uganda, we were granted production licences in August 2016 and in
January 2017 announced the sale of 21.57 per cent of our 33.33 per cent holding in the project to Total, in return for a total consideration of \$900 million, payable over the course of the development project. This represents a reimbursement of a portion of our past costs, part of which will be used to fund our share of the development capex required for the upstream project and the export pipeline. Subject to completion, Tullow will have an 11.76 per cent shareholding (expected to reduce to 10 per cent in the upstream after the Government of Uganda formally exercises its back-in right) in a long-life, low-cost project that will be cash positive to the Company from day one.
In Kenya, following the successful Etom discovery earlier in the year, we restarted our exploration programme in Turkana, which has begun with a discovery by Erut-1 in the far north of the South Lokichar Basin. We are also well advanced in planning the Early Oil Pilot Scheme, which will provide valuable reservoir information and build effective working relationships with the local government and community on a small-scale project, before we embark upon the major upstream and pipeline development.
Throughout the downturn, while exploration capex was reduced, the team continued to identify and evaluate opportunities and has built a pipeline of good quality targets across Africa and South America. Exploration activities are picking up during 2017 and we will take advantage of the significantly reduced cost of drilling and the attractive opportunities the team has identified over the past two years.
The Major Simplification Project, started in 2015, has not only resulted in a leaner company, it has created a more efficient and effective one, with clearer lines of responsibility and accountability, better performance management, and improved risk management and assurance processes, from inception of a project to closure. But effective risk management, in an uncertain and unpredictable world, also depends upon a culture that is open, transparent and responsive to changes in the external environment, not least the expectations of society. Tullow was among the first in the industry to disclose tax payments to governments and is also one of the first oil companies publicly to rule out exploration in or close to World Heritage sites. Corruption remains a major challenge in many of the countries where we operate, and during 2016, 97 per cent of staff, including the Board, completed an ethical conduct E-learning programme. Improving the diversity of the executive pipeline, so that it better reflects the countries where we operate, remains a key priority, with new aspirational targets and concrete steps to accelerate the career development of Africans and women. In Kenya, our community relations officers are working closely with the local community to understand and address their concerns, particularly in relation to land access and water. Tullow is working to obtain their informed consent in advance of the development of the project. By proactively addressing such issues, we de-risk our operations and seek to enhance the long-term returns to our shareholders.
Thirty one years after founding Tullow Oil, Aidan Heavey has decided to step down as CEO at the AGM in 2017. The Company that Aidan has built bears many of the hallmarks of the man: entrepreneurial, adaptable, resilient and committed to creating shared prosperity for our shareholders and for the countries and communities where we operate. The Board reviewed both internal and external candidates to replace Aidan as CEO, but in the end there was no doubt about the preferred successor. Paul McDade has worked for Tullow Oil for 16 years, the last 12 as COO. During this time he has been responsible for Tullow's day-to-day operations and he is imbued with the Company's culture and values.
The Board has taken the unusual step of asking Aidan to remain with the Company as Chairman, for a transitional period of up to two years. Over the past three decades, Aidan has built up a broad network of contacts and relationships across Africa that represents a significant competitive advantage for the Company. Although the appointment of a former CEO as Chairman diverges from UK corporate governance principles, given the history of the Company and the markets in which it operates, the Board unanimously believes that a phased transition of the leadership of the Company is in the best interests of shareholders. As a consequence, after completing the CEO succession process, I will step down as Chairman at the AGM in 2017, after six challenging, enjoyable and fulfilling years at Tullow.
Ann Grant, who has served as Senior Independent Director (SID) with great distinction during the succession planning for both the CEO and the Chairman, will also step down at the AGM after nine years with Tullow. Jeremy Wilson will replace her as SID, a role that will carry additional responsibilities, since Aidan will not be an independent Chairman. All of these appointments will be subject to shareholder approval at the AGM.
I would like to thank all of my colleagues at Tullow for their hard work and dedication over the past 12 months, and to congratulate them on their achievements. I wish Paul, Aidan and Jeremy every success in their new roles.
During the course of 2016 we have repositioned Tullow Oil for growth. The Company is leaner, more efficient and more effective. It has demonstrated technical and operational excellence, delivering TEN on time and on budget and responding to the unprecedented events on the Jubilee FPSO with speed and skill. The farm-down in Uganda gives Tullow a material interest in an attractive project, which will be cash positive to the Company from completion. In Kenya we continue to make good progress towards the development of a major long-life, low-cost project with significant upside potential. And our exploration team is poised to restart drilling activities, taking advantage of the significantly reduced cost of exploration, with a portfolio of prospects accumulated over two years of research. Tullow Oil will be led into the next phase of its development by Paul, with the continuing support of Aidan. 2016 therefore marks the end of one exciting era, and the beginning of another.
Simon R Thompson Chairman 7 February 2017
Over the last two years we have moved quickly to make significant changes to our business and as a result we are a far better business than we were in 2014.
Over the past year staff, investors, industry partners and friends have all asked me the same question. How does this industry downturn compare to all the others? My answer is clear. This has been the worst slump that the industry has faced in the 31 years since I founded Tullow and, although it does seem that the worst has passed, the collapse in the oil price leaves behind it an oil and gas sector that has changed permanently. Critically, there appears to be no consensus over the future of the sector: there is no settled view about how oil prices will behave over the next ten years, when peak demand or supply will arrive, or how serious the threat to oil and gas from new technology and carbon-focused legislation really is. As a result, oil and gas companies will probably be forced to assume that oil prices will remain low in the short to medium term, permanently placing an emphasis on efficient exploration and low-cost production. Through the work Tullow has done over the past two years, I believe that the Group is very well placed to cope with and thrive in this new industry reality.
We have low-cost oil-producing assets in West Africa. The highlight of 2016 was, of course, first oil from the TEN oil fields in August. This project was exceptionally well executed and on time and on budget and I sincerely thank all colleagues and partners involved with this project for their hard work and dedication. To deliver a complex project of this nature on time is a stunning achievement. But first oil from TEN has wider significance for Tullow in terms of cash flow and debt. Due to the
"Through the work Tullow has done over the past two years, I believe that the Group is very well placed to cope with and thrive in this new industry reality."
Aidan Heavey Chief Executive Officer
additional production from TEN, we are now generating free cash flow for the first time in some years and we have begun the process of steadily paying down our debt.
The Jubilee field is also a low-cost oil-producing asset and, with TEN now up and running, we believe that we can achieve operating expenditure of around \$8/barrel in Ghana which, in a world of \$50 oil, is vital. But Jubilee has had its own challenges this year with problems with the turret on the FPSO, which was handled expertly by teams across the Group. Those teams worked tirelessly throughout the year looking at the solution to the problem, ongoing production operations, insurance, financing and other critical functions and I thank them for all that they have done in dealing with this highly complex issue. We now have a clear plan of action and are working closely with the Government of Ghana and our partners to make sure the issue is dealt with professionally and safely. Importantly, our costs and production losses associated with this issue are covered by our insurance.
Progress on our East Africa projects gained momentum in 2016 with the decision by the Government of Uganda on its pipeline routing through Tanzania, necessitating a standalone Kenyan pipeline; the granting of our long-awaited Uganda production licences; and, in January 2017, agreeing to farm-down a 21.57 per cent interest in the Uganda project to Total. The deal with Total delivers on our longstanding commitment to reduce our equity in Uganda and aligns the Joint Venture partnership on the upstream, accelerating progress
towards Final Investment Decision which we anticipate at the end of 2017 and first oil three years later. On completion of the deal, our 11.76 per cent interest in the upstream and pipeline, which is expected to reduce to 10 per cent in the upstream when the government exercises its back-in rights, is expected to provide the Company with around 23,000 bopd when the project achieves plateau production, at no further cost to the Company. It also underpins the commercial nature of our East Africa portfolio and allows us to focus on our Kenyan operated exploration and development assets.
We expect to reach FID for the Full Field Development in Kenya in 2018. Both developments in East Africa have changed over the past year as falling industry costs, new technology and new approaches to these fields have shown that we can produce these resources significantly below the cost levels forecast before the oil price fell.
We have an exploration team that is well positioned in this environment. We remain focused on Africa and South America and on geologies that we know well and have developed a strategic approach that ensures we carefully manage our technical and financial risk in new licences. This new approach means that our team can make progress even with highly constrained budgets and are well prepared for when market conditions change. Angus McCoss, our Exploration Director, sets out
more information on our exploration strategy on pages 26 and 27.
Even if oil prices do not change significantly in the short to medium term, Tullow remains well placed having gone into the slump with a strong set of licences, substantial technical expertise and 31 years of experience and contacts across Africa, which we believe is unrivalled amongst our peers. We continue to look at opportunities and data rooms across Africa and South America. The oil that we are developing in West and East Africa is oil that Tullow found and I remain convinced that organic growth through the drill bit is the best way to grow our Company.
The Group's net debt at the end of 2016 was almost \$5 billion. While it was not the Board's intention for our debt to be so high, the combination of continued low oil prices and our commitment to develop TEN made this unavoidable.
Simon Thompson will be stepping down from the Board at Tullow's 2017 Annual General Meeting in April, after five years as Tullow's Chairman and six years on the Board. I would like to thank Simon for his significant contribution to the Board during this time and wish him every success in his next endeavours. He has been a remarkable Chairman and has provided excellent leadership, particularly in the last few years where the Board has had to make some difficult decisions. His direction has taken us through some of our most exciting but also some of our most challenging years and the Board and I are grateful for the help, guidance and advice he has provided throughout his tenure.
Simon Thompson visiting the Jubilee FPSO, Kwame Nkrumah, offshore Ghana
We are now in a position where we are beginning the process of deleveraging through free cash flow from our producing assets, by constraining our capital investment while oil prices remain low, potentially farming down assets in West and East Africa where we have significant equity and other options available to the Group.
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31 years after founding and running the Company, I will be stepping down as Chief Executive at the next AGM. Paul McDade, who has run our business as Chief Operating Officer for the last 12 years, will succeed me. Simon Thompson, the Company's Chairman, will step down after six years on the Board and I will become Chairman for a transitional period of up to two years, by which time I will have fully transitioned my responsibilities to Paul and worked with the Nominations Committee to find a new Chairman for Tullow. These changes bring a balance between continuity and fresh thinking and I'm confident that Paul is the right candidate to lead the Company during what we intend to be a period of growth.
Tullow's repositioning has involved a long period of hard work and restructuring that began in the autumn of 2014 as the oil price began to fall from \$100 per barrel. We moved quickly and made huge changes to our business. Many of those changes were very painful but we are a far better business than we were in 2014: we are more efficient, focused and
leaner than we have been for many years and I thank all the staff of Tullow for their hard work in making these changes happen in very difficult times.
Aidan Heavey Chief Executive Officer
7 February 2017
| Our strategy | 14 |
|---|---|
| Organisation & Culture | 54 |
| Shared Prosperity | 56 |
STRATEGIC REPORT MARKET REVIEW
Analysts predict a gradual and cautious increase in investment across the sector as oil prices rise.
In 2016, the global economy was shaped by a number of political events, most notably the UK's decision to vote in favour of leaving the European Union, Donald Trump's win in the United States presidential election, the rejection of constitutional reforms in Italy and a series of terrorist incidents across Europe.
The trajectory of global interest rates continues to be the primary focus for investors. Following the first rate rise in seven years in December 2015, the Federal Reserve voted in favour of a further rate rise to 0.25 per cent in December 2016 on the back of an ongoing recovery in GDP, decline in unemployment and a less-volatile-thananticipated reaction to Donald Trump's election. In the UK, Sterling endured a significant sell-off following the UK's decision to leave the European Union, falling from 1.50 to 1.23 by year end versus the US dollar. The 8 per cent fall on 24 June was the largest one-day fall since the introduction of free-floating exchange rates in the early 1970s. On the back of the decision, the Bank of England cut interest rates by 25 basis points to a record low of 0.25 per cent alongside a variety of stimulus measures including the purchase of gilts and corporate bonds and a lending programme for banks. The outlook in Europe continues to be challenging; in March 2016 the ECB announced a significant package to ease monetary policy, shifting the focus away from rate cuts to quantitative and credit easing, a process which the ECB has confirmed will be continuing throughout 2017.
Brent crude made a material recovery in the second half of 2016, breaching \$50/bbl by year end having traded between \$25 and \$30 for much of the first quarter of 2016. Oversupply concerns and demand uncertainty had previously subdued oil prices, and whilst both themes remain pertinent, the former was somewhat addressed by OPEC, firstly in September when the cartel announced an agreement in principle, and then again at the end of November 2016 when it agreed its first supply cut in eight years. Saudi Arabia and its Gulf allies accepted large production cuts whilst Iran agreed to freeze output. Led by Russia, an eclectic consortium of non-OPEC nations ranging from Mexico to Brunei agreed to curb output as well to compound the effect. The importance of this joint accord was underlined by the rise in Brent on the back of the announcement, rallying eight per cent. Strategically, the decision marked a significant departure from the "market share retention" strategy adopted two years previously, when a conscious decision was taken to maintain output in a falling market. Looking ahead, forecasted robust demand growth in 2017 – driven primarily from the Far East – is widely expected to bring the market into a supply deficit for the first time in several years, assuming full OPEC compliance to its proposed quotas. In China, the liberalisation of the refining sector, falling domestic production and opportunistic crude purchasing for strategic reserves proved supportive for the oil prices in 2016 and require careful monitoring going forward. The response of US tight oil production to the OPEC
decision could also prove an important bellwether in 2017. A longer-term price recovery will be predicated on the ability of the supply shortfall to significantly draw down still sharply elevated global oil inventory levels. The World Bank's forecast for oil in 2017 is \$55/bbl and \$59.90/bbl in 2018.
The global oil and gas industry remained subdued in 2016 due to the oil price with limited expenditure in oil exploration and relatively few major discoveries. Wood Mackenzie estimated in mid-2016 that lower oil prices would see roughly \$1 trillion cut from planned spending on exploration and development in
2015–2020 with a consequent effect on production growth. The Super Majors appear to be focusing on gas with BP purchasing gas assets in Senegal and Mauritania in December 2016 following the completion of Royal Dutch Shell's acquisition of BG Group in February 2016. By the end of 2016, the mood within the global oil and gas industry appeared to be more optimistic following OPEC's decision to cut production, with most analysts predicting a gradual and cautious increase in investment across the sector as oil prices rise.
UK equity markets ended the year higher, with the FTSE 100 up 11 per cent and the FTSE 250 up 3 per cent. UK markets had a weak start to the year resulting from global growth concerns but they became increasingly volatile following the 'Brexit' vote in June. The immediate reaction to the vote saw equities falling significantly lower, particularly those with exposure to the UK economy as recession fears set in. However, due to the significant devaluation of Sterling, UK equities ultimately rose and managed to recover most of their losses by October. Overall, given the FTSE 100's exposure to US dollar earning companies and large multi-nationals, the FTSE 100 outperformed the more domestically focused FTSE 250. In absolute terms, whilst the FTSE 100 closed the year 11 per cent higher, on a US dollar basis, the index actually ended lower.
Towards the end of the year, the election of Donald Trump, whilst a shock to financial markets, was a positive catalyst as markets reacted favourably to potential Trump policies around growth and fiscal stimulus. Bond markets fell sharply while the US dollar rallied to 14-year highs, amidst a surprisingly positive outcome for equities driven by investment into more cyclical stocks, particularly in the Natural Resources, Industrial and Financial sectors. The FTSE 350 Oil & Gas sector outperformed the wider market, closing the year up 37 per cent. Tullow shares added 87 per cent and closed at 310p reflecting a resurgence in sentiment after
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a weak 2015 which came alongside the upward trajectory of the oil price.
Economic performance in Africa in 2016 was mixed with non-resource-rich economies performing well and resourcedependent economies like Nigeria and Angola struggling. Overall, Africa faced some of its lowest growth over the past 20 years but cautious optimism about the world economy, domestic political responses to low growth and recent rises in the oil price see most commentators forecasting improved growth in 2017. Growth remains highest in East and West Africa and lowest in South and North Africa. In Ghana, the NPP won the 2016 national elections and His Excellency Nana Akufo-Addo took office as President on 7 January 2017. In Kenya, national elections will take place in August 2017.
| Our strategy | 14 |
|---|---|
| Operations review | 24 |
| Governance & Risk Management | 40 |
Tullow is a leading independent exploration and production company primarily focused on Africa and South America. Our business model shows the parts of the Group that work together to run our business and create value. The skills, experience and reputation we call upon across the seven elements of our business model are what we believe set Tullow apart from its peers.
We create value in two simple ways: we find oil and we sell oil. To achieve this we must execute exploration campaigns, deliver selective development projects, maintain our production and ensure we are suitably financed through a mix of diverse funding options and portfolio management. These elements are the basis of our exploration-led strategy which is explained on page 26.
The skills, experience and reputation we call upon across the seven elements of our business model are what we believe set Tullow apart from its peers.
Our business model addresses the fundamentals that we must have in place to manage our risks and help us deliver our strategy. These include: sustainable operations by protecting our people, communities and environment; high standards of governance coupled with strong and effective risk management; an engaged, multi-disciplined, diverse and entrepreneurial team; and making a positive and lasting contribution where we operate.
Element of business model Our key strengths and activities 2016 progress
Exploration & Appraisal Execute high-impact, near-field E&A programmes
Safely deliver selective development projects. All major projects and production operations focus on increasing cash flow and commercial reserves
Continually manage financial and business assets to enhance our portfolio, replenish upside and support funding needs
Achieve safe and sustainable operations, minimise our adverse environmental and social impacts, and achieve high standards of health and safety
Achieve strong governance across all Tullow activities and maintain an appropriate balance between risk and reward
Build a strong, unified team with excellent commercial, technical and financial skills and entrepreneurial flair
Create sustainable, transparent and tangible benefits from the development of oil in host countries
| Our key strengths and activities | 2016 progress |
|---|---|
| • Ninety per cent of Tullow's 1.2 billion boe commercial reserves and contingent resources are low-cost supply oil assets, which we discovered ourselves • High-graded portfolio of highly prospective acreage, ready for when market returns • Achieving more with less investment, limiting capital exposure through lower equities and targeted carries from partners |
52,937 SQ KM of new acreage in Zambia |
| • Competitive industry operating costs, averaging \$14/boe across the Group, with the ability to achieve operating expenditure of around \$8/boe in Ghana • Ability to handle large-scale complex development projects on time and on budget • Expertise to manage crisis situations with seamless transfer to manageable projects |
71,700 BOEPD net production* |
| • Free cash flow generative, with clear path to paying down debt • Sufficient liquidity to protect us through further oil price downturns • Ability to flex capital expenditure commitments • Commercial attractiveness of Uganda asset proven through farm-down delivery • Prudent hedging strategy, protecting us from oil price volatility • Strong, long-term relationships with banks |
FARM-DOWN of Ugandan assets to Total under way |
| • Top quartile industry occupational health and safety performance • Committed to not exploring for or exploiting oil in World Heritage Sites • Signatories of the Voluntary Principles of Security and Human Rights • Committed to respectful and proactive engagement with affected communities and the swift resolution of grievances |
ZERO Lost-Time Injuries |
| • Risk management process embedded in the business from Board to field operations • Integrated Management System (IMS) ensuring one set of policies, standards and procedures that all staff and contractors follow • Zero tolerance of bribery and corruption across the business and supply chain |
PROGRESS to embed IMS continues |
| • Efficient team, with clear lines of responsibility and accountability across the business • Strong focus on performance management, ensuring delivery of business plans and core strategy • Technical expertise retained to deliver large-scale complex projects; and focused and highly prospective exploration programme • Exceptional share award rewarding employees' commitment and engagement |
40 % reduction in G&A |
| • Strong and deep relations with core African host nations based on respect and delivery • Committed to building capacity among our host nascent oil industries • Track record for delivering on local content and localisation commitments |
\$1 BN total socio-economic contribution |
* Includes 4,600 boepd insured barrels from the Jubilee field
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Our strategy has shown Tullow's resilience during the recent industry downturn and demonstrates our flexibility to oil price volatility.
Strategy in action: The fall in oil prices since mid-2014 saw us reduce our exploration expenditure but we have made this investment work harder, focusing on targeted drilling, seismic acquisition in key prospective areas and replenishing our prospect inventory. In 2016, we continued low-cost exploration activities in the South Lokichar Basin in Kenya and management estimates that gross mean recoverable resources increased to 750 mmbbls. Exploration activity recommenced in December to further underpin the discovered resource base and close the gap towards the basin's upside of 1 billion barrels.
Future plans: Exploration is fundamental to our growth strategy. Lower industry costs, carries for our share of costs by JV partners and appropriate equity interests enable us to maximise a constrained budget and maintain a meaningful exploration and appraisal programme. In 2017, Tullow plans to drill the exciting Araku prospect offshore Suriname and conduct seismic campaigns in Mauritania, Kenya, Ghana, Jamaica, Uruguay and Guyana.
Strategy in action: Our production was enhanced in 2016 with the addition of the TEN field, offshore Ghana. With the Jubilee and TEN fields, we now have two young assets in Ghana which have a low cost of supply compared to other fields globally. These fields together with a prudent hedging policy will provide a solid revenue base for our business, even if oil prices remain low in the short to medium term.
Future plans: Through the assets we have onstream today, our production profile has potential to reach in excess of 100,000 bopd net to Tullow from the early 2020s, delivering substantial cash flow. We also plan to further reduce the underlying operating cost of each barrel produced in Ghana through the synergies in operating two offshore fields.
Strategy in action: Tullow has a focus on continued cost management, and the Group is on track to deliver G&A cost savings in excess of its \$500 million target. While some budget reductions are a result of lower industry costs, a large proportion of savings can also be attributed to thinking innovatively and adapting our processes to be more efficient.
Future plans: Tullow will remain disciplined in terms of its budgeting, capital allocation and savings realised from more efficient ways of working. The Group is committed to retaining its cost-conscious approach, even when oil prices recover.
Strategy in action: In 2016, Tullow made good progress to divest and exit/relinquish its Norwegian assets and all deals are expected to complete by April 2017. In early 2017, Tullow agreed to farm-down to Total a substantial portion of its Uganda assets for a total consideration of \$900 million, leaving Tullow with an 11.76 per cent interest in the upstream, which we expect to reduce to 10 per cent once the Government of Uganda formally exercises its back-in right.
Future plans: In 2017, we will focus on completing the farm-down of the interest in our Uganda asset. Tullow's high equity levels in parts of our asset base also present further future portfolio management opportunities.
Strategy in action: We selectively develop the oil we find, focusing on development projects that are economically viable and will return sustainable future cash flows. The TEN Project, a large complex development offshore Ghana was delivered on time and on budget in August 2016. Further progress on the Kenyan and Ugandan developments was achieved in 2016 and significant steps have been taken in both countries to progress the projects and commence Front End Engineering Design (FEED) in 2017.
Future plans: The opportunity to develop the significant resources discovered in Kenya and Uganda is a major part of Tullow's strategy. These low cost developments make them very competitive and commercially viable, even at low oil prices.
Strategy in action: As and when surplus cash is generated, cash is reinvested into additional operational activities, used to pay down debt or returned to shareholders. Following first oil from the TEN fields, Tullow started generating positive free cash flow in the fourth quarter of 2016.
Future plans: The Board's main priority is to deleverage the business and to achieve our policy of having less than 2.5 times net debt to Adjusted EBITDAX. We are pursuing multiple paths to achieve this objective, including organic repayment of debt from free cash flow; portfolio management; as well as other financing levers available.
The Group's progress against its corporate scorecard is tracked to assess our performance against our strategy.
The scorecard is made up of a collection of key performance indicators (KPIs) which indicate the Group's overall health and performance across a range of operational, financial and non-financial measures.
The scorecard is central to Tullow's approach to performance management and the 2016 indicators were agreed with the Board. Each year, targets within the scorecard may change to reflect the most material strategic objectives and
associated risks the Group faces, as well as measures to deliver on the longer-term strategy of the Company. Tullow's performance against the scorecard is tracked and reviewed at quarterly performance management meetings, which are attended by Executive Directors and Senior Leaders. The Group's ongoing performance is cascaded quarterly to staff through management briefings and internal communications.
The Group scorecard is used to determine Executive Directors' and employees' performancerelated pay to ensure that all areas of the business are driving towards the same goals. Executive Directors' and Vice Presidents' performance is judged solely on the delivery of the targets set in the Group scorecard, whereas the remainder of the permanent employees' bonuses are based on a combination of individual and Group performance. In April 2016, a decision was taken to increase the Company performance element of the Employee Bonus Plan from 20 per cent to 30 per cent for all employees in this plan, which is the majority of our employees. This change is designed to encourage more collaborative and team-based working, and reinforce that all employees contribute to the Group's overall performance.
Each objective measured has a percentage weighting, and financial and production indicators have trigger, base and stretch performance targets. As reflected in the adjoining table, in 2016, Tullow's overall performance was 38.8 per cent. Although Tullow was the best performer in our peer group by some margin in 2016, the 'relative' Total Shareholder Return (TSR) tracks our performance over a three-year period and therefore we remain below the median and score nil of the possible score of 50 per cent. However, the delivery of the majority of remaining targets reflects strong performance in maintaining liquidity, sustaining cash flows, operating safely, reducing our costs and overall operational delivery. More detailed discussion on each KPI begins overleaf.
Remuneration report 80
Ensuring appropriate financing is in place to support the Company's growth strategy by ensuring we have sufficient liquidity to meet our capital commitments as well as continuing to invest in projects and assets that will generate future value.
Two key targets make up this KPI: ensuring funding capacity for 2016 and determining a longer-term strategic solution to deleverage and rebase our balance sheet. The first target includes maintaining liquidity through the biannual redetermination of our Senior Reserves Based Lending (RBL) debt facility; extending the Rolling Corporate Facility by one year; and amending the gearing covenant. The second target focuses on deleveraging and rebasing our balance sheet.
Funding capacity was achieved by securing a year's extension to our Corporate Facility, amending the financial covenant under the RBL and Corporate Facility and the issuance of \$300 million convertible bonds. Positive free cash flow generation in Q4 has begun the gradual deleveraging process. The farm-down of our Uganda assets will fully fund our future capital commitments associated with this project, once the deal is complete.
FACILITY HEADROOM & FREE CASH AT YEAR END \$1 BN
Production generates high-margin annual cash flow helping us to invest in future exploration and developments and repay debt. Setting production targets ensures we maximise revenues and achieve ongoing liquidity.
Our trigger target of 77,300 boepd pays 0%; our base target of 81,400 boepd pays 50%; and our stretch target of 85,300 boepd pays 100%.
2016 production was 71,700 boepd, which includes the 2016 net lost production covered by insurance, equating to 4,600 boepd. Our KPI for production therefore achieved no payout, due to the Jubilee turret issue and the slower ramp up of production at the TEN fields.
WORKING INTEREST PRODUCTION 71,700 BOEPD
Underlying cash operating costs represent the cost to Tullow for each barrel of oil produced. The lower the cost, the higher the margin Tullow receives when the oil is sold. Underlying cash opex is impacted by industry costs, inflation, Tullow's fixed costs and production output.
Our trigger target of \$16.5 underlying cash opex/boe pays 0%; our base target of \$15.7 opex/boe pays 50%; and our stretch target of \$14.9 pays 100%.
2016 operating costs were \$14.3 per boe (including insurance payouts), achieving the maximum payout available. The expected insurance payout for operating costs relating to the Jubilee turret issue is \$31.8 million.
Our general and administrative costs are the overall running costs of the business that support our operational activity. The Net G&A represents Tullow's corporate costs. Throughout the last two years we have worked hard to streamline these costs and achieve a fit for purpose G&A budget.
The trigger target of \$147 million pays 0%; our base target of \$127 million pays 50%; and our stretch target of \$100 million pays 100%.
2016 Net G&A was \$116.4 million, achieving a 0.9% payout of the 1.25% allocation based on a sliding scale.
We must manage capital investment efficiently to reflect an oil price which may remain low in the short to medium term and provide the investment required to grow and sustain our business, supporting development costs for major projects, exploration campaigns and infill drilling programmes.
The trigger target of \$1.1 billion pays 0%; and the stretch target of \$942 million pays 100%.
2016 capex was \$857 million (net of the insurance payout), overachieving the stretch target of \$942 million and therefore receiving 100% payout.
Safe and sustainable operations mean we protect people and our facilities as well as the communities and environment that may be affected by our activities. It ensures Tullow operates safely and efficiently while maintaining a good corporate reputation.
Tullow's safe and sustainable operations are measured by three targets: process safety, focused on reducing process safety events and making improvements to our asset integrity; occupational health & safety focused on Lost Time Injury Frequency (LTIF) reduction and malaria prevention; and sustainability, including metrics focused on environmental and social performance.
In 2016 there were no Tier 1 or Tier 2 incidents. The Jubilee Asset Integrity improvement plan is on schedule. The LTIF rate was zero, beating the stretch target of 0.24. There were no serious malaria cases reported. There have been no significant work disruptions reported in 2016. Overall the safe & sustainable KPI achieved 4.1% out of a maximum 5% allocation.
* Incident frequency per million manhours
Trend
The TEN Project represented the majority of Tullow's capital expenditure for both 2015 and 2016 and completing it not only demonstrates our capability to deliver large scale, complex projects but also increased production revenues, enabling the business to organically deleverage through free cash flow.
This KPI was based on the following targets: timing of achieving first oil; ramp-up of production; production attainment; and operability. These targets all reflected an equal weighting of the maximum score of 5%.
First oil was achieved in August 2016; ramp up production was 5.5mmbbls; the capacity of the FPSO has been successfully tested at an average rate of over 80,000 bopd in 2017; systems are operational and commissioning is ongoing. The TEN project ranks in the top 10% of global projects for both schedule delivery and capex budget (per Independent Project Analysis (IPA)). A score of 4.5% out of the maximum 5% has been given.
Tullow's basin-opening discoveries in Uganda and Kenya have discovered a new oil province which has the potential of being a 2.45 billion boe resource. Monetising these discoveries through development and/or portfolio management is a fundamental part of Tullow's strategy.
This KPI is comprised of the following targets: implementing a material transaction on our East Africa portfolio; maintaining East Africa development for Final Investment Decision by the end of 2017; and presenting Kenya Early Oil Pilot Scheme Investment Proposal.
The farm-down of our Uganda assets to Total was announced in early 2017. Also in Uganda eight production licences were awarded; the pipeline is progressing; upstream and pipeline FEED are commencing in 2017; and upstream ESIA scoping studies are approved. In Kenya, our licences have been extended; water injection testing has commenced; and the Kenya Early Oil Pilot scheme has been approved by the upstream partners. Overall, this KPI achieved 4.5% out of the potential 5% allocation.
Value creation from converting discovered resources into reserves from material, low-cost, high-return oil exploration with clear routes to commercialisation.
This KPI is made up of the following three targets: accessing material acreage positions; progressing quality prospects; and discovering predicted risked volumes through exploration.
Two new licences in Guyana and Zambia were signed. Thirteen quality prospects were progressed, across Kenya, Namibia, Norway, Suriname and Mauritania. In Norway, the Cara discovery and the Wisting appraisal well added a combined P50 resource estimate of approximately 41mmboe net. Overall, the exploration KPI achieved 3.4% out of the 5% allocation.
Delivering an organisational strategy that results in efficient ways of working and effective governance is key to delivering against our overall Company strategy and maintaining engaged employees.
This target is made up of: organisational efficiency and effectiveness; diversity; and ethics & compliance. The targets include: fully implementing the Integrated Management System (IMS); running an employee feedback survey; ensuring key risks are effectively managed and monitored; improving the effectiveness of SAP; progressing the diversity strategy; and demonstrating delivery against a new Ethics & Compliance scorecard.
Highlights from the progress against this KPI include: IMS implementation on track; the employee survey ran with high participation and action plans were developed to address feedback; all key risks have controls in place to manage them, and are monitored quarterly; all recommendations from an external audit on SAP effectiveness have been implemented; aspirational diversity targets have been agreed and senior leadership engaged; and an Ethics & Compliance e-learning module has been rolled out. Overall, this KPI scored 4.1% out of a 5% allocation.
Our strategy is to build long-term sustainable value growth, leading to substantial returns to our shareholders.
If median TSR performance is achieved, 25% of the 50% award vests; if upper quintile performance is achieved, 100% of the 50% award vests. TSR is based on performance over the 36 months ended 31 December 2016.
Tullow's share price closed 97% up from 4 January when the share price was 165.7p. While this annual performance puts Tullow in the upper quintile of our peer group, because TSR is measured on a rolling three-year basis, Tullow's performance in this timeframe was below the median range, and therefore this KPI has no payout. Over the 36-month period, Tullow experienced negative TSR of 68% compared to a median negative of 26%.
Stretching financial, operational and organisation targets are included in the 2017 scorecard, as well as measures to deliver on the longer-term growth strategy of the Company.
A summary of the targets is listed below, and the KPIs will be disclosed in the 2017 Annual Report:
We aim to create sustainable value across the oil and gas life cycle. We do this by paying fair and appropriate amounts of tax, being transparent in the payments we make to governments, creating local employment and identifying opportunities for local businesses within our supply chain.
| Production | 2016 |
|---|---|
| Once a field is producing, investment will focus on sustaining and extending plateau production. This involves general maintenance, steps to protect the integrity of the field and additional infill or near-field exploration drilling. |
\$857 M invested |
| The main economic value to host governments is from production revenues and income taxes on Tullow's profits. |
\$438 M paid to governments |
| Goods and services from local businesses and expertise from the local workforce are required to run operations, maintain production and develop fields further. Tullow continues to invest in capacity building and training to grow levels of local employment and business participation in the supply chain. |
\$337 M spent with local suppliers |
| An agreement between Tullow and the government determines how and when Tullow and its Joint Venture (JV) partners can recover the significant investment that has been made during the exploration, appraisal and development phases. Typically, the oil company's share of production or revenue is higher in the earlier years of production as costs are recovered in the form of allowable deductions against income tax or as an allocation of production, commonly known as 'cost oil'. |
67,100 BOPD |
| 20-50 YEAR PERIOD |
|
2016 demonstrated that Tullow is a capable operator that can deliver projects of material size and scale.
2016 was a real test of the strength and resilience of our operational and EHS teams. This was most evident in Ghana with the delivery of TEN first oil on time and on budget and the Turret Remediation Project, where a very significant incident was safely and smoothly transitioned into a remediation project. Both projects have been executed incredibly well, against clear milestones and deliverables and with exceptional EHS records.
In Uganda, we are pleased with the farm-down of our assets to Total, which underlines our commitment to Uganda for the long-term through our retained 11.76 per cent stake in the upstream, which we expect to reduce to 10 per cent when the government backs in. The agreement of this deal followed significant momentum in 2016 with the Government of Uganda's decision on the routing of the export pipeline and issuance of production licences, milestones which serve to accelerate the Lake Albert development project. All partners are aligned on making rapid progress, for both the upstream and pipeline FEED, to commence in early 2017 with a target of reaching FID by the end of 2017. The extensive well database and work completed to date provide significant confidence in the discovered resources allowing us to move forward at a time when industry costs are at a historical low.
In Kenya, an Early Oil Pilot Scheme (EOPS) proposal was sanctioned by JV partners' boards in order to provide the technical, logistical, social and political insights into what will be required for
"2016 was a real test of the strength and resilience of our operational and EHS teams. On the Turret Remediation Project, I am very proud of the teamwork, adaptability and professionalism shown by all teams as they came together to respond to and manage this unprecedented event."
Paul McDade Chief Operating Officer
the Full Field Development (FFD). While the scheme will produce a modest 2,000 bopd, EOPS will mark Tullow's first oil production from our decade-long presence in East Africa.
Projects of this scale are rarely delivered on time and within budget. It was a massive undertaking but the team's project delivery was seamless. The Independent Project Analysis (IPA) ranked the TEN Project in the top 10 per cent of global projects for both schedule and capex budget.
It signified another historic moment for Ghana, which now has a second field on stream, and demonstrates real progress for its oil and gas industry. For Tullow, the successful execution of the TEN Project has cemented our reputation and track record for delivering large-scale, complex projects. Projects such as Jubilee and TEN are normally executed by the industry majors, so this achievement demonstrates to our host governments that Tullow is a capable operator that can deliver projects of material size and scale.
The production ramp-up from TEN, since first oil, was slower than initially planned, after which production steadily ramped up and in January, the FPSO was tested above its capacity of 80,000 bopd. Systems are now operational and commissioning is nearing completion.
Due to the drilling moratorium imposed as part of the ongoing ITLOS maritime border dispute, drilling of the remaining development wells cannot be completed, so 2017 production will rely on the existing 11 wells which are expected to deliver around 50,000 bopd. A judgment from ITLOS on the boundary is expected to be handed to the Governments of Ghana and Côte d'Ivoire at the end of 2017, and we hope that we will be able to start drilling again in early 2018. While the ramp-up of production has been slower, the data collected to date underpins both the expected oil in place and reserves in the Ntomme and Enyenra fields.
While no one would have wanted this event to happen, I am very proud of the teamwork, adaptability and professionalism shown by all teams across Tullow as they came together to respond to and manage this unprecedented event and transform it into what we now refer to as the Turret Remediation Project. This was a very significant and complex undertaking which has again demonstrated the expertise and quality of our personnel and the effective way in which they work to support each other. When the interim spread mooring of the FPSO completes in February 2017, the tugs will be removed, significantly reducing the operational complexities that the team had to manage before.
The next phase of the project will involve modifications to the turret systems for long-term spread moored operations. The assessment of the optimum long-term heading continues, to determine if a rotation of the FPSO is required. Detailed planning for this continues with JV partners and the Government, with final decisions and approvals expected in the first half of 2017 and work expected to be carried out in the second half of 2017.
The Early Oil Pilot Scheme will produce around 2,000 bopd, from five existing Ngamia and Amosing wells, which will be transported 1,107 km from Turkana to Mombasa by road to be stored in existing storage tank facilities. First exports are being targeted for the second half of 2017.
Transportation of oil by road is not unique to Kenya. Oil trucking is also widely practised in oil production projects in many locations around the world such as the United States, India, Russia and Kazakhstan. The most relevant project of equivalent scale and terrain is arguably the Cairn India development of the Mangala field in Rajasthan. This initially started by exporting oil by truck, before moving to a 670 km-long pipeline.
EOPS has a clear strategic rationale, which is to unlock the potential and de-risk the technical and non-technical aspects of the Full Field Development (FFD). These include gaining further insight into the subsurface allowing us to continue to optimise our development plans and working together with the Government of Kenya on the negotiation and delivery of key agreements that are required for upstream development. We will also have the opportunity to develop local content both for upstream operations, including the required logistics services.
There will be many challenges ahead in 2017, as there were in 2016. However, the hard work that we have done over the last two years in reorganising the Company, making sure we are more efficient in how we manage the business and in making some difficult business decisions, leaves us in great shape to face these challenges.
In Ghana, we must complete the work on the Jubilee FPSO and progress the Greater Full Jubilee field development; at TEN we will work to maximise production from our existing wells and prepare to restart drilling post ITLOS. In Uganda, we will be working to progress towards FID, whilst in Kenya we will be progressing the Early Oil Pilot Scheme and integrating the new well results in our full field development plans.
It will be a significant year for our non-operated business as we continue to balance investment with production and cash flow. This business is important because the 22,000 bopd comes from over 500 wells across five countries so it provides our production profile with resilience and helps spread risk. These West African and our North Sea assets are mature fields and are, in most cases, beyond plateau. We are working with our JV partners to sustain the life of the fields and maintain production through infill drilling programmes; however, this requires ongoing investment.
We will continue to balance our investment plans with our priority to deleverage the business and create financial capacity, which will of course be affected by future oil prices. Regardless of when we decide to ramp up investment across the portfolio, we know that the barrels are still in the ground, so production is deferred, not lost, and can be produced at a potentially higher oil price in future.
In East Africa, Kenya's Early Oil Pilot Scheme will be an important project to progress, as will completing the deal on the farm-down of our assets in Uganda, working alongside the JV to progress Uganda to FID, after over ten years of hard work. In Ghana, we are looking forward to demonstrating that our team has the ability to move from 'capital project' mode to a steady operating mode, delivering world-class performance in both safety and cost.
As we deleverage our balance sheet and oil prices stabilise at higher levels, I look forward to returning to exploration and growth. The exciting Araku well in Suriname will be the first step in again demonstrating the value that exploration can deliver.
Finally, it is an honour that I have been selected by the Board to take over as CEO at the April AGM. Taking the helm of a company that Aidan has built up over the last 31 years to be Africa's leading independent oil company is a responsibility that I am very much looking forward to taking on. We have a great team, world-class assets and a reputation for being focused on shared prosperity, which is a strong foundation that I will build on.
Capital spend has significantly reduced across the industry, with exploration and appraisal budgets delivering the biggest adjustments. Angus McCoss, Tullow's Exploration Director, explains how Tullow continues to create an effective and impactful E&A programme with lower levels of investment.
Exploration continues to be Tullow's long-term way of investing to secure new, valuable and material supplies of monetisable oil, to sustain and grow our Company far into the future. Exploration and production are naturally cyclical, and recently we have also been impacted by external factors, particularly the weaker oil price. We have lean years punctuated by occasional wildcat breakthroughs and higher-capex years when we have busily and successfully drilled out and appraised our new basins. In exploration that means cycling between years of prospecting at the seismic workstation and years when drilling is a more significant part of our plans. It is vitally important to the Board that exploration remains an integral and adaptive part of our strategy.
Recent Wood Mackenzie research has shown that global upstream capital spend from 2015 to 2020 has been reduced by 30 per cent or c.\$1 trillion, including exploration spend. This reduced investment has prompted a debate on whether the downturn in exploration investment will lead to a renewed supply shortage and higher prices in the long term or whether US shale resources and slowing demand growth will cause oil and gas prices to remain weak.
At Tullow, we believe that exploration is an essential value creation tool for the industry, and that Tullow and our peers will need to continue to find new competitive supplies of low cost oil in years to come.
"At Tullow, we believe that exploration is an essential value creation tool for the industry, and that Tullow and our peers will need to continue to find new competitive supplies of low-cost oil in years to come."
Angus McCoss Exploration Director
Our exploration and appraisal spend has come down from \$800 million a few years ago, to closer to c.\$80 million for exploration in 2016. That has led to a renewed focus away from complex wells, towards an emphasis on high-quality seismic and more time to apply rigorous geological methods to identify our best prospects. This allows for a better understanding of the geology and prospectivity of a licence before committing to drill, which should help increase our chance of exploration success. We continue to avoid complex wells and we apply strict geological, capital/risk and commercial filters so that we remain focused on high-margin oil plays in onshore rifts, simple offshore geologies and settings, and our key areas of production.
Going forward, with our reset and refocused exploration strategy and our experienced prospectors, we believe we can continue to do more with less and limit our capital exposure through lower equities and targeted carries from Partners.
We have focused our activity in 2016 on four main areas: exploring in the South Lokichar and Kerio Valley Basins in Kenya, where management estimates that gross mean recoverable resources increased to 750 mmbbls; acquiring and evaluating data across our South America acreage, including 3D seismic acquisition in Suriname; entering new areas such as Zambia, adding to our onshore rift basin acreage; and further
right-sizing our portfolio through farm-downs in South America and divestment of our Norwegian assets. A full review of our 2016 activity can be found on pages 28 to 31.
We remain very enthusiastic about the significant exploration potential of this exciting area. We continue to watch the results of the significant Liza and more recent Payara-1 discovery in the Guyana-Suriname Basin with great interest because of its close proximity to Tullow's Kanuku and Orinduik licences. The next step for both our blocks is the acquisition of 3D seismic over this area in 2017, with a view to preparing prospects for drilling in 2018/19.
We are more advanced in Suriname following the acquisition of 3D seismic over Block 54 in 2016 where the most exciting prospect identified to date on our 3D seismic is Araku. We are preparing to drill in the second half of 2017 and it has been significantly derisked through excellent seismic work completed to date.
In both Guyana and Suriname, Tullow's blocks are on the shelf in c.100 m to 1,000 m of water, making drilling and possible subsequent development much lower cost compared to operations in deeper water. The Araku well, for example, is forecast to cost around \$14 million net to Tullow, as we take advantage of significantly lower rig rates during the downturn and simple well designs.
Africa remains Tullow's heartland and we have teams focused on Tullow's acreage across the continent, focusing on three key areas. The first is near-field exploration to sustain production and increase reserves in our main producing assets in
West Africa; the second is dedicated to increasing discovered resources in Kenya; and our New Ventures team is working on activity in new and existing frontier areas such as Mauritania, Namibia and most recently Zambia.
In Kenya, we recommenced exploration in the fourth quarter of 2016 with an initial programme of four wells in the South Lokichar Basin with the potential to extend this by a further four. These are low cost wells, costing around \$4–6 million net to Tullow per well. The team has identified significant upside in the basin, particularly in the north around the Etom-2 discovery and that area was tested with the successful Erut-1 well in January 2017 which extended known hydrocarbons to the far north of the Lokichar Basin. The next wells planned are those in the Ngamia and Amosing fields, which will target undrilled volumes, with an aim of extending the size of these existing discoveries. After those are completed, we will continue further exploration drilling in the northern part of the basin.
The programme in Kenya is aiming to increase management's estimate of gross mean recoverable oil volumes from 750 million barrels towards 1 billion barrels, as we prepare for our Kenya development FID in 2018.
Tullow has a low-cost production portfolio ranging from \$20 to \$40/bbl across its full life cycle which enables us to generate strong margins, even at a low oil price. The high quality of our portfolio of strongly oil-focused exploration assets backed up by our talented team sets us apart from our peers. Of the oil we currently produce, 90 per cent has been discovered by teams at Tullow, working together across all disciplines. Looking ahead, we have strategic options to discover more oil ourselves that will further underpin Tullow's value and provide growth opportunities for our stakeholders.
Drilling operations in the South Lokichar basin, Kenya
Map showing Tullow acreage position offshore Guyana and Suriname
In February 2016, an issue with the turret bearing of the Jubilee FPSO Kwame Nkrumah was identified resulting in the need to implement new operating and offtake procedures, utilising tugs, a dynamically positioned shuttle tanker and a storage tanker. After a period of planning, Tullow and its JV Partners established that the preferred long-term solution to the turret issue is to convert the FPSO to a permanently spread-moored vessel, with offtake through a new deep-water offloading buoy. The first phase of this work, involving the installation of a stern anchoring system, is expected to be completed in February 2017, after which the tugs maintaining the FPSO on heading control will no longer be required.
The next phase of the project will involve modifications to the turret systems for long-term spread-moored operations. In addition, the assessment of the optimum long-term heading continues, in order to determine if a rotation of the FPSO is required. Detailed planning for these works continues with the JV Partners and the Ghanaian Government, with final decisions and approvals being sought in the first half of 2017. Work is expected to be carried out in the second half of 2017, with an anticipated facility shutdown of up to 12 weeks, although work continues to optimise and reduce the shutdown period.
The final phase of the project will involve the installation of a deep water offloading buoy which is planned to be installed in the first half of 2018. This will remove the need for the dynamically positioned shuttle tanker and storage tanker and the associated operating costs. This phase of work also requires approval of both the Government of Ghana and the Jubilee JV Partners.
The capital costs associated with the remediation works, the lost revenue resulting from the shutdown period and the increased operating costs are expected to be covered by the Joint Venture Hull and Machinery insurance policy and Tullow's corporate Business Interruption insurance policy.
Full-year 2016 production from the Jubilee field averaged 73,700 bopd
| Countries | 7 |
|---|---|
| Licences | 54 |
| Acreage (sq km) | 16,185 |
| 67,100 BOEPD* 2016 net production |
|---|
| 553.5 MMBOE Total net reserves & resources |
| \$1,270 M 2016 net sales revenue |
| \$694 M 2016 net investment |
* Including the impact of insured barrels from the Jubilee field, West Africa working interest production was 71,700 boepd.
(net: 26,200 bopd). In addition, under Tullow's corporate Business Interruption insurance the Group received insurance payments which equates to 4,600 bopd of net equivalent production. Tullow expects 2017 production from the Jubilee field to average 68,500 bopd (net: 24,300 bopd), assuming 12 weeks of shutdown associated with the next phase of remediation works. Tullow's corporate Business Interruption insurance policy is expected to reimburse Tullow for the equivalent of 12,000 bopd of annualised net production for this shutdown period, increasing Tullow's effective net production
In December 2015, Tullow submitted the Greater Jubilee Full Field Development Plan to the Government of Ghana. This project, to extend field production and increase commercial reserves, was redesigned given the current oil price environment to reduce the overall capital requirement and allow flexibility on the timing of capital investment. Tullow has sought to address comments made by the Government of Ghana on the plan and, in light of the current Turret Remediation Project, approval of the plan by the Government of Ghana is now expected in mid-2017.
to around 36,300 bopd in 2017.
In May 2013, the Government of Ghana approved the TEN Plan of Development, Tullow's second major operated deep-water development project. The project remained on schedule and on budget throughout the development phase with first oil delivered in August 2016. Net capital expenditure by Tullow in 2016 was approximately \$600 million, in line with the Group's forecast.
Following first oil, the oil production, gas compression/injection and water injection systems were commissioned and are operational. In early January 2017, the capacity of the FPSO was successfully tested at an average rate in excess of the design capacity of 80,000 bopd during a 24-hour flow test. Gross annualised working interest production in 2016 averaged 14,600 bopd (net: 6,900 bopd).
Production testing and initial results from the 11 wells indicate reserves estimates for both Ntomme and Enyenra
to be in line with previously guided expectations. However, due to some issues with managing pressures in the Enyenra reservoir and because no new wells can be drilled until after the ITLOS ruling, which is expected in late 2017, Tullow is managing the existing wells in a prudent and sustainable manner. As a result, Tullow expects production from TEN to be around 50,000 bopd (net: 23,600 bopd) in 2017, although work continues to evaluate ways to increase production.
Gas production from the TEN fields is currently being reinjected. The gas export line between the TEN and Jubilee developments is expected to be connected this month with gas export expected to commence later in 2017.
Proceedings at ITLOS with regard to the maritime border dispute between Ghana and Côte d'Ivoire continue, with oral hearings scheduled for this month, and a final ruling anticipated in the fourth quarter of 2017. Drilling is expected to resume in 2018 after the final ruling.
West Africa non-operated production was in-line with expectations in 2016 at 27,800 bopd net. Due to low oil prices, capital expenditure was reduced substantially across a number of these fields in 2016. While this reduced investment helps maximise near-term cash flow it does impact the rate of production decline, and as a result 2017 forecast production across the West African non-operated portfolio is expected to be around 22,000 bopd net. There is flexibility to increase capital investment in the medium term to offset production decline in these mature assets, as market conditions improve.
Full year gas production from Europe averaged 6,200 boepd net in 2016. Decommissioning operations in the UK Southern North Sea on the CMS assets are continuing on schedule and are expected to be completed in the first quarter of 2017. 2017 average net production is expected to be around 6,500 boepd.
Regional information 2016
Key offices
Countries 2 Licences 17 Acreage (sq km) 50,344
639.6MMBOE
Total net reserves & resources
\$86M
2016 net investment
Exploration and appraisal of the South Lokichar basin continued in 2016 and the initial phase was completed in the first half of the year. The success of this programme and analysis of the discoveries led management to upgrade the South
Lokichar mean resource estimate to 750 mmbo. Also in the first half of the year, Tullow expanded its exploration drilling programme in Kenya to the Kerio Valley Basin in Block 12A where the Cheptuket-1 well encountered oil shows, seen in cuttings and rotary sidewall cores. Post-well analysis is still in progress. Further exploration activities in Block 12A and Tullow's other remaining unexplored Kenyan acreage continue to be evaluated.
After identifying a number of new prospects and appraisal opportunities, drilling re-commenced in the South Lokichar Basin in mid-December 2016 with a four-well exploration and appraisal programme. The first was Erut-1, an exploration well located at the northern limit of the basin, approximately 11 km north of the Etom field. The well discovered a gross oil interval of 55m with 25m of net oil pay at a depth of 700m. The overall oil column for the field is estimated to be 100 to 125m. Pending lab results, the oil recovered from Erut-1 appears to be a typical South Lokichar waxy light crude. This well proves that oil has migrated to the northern limit of the South Lokichar Basin and has derisked multiple prospects in this area. The rig is now drilling the Amosing-6 well to appraise undrilled volumes. It will then move to drill the Ngamia-10 well, an appraisal well to the south of the Ngamia discovery well. The fourth well planned in this programme will drill the Etete prospect, a structure approximately 2 km south of the Etom field. This programme could be extended by up to four additional wells depending upon the results from these initial four wells. Tullow believes that significant upside remains across the South Lokichar Basin with the potential to increase the resource estimate to over 1 billion barrels of recoverable oil.
Good progress was made during 2016 on a standalone development in Kenya with an export pipeline to Lamu; life-of-field development costs (comprising operating
expenditure, capital expenditure and potential pipeline tariffs) are expected to be in the region of \$25 to \$30 per barrel. Preparations for the upstream development Front End Engineering Design (FEED) are under way, with FEED expected to commence in the second half of 2017. Other activity during the year included water injection trials which were successfully completed on the Amosing oil discovery in the South Lokichar Basin. Data from the trials shows the viability of water injection for development planning and a similar programme of water injection tests on the Ngamia oil discovery is scheduled to commence later this month. The Environmental and Social Impact Assessments (ESIA) scoping report and terms of reference were approved and ESIA baseline surveys are nearing completion.
Tullow and its JV Partners, Africa Oil and Maersk Oil, signed a Memorandum of Understanding in July 2016 with the Government of Kenya which confirms the intent of the parties to jointly progress the development of a Kenya crude oil pipeline. Subsequent to this, the JV Partners and the Government of Kenya are also in the final stages of negotiation of a Joint Development Agreement (JDA) which sets out a structure for the Government of Kenya and the JV Partners to progress the development of the export pipeline. This agreement will ultimately enable important studies to commence such as pipeline FEED and ESIA, as well as studies on pipeline financing and ownership.
An Early Oil Pilot Scheme (EOPS), which involves the transportation of early South Lokichar oil production to Mombasa by road, was sanctioned by the JV Partners in the third quarter of 2016. The various agreements are in the final stages of negotiations with the Government of Kenya. The EOPS will use existing upstream wells and oil storage tanks to initially produce approximately 2,000 bopd gross in 2017. The EOPS will provide important information which will assist in full field development planning.
In April 2016, the Government of Uganda confirmed its decision to route an oil export pipeline through Tanzania to the port of Tanga, providing clarity on the development of Uganda's oil resources. In August 2016, the Government awarded eight
Production Licences in the Tullow and Total operated areas. The Government of Uganda has also made significant progress on the constitution of both the Petroleum Authority to regulate the oil industry and the Uganda National Oil Company which will be the Government representative in the Uganda Joint Venture.
The first phase of the upstream ESIA has also been completed; the second phase is in progress. FEED for both the upstream and pipeline are expected to commence this month. Overall, the Government and JV Partners continue to aspire to achieve FID by the end of 2017, with first oil expected to occur three years after FID.
On 9 January 2017, Tullow announced that it had agreed a substantial farm-down of its assets in Uganda to Total. Under the Sale and Purchase Agreement, Tullow has agreed to transfer 21.57% of its 33.33% Uganda interests to Total for a total consideration of \$900 million. Upon completion, the farm-down will leave Tullow with an 11.76% interest in the upstream and pipeline projects. This is expected to reduce to a 10% interest in the upstream project when the Government of Uganda formally exercises its back-in right. Although it has not yet been determined what interests the Governments of Uganda and Tanzania will take in the pipeline project, Tullow expects its interests in the upstream and pipeline projects to be aligned.
The consideration is split into \$200 million in cash, consisting of \$100 million payable on completion of the transaction, \$50 million payable at FID and \$50 million payable at first oil. The remaining \$700 million is in deferred consideration and represents reimbursement by Total in cash of a proportion of Tullow's past exploration and development costs. The deferred consideration is payable to Tullow as the upstream and pipeline projects progress and these payments will be used by Tullow to fund its share of the development costs. Tullow expects the deferred consideration to cover its share of upstream and pipeline development capex to first oil and beyond. Completion of the transaction is subject to certain conditions, including the approval of the Government of Uganda, after which Tullow will cease to be an operator in Uganda. The disposal is expected to complete in 2017.
Tullow believes this agreement will allow the Lake Albert Development to move ahead and increases the likelihood of FID around the end of 2017.
Drilling operations at Amosing field, South Lokichar Basin, Kenya Early drilling at Jobi-Rii field, Lake Albert, Uganda
Tullow has continued to actively manage its New Ventures portfolio throughout 2016 through both licence acquisitions and farm-downs of existing acreage to optimise the allocation of exploration expenditure. Notwithstanding a lower exploration budget, Tullow continues to successfully replenish and high-grade its exploration portfolio, and believes that the portfolio should give the Group significant low-cost opportunities for the future.
New Ventures activity in 2016 also involved the continued refinement of the Group's frontier exploration portfolio and Tullow has taken the decision not to pursue its interests in Madagascar, Ethiopia, French Guiana, Guinea, Norway and Greenland and the Group has, with the exception of Norway, now exited these countries.
In June 2016, Tullow extended its East African rift play acreage through the award of Petroleum Exploration Licence 28, onshore Zambia. The 53,000 sq km block builds on Tullow's existing low-cost, core East African Tertiary rift basins, giving the Group access to three further unexplored basins. Tullow initially plans to complete geological studies, acquire a gravity survey and collect passive seismic data. If the results are positive the Group will then acquire a 2D seismic survey in the block.
During the year, there was a focus on interpreting previously acquired seismic surveys to prepare prospects in advance of making the decision on whether to drill. Encouraging oil plays have been identified in Blocks C-3 and C-10 in Mauritania and in the PEL30 and PEL37 licences in Namibia. Tullow plans to acquire a 3D seismic survey over its Mauritanian acreage in June 2017.
Tullow has continued to advance its operations in South America and plans are ongoing to drill the high impact Araku prospect (Tullow: 30%), offshore Suriname, in the second half of 2017. This prospect is a large structural trap which has a resource potential estimated at over 500 mmbo. It has been significantly de-risked by a 3D seismic survey carried out in 2015 which identified
Tullow withdrew from Ethiopia, French Guiana, Greenland, Guinea and Madagascar in 2016/early 2017.
| Countries | 9 |
|---|---|
| Licences | 31 |
| Acreage (sq km) | 186,505 |
2016 net investment
geophysical characteristics that are consistent with potential oil or gas effects in the target reservoirs. A rig is currently being sourced for the well which is expected to cost \$14 million net to drill.
In Guyana, the Group is planning to acquire 3D seismic data over the offshore Orinduik licence, awarded in 2016, and Kanuku licence which are located up-dip of ExxonMobil's Liza oil discovery. These programmes are expected to cover up to 6,000 sq km and will enable evaluation of attractive leads mapped on existing 2D seismic data.
Offshore Uruguay, a 2,500 sq km 3D seismic programme commenced in January 2017 to capture data over high-quality leads identified in Block 15 in the Pelotas Basin.
In Jamaica, following the completion of a drop core and seep study in the Walton Morant blocks that identified a live oil seep, Tullow will acquire a further 680 km of 2D seismic data before considering the acquisition of a 3D seismic survey.
The divestment of the Norway business is progressing well with two deals completed before year end and one in January 2017. Four licences, including the Wisting oil discovery, have been sold to Statoil, eight licences, including the Oda asset, have been sold to Aker BP ASA and two further licences have been sold to ConocoPhillips. A further two sales were executed in December 2016 with two separate parties. These sales, covering a further 13 licences, and which include the 2016 Cara oil and gas discovery, are expected to complete by April 2017. In aggregate, the Norway asset sales are expected to yield proceeds of up to \$0.2 billion. Once completed, the Group will no longer hold any licences on the Norwegian Continental Shelf.
In May 2016, Tullow agreed to sell a 20 per cent interest in and transfer operatorship of the Bannu West licence in Pakistan to Mari Petroleum. The Government's approval of the Bannu West transfer is nearing completion. In July 2016 Tullow received Government approval of the transfer of operatorship of Block 28 in Pakistan to OGDCL. The Group's position in Pakistan is now entirely non-operated.
1
We have continued to actively manage our financial position and end the year with a number of major achievements.
As both Aidan and Simon discussed in their statements, 2016 has been another challenging year for the oil and gas industry, including Tullow, but we have continued to actively manage our financial position and end the year with a number of major achievements. The self-help, cost reduction and efficiency programme we started in 2014 and continued through 2015 has resulted in net admin expenses being significantly lower year on year at \$116 million (2015: \$194 million), reflecting the ongoing improvements we have delivered in the way we run our business. At the end of 2014 we set a target to generate over \$500 million in cash cost savings over three years, and our 2016 results show we have achieved nearly \$300 million of that target and are on track to deliver over \$600 million in savings overall.
We have also continued to drive down our capital expenditure and during the year we reduced our capex budget from \$1.1 billion initially guided to \$0.9 billion (2015: \$1.7 billion). Moving forward we expect to see capex reduce considerably as committed spend on capital intensive projects such as TEN are now effectively complete. Looking ahead our capital expenditure is expected to be \$0.5 billion across our portfolio in 2017, but this will effectively be around \$0.4 billion as our Uganda spend will now be offset by the deferred consideration agreed in the farm-down to Total which we announced in January 2017.
Successfully agreeing the farm-down of a 21.57 per cent interest in the Uganda project to Total for a total consideration of \$900 million is a significant achievement for Tullow. The agreement will see Tullow receive \$100 million on completion,
"Looking ahead, maintaining flexibility is key to our investment plans and in 2017 we are forecasting that we will invest around \$0.5 billion across our portfolio."
Ian Springett Chief Financial Officer
another \$50 million at FID and a further \$50 million at First Oil. The remaining amount is a deferred consideration and represents reimbursement by Total of \$700 million in cash for a proportion of Tullow's past costs. The deferred consideration will be used by Tullow to fund its share of the upstream and pipeline development capex through to first oil and beyond. The agreement paves the way for this low-cost development to progress, with Total driving the project forward to a target FID at the end of 2017. It also brings important benefits to Tullow's liquidity position, through near-term cash proceeds and by effectively removing Uganda capex from our forecast spend.
We have also successfully executed five transactions to dispose of our Norway business, expected to yield proceeds of up to \$0.2 billion. The Norway exit was accomplished by understanding the types of potential buyers and repackaging our assets to suit. We have already completed three of five transactions and expect to complete the remaining two transactions in the first quarter of 2017.
Maximising our cash flow and maintaining liquidity continues to be key and our hedging programme continues to support this. The programme contributed some \$363 million to the revenue of the business in 2016, and with c.60 per cent of our production hedged at around \$60 per barrel in 2017, we are in a good position to protect future revenues and cash flows from the ongoing volatility of the oil price.
At year end, our net debt was \$4.8 billion, giving us a net debt to Adjusted EBITDAX ratio of 5.1 times. With TEN now on stream, we are generating free cash flow
and this puts Tullow in a position to begin to organically deleverage. Deleveraging remains our top priority and we will continue to pursue portfolio management and consider other tactical options to accelerate this process to take us back to within our long-term policy of less than 2.5 times net debt to Adjusted EBITDAX.
During the year we took prudent steps to manage our debt and headroom, secure liquidity, and diversify our sources of funding. We worked through two RBL redeterminations; extended the maturity of our RCF into 2018; and issued convertible bonds of \$300 million. We also raised an additional \$345 million through our RBL accordion facility which will come into effect in April 2017 and will largely offset the next scheduled amortisation. All these steps are decisive actions put in place to ensure Tullow is in the best position ahead of refinancing its RBL in 2017.
The Jubilee turret issue and subsequent remediation was an unforeseen event but I am incredibly proud of how the issue has been dealt with both operationally and financially. The insurance we have in place is an excellent reflection of Tullow's prudent financial management and, following affirmation of both Hull and Machinery and Business Interruption cover, we can continue to resolve the issue with confidence that Tullow will be expected to be made whole.
Despite these many achievements in the year, we have reported a significant loss in 2016 of \$0.6 billion. This is predominantly due to exploration write-offs associated with the Norway disposals and Uganda farm-down, goodwill impairment, provision for onerous service contracts and impairments of property, plant and equipment, triggered by lower for longer oil prices. While these non-cash items impact the income statement, our operating cash flow has remained strong and we generated \$0.8 billion of operating cash flow from our low-cost production and the benefit of our hedging programme.
Looking ahead to 2017, at a \$50/bbl oil price, we will be generating positive free cash flow, giving us a solid base to balance paying down debt but also investing in growth options for the Group. We are at an inflection point with significant committed spend behind us; we have worked hard to drive down costs; we anticipated and resolved issues well ahead of time; we protected our revenues through hedging; and we have successfully agreed an important farm-down of our Uganda assets, removing our exposure to future development capex associated with this important project once this deal completes. Having acted early and made significant adjustments to our cost base, Tullow is now in an optimum position for future growth.
Working interest production averaged 67,100 boepd, a decrease of 9 per cent for the year (2015: 73,400 boepd). Including the impact of insured barrels from the Jubilee field, working interest production averaged 71,700 boepd, a decrease of 2 per cent. The impact of first oil from the TEN fields was offset by reduced production from the Jubilee field as a result of the Turret Remediation Project, declines in UK and Netherlands gas production as well as reductions across the non-operated West Africa portfolio. Sales volumes for West African oil and European gas averaged 51,100 bopd and 8,800 boepd respectively.
On average, oil prices in 2016 were lower than in 2015. The Group's realised oil price after hedging in 2016 was \$61.4/bbl and \$41.7/bbl before hedging (2015: \$67.0/bbl and \$50.4/bbl respectively), a decrease of 8 per cent versus a 16 per cent decrease in Brent oil prices over the period. European gas prices in 2016 were lower than in 2015. The Group's realised European gas price after hedging in 2016 was 33.9p/therm (2015: 41.8p/therm), a decrease of 19%.
| Financial results summary | 2016 | 2015 | Change |
|---|---|---|---|
| Working interest production volume (boepd)1 | 67,100 | 73,400 | -9% |
| Sales volume (boepd) | 59,900 | 67,600 | -11% |
| Realised oil price (\$/bbl) | 61.4 | 67.0 | -8% |
| Realised gas price (p/therm) | 33.9 | 41.8 | -19% |
| Sales revenue (\$m)2 | 1,270 | 1,607 | -21% |
| Underlying cash operating costs per boe (\$/boe)3 | 14.3 | 15.1 | 5% |
| Exploration costs written off (\$m) | 723 | 749 | 3% |
| Impairment of property, plant and equipment, net (\$m) | 168 | 406 | 59% |
| Operating loss (\$m) | (755) | (1,094) | 31% |
| Loss before tax (\$m) | (908) | (1,297) | 30% |
| Loss after tax (\$m) | (597) | (1,037) | 42% |
| Basic loss per share (cents) | (65.8) | (113.6) | 42% |
| Operating cash flow before working capital (\$m) | 774 | 967 | -20% |
| Operating cash flow before working capital per boe (\$/bbl) | 29.4 | 35.9 | -18% |
| Capital investment (\$m)3 | 857 | 1,720 | -50% |
| Net debt (\$m)3 | 4,782 | 4,019 | 19% |
| Gearing (times)3 | 5.1 | 3.8 | 1.3 |
| Free cash flow (\$m)3 | (792) | (940) | 16% |
Including the impact of insured barrels from the Jubilee field, Group working interest production was 71,700 boepd.
Sales revenue excludes \$90 million of other operating income which represents accrued proceeds under Tullow's corporate Business Interruption insurance policy.
Underlying cash operating costs per boe, capital investment, net debt, gearing and free cash flow are non-IFRS measures and are explained later in this section.
Underlying cash operating costs amounted to \$377 million; \$14.3/boe (2015: \$406 million; \$15.1/boe). Underlying cash operating costs in 2016 includes \$32 million of insurance proceeds. The decrease of 5 per cent in underlying cash operating costs per boe was principally due to the impact of ongoing cost saving initiatives and the start-up of the TEN fields which have a low operating cost per boe.
DD&A charges before impairment on production and development assets amounted to \$449 million; \$17.0/boe (2015: \$551 million; \$20.5/boe). The Group recognised an impairment charge of \$168 million (2015: \$406 million) in respect of lower forecasts of oil and gas prices and an increase in estimated future decommissioning costs. The Group recognised an impairment of goodwill of \$164 million (2015: \$54 million) associated with the disposal of the Group's Norwegian assets.
Administrative expenses of \$116 million (2015: \$194 million) include an amount of \$41 million (2015: \$48 million) associated with a share-based payment charge. The Major Simplification Project, which was undertaken during 2015, is on track to generate savings of approximately \$600 million by mid-2018, ahead of the Company's initial target of \$500 million, with savings of approximately \$300 million having been achieved as at 31 December 2016.
During 2016, the Group recognised an income statement charge for restructuring costs of \$12 million (2015: \$41 million) relating to headcount reductions associated with the Major Simplification Project and Norway country exit. This has been presented separately from administrative expenses in the income statement.
| Exploration costs written off | 2016 \$m |
2015 \$m |
|---|---|---|
| Exploration costs written off | (723) | (749) |
| Associated deferred tax credit | 299 | 277 |
| Net exploration costs written off | (424) | (472) |
During 2016, the Group spent \$82 million, including Norway exploration costs on a post-tax basis, on exploration and appraisal activities and had written off \$58 million in relation to this expenditure. This included write-offs in Norway (\$18 million) and New Ventures costs (\$18 million). In addition, the Group has written off \$366 million in relation to prior years' expenditure primarily as a result of the farm-down in Uganda (\$248 million), the disposals in Norway (\$61 million) and country exit in Madagascar (\$22 million). The total exploration costs written off net of tax is \$424 million (2015: \$472 million).
At the end of 2016, Tullow had provided \$133 million (2015: \$186 million) for onerous service contracts due to the reduction in planned future activity under those contracts. The changes in estimates for the provision resulted in an income statement charge in 2016 of \$115 million (2015: \$186 million).
Tullow undertakes hedging activities as part of the ongoing management of its business risk to protect against volatility and to ensure the availability of cash flow for reinvestment in capital programmes that are driving business growth.
At 31 December 2016, the Group's derivative instruments had a net positive fair value of \$91 million (2015: positive \$623 million), net of deferred premium. While all of the Group's commodity derivative instruments currently qualify for hedge accounting, a pre-tax credit of \$18 million (2015: charge of \$59 million) in relation to the change in time value of the Group's commodity derivative instruments has been recognised in the income statement for 2016.
Net financing costs for the year were \$172 million (2015: \$145 million). The increase in financing costs is associated with an increase in borrowing levels and a decrease in capitalised interest on the TEN development due to first oil. 2016 net financing costs include interest incurred on the Group's debt facilities, foreign exchange gains and the decommissioning finance charge, offset by interest earned on cash deposits and borrowing costs capitalised principally against the Ugandan assets and the TEN development.
The net tax credit of \$311 million in 2016 relates to a tax charge in respect of hedging profits offset by credits in respect of the Group's North Sea, Gabon, Equatorial Guinea and Ghana production activities, Norwegian exploration costs and non-recurring deferred tax credits associated with exploration write-offs and impairments.
The Group's statutory effective tax rate for 2016 is 34.2 per cent (2015: 20.1 per cent). The increase in the tax rate for 2016 is mainly due to higher deferred tax credits on exploration costs written off and other impairments in addition to lower prior year tax charges relating to Uganda.
After adjusting for non-recurring amounts related to exploration write-offs, disposals, impairments and onerous lease provisions and their associated deferred tax benefit, the Group's adjusted tax rate for 2016 is 23.3 per cent (2015: 29 per cent). The decrease in the adjusted tax rate is primarily a result of lower profits from overseas production activities and an increase in hedging profits taxed at the UK corporate tax rate of 20 per cent.
The Group's future statutory effective tax rate is sensitive to the geographic mix in which pre-tax profits and exploration costs written off arise. It is however expected that the adjusted tax rate should broadly follow the UK's standard rate of corporation tax over the short term as more of the Group's profit is forecast to arise in the UK.
The loss for the year from continuing activities amounted to \$597 million (2015: \$1,037 million). Basic loss per share was 65.8 cents (2015: 113.6 cents).
In view of the fall in the oil price, the Board suspended the payment of dividends in early 2015. At a time when Tullow is focusing on capital allocation, financial flexibility and cost reductions, the Board believes that Tullow and its shareholders are better served by retaining funds in the business.
Operating cash flow before working capital movements decreased by 20% to \$0.8 billion (2015: \$1.0 billion) as a result of reduced sales volumes and lower realised commodity prices, partially offset by lower cash operating costs and revenue from the TEN development. In 2016, this cash flow together with increased debt facilities helped fund the Group's \$1.0 billion of capital expenditure in exploration and development activities and \$284 million servicing the Group's debt facilities.
| Reconciliation of net debt | \$m |
|---|---|
| Year-end 2015 net debt | 4,019 |
| Sales revenue | 1,270 |
| Other operating income – lost production insurance proceeds |
90 |
| Operating costs | (377) |
| Operating expenses | (209) |
| Cash flow from operations | 774 |
| Movement in working capital | (177) |
| Tax paid | (85) |
| Capital expenditure | (1,031) |
| Disposals | 63 |
| Other investing activities | 1 |
| Financing activities | (319) |
| Foreign exchange gain on cash and debt | 11 |
| Year-end 2016 net debt | 4,782 |
2016 capital investment amounted to \$0.9 billion (2015: \$1.7 billion) with \$0.8 billion invested in development activities and \$0.1 billion invested in exploration and appraisal activities. More than 80% of the total was invested in Kenya, Ghana and Uganda and over 90%, more than \$0.8 billion, was invested in Africa. Capital expenditure will continue to be carefully controlled during 2017. The Group's capital expenditure associated with operating activities is expected to reduce from \$0.9 billion in 2016 to \$0.5 billion in 2017. The 2017 total comprises Ghana capex of c.\$90 million, West Africa nonoperated capex of c.\$30 million, Kenya pre-development expenditure of c.\$100 million and exploration and appraisal spend limited to c.\$125 million. Uganda expenditure of c.\$125 million will be offset by completion of the Uganda farm-down.
On 9 January 2017, Tullow announced that it had agreed a substantial farm-down of its assets in Uganda to Total. Under the Sale and Purchase Agreement, Tullow has agreed to transfer 21.57% of its 33.33% Uganda interests to Total for a total consideration of \$900 million. Upon completion, the farm-down will leave Tullow with an 11.76% interest in the upstream and
pipeline projects. This is expected to reduce to a 10% interest in the upstream project when the Government of Uganda formally exercises its right to back-in. Although it has not yet been determined what interests the Governments of Uganda and Tanzania will take in the pipeline project, Tullow expects its interests in the upstream and pipeline projects to be aligned.
The consideration is split into \$200 million in cash, consisting of \$100 million payable on completion of the transaction, \$50 million payable at FID and \$50 million payable at first oil. The remaining \$700 million is in deferred consideration and represents reimbursement by Total in cash of a proportion of Tullow's past exploration and development costs. The deferred consideration is payable to Tullow as the upstream and pipeline projects progress and these payments will be used by Tullow to fund its share of the development costs. Tullow expects the deferred consideration to cover its share of upstream and pipeline development capex to first oil and beyond. Completion of the transaction is subject to certain conditions, including the approval of the Government of Uganda, after which Tullow will cease to be an operator in Uganda. The disposal is expected to complete in 2017.
The divestment of the Norway business is progressing well with two deals completed before year-end and one in January 2017. Four licences, including the Wisting oil discovery, have been sold to Statoil, eight licences, including the Oda asset, have been sold to Aker BP ASA and two further licences have been sold to ConocoPhillips. A further two sales were executed in December 2016 with two separate parties. These sales, covering a further 13 licences, and which include the 2016 Cara oil and gas discovery, are on track to complete in the first quarter of 2017. In aggregate, the Norway asset sales are expected to yield proceeds of up to \$0.2 billion. Once completed, the Group will no longer hold any licences on the Norwegian Continental Shelf.
Following the scheduled amortisation of RBL facility commitments in October 2016, the Group ended the year with available credit under the RBL facility of \$3.3 billion, \$1.0 billion under the Corporate Facility, \$1.3 billion of corporate bonds, \$300 million of Convertible bonds and \$116 million under the Norwegian Exploration Finance Facility. At the end of 2016, Tullow had total facility headroom and free cash of \$1.0 billion, in aggregate, and net debt of \$4.8 billion.
In April 2016 the Corporate Facility was extended to April 2018 with commitments reducing to \$800 million in April 2017 and to \$600 million in January 2018. On 7 February 2017, the Corporate Facility was extended by a further year to April 2019 with commitments of \$500 million from April 2018 reducing to \$400 million in October 2018. In October 2016 Tullow also secured \$345 million of new commitments from its existing lenders by exercising an accordion facility embedded in the RBL which will take effect from 1 April 2017. The new commitments will largely offset the impact of the scheduled RBL amortisation in April 2017 and will ensure Tullow has appropriate headroom throughout 2017 as it refinances its bank facilities.
The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices and different production rates from the Group's producing assets. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.0 billion of debt liquidity headroom and free cash at the end of 2016. The Group's forecasts show that the Group will be able to operate within its current debt facilities and have sufficient financial headroom for the 12 months from the date of approval of the 2016 Annual Report and Accounts.
Notwithstanding our forecasts of liquidity headroom throughout the 12-month period, risk remains in relation to the volatility of the oil price environment, operational performance of the Group's assets, their impact on operating cash flows and the Group's currently contracted debt maturity profiles, such that the Group's liquidity position may deteriorate within the assessment period.
To mitigate these risks and to fulfil the Group's objective to reduce net debt, the Group continues to closely monitor cash flow projections and will take mitigating actions in advance to maintain our liquidity. Actions available to the Group include additional funding options, further rationalisation of our cost base including cuts to discretionary capital expenditure and portfolio management.
Based on the analysis above and the level of mitigating actions available, the Directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing the annual Financial Statements.
The principal financial risks to performance identified for 2017 are:
On 5 January 2017, Tullow announced that Ian Springett, CFO, has taken an extended leave of absence to undergo treatment for a medical condition, with Les Wood, Vice President Finance and Commercial, appointed Interim CFO.
On 9 January 2017, Tullow announced that it had agreed a substantial farm-down of its assets in Uganda to Total. For further details please see above.
On 11 January 2017, the Group announced that Paul McDade, currently Chief Operating Officer, will be appointed Chief Executive Officer following Tullow's Annual General Meeting on 26 April 2017. This follows an internal and external process led by Tullow's Nominations Committee. At the same time, after six years on Tullow's Board and five as Chairman, Simon Thompson will step down from the Board. Aidan Heavey, Chief Executive Officer and founder of Tullow Oil, will succeed
Mr. Thompson as Chairman of the Group for a transitional period of up to but not exceeding two years. Ann Grant, Senior Independent Director, will retire at the AGM after nine years' service on the Board. Jeremy Wilson, a non-executive Director of Tullow and Chairman of the Remuneration Committee, will succeed Ms Grant as Senior Independent Director.
On 17 January 2017, the Group announced that the Erut-1 well in Block 13T, Northern Kenya, had discovered a gross oil interval of 55 metres with 25 metres of net oil pay at a depth of 700 metres. The overall oil column for the field is estimated to be 100 to 125 metres.
On 7 February 2017, Tullow agreed a one year maturity extension of its Corporate Facility to April 2019, with commitments of \$500 million from April 2018 reducing to \$400 million in October 2018. The extension has been significantly oversubscribed, demonstrating the continued support from Tullow's relationship banks.
The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include capital investment, net debt, gearing, adjusted EBITDAX, underlying cash operating costs and free cash flow.
Capital investment is a useful indicator of the Group's organic expenditure on exploration and appraisal assets and oil and gas assets incurred during a period. Capital investment is defined as additions to property, plant and equipment and intangible exploration and evaluation assets less decommissioning asset additions, capitalised share-based payment charge, capitalised finance costs, additions to administrative assets, Norwegian tax refund, and certain other non-cash capital expenditure.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Additions to property, plant and equipment |
818.5 | 1,258.2 |
| Additions to intangible exploration and evaluation assets |
291.4 | 626.3 |
| Less | ||
| Decommissioning asset additions | (57.1) | 147.4 |
| Capitalised share-based payment charge |
(2.7) | (18.6) |
| Capitalised finance costs | (138.8) | (160.1) |
| Additions to administrative assets | (1.6) | (23.1) |
| Norwegian tax refund | (50.5) | (50.4) |
| Other non-cash capital expenditure | (2.2) | (59.7) |
| Capital investment | 857.0 | 1,720.0 |
| Movement in working capital | 122.1 | (53.9) |
| Additions to administrative assets | 1.6 | 23.1 |
| Norwegian tax refund | 50.5 | 50.4 |
| Cash capital expenditure per the cash flow statement |
1,031.2 | 1,739.6 |
Net debt is a useful indicator of the Group's indebtedness, financial flexibility and capital structure because it indicates the level of borrowings after taking account of cash and cash equivalents within the Group's business that could be utilised to pay down the outstanding borrowings. Net debt is defined as current and non-current borrowings plus unamortised arrangement fees and the equity component of any compound debt instrument less cash and cash equivalents.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Current borrowings | 591.5 | 73.8 |
| Non-current borrowings | 4,388.4 | 4,262.4 |
| Unamortised arrangement fees | 35.5 | 38.8 |
| Equity component of convertible bonds |
48.4 | – |
| Less cash and cash equivalents | (281.9) | (355.7) |
| Net debt | 4,781.9 | 4,019.3 |
Gearing is a useful indicator of the Group's indebtedness, financial flexibility and capital structure and can assist securities analysts, investors and other parties to evaluate the Group. Gearing is defined as net debt divided by Adjusted EBITDAX. Adjusted EBITDAX is defined as loss from continuing activities less income tax credit, finance costs, finance revenue, (loss)/gain on hedging instruments, depreciation, depletion, amortisation, share-based payment charge, restructuring costs, gain/(loss) on disposal, goodwill impairment, exploration costs written off, impairment of property, plant and equipment net, provisions for inventory and provision for onerous service contracts.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Loss from continuing activities | (597.3) | (1,036.9) |
| Less | ||
| Income tax credit | (311.0) | (260.4) |
| Finance costs | 198.2 | 149.0 |
| Finance revenue | (26.4) | (4.2) |
| (Gain)/loss on hedging instruments | (18.2) | 58.8 |
| Depreciation, depletion and amortisation |
466.9 | 580.1 |
| Share-based payment charge | 43.9 | 48.7 |
| Restructuring costs | 12.3 | 40.8 |
| Loss on disposal | 3.4 | 56.5 |
| Goodwill impairment | 164.0 | 53.7 |
| Exploration costs written off | 723.0 | 748.9 |
| Impairment of property, plant and equipment, net |
167.6 | 406.0 |
| Provisions for inventory | – | 22.2 |
| Provision for onerous service contracts, net |
114.9 | 185.5 |
| Adjusted EBITDAX | 941.3 | 1,048.7 |
| Net debt | 4,781.9 | 4,019.3 |
| Gearing (times) | 5.1 | 3.8 |
Underlying cash operating costs is a useful indicator of the Group's underlying cash costs incurred to produce oil and gas. Underlying cash operating costs eliminates certain non-cash accounting adjustments to the Group's cost of sales to produce oil and gas. Underlying cash operating costs is defined as cost of sales less operating lease expense, depletion and amortisation of oil and gas assets, underlift, overlift and oil stock movements, share-based payment charge included in cost of sales, and certain other cost of sales.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Cost of sales | 813.1 | 1,015.3 |
| Less | ||
| Operating lease expense | 21.0 | – |
| Depletion and amortisation of oil and gas assets |
448.5 | 551.2 |
| Underlift, overlift and oil stock movements |
(76.5) | (1.5) |
| Share-based payment charge included in cost of sales |
2.7 | 0.8 |
| Other cost of sales | 40.2 | 58.5 |
| Underlying cash operating costs | 377.2 | 406.3 |
Free cash flow is a useful indicator of the Group's ability to generate organic cash flow to fund the business and strategic acquisitions, reduce borrowings and available to return to shareholders through dividends. Free cash flow is defined as net cash from operating activities, net cash used in investing activities, net cash generated by financing activities and foreign exchange loss less repayment of bank loans, drawdown of bank loans and issue of convertible bonds.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Net cash from operating activities | 512.5 | 978.2 |
| Net cash used in investing activities | (967.2) | (1,679.6) |
| Net cash generated by financing activities |
399.3 | 745.5 |
| Foreign exchange loss | (18.4) | (7.4) |
| Repayment of bank loans | 769.1 | 191.8 |
| Drawdown of bank loans | (1,187.5) | (1,168.8) |
| Issue of convertible bonds | (300.0) | – |
| Free cash flow | (792.2) | (940.3) |
As a responsible operator, Tullow manages non-technical, or above ground, risks with the same rigour and focus with which it manages the below-ground technical challenges of exploring for and producing oil and gas.
Our commitment to safety and sustainability has not been deterred in 2016 by the downward market pressures driven by the fall in oil prices and the impact that this has had on budgets. This is most evident in our Lost Time Injury Frequency rates moving to industry top quartile performance. Additionally, our performance and commitment to health, safety and environmental performance was the highest performing category in our employee feedback survey. We manage our operations responsibly through mandatory policies and standards to which we hold all employees and contractors accountable. Our organisational structure makes clear the accountabilities within the business and the corporate centre for delivery and structured and independent assurance, respectively.
Our safety and sustainability performance is incentivised through Tullow's Group scorecard. See pages 16 to 21 for more information.
PSM involves managing a number of technical (plant), managerial (processes) and human factors (people) activities which, if not managed effectively, could lead to a major incident. PSM is applicable to drilling and production operations within Tullow. It applies to the concept selection, design, construction and commissioning, and operations, including modifications.
2016 saw the addition of a second FPSO in Ghana, installed at the TEN fields. PSM was incorporated throughout the project life cycle. The safety and environmentally critical element performance standards were agreed and independently verified at both the design
"We are very proud of our achievement of moving to top quartile industry performance on health and safety management."
Aidan Heavey Chief Executive Officer
score achieved out of a 5% allocation for safe and sustainable operations in the Group scorecard
ZERO
LTIs in the last 12 months; top quartile LTIF performance
lost man-hours from community related operations stoppages as a result of improved stakeholder engagement in Kenya
and commissioning phases. The Company also made progress against an Asset Integrity Improvement Plan on Jubilee, an FPSO which achieved five years of production in 2016. A key element of the plan was to clarify and simplify the documented management system and provide easy access to controlled documents. This progressed and was verified as part of the 2016 PSM audit.
The Kenya Early Oil Pilot Scheme (EOPS) has taken PSM into account during the concept select phase. The likelihood of major accident events is low because of the simple nature of the facilities. However, PSM continues to be considered as part of the design and operational phases of both the EOPS and Full Field Development (FFD). Transport safety for EOPS will be a priority in 2017.
Challenges that emerged in 2016 included clarifying, simplifying and better defining accountabilities within the Tullow Ghana and MODEC personnel and management systems. Targeted improvements are being worked into 2017 planning.
Environmental management covers Environmental and Social Impact Assessments (ESIAs) and Management Plans (ESMPs), resource use minimisation, waste management, protected areas and biodiversity, GreenHouse Gases (GHGs) and emissions management, and close-out/ decommissioning/remediation.
Tullow's Group total scope 1 emissions, which in 2016 included gas and diesel from our offices as well as emissions from our operations, were 754,338 tonnes of CO² e (2015: 752,539 tonnes CO² e) and 142 tonnes of CO² e per 1,000 tonnes of
hydrocarbon produced (2015: 122.07 tonnes of CO² e per 1,000 tonnes of hydrocarbon produced). Total scope 2 emissions were 4,763 tonnes of CO² e (2015: 4,631 tonnes of CO² e. Full details of our Basis of Reporting can be found online.
ESIA commitments are being met within Tullow businesses. Within the New Ventures team, ESIA close-out reports are documented when operations are completed. Additionally, the IFC, an equity partner in our Kenya project, has reviewed current operations and planning and found the work to date to be compliant with IFC Performance Standards. Progress has been made in remediating legacy drilling waste in Uganda, and the work is expected to be complete by the end of the year.
Tullow has formally announced its 'no go' commitment for World Heritage Sites, and this commitment was accepted by UNESCO in 2016. The associated Protected Area Procedure has been operationalised in all decision making.
There are challenges that remain. We need to continue to raise the profile of environmental management in business decision making. In an operational environment, we will expand Safety Critical Elements to include Environmentally Critical Elements. As we develop the Kenya business, we need to factor water use minimisation into development planning and execution. The use of the Turkwel Dam is our current preferred source for operational use, and this will require more planning and dialogue with stakeholders in 2017.
The Group Emergency Preparedness Standard has been updated to better describe the minimum training requirements for the three tiers – Field, Incident and Crisis Management Teams – as well as to provide clear definitions on the different types of exercises to be conducted annually. TEN has been covered in the Tullow Ghana Offshore Security Plan at an early stage, and security lessons learnt from Jubilee, particularly those pertaining to the no-go zone around the FPSO, have been incorporated into the TEN Project.
There has been significant progress in the delivery of training on Human Rights and Voluntary Principles on Security and Human Rights (VPSHRs) to private and public security supporting our operations in Kenya and Ghana. In late 2016, the Government of Kenya and Tullow agreed a structure for an important Memorandum of Understanding (MOU) to cover
Tullow LTIF OPG average LTIF
0 0.1 0.2
VPSHR compliance, which will be executed in 2017. This was an important milestone in continuing to improve performance and align fully to the aspirations of the Voluntary Principles. Additionally and based on recommendations from an external review, the Tullow grievance management processes have been enhanced to better manage any allegations of human rights abuse by public/private security forces. There have been no allegations reported.
12 12 13 14 15 13 14 15 16 16
After a challenging health and safety performance in 2014/15, the Company has achieved top quartile performance for the LTIF measure. In 2016, Tullow reduced its LTIF from 0.3 to zero Improved performance in our drilling and completions activities contributed to this outcome.
Given a malaria-related fatality in late 2015, the Group put a lot of energy into refocusing its prevention-related activities. Senior leadership was very visible in this effort.
Social performance covers all our interactions with communities, including stakeholder engagement and management, grievance management, land access and compensation, impact mitigation and community consent and agreements.
Performance associated with the management of grievances and work disruptions saw improvement in 2016. The Company developed a Master Plan for Kenya that considers the holistic management of non-technical risks from a 'landscape' perspective. The Company developed a growing understanding of traditional Turkana this year and will use this to embark on a process to reach agreement with all stakeholders for FFD. The Company's Human Rights Policy articulates our aim to obtain 'agreement' of project-affected communities where we operate, and guides us toward Free Prior Informed Consent (FPIC) where land and livelihoods are affected by our operations. Challenges remain in fully operationalising the Human Rights Policy, including how we assess compliance in our supply chain.
1
STRATEGIC REPORT GOVERNANCE & RISK MANAGEMENT CHAIRMAN'S INTRODUCTION
Good governance is incentivised through KPIs in our Group Scorecard affecting Executive Directors' and employees' variable, performance-related pay.
Our approach to corporate governance and risk management sets the tone, direction and policies that result in actions and behaviour across our business, which in turn form the core of our corporate reputation. Our approach includes creating a culture of ethical behaviour aligned to our values and a robust Integrated Management System (IMS) to govern how the business is run. This includes the management of inherent opportunities and risks and responsiveness to the concerns of our shareholders and broader stakeholders.
Good governance and risk management is incentivised by Key Performance Indicators (KPIs) in our Group scorecard affecting Executive Directors' and employees' variable, performance-related pay. See pages 16 to 21 for more information.
Tullow saw a major overhaul of its risk, assurance and performance management processes in 2015 as part of the Major Simplification Project (MSP). This effort clarified accountabilities for decision making and identified roles for business delivery, risk management and independent assurance. In late 2015, the Company launched an IMS to set out all mandatory policies, standards and the controls necessary to ensure that our activities and associated risks are effectively managed. In 2016, we began the process of embedding the IMS resulting in it becoming fully operationalised by the year end.
One key change in approach that the IMS introduced was an effective and 'joined up' Life Cycle Value Chain (LCVC) process that combined multiple legacy stage gate processes. This enables our three Business Delivery Teams to progress business opportunities, with relevant corporate centre functional involvement in independent assurance reviews and key decision points at each gate.
The risk management process is consistent across the Group, with management and oversight from the field to the Board of Directors. The Board of Directors carried out a robust assessment of the principal risks facing the Company, including those that would threaten our business model, future performance, solvency and liquidity. Principal risks are overseen by the Tullow Board of Directors. A full report of these strategic, financial, operational and compliance risks, including potential impacts and controls, mitigation actions and assurance, are summarised on pages 44 to 53.
Assurance processes are now connected and consistent across the Group. There is clarity on what needs to occur at each of the four tiers and annual planning is done in a way that minimises duplication and burden on the business, while providing independent assessments where needed.
Performance scorecards are now fully implemented. These give Senior Management a line of sight of performance on a regular basis. A subset of the KPIs are both monitored regularly by Executive Management and have targets which are tied to remuneration.
While significant progress has been made to embed the IMS within the organisation in 2016, there is further work to be done to reap its full benefits. In 2017, the Executive team will require the Corporate Centre functional heads to fully own their standards and ensure full understanding and compliance in all parts of the business. There are opportunities to further align Business Delivery Team and functional performance scorecards to be more efficient. Additionally, a challenge remains within the assurance process to demonstrate that activities conducted in the businesses without Group oversight are fully effective across all parts of the business.
As part of our commitment to managing the way we work ethically and legally, we continually look for ways to engage both internal and external stakeholders on our compliance standards as well as our Code of Ethical Conduct (the "Code"). During 2016, we introduced an e-learning module covering the key areas of our Code, including anti-corruption, which all Tullow staff including contractors and Board members were required to complete. The course raised awareness of our Code and generated good discussions among our teams. By the end of the year, 97 per cent of the workforce had completed this programme. In addition, all Tullow staff completed their annual compliance certification with the Code of Ethical Conduct and its related standards, procedures and guidelines. The certifications were assured by our Group Ethics & Compliance function and it was signed off by Ian Springett, our Chief Financial Officer, who has executive responsibility for ethics and compliance.
We are committed to upholding and maintaining our zero tolerance of bribery. A key component of our anti-corruption programme is the internal control on managing expenditures related to public officials where such expenditures are related to Tullow business. Any such expenditure must be reviewed by our
Ethics & Compliance group prior to any engagement. In 2016, we introduced an electronic register to automate this process and improve compliance monitoring and assurance.
The Board, via our Ethics & Compliance Committee, oversees the development and monitors the implementation and effectiveness of the Code and other Company standards in relation to good ethical behaviour. Our Audit Committee also reviews the adequacy and security of the Company's arrangements for staff to raise concerns, in confidence, about possible improprieties in financial reporting or other matters. In 2016, we recorded 91 'speaking up' cases (2015: 103), of which 18 were submitted via our confidential, external and independent
reporting option provided by Safecall. We investigated all reported possible or actual breaches of our Code, following which three members of our workforce left the Group and had their contracts terminated. This is necessary to uphold good corporate governance and ensure that we safeguard the integrity of our Code and that of the Company.
Tullow works to maintain interactions with all stakeholders, such as governments at all levels, advocacy NGOs, multilaterals and communities. There are genuine, inherent risks in failing to understand and respond to what is important to our stakeholders. These can translate into real business and opportunity costs and impact our reputation.
We communicate factual information about our operations and ambitions to ensure our stakeholders understand our business and can ask questions and make decisions in an informed way.
We also engage to solicit input and ideas on different policy and performance issues, informing our business plans, practices and processes to help identify and assess risks to business delivery and to address problems early on when they arise.
For example, in 2016 we engaged with a number of organisations, including the World Bank Group, Millennium Water Alliance, World Resources Institute and Human Rights Watch, to gain their perspective on water management issues. Such discussions facilitate the development of key Company policies and processes, which in turn support internal discussions on desired performance and allow a considered and timely response to stakeholder expectations on critical issues.
Within the IMS, we have new standards and guidelines to support stakeholder engagement activities. These are aimed at ensuring the business is suitably prepared for and resourced to build and manage effective relations with all external stakeholders, and that we carry out this engagement in a systematic way as part of risk identification and management. This has led to the development of a structured framework and approach to managing engagement with national Government in Ghana, and to improvements in the cross-functional sharing of engagement outcomes in Kenya and Uganda. Challenges remain in navigating through Kenya's devolved government structure, with forthcoming national elections, and in fully embedding the use of new stakeholder management tools and processes across the business.
Chairman 7 February 2017
Simon Thompson (age 57, British) was appointed as a non-executive Director in 2011 and as non-executive Chairman in January 2012. Simon worked for investment banks N M Rothschild and S. G. Warburg before joining the Anglo American group in 1995, where he held a number of senior positions and became an Executive Director in 2005. Since leaving Anglo American, he has served as a non-executive Director of Amec Foster Wheeler plc, AngloGold Ashanti Ltd, Newmont Mining Corporation and Sandvik AB. Simon will step down from the Board following the Annual General Meeting on 26 April 2017.
Simon is Chairman of 3i Group plc and a non-executive Director of Rio Tinto plc. He is also a member of the Advisory Council at the Institute of Business Ethics and a member of the Advisory Panel on Business and Sustainability at the International Finance Corporation.
N*, R, EHS
Aidan Heavey (age 63, Irish) is the founder of Tullow Oil and has been Chief Executive Officer since 1985. He has played a key role in Tullow's development as a leading independent oil and gas exploration and production group. Aidan will be appointed as non-executive Chairman on 26 April 2017 following Tullow's Annual General Meeting.
Ian Springett (age 59, British) is a Chartered Accountant and was appointed to the Board of Directors in 2008. Prior to joining Tullow, Ian worked at BP for 23 years where he gained extensive international oil and gas experience. Ian has held a number of senior positions at BP, including vice president of BP Finance and CFO for the United States, and also served as a business unit leader in Alaska.
Ian was appointed a non-executive director of G4S plc with effect from 1 January 2017.
E&C
Paul McDade (age 53, British) was appointed to the Board of Directors in March 2006, having joined Tullow in 2001. Paul was appointed Chief Operating Officer following the Energy Africa acquisition in 2004, having previously managed Tullow's UK gas business. Paul will be appointed Chief Executive Officer on 26 April 2017, following Tullow's Annual General Meeting. An engineer with over 25 years' experience, Paul has worked in various operational, commercial and management roles with Conoco, Lasmo and ERC. He has broad international experience having worked in the UK North Sea, Latin America, Africa and South East Asia. Paul holds degrees in civil engineering and petroleum engineering.
EHS
Angus McCoss (age 55, British) was appointed to the Board of Directors in December 2006 following 21 years of wide-ranging exploration experience, working primarily with Shell in Africa, Europe, China, South America and the Middle East. Angus held a number of senior positions at Shell, including Regional Vice President of Exploration for the Americas and General Manager of exploration in Nigeria. He holds a PhD in structural geology.
Angus is a non-executive Director of Ikon Science Limited and a member of the advisory board of the industry-backed Energy and Geoscience Institute of the University of Utah.
Ann Grant (age 68, British) was appointed as a non-executive Director in May 2008 and Senior Independent Director in April 2014. Ann was Vice Chairman (Africa) at Standard Chartered Bank from 2005 to 2014. Her earlier career was as a British Diplomat, from 1971 to 2005. From 1998, she worked at the Foreign and Commonwealth Office in London as Director for Africa and the Commonwealth. From 2000 to 2005, Ann was the British High Commissioner to South Africa. After nine years' service, Ann will retire from the Board following Tullow's Annual General Meeting on 26 April 2017.
Ann is a trustee of the Overseas Development Institute and a council member of the London School of Hygiene and Tropical Medicine. Ann is also a trustee of the Rift Valley Institute and chairs the Serious Music Trust.
E&C*, A, N
Tutu Agyare (age 54, Ghanaian) was appointed as a non-executive Director in August 2010. He is currently a Managing Partner at Nubuke Investments, an asset management firm focused solely on Africa, which he founded in 2007. Previously, he had a 21-year career with UBS Investment Bank, holding a number of senior positions, most recently as the head of European emerging markets, and served on the Board of Directors.
Tutu is a director of the Nubuke Foundation, a Ghanaian-based cultural and educational foundation. Tutu is also a senior adviser to Power Africa, an initiative launched by the Obama administration to increase access to electricity in Africa.
Steve Lucas (age 62, British) was appointed as a non-executive Director in March 2012. A Chartered Accountant, Steve was Finance Director at National Grid plc from 2002 to 2010 and previously worked for 11 years at Royal Dutch Shell and for six years at BG Group, latterly as Group Treasurer.
Steve is a non-executive Director of Acacia Mining plc and Chairman of Ferrexpo plc. Steve is also a Director of Mauser Group BV.
Anne Drinkwater (age 61, British) was appointed as a non-executive Director in July 2012. Anne's appointment followed a long career at BP, where she held a number of senior business and operations positions, including President and Chief Executive Officer of BP Canada Energy Company, President of BP Indonesia and Managing Director of BP Norway.
Anne is a non-executive Director and the non-executive Deputy Chairman of Aker Solutions ASA (Norway) and is an oil and gas adviser to the Government of the Falkland Islands.
EHS*, A, R, N
Jeremy Wilson (age 52, British) was appointed as a non-executive Director in October 2013 following a 26-year career at J.P. Morgan where he held a number of senior positions, most recently Vice Chairman of the Energy Group.
Jeremy is a non-executive Director of John Wood Group PLC (UK) and a director of The Lakeland Climbing Centre Ltd and the Lakeland Climbing Foundation.
Mike Daly (age 63, British) was appointed as a non-executive Director in June 2014 following a 28-year career at BP where he held a number of senior roles. Most recently, he was Executive Vice President Exploration, and a member of BP's Group executive team until January 2014.
Mike is a visiting Professor at the University of Oxford and a Senior Director at Macro Advisory Partners. Mike is also a non-executive Director of CGG, an integrated geoscience company based in France, which is listed on the Euronext and New York Stock Exchanges.
A, N, EHS
Kevin Massie was appointed Company Secretary on 1 January 2016. Kevin was previously Corporate Counsel and Deputy Company Secretary at Tullow.
| * | Committee Chair | |
|---|---|---|
| A | Audit Committee | |
| EHS | EHS Committee | |
| E&C | Ethics and Compliance Committee | |
| N | Nominations Committee | |
| R | Remuneration Committee | |
| >> | ||
| Audit Committee Nominations Committee EHS Committee Remuneration Committee |
69 74 76 80 |
|
We recognise that effective risk management is fundamental to helping us achieve our strategic objectives. Risk management is embedded in our critical business activities, functions and processes. Materiality and our tolerance for risk are key considerations in our decision-making process.
Risk management is integral to Tullow's strategy and to the achievement of our long-term goals. Our success as an organisation depends on our ability to identify, assess and successfully manage our risks. Our approach to risk management is designed to provide reasonable, but not absolute assurance that our assets are safeguarded and the risks facing the business are being mitigated. We believe that an effective and joined-up risk management approach enhances Tullow's ability to achieve its strategic objectives, and helps protect our business, people and reputation.
The Board, as part of its role in providing strategic oversight and stewardship of the Company, is responsible for maintaining an effective risk management and internal control system. The Executive team, Group functional heads and Business Delivery Teams (BDTs) are responsible and accountable for monitoring and managing the risks that fall under their remit. It is then every leader and manager's job to manage the day-to-day risks the Group may face. They are responsible for identifying the risks, assessing them and establishing appropriate actions to either manage, terminate or transfer the risk to an acceptable level as defined by the Board.
The risk register continues to be the core element of the risk management process. Each layer of the organisation is responsible for maintaining a risk register at its business level, which is reviewed formally on a quarterly basis at its business performance reviews. The risk register identifies risks facing the Group, which are assessed at both an inherent and residual level against two scales: a) according to their likelihood; and b) according to their potential consequence to the Group, not only financially, but also in terms of safety, reputation, legal and regulatory. This assessment enables the risk owners to determine the strength of existing controls and mitigating actions and to identify the additional treatment required to reduce the risk to the agreed tolerance level. Tullow recognises that risk cannot be totally eliminated and that there are some risks the Board will choose to accept. These decisions will come down to experience after consideration of the Group's defined risk appetite.
The risk registers are consolidated upwards to the Group who prepare a risk register, called the Enterprise Risk Register. These enterprise risks are formally reviewed twice a year.
The principal risks, which are the key risks facing the Company, are a subset of the Enterprise risks. The risk register, its method of preparation and the operation of key controls are periodically reported to the Executive and the Audit Committee. The Board has delegated responsibility for the risk management process to the Audit Committee, and Group Internal Audit is responsible for coordinating this process.
The risk management process is also an integral part of the annual business planning process and ongoing business performance management. A key component of the process is not just risk identification, but also the 'top-down' and 'bottom-up' discussions that occur to agree mitigation plans and evaluate actions and to understand compound risk and risk interdependencies.
In order to ensure both complete and systematic identification of risks and commonality of risk definitions, the Group maintains a 'risk universe', which lists an extensive collection of potential risks that could impact the Company's performance. These risks are separated into four classes: Strategic, Financial, Operational and Compliance, which are further broken down in to eleven risk categories. Executive Directors are assigned responsibility for these categories and assurance and oversight responsibilities are assigned to the
Board and respective Board Committees. A summary of our risk universe is detailed below.
The Board is responsible for setting the Group's risk appetite and acceptable risk tolerance levels and putting in place a mechanism to monitor compliance with these agreed tolerances. Risk workshops attended by the Executive Directors, BDT VPs and Group Functional VPs were undertaken during 2016, to agree the principal risks, understand the risk interdependencies and define tolerances for each risk.
In considering the Group's risk appetite, the Board has reviewed the risk process, the assessment of principal risks and the existing controls and mitigating actions that drive towards residual risk. The risk appetite has been adopted by the Board of Directors and is kept under regular review (at least annually) to reflect the current external and market conditions.
On pages 46 to 53 we have identified the principal risks that we see as most relevant to Tullow at this time. There may be other risks that could emerge in the future. If these risks are not successfully managed, our cash flow, operating results, financial position, business and reputation could be materially adversely affected.
| STRATEGIC | ||
|---|---|---|
| Principal Risks | Causes | Potential Impact |
| 1. Strategy not fully achievable in sustained low oil price environment Executive responsibility Aidan Heavey Chief Executive Officer Link to business model Sustainable long-term value growth |
• Low oil price environment due to global supply/demand balances and shift to alternative energy sources as a result of climate change |
• Business not robust to oil price downside • Inability to monetise chosen assets • Inability to deleverage the business • Capital committed to sub-optimal projects • Overheads (i.e. G&A spend) not matched to asset base • Portfolio not optimised to sustain long-term strategy |
| 2. Inability to progress major portfolio options Executive responsibility Ian Springett Chief Financial Officer Link to business model Finance & Portfolio Management |
• Reduction in market appetite for E&P assets |
• Inability to monetise chosen assets and deleverage balance sheet • Write-downs on acquired assets • Over investing in mature assets for low returns • Capital commitments requiring scarce investment best spent elsewhere in the portfolio • Failure to exit mature assets at appropriate time • Exposure to decommissioning costs |
| 3. Failure to realise expected value from TEN due to ITLOS Executive responsibility Paul McDade Chief Operating Officer Link to business model Development & Production |
• Freezing of new drilling activity in TEN as a result of ITLOS ruling • ITLOS rules against Ghana in border dispute with Côte d'Ivoire resulting in movement of the maritime border and TEN reserves/facilities into CDI waters and suspension of drilling activities |
• Loss of some or all of TEN reserves/ facilities due to ITLOS decision putting part of field in CDI waters • Delay in resumption of development drilling plans and production ramp-up |
| 4. Disruption to business due to political/regulatory influence Executive responsibility Paul McDade Chief Operating Officer Link to business model Responsible Operations and Shared Prosperity |
• Fiscal pressures on governments as a result of reduced revenues due to low oil price and local currency exchange rate challenges • Uncertainty arising from changes in government leadership • Pace of national content requirements |
• Significant variance to plans due to delayed regulatory approvals/lack of support • Regulatory and tax changes affecting profitability and viability of projects/operations |
| Risk Mitigation and Assurance | 2016 outcomes and ongoing actions |
|---|---|
| • Robust planning of strategy • Business plan reviewed and approved annually by the Board includes options/alternatives for lower oil prices • Strict capital allocation process in line with business plan and gate reviews for all new investments • Track delivery through rigorous regular performance management and reporting • Regular investor meetings with Executive to gain feedback and challenge • Board Strategy Day portfolio reviews |
• Improved Group capital allocation process and reporting • Significant reduction in 2017 planned capital spend • Detailed portfolio review • Tested and retained options for increased EBITDA delivery • Focused on deleveraging options |
| • Maintain a highly competent transaction capability • Regular portfolio assessments by the Board in the annual strategy review • Meet relevant commercial and investment appraisal standards and review all major acquisition or divestment proposals • Major decisions and new country entry follow Executive Director/Board approval process • Conduct post-transaction reviews, whether completed or aborted |
• Improved portfolio analysis • Bi-annual portfolio reviews with Business Delivery Teams • Portfolio review on Board agenda • Executing current strategic portfolio plan • Focus on securing maximum value in current operations • Clear identification of level of commitments in new licenses • Successful farm down of Uganda and disposal of Norway |
| • Regularly monitor the ITLOS case, analysing claims with expert counsel assistance • Work closely with the Government of Ghana to understand fully the potential impact and encourage continued dialogue between both countries |
• Case progressed in line with schedule defined by ITLOS • Scenario analysis undertaken |
| • Non-Technical Risk Standard sets minimum requirements for stakeholder management • Country Strategy Papers and stakeholder engagement plans, supported by experienced staff to manage developments • Safety, Sustainability and External Affairs (SSEA) scorecard monitors effectiveness |
• Fully embedded Non-Technical Risk Standard • Mapped and set out integrated solutions for complex risks • Negotiated TEN gas sales /delivery agreements and delivered TEN successfully • Negotiated settlement of tax disputes |
| STRATEGIC CONTINUED | ||
|---|---|---|
| Principal Risks | Causes | Potential Impact |
| 5. Disruption to business due to community and political influence Executive responsibility Paul McDade Chief Operating Officer Link to business model Responsible Operations and Shared Prosperity |
• Conflicting interests between the country government and traditional leadership models • Government inability to deliver infrastructure on time for projects and provide security for critical infrastructure |
• Inability to achieve community support for new projects due to opposition/loss of licence to operate leading to delays in project delivery • Unplanned costs due to community unrest/opposition • Inability to gain land lease extensions • Significant security risk to Tullow employees and contractors |
| FINANCIAL | ||
| Principal Risks | Causes | Potential Impact |
| 6. Insufficient liquidity and funding capability Executive responsibility Ian Springett Chief Financial Officer Link to business model Finance and Portfolio Management |
• Lack of capital discipline and unsuccessful portfolio management • Reduced asset quality limiting ability to raise debt • Reduced bank/DCM appetite for E&P sector as a result of capital markets uncertainty • Significant unplanned cash outflows and elevated leverage |
• Inability to finance strategic objectives • Liquidity headroom squeezed • Ability to raise further debt constrained • Inability to fund capital investment /projects |
| 7. Failure to manage commodity price risk Executive responsibility Ian Springett Chief Financial Officer Link to business model Finance and Portfolio Management |
• Oil price decline | • Commodity price volatility reduces cash flow and asset value • Reduced revenues, EBITDA, debt capacity and funding to support investment programme |
| Potential Impact | Risk Mitigation and Assurance | 2016 outcomes and ongoing actions |
|---|---|---|
| • Lack of capital discipline and • Inability to finance strategic objectives unsuccessful portfolio management • Liquidity headroom squeezed • Reduced asset quality limiting ability • Ability to raise further debt constrained • Inability to fund capital investment /projects • Reduced bank/DCM appetite for E&P sector as a result of capital • Significant unplanned cash outflows |
• Prudent approach to diversified debt and equity, with a balance maintained through business planning and performance management processes • Board-approved funding policy targets in place • Optimisation of debt capital structure • Good relationships with banks and capital markets investors • Regular funding and liquidity projections reported to management and periodic financing strategy review carried out • Financing standard in place to ensure optimal funding |
• \$300 million additional bank commitments secured in 2016 • Strength of assets retained debt capacity despite fall in oil prices • 2016 year-end facility headroom and free cash of \$1 billion; net debt of \$4.8 billion • Mark-to-market value of hedging instruments \$91 million at end of 2016 • 2017 financing initiatives in progress • Capital allocation process to meet funding targets |
| • Commodity price volatility reduces cash flow and asset value • Reduced revenues, EBITDA, debt capacity and funding to support investment programme |
• Board-approved hedge programme to protect against low oil prices • Programme monitored regularly and communicated to the Board • Hedging programme executed and approved in accordance with the policy • Regular review of hedge strategy, position and effectiveness |
• Mark-to-market value of oil hedges at the end of 2016 was \$91 million • Approximately 60 per cent of 2017 entitlement oil production hedged at an average floor price of \$60/bbl |
| OPERATIONAL | |||
|---|---|---|---|
| Principal Risks | Causes | Potential Impact | Risk Mitigation and Assurance |
| 8. Major process safety/ equipment/EHS failure Executive responsibility Paul McDade Chief Operating Officer Link to business model Development & Production |
• Inadequate maintenance of safety critical equipment onboard Jubilee/ TEN FPSOs Loss of wells, subsea equipment or FPSOs systems • Error in well design, equipment selection or programme • Ineffective standards and procedures or improper work practices • Loss of rig position |
• Multiple fatalities • Serious environmental or asset damage • Serious reputational damage • Significant financial consequences • Significant loss of production, injection or export capacity |
• Independently verified safety cases to demonstrate risks reduced to ALARP and EHS management system in place and risk insurance provided • Minimum Asset Integrity, maintenance and planning requirements mandated • Effective controls within Jubilee Turret Case to Operate • Analysis of key FPSO systems (power, gas, water etc.) to support top quartile reliability and computerised maintenance management system (CMMS) to manage asset integrity • Standard processes in place for major topside upgrades and to manage equipment corrosion and well integrity • Competency training assessment programmes, regular emergency response exercise and oil spill contingency plans in place • Skilled and well trained people to ensure safe operations • All wells designed, constructed and operated in accordance with appropriate standards and procedures • Third party well examination, internal audit and assurance processes carried out |
| 9. Inability to replenish exploration portfolio Executive responsibility Angus McCoss Exploration Director Link to business model Exploration and Appraisal |
• Lack of/under investment in portfolio high grading activities • Lack of dedicated resources to identify new business activities • Failure to encourage entrepreneurial/ creative exploration innovation or de-motivation of key staff |
• Failure to replenish exploration acreage or fund new ventures • Loss of reputation and exploration value from share price • Sustained exploration failure results in poor or no drill-ready prospects |
• New opportunities are considered against existing portfolio to maintain diversity of prospects and the exploration portfolio is reviewed annually • An Exploration and Appraisal Values Controls Standard in place • Exploration and Development Geosciences Executive team work across the business on portfolio planning • A review of exploration prospect inventory and tracking of net prospective risked resources takes place twice a year |
| 10. Major cyber or information security incident Executive responsibility Angus McCoss Exploration Director Link to business model Governance and Risk Management |
• External cyber-attack resulting in network compromise or disruptive/ destructive impact to Industrial Control Systems • Deliberate or accidental internal theft/ loss of confidential information |
• Disruption to or halt of critical business systems resulting in stopped production, explosion or loss of life • Loss or theft of confidential information • Loss of competitive advantage and intellectual property • Reputational damage |
• Advanced Security Operations Centre (ASOC) provides global monitoring, analysis, alerting and incident response • Bespoke advanced security equipment used at key operations sites • Active member of Cyber Information Sharing Partnership (CISP) • Third-party specialists analyse vulnerabilities and provide network assurance activities • Enterprise-wide information security awareness training, aligned with Information Security Standards |
| 11. Failure to have a balanced, diverse workforce and attractive employee proposition Executive responsibility Aidan Heavey Chief Executive Officer Link to business model Organisation & Culture |
• Tullow culture and values not embedded • Staff do not support our current operating model • Lack of staff confidence in strategy and senior leadership • Diversity and localisation plans not effectively implemented • Ineffective staff development and reward programmes |
• Loss of key personnel/lack of succession and increased staff turnover • Lack of in-house skills and requirement to buy-in short-term contractors increases costs • Negative relations with the government due to failure to implement localisation plans • Reputational damage |
• Biannual performance and development cycle • Succession planning, localisation and diversity objectives are set and key targets monitored • Nominations Committee focus on diversity plan • Periodic reporting to Executives of HR data • Staff engagement plan is agreed with HR, Communications and Executives, with key actions • Annual Employee Engagement Survey and annual review of reward package |
| Causes Potential Impact |
Risk Mitigation and Assurance | 2016 outcomes and ongoing actions |
|---|---|---|
| • Inadequate maintenance of safety • Multiple fatalities critical equipment onboard Jubilee/ • Serious environmental or asset damage TEN FPSOs Loss of wells, subsea • Serious reputational damage equipment or FPSOs systems • Significant financial consequences • Error in well design, equipment • Significant loss of production, injection selection or programme or export capacity • Ineffective standards and procedures or improper work practices • Loss of rig position |
• Independently verified safety cases to demonstrate risks reduced to ALARP and EHS management system in place and risk insurance provided • Minimum Asset Integrity, maintenance and planning requirements mandated • Effective controls within Jubilee Turret Case to Operate • Analysis of key FPSO systems (power, gas, water etc.) to support top quartile reliability and computerised maintenance management system (CMMS) to manage asset integrity • Standard processes in place for major topside upgrades and to manage equipment corrosion and well integrity • Competency training assessment programmes, regular emergency response exercise and oil spill contingency plans in place • Skilled and well trained people to ensure safe operations • All wells designed, constructed and operated in accordance with appropriate standards and procedures • Third party well examination, internal audit and assurance processes carried out |
• Safety case verification by industry experts • Competency gaps/losses identified • Assurance against production operations standards • Assurance against Production Well Integrity Procedure • Original turret manufacturer and JV partners input to CtO, with external assurance • Asset Integrity and Reliability Plan in place • Well integrity Management System and FPSO Performance Standards and Assurance and verification criteria implemented • Insurance process in place • Frequent review of Well Engineering Management System to ensure well control risk effectively addressed • Rig HSE Case and third-party equipment audits carried out • Training and competency matrix and asset |
| • Lack of/under investment in portfolio • Failure to replenish exploration acreage high grading activities or fund new ventures • Lack of dedicated resources to identify • Loss of reputation and exploration value new business activities from share price • Failure to encourage entrepreneurial/ • Sustained exploration failure results creative exploration innovation or in poor or no drill-ready prospects de-motivation of key staff |
• New opportunities are considered against existing portfolio to maintain diversity of prospects and the exploration portfolio is reviewed annually • An Exploration and Appraisal Values Controls Standard in place • Exploration and Development Geosciences Executive team work across the business on portfolio planning • A review of exploration prospect inventory and tracking of net prospective risked resources takes place twice a year |
integrity and reliability plan in place • New licence granted in Namibia • Farm-down of licences in Pakistan, Norway, Mauritania and Uganda • Review of New Ventures strategy • Seismic interpretation used to decipher best prospects • Ongoing farm-downs to reduce Tullow equity earlier in licence cycle |
| 10. Major cyber or information • External cyber-attack resulting in • Disruption to or halt of critical business network compromise or disruptive/ systems resulting in stopped production, destructive impact to Industrial explosion or loss of life Control Systems • Loss or theft of confidential information • Deliberate or accidental internal theft/ • Loss of competitive advantage and loss of confidential information intellectual property Governance and Risk Management • Reputational damage |
• Advanced Security Operations Centre (ASOC) provides global monitoring, analysis, alerting and incident response • Bespoke advanced security equipment used at key operations sites • Active member of Cyber Information Sharing Partnership (CISP) • Third-party specialists analyse vulnerabilities and provide network assurance activities • Enterprise-wide information security awareness training, aligned with Information Security Standards |
• Ongoing enterprise-wide awareness training, with additional bespoke training for higher risk areas • Ongoing improvement of network infrastructure resilience • Specialist external assurance of TEN and Jubilee Industrial Control Systems |
| 11. Failure to have a balanced, • Tullow culture and values not embedded • Loss of key personnel/lack of succession diverse workforce and attractive and increased staff turnover • Staff do not support our current operating model • Lack of in-house skills and requirement to buy-in short-term contractors • Lack of staff confidence in strategy increases costs and senior leadership • Negative relations with the government due • Diversity and localisation plans not to failure to implement localisation plans effectively implemented • Reputational damage • Ineffective staff development and reward programmes |
• Biannual performance and development cycle • Succession planning, localisation and diversity objectives are set and key targets monitored • Nominations Committee focus on diversity plan • Periodic reporting to Executives of HR data • Staff engagement plan is agreed with HR, Communications and Executives, with key actions • Annual Employee Engagement Survey and annual review of reward package |
• Revised organisation design with clear accountabilities • Embedded performance management framework • Implementation of employee engagement plan • Restructured HR delivery and reward team • Review and revision of reward packages • Diversity plan defined with actions implemented for 2016 |
| COMPLIANCE | ||
|---|---|---|
| Principal Risks | Causes | Potential Impact |
| 12. Major breach of business or ethical conduct standards Executive responsibility Aidan Heavey Chief Executive Officer Link to business model Governance and Risk Management |
• Insufficient staff understanding of compliance • Poor leadership behaviour • Insufficient 'speaking up' culture • Lack of compliance monitoring in business units and failure to adequately respond to non-compliance |
• Unethical behaviour • Breaches anti-corruption laws • Investigations result in reputational damage • Cost of investigations and fines • Senior officers liable under UK Bribery Act |
In accordance with provision C2.2. of the 2014 revision of the UK Corporate Governance Code, the Board has assessed the prospects and the viability of the Group over a longer period than the 12 months required by the 'Going Concern' provision.
The Board conducted this review for a period of three years taking into account the Group's current position and potential impact of its principal risks. The three-year period was selected for the following reasons:
Based on these factors, the Directors consider that a three-year assessment period appropriately reflects the underlying prospects and viability of the Group, and the period over which the principal risks are reviewed.
In order to make an assessment on the Group's viability, the Directors have made a detailed assessment of the Group's principal risks, and the potential implications these risks would have on the Group's liquidity and its business model over the assessment period. This assessment included, where appropriate, detailed cash flow analysis, and the Directors also considered a number of reasonably plausible downside scenarios, and combinations thereof, together with associated summaries/documents provided by the Group's Finance and Treasury teams. The assessment has assumed that capital markets continue to operate under normal market conditions.
The Directors have also identified mitigating actions which the Group already has in place, such as hedging and insurance, and additional mitigating actions that are available to the Group, such as additional funding options, further rationalisation of our cost base including cuts to discretionary capital expenditure and portfolio management. Based on the results of the analysis the Board of Directors has a reasonable expectation that the Company will be able to continue in operation and meet its liabilities as they fall due over the three-year period of their assessment.
Notwithstanding our forecasts of liquidity headroom throughout the assessment period, risk remains in relation to the volatility of the oil price environment, operational performance of the Group's assets, their impact on operating cash flows and the Group's currently contracted debt maturity profiles, such that the Group's liquidity position may deteriorate within the assessment period and the Group may become non-compliant with one of its financial covenants during the assessment period. To mitigate these risks and to fulfil the Group's objective to reduce net debt, the Group continues to closely monitor cash flow projections and will take mitigating actions in advance to maintain our liquidity.
The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices and different production rates from the Group's producing assets. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.0 billion of debt liquidity headroom and free cash at the end of 2016. The Group's forecasts show that the Group will be able to operate within its current debt facilities and have sufficient financial headroom for the 12 months from the date of approval of the 2016 Annual Report and Accounts.
Notwithstanding our forecasts of liquidity headroom throughout the 12-month period, risk remains in relation to the volatility of the oil price environment, operational performance of the Group's assets, their impact on operating cash flows and the Group's currently contracted debt maturity profiles, such that the Group's liquidity position may deteriorate within the assessment period.
To mitigate these risks and to fulfil the Group's objective to reduce net debt, the Group continues to closely monitor cash flow projections and will take mitigating actions in advance to maintain our liquidity. Actions available to the Group include additional funding options, further rationalisation of our cost base including cuts to discretionary capital expenditure and portfolio management.
Based on the analysis above and the level of mitigating actions available, the Directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing the annual Financial Statements.
Despite the challenges of the downturn for Tullow and the industry, we ended 2015 with a new organisation structure that makes us more efficient, providing clearer lines of responsibility and accountability inside the business.
A year on from the implementation of Tullow's Major Simplification Project (MSP), which saw a headcount reduction of around 40 per cent, and with further headwinds and uncertainty generated by lower and more volatile oil prices, the teams across Tullow focused on what we could control: project execution, cost and efficiency. From an organisational and cultural perspective, we made progress in embedding a more performancefocused culture across our business. Our organisational performance is incentivised through Tullow's Group scorecard, related to Executive Directors' and employees' variable pay. See pages 16 to 21 for more information.
During the year, we carried out an employee survey, Tullow Pulse, to ask for employee feedback and views about our organisation following our 2014 MSP. Eighty-eight per cent of employees and contractors took part in the survey, which was the highest ever response rate. This high level of engagement, with rich and honest feedback, has paved the way to put in place plans to build on the positive feedback received and concentrate on areas of concern. The survey showed clear support for improvements in financial governance and organisational structure, which were two main features of the MSP. There were also positive views about our EHS performance, and the performance of line managers, which employees felt continued to improve year on year. Areas which received less favourable comments included certain feedback for Senior Management, views
Last year Tullow reached its 30-year anniversary, which presented a company-wide opportunity to celebrate the company's history, heritage and values and reiterate its vision and strategy.
Each major office planned various activities and celebrations to mark the day and provide opportunities for informal staff meetings.
Staff in London networked at a poster fair, which was focused on sharing best practice between functions, demonstrating progress against the corporate scorecard and cost cutting/ efficiency initiatives.
Employees from all over the group contributed to a video montage of Tullow people stories to showcase the Company's diversity. We also ran a Tullow history quiz and a timeline poster with the future left blank for people to write their thoughts on what Tullow's future could look like.
on career and personal development and trust. We are now working to understand the detailed reasons behind these responses and will implement action plans during 2017.
In order to attract and retain the best talent available at all levels of the organisation, our total reward package is designed to be competitive in the oil and gas sector and across all locations in which Tullow operates. Our approach of 'paying for performance' ensures that our employees are engaged and motivated through an appropriate mix of fixed (base salary, pension and benefits) and variable (cash bonus and share awards) rewards.
This year, we made changes to our Employee Bonus Plan (EBP) and annual performance management process to better reflect our new structure and the challenging business circumstances in which we continue to operate.
The EBP has been changed to pay 30 per cent (up from 20 per cent) of bonus to reflect Company performance, while the remaining 70 per cent is dependent on an employee's individual performance. Annual share awards, made under the Employee Share Award Plan (ESAP), will then match the value of the employee's annual bonus for the year.
The new EBP and ESAP are more transparent to our employees and more in line with the Tullow Incentive Plan (TIP) offered at senior levels. We also believe that the changes provide better employee alignment with our overall Company scorecard objectives and reflect our collaborative approach and team spirit.
Around 1,100 Tullow employees across 12 countries benefited from the first half of an exceptional ESAP award vesting in December – the first time in six years that shares have vested for current employees of the Company. This acknowledges the collective effort in implementing the reorganisation of the business through the MSP.
Performance management, under the annual appraisal process, has been simplified and now ranks performance in three categories: outstanding, successful and developing. These categories assist in providing more clarity to employees on their performance and recognise the desired highperforming nature of our organisation.
During 2016, we completed work to ensure we have the right size of organisation to meet Tullow's business needs. While there was a marked reduction in recruitment across the Company, our offices in Ghana, Kenya and Uganda continued to evolve, increasing the representation of local nationals in their workforces, in line with the respective governments' localisation objectives.
Tullow continues to focus on fair and equal representation of African nationals and female employees across the group. While we have strong diversity in nationality with 46 countries represented, there is an under representation of Africans in leadership roles. Our largest business in Ghana has over 65 per cent of employees from the African continent; over a quarter of the workforce is British and the rest are from other nations. However, the challenges in increasing African participation are significant as the oil and gas sector is only just developing in our countries of operations and so there are currently fewer people with sector-specific skills.
Women made up 29 per cent (336/1,152) of our total workforce (2015: 28 per cent; 396/1,403), 13 per cent (9/68) of senior managers (2015: 12 per cent; 14/115); and 18 per cent (2/11) of our Board of Directors.
While there is gender parity in many of our functions, there are imbalances in Development & Operations and Information Systems, reflecting the lower participation of women in these industries in the UK. There are also more women in clerical and administrative roles than in professional or senior leadership levels. The Board is addressing these issues through long-term planning and management of a sustainable people plan and has endorsed a set of aspirational targets.
Our diversity and inclusion plan reinforces our policy of not tolerating discrimination and recognising that our rich diversity, skills, capabilities and cultural backgrounds can add huge value to our business and enhance the employee value proposition, staff engagement and retention.
Our focus in 2016 was to secure senior leadership commitment to the diversity and inclusion agenda and to raise awareness about the benefits of a diverse workforce. One of the first actions we took was to scrutinise our whole population data with the Executive team and those who report to them so they fully understand our challenges and can start to document progress. We also took steps to raise awareness
of the benefits of a diverse workforce through diversity and inclusion workshops and held some sessions on unconscious bias with the Executive and senior managers. In addition, we conducted several focus groups to access employees' views and opinions on diversity and we have incorporated that feedback into our plan.
To ensure we have a broad perspective on these challenges we carried out extensive external networking in our own sector and beyond. We then undertook a benchmarking exercise to gain a better understanding of the particular challenges of increasing the number of technically skilled female and African staff in the workforce.
Further work in this area included a regulatory requirements review of employment law in all our countries of operations to ensure we are compliant. At the end of the year we launched a taskforce to assess our in-house recruitment and promotions policies and procedures, the results of which will be reported next year. Our scorecard this year also included the development of a sustainable diversity plan.
In 2016, we launched two major employee development programmes across the organisation to prepare talented people for future leadership roles. 24 high-potential employees were selected to attend a development centre as part of the Senior Leadership Programme where they were assessed against a model of potential options for future roles and were allocated targeted support from the leadership team. A bespoke development plan was then designed for each participant.
The Executive Development Programme identified eight individuals in Tullow who have the potential to move into an Executive level role within an agreed timeframe. Participants were provided with a one-to-one assessment to create a detailed profile outlining their strengths and development needs.
In Ghana, we held a career development week. The event was successful and will be run annually and used in other locations to build capacity and remind employees of the leadership and development tools and systems available.
We have implemented and applied a 70:20:10 development Framework that provides 70 per cent on the job training and experience, 20 per cent mentoring and 10 per cent formal training. We also ran short focused courses to help leaders and managers support the growth of their teams and improve performance. Over 150 employees attended and more topics will be introduced next year.
The employee survey showed clearly that career and personal development is one of the most important areas for our employees and we will address the issues raised through a dedicated work stream and action plan in 2017.
Tullow has a role to play in creating shared prosperity and leaving a legacy of sustainable social and economic benefits. We aim to do this by paying fair and appropriate amounts of tax, being transparent in the payments we make to governments, creating local employment, and building capacity to enable local businesses to compete as prospective suppliers to Tullow.
Tullow prides itself on its strong licence to operate and deep relationships with host governments in Africa, which are based on a history of respect and delivery. These relationships are underpinned by our alignment to host governments' national priorities. Tullow's successful exploration has initiated nascent oil industries in all three of our key operating countries. There is therefore clearly a role for us to play in supporting the development of institutional and industry capacity to meet our needs and to allow governments and the national economies to optimise the socio-economic benefits that a growing oil industry can bring.
We do this by paying fair and appropriate amounts of tax to our host governments, being transparent about the taxes we pay, creating local employment within Tullow and across our supplier base, and helping to build capacity to enable local businesses to participate in our supply chain and in the broader economy.
Tullow's Group scorecard includes KPIs that track the progress we make in the area of Shared Prosperity, which account for part of Executive Directors' and employees' variable, performancerelated pay. See pages 16 to 21 for more information.
Our payments to governments, including payments in kind, amounted to \$438 million in 2016 (2015: \$391 million). Total payments to all major stakeholder groups including employees, suppliers and communities, as well as governments, brought our total socio-economic contribution to \$1 billion (2015: \$1.1 billion). This included \$337 million spent with local suppliers, \$227.4 million
"There is a role for us to play in supporting the development of institutional and industry capacity to meet our needs and to allow governments and the national economies to optimise the socio-economic benefits that a growing oil industry can bring."
Aidan Heavey Chief Executive Officer
in payroll globally and \$3.3 million in discretionary spend on social projects.
Our total payments made to the Ghanaian Government in 2016 amounted to \$236 million (2015: \$237 million). The increase in income taxes and Value Added Tax was partially offset by a reduction in our carried interest payments of approximately \$33 million.
Activity on Ghana's TEN Project and, more recently, the Jubilee Turret Remediation Project have created opportunities for Tullow to meet our commitment to increasing the participation of local companies in our supply chain. Our strong engagement with the Ghana Petroleum Commission (PC) has been integral to ensuring our efforts are aligned to Local Content and Local Participation Regulations (LI 2204). As a result of initiatives such as unbundling large scopes of work to identify opportunities for participation of local businesses and early recognition of contracts which can be tendered exclusively in country, our spend with local companies has increased as a proportion of total supplier spend and is up 5 per cent from 2015 to 17 per cent. On selected contracts we continue to mandate minimum local content expectations within contracts with our international suppliers. Contracts with in-country capability in 2016 included: construction, information services, socio-economic investment projects, civil engineering, training and consultancy services, aviation and marine transport.
During the year in Ghana, there was a notable shift in spend away from purely international companies to Joint Ventures between Ghanaian and international
companies. Joint Ventures registered in-country meet the requirements of LI2204, bring further foreign direct investment to build capacity to meet the requirements of the industry, and develop a competitive supplier base for Tullow to engage.
Tullow in Ghana continues to support local businesses to develop their capacity to meet the high technical standards and requirements of the oil and gas industry. Together with the PC, we delivered three pre-tender seminars, bringing the total number of local business development seminars provided since 2013 to over 20, reaching 1,300 participants.
Outside the traditional oil and gas scope of work, Tullow Ghana also carried out a six-month pilot programme where 25 per cent of our foreign exchange business was tendered through indigenous banks. This initiative, supported by a capacity-building seminar, received a commendation from the PC. Our ongoing efforts were also recognised at the 2016 Offshore Oil and Gas Awards, where Tullow Ghana received the Best Ghana/Local Content Initiative Award.
In Kenya, the trend of increasing the proportion of Tullow capital expenditure targeting local suppliers continued. In 2016, 31 per cent of overall supplier spend was with Kenyan businesses, up from 25 per cent in 2015. However, lower oil prices in 2016 led to lower capital spending and a significant reduction in operational activity, reducing the overall amount spent with both local and international companies.
The increased participation of Kenyan businesses in Tullow's supply chain has been achieved as a result of a number of initiatives included in our Local Content and Capacity Building framework. These include supporting training in business skills such as project management, record keeping, business planning, accounting and marketing. This training targeted small and medium-sized businesses which may benefit in general from the presence of our industry, even if not directly engaged in our supply chain. For potential suppliers, we also provided training on the process and requirements for participating in tenders, as well as mentorship programmes, supplier on-boarding and quarterly supplier forums. This approach is expected to help increase participation of local suppliers across our activities.
SPEND WITH SUPPLIERS (\$ MILLION)
Internationals International/JV Local businesses
In Ghana, we have built a strong relationship with the regulator to improve the number of nationals in the Ghana operations. There have been a number of joint initiatives between the PC and Tullow Ghana to support localisation through weekly meetings, resulting in the joint review and signing off of Tullow Ghana's localisation plans. Ghana has also initiated a localisation programme with five streams – Development, Resourcing, Localisation Strategy, Localisation Performance Management, and Employee Value Proposition – led by the leadership team to address localisation challenges holistically.
The Ghana business introduced its RISERS Programme which is focusing on developing high-potential employees into management roles and enhancing localisation at the senior levels. The programme is for two years with two development streams: Future Managers Programme and Technical Experts Programme. Eighteen employees, spread across various functions, at mid-career level who have demonstrated consistent strong performance and high potential have been selected and are being developed in line with the Tullow development framework on the programme.
2016 was a year of transition for Tullow. Flagship programmes, including our international scholarship programme which saw 426 African students complete master's programmes in the UK and Ireland over the course of six years, were completed. We completed our commitment to the Jubilee Technical Training Centre (JTTC) in Takoradi, Ghana, and that facility is now a part of Takoradi Polytechnic. Finally, we opened both the Essikado Maternity Hospital and Asuansi Science Laboratory and transferred the management of both to the local authorities.
Tullow's approach to socio-economic investment has been reviewed and improved with a focus now on: 1) building capacity through education STEM subjects – science, technology, engineering and mathematics; 2) projects which strengthen local and national economies; and 3) developing shared infrastructure by adapting and leveraging Tullow's infrastructure plans and projects to benefit host communities.
Tullow will look for funding from other businesses, multilaterals and foundations to better leverage our investments. To improve delivery, we will commission partners with expertise in implementing projects. Putting this new approach into operation will be a priority in 2017.
This Strategic Report and the information referred to herein have been approved by the Board and signed on its behalf by:
Kevin Massie Corporate Counsel and Company Secretary
Operatives onboard the TEN FPSO, Prof. John Evans Atta Mills, offshore Ghana
| Directors' report | 60 |
|---|---|
| Audit Committee report | 69 |
| Nominations Committee report | 74 |
| EHS Committee report | 76 |
| Ethics & Compliance Committee report | 78 |
| Remuneration report | 80 |
| Other statutory information | 101 |
As a UK premium listed Company, Tullow Oil plc's governance policies and procedures are based on the principles of the UK Corporate Governance Code (2014) ('the Code'). A copy of the Code is available at www.frc.org.uk. Notwithstanding the fact that the reporting period to which this document relates began before 17 June 2016, the Company considered it beneficial to adopt the provisions of the April 2016 edition of the Code for the year ended 31 December 2016 earlier than required by the UK Listing Rules.
This corporate governance report describes how the Company has applied the principles and standards set out in the Code during the year and sets out our activities relating to the main sections of the Code: leadership, effectiveness, accountability, remuneration and relations with shareholders.
The Company is also required to disclose whether it has complied with the more detailed provisions of the Code during the year and, to the extent it has not done so, to explain any deviations from them. It is the Board's view that the Company has fully complied with all of the provisions of the Code during the year ended 31 December 2016. While the Board believes that the Company has been fully compliant with the Code during the year ended 31 December 2016, Tullow's recent announcement of proposed Board changes, specifically the appointment of Aidan Heavey as non-executive Chairman from the conclusion of the 2017 Annual General Meeting subject to shareholder approval, contravenes section A.3.1. of the Code. The Board believes that this is a necessary and temporary deviation from the principles of the Code in order to ensure an orderly transition of key stakeholder relationships held by Aidan as the Company's founder and long-serving Chief Executive Officer as he moves into retirement. A full explanation of the Board's decision is set out on page 75 of the Nominations Committee report.
The long-term success of the Company is the collective responsibility of the Board.
The Board is accountable to shareholders for the creation and delivery of strong, sustainable financial performance and long-term shareholder value. It meets these aims through setting the Group's strategy and ensuring that the necessary resources
are available to achieve the agreed strategic goals. The Board also sets the Company's key policies and reviews management and financial performance. The Board operates within a framework of controls and these clear procedures, lines of responsibility and delegated authorities allow risk to be assessed and managed effectively. These are underpinned by the Board's work to set the Group's core values and standards of business conduct and ensure that these, together with the Group's obligations to its stakeholders, are widely understood across all its activities.
The Board and its Committees deal with its core activities in planned meetings throughout the year. Matters which require decisions outside the scheduled meetings are dealt with through additional ad hoc meetings and conference calls. During 2016, the Board met seven times. A programme of strategy presentations covering a wide number of operational and other issues is made to the Board in June each year. During the year, each of the Business Delivery Team heads and other heads of functions presented a strategic overview of their respective area to the Board for endorsement. In addition, the Board reviewed and approved the implementation of Tullow's Integrated Management System designed to centralise and simplify Tullow's policies and processes and more clearly map accountabilities within the business. The Board also regularly reviews the Enterprise Risk Management System and the risks facing the Company in conjunction with the Audit Committee.
The Board normally holds one Board meeting at a principal overseas office of the Group. These meetings ensure that the Board has a clear knowledge of the Company's overseas operations. During the trip, Senior Management from across the Group present to the Board and have an opportunity to meet its members informally. In addition, the Board meets a broad cross-section of staff, assesses Senior Managers and reviews in-depth operational matters and, in particular, matters relating to non-technical risks. In October 2016, the Board travelled to Cape Town.
The Chairman and the Chief Executive Officer maintain frequent contact with the other Directors in addition to the regular Board meetings. This ensures that all members of the Board have an opportunity to discuss any issues of concern and to be fully briefed on the Group's operations.
The Board has a formal schedule of matters reserved that can only be decided by the Board. This schedule is reviewed by the Board each year. The key matters reserved are the consideration and approval of:
During 2016, the Board considered all relevant matters within its remit, with a particular focus on the following issues:
The attendance of Directors at the seven scheduled meetings of the Board held during 2016 was as follows:
2
| Director | No. of meetings attended (out of a total possible) |
|---|---|
| Tutu Agyare | 7/7 |
| Mike Daly | 7/7 |
| Anne Drinkwater | 7/7 |
| Ann Grant | 7/7 |
| Aidan Heavey | 7/7 |
| Steve Lucas | 7/7 |
| Graham Martin | 2/2 |
| Angus McCoss | 7/7 |
| Paul McDade | 7/7 |
| Ian Springett | 6/7 |
| Simon Thompson | 7/7 |
| Jeremy Wilson | 7/7 |
In addition to the Board members, a number of Senior Managers attend relevant sections of Board meetings by invitation.
The Chairman is primarily responsible for the effective working of the Board, whilst the Chief Executive Officer is responsible for the operational management of the business, for developing strategy in consultation with the Board and for implementation of the strategy. This separation of responsibilities is clearly defined and agreed by the Board.
The Chairman leads the Board, setting the agenda and ensuring that the meetings provide adequate time for discussion. From the time of his appointment as Chairman on 1 January 2012, and throughout his tenure of office, including for the year ended 31 December 2016, Simon Thompson met the independence criteria set out in the Code.
Non-executive Directors
The non-executive Directors have a broad range of business and commercial experience. They provide independent and constructive challenge to the Executive Management and monitor the performance of the management team in delivering the agreed objectives and targets. At the end of every scheduled Board meeting, the Chairman holds a discussion with the non-executive Directors without the Executive Directors. These are supplemented by informal meetings between the Chairman, the Chief Executive Officer and the non-executive Directors.
The non-executive Directors receive regular briefings on the more technical and operational aspects of the Group's activities. These include major offshore projects (e.g. TEN, the Jubilee Turret Remediation Project and the Kenya Early Oil Pilot Scheme). Non-executive Directors with particular expertise in these areas also meet the Chief Operating Officer and the Exploration Director to discuss operations in more detail.
Non-executive Directors are initially appointed for a term of three years, subject to annual re-election. This may, subject to satisfactory performance and re-election by shareholders, be extended by mutual agreement.
The Senior Independent Director is available to meet shareholders if they have concerns that cannot be resolved through discussion with the Chairman, the Chief Executive Officer or the Chief Financial Officer or for matters where such contact would be inappropriate. During the year, she met with the other non-executive Directors without the Chairman to discuss the Chairman's performance.
The Board has delegated matters to five Committees: the Audit Committee, the EHS Committee, the Ethics & Compliance Committee, the Nominations Committee and the Remuneration Committee and the Board is satisfied that the Committees have sufficient resources to carry out their duties effectively. Their terms of reference are reviewed and approved annually by the Board and the respective Committee Chairs report on their activities at the next Board meeting. Details of Committee membership, roles and work are set out later in this report: the Audit Committee on page 69, the EHS Committee on page 76, the Ethics & Compliance Committee on page 78, the Nominations Committee on page 74, and the Remuneration Committee on page 80.
In addition to delegating certain matters to Board Committees, the Board has also delegated certain operational and management matters to the Executive Directors. In line with ICSA guidance, the Board approved formal terms of reference for the Executive Directors' Committee in December 2014 and reviewed and reaffirmed these terms of reference in December 2016.
During the year ended 31 December 2016, the Board comprised the Chairman, the Chief Executive Officer, three other Executive Directors and six independent non-executive Directors. Their biographical details are set out on pages 42 and 43.
The Directors believe that the Board and its Committees consist of Directors with an appropriate balance of skills, experience, independence and diversity of background to enable them to discharge their duties and responsibilities effectively. The composition of the Board reduced by one with the retirement of Executive Director Graham Martin at the 2016 AGM.
The Board considers each of the non-executive Directors to be independent in character and judgement. The Board is fully satisfied that Ann Grant demonstrates complete independence and robustness of character and judgement in her capacity as Senior Independent Director. The Board is of the view that no individual or group of individuals dominates decision making.
Governance & risk management 16%
The Nominations Committee reviews the structure, size and composition of the Board and makes recommendations to the Board about any changes required. As part of the appointments process, candidates disclose any other significant time commitments they may have and are required to inform the Board of any subsequent changes to such commitments.
All Directors have disclosed their other significant commitments and confirmed that they have sufficient time to discharge their duties effectively.
All new Directors receive an induction programme when they join the Board. This reflects their background, experience and knowledge and their understanding of the upstream oil industry and Tullow in particular. The programme includes one-to-one meetings with Senior Management, functional and Business Unit heads and, where appropriate, visits to the Group's principal offices and operations. New Directors also receive an overview of their duties, corporate governance policies and Board processes.
All members of the Board have access to appropriate professional development courses to support them in meeting their obligations and duties. During the year, Directors attended external seminars on relevant topics relating to the business. They also receive ongoing briefings on current developments, including updates on governance and regulatory issues.
Directors have access to independent professional advice, at the Company's expense, on any matter relating to their responsibilities.
The Company Secretary is Kevin Massie, who is also the Company's Corporate Counsel. He is responsible for ensuring compliance with all Board procedures and for providing advice to Directors when required. The Company Secretary provides company secretarial services to the Board and the Group. He acts as secretary to the Audit, Ethics & Compliance, Nominations and Remuneration Committees and has direct access to the Chairs of these Committees.
In accordance with the requirements of the UK Governance Code, listed companies are required to undertake an external evaluation of the performance of the Board every three years, and accordingly, the Board engaged Lintstock Ltd. Lintstock has no other connection to the Company.
The first stage of the review involved Lintstock engaging with the Chairman and the Company Secretary to set the context for the evaluation and to tailor questionnaires to the specific circumstances of the Company. All respondents were then requested to complete an online questionnaire addressing Board, Board Committees, Chairman and individual performance. Interviews were then conducted with members of the Board by two partners from Lintstock to expand upon the issues raised in the questionnaires. The anonymity of all respondents was ensured throughout the process in order to promote the open and frank exchange of views. Lintstock subsequently produced a report which addressed the following areas:
The Board objectives for 2017, set out on page 65, reflect the action plan and priorities agreed by all the Directors as part of the evaluation.
We remain confident that the Board and the wider leadership team have the experience and track record to meet the Company's aims of delivering long-term growth and successfully managing the challenges of an expanding international company. The Board sets its specific future objectives at the end of each year and they reflect the particular focus of the Company in the year ahead. Progress against each objective is tracked by the Company Secretary and reviewed with the Chairman at the mid-year point.
The following table shows how the Board performed against the 2016 objectives and also details the priorities and rolling agenda items the Board will focus on in 2017.
All Directors seek re-election every year and accordingly all Directors will stand for re-election in 2017 with the exception of Simon Thompson and Ann Grant who have already announced their resignations from the Board at the conclusion of the 2017 Annual General Meeting. The Board will set out in the Notice of AGM its reasons for supporting the re-election of each of the Directors at the forthcoming AGM. The Notice of AGM will be mailed to shareholders separately.
| 2016 Board Objectives | |
|---|---|
| Strategy and execution |
Test Tullow's strategy against evolving market and socio-political conditions to ensure that we: • reduce costs, maximise cash flow from operations and manage the business to deleverage the balance sheet; • pursue portfolio management options; • deliver the TEN Project on time and on budget; • create options for future growth, and continue to high-grade prospects, while minimising exploration expenditure; and • eliminate non-core activities and focus on core value creation opportunities. |
| Risk management |
Ensure the effective implementation of the revised enterprise risk management process. Maintain focus on: • liquidity management; • operational and project risk; • safety, health and environment; • community relations and social performance; • reserves and resources management; and • government relations. |
| Governance and values |
• Maintain and enhance Tullow's culture and values under challenging market conditions. • Ensure the new Code of Ethical Conduct is embedded and encourage all levels of management to champion the new Code. • Ensure that the Integrated Management System (IMS) is embedded and that Tullow's policies, standards and procedures are consistently followed and result in efficient, safe and responsible operations. |
| Organisational capacity |
• Monitor and assess the new organisational design. Continue to look for ways to improve efficiency, effectiveness and accountability. • Continue to develop effective succession planning for the Executive Directors and Senior Management. • Develop detailed plans to enhance the diversity of the leadership pipeline. |
| Stakeholder engagement |
• Ensure that shareholders, staff and other major stakeholders understand and are aligned with the Tullow strategy. • Engage with shareholders and other key stakeholders to develop an appropriate remuneration policy for approval by shareholders in 2017. • Further enhance engagement with governments and Civil Society Organisations (CSOs) in our principal countries of operation. |
| 2016 Board Performance | 2017 Board Objectives |
|---|---|
| • The strategy was debated at the Board's annual strategy offsite in June and regularly reviewed throughout the year, as market conditions evolved. • The Board received regular updates on the TEN Project, which achieved first oil in August 2016, on time and on budget. • Cost reduction campaigns throughout the business resulted in a reduction of \$82 million in net G&A. • The exploration budget was reduced to \$116.4 million resulting in a reduction in Group capex while still creating significant opportunities for future growth. • Significant progress was made towards the EOPS project in Kenya and the Board welcomed the return to exploration drilling in Turkana commencing in December 2016. In Uganda, significant progress was achieved around the proposed pipeline route and settlement of legacy issues. • A number of non-core assets were successfully sold including the majority of Norwegian licence areas. • A revised enterprise risk management process was implemented, which maps Tullow's key risks, potential impacts, mitigation strategies and assurance processes. • A new integrated risk management system has been launched across the Tullow Group to centralise and simplify corporate policies and standards. The Board receives regular reporting of project-specific technical and non-technical risks. • The Board receives quarterly political risk reports highlighting emerging issues in the countries and regions where Tullow is active. • Performance management has been added as a key component of the |
• Review Tullow's strategy in light of the changed external environment. • Ensure West Africa is managed to maximise cashflow, through safe and efficient operations and the efficient use of capital, whilst extending the period of production plateau. • Clarify the plan for commercialisation of East Africa resources and support its execution. • Articulate Tullow's risk appetite and encourage active portfolio management to balance risk and reward. • Deleverage balance sheet, manage financial structure and employ capital to maximise returns. • Refocus the Company on value growth through a combination of exploration and new investment opportunities. • Continue to assess our risk appetite and identify and mitigate key risks in our business. • Ensure, through the Board Committee structure, an active overview of and interaction with the Company's Enterprise Wide Risk process. • Ensure there is an ongoing consideration of the Company's top risks, that these are identified in the EWR process and are being actively managed by the Executive. |
| strategic people plan and is subject to regular Board review. • The new Code of Ethical Conduct was successfully launched across Tullow with E-learning modules and self-certification against the Code approaching a 97 per cent response rate. • The new Ethics & Compliance Committee of the Board met periodically to review the Company's performance, including performance against a specific Ethics & Compliance KPI in the Group scorecard. • The IMS was launched and is targeting full compliance by the end of 2016. |
• Maintain and enhance Tullow's culture and values as market conditions continue to improve. • Ensure that the Code of Ethical Conduct is actively followed throughout all levels of the Company and maintain a culture of accountability for ethics and compliance in both the Business Units and the corporate centre. • Monitor compliance against the new IMS and ensure that the IMS is continuously improved as the business evolves. • Ensure that Tullow's policies, standards and procedures, as set out in the IMS, are consistently followed ensuring efficient, safe and responsible operations. |
| • Following the completion of the Major Simplification Project, considerable focus was placed on retaining cost consciousness, performance management and accountability in the business. • The Nominations Committee met frequently throughout the year to advance succession planning at executive director level and below. • A new Senior Leadership programme was launched to identify and develop future leaders with an emphasis on ensuring a diverse and deep pipeline of talent. • Succession planning, diversity and talent management were discussed periodically at the Board meetings and were reviewed in depth at the Board's strategy offsite meeting. |
• Work with the new CEO and Executive team to ensure a smooth executive transition. • Review Board structure for current environment and changed management. • Review effectiveness of each Committee. • Continue to assess the post MSP organisational design and ensure that the Executive and OSE are actively improving the organisational efficiency, effectiveness and accountability. • Continue to develop effective succession planning for the Executive and Non-Executive Directors and senior management. • Ensure that the diversity programme, initiated in 2016, to improve diversity across the whole organisation remains an area of focus for the Executive team. |
| • Both Executive and non-executive Directors engaged with shareholders, staff, CSOs and other major stakeholders throughout the year. • Internal communications continued to be improved with the roll-out of new E-learning modules and more targeted employee communications. |
• Work with the new CEO to ensure a smooth transition of high-level stakeholder relationships. • Ensure that shareholders, staff and other major stakeholders understand and are aligned with the Tullow strategy. • Ensure that the organisation fully understands the importance of stakeholder relationships in Tullow's strategy of shared prosperity. |
Exploration and production companies have faced yet another challenging year in 2016 with oil prices falling to record lows in the first half of the year, impacting both companies and investors. The sector did, however, see some recovery in the second half of the year, with oil prices reaching over \$50/bbl, positively impacting stocks across the sector. Tullow's share price increased just short of 100 per cent during the year, exceeding the performance of our peer companies.
Tullow's outperformance is not purely down to the oil price, as this year we saw the Company deliver against market expectations and deal with the various challenges the Group faced, such as TEN first oil; work to resolve the Jubilee turret issue and affirmation of insurance cover; significant progress in East Africa; and prudent management of our balance sheet. Regular communication of these achievements and challenges is a key part of our dialogue with shareholders and the Investor Relations (IR) team and Executives have maintained open and transparent channels throughout the year.
This has been achieved through regulatory announcements, regular meetings, presentations, investor conferences and ad hoc events with institutional investors and sell-side analysts. Over the year, the IR team and Senior Management met some 330 institutions and the Group participated in over
30 roadshows and investor conferences around the world. Executive Directors and Senior Management met institutional investors in the UK, Europe, Ghana, South Africa and North America.
Tullow also proactively organised two roadshows for governance analysts led by the Chairman, who was joined by the Senior Independent Director, the Chair of the Remuneration Committee and the Company Secretary. One of these roadshows was specifically to gain feedback on Tullow's revised remuneration policy. Institutional shareholders are offered the opportunity to meet the Chairman to discuss any issues and concerns in relation to the Group's governance and strategy. Non-executive Directors are also available to attend meetings with major shareholders if requested to do so.
Tullow also proactively offered conference calls with Socially Responsible Investors to discuss topics including health and safety, the environment, corporate governance, bribery and corruption, country and political risk and other operational matters. These meetings were hosted by our Vice President of SSEA and the IR team.
Tullow's fifth Ghana Investor Forum took place in May 2016 in Accra. The event gave key institutional shareholders the chance to hear presentations and question the Executive Directors and Senior Managers from the Ghana Business Unit.
| Mutual Fund Manager | 38 |
|---|---|
| Pension Fund Manager | 20 |
| Insurance Fund Manager | 12 |
| Asset Manager | 11 |
| Private Banking | 8 |
| Other | 11 |
| Value & Growth | 40 |
|---|---|
| Retail | 15 |
| Value | 11 |
| Growth | 10 |
| Hybrid | 7 |
| Other | 17 |
We ensure shareholders can access details of the Group's results and other news releases through the London Stock Exchange's Regulatory News Service. In addition, these news releases are published on the Media section of the Group's website: www.tullowoil.com. Shareholders and other interested parties can subscribe to email news updates by registering online on the website. The Group continually looks for ways to improve how we use online channels to communicate with our stakeholders through our corporate website, webcasting and social media channels.
Another important way we keep shareholders informed is through regular formal reporting and Tullow's reports are available on the corporate website.
The IR and Group Finance teams have continued their engagement with our bond investors through a number of high-yield conferences and one-on-one meetings throughout the year.
Trading Statement and Operational Update
Full-year Results
Annual General Meeting Annual General Meeting Trading Update
Trading Statement and Operational Update Half-year Results
November Trading Update
Financial results, events, corporate reports, webcasts and fact books are all stored in the Investor Relations section of our website www.tullowoil.com/investors.
2016 Annual Report and Accounts www.tullowoil.com/reports.
This report provides shareholders with a clear assessment of the Group's position and prospects supplemented, as required, by other periodic financial and trading statements.
The Board's arrangements for the application of risk management and internal control principles are detailed below. The Board has delegated oversight of the relationship with the Group's external auditor to the Audit Committee. Its work is outlined in the Audit Committee report on page 69.
The Directors acknowledge their responsibility for the Group's systems of internal control, which are designed to safeguard the assets of the Group and to ensure the reliability of financial information for both internal use and external publication and to comply with the requirements of the UK Corporate Governance Code.
Overall control is ensured by a regular detailed reporting system covering both technical progress of projects and the state of the Group's financial affairs. The Board has put in place procedures for identifying, evaluating and managing principal risks that face the Group. Principal risks are regularly reported to the Board.
Tullow recognises that any system of internal control can provide only reasonable, and not absolute, assurance that material financial irregularities will be detected or that the risk of failure to achieve business objectives is eliminated. However, the Board's objective is to ensure that Tullow has appropriate systems in place for the identification and management of risks.
In accordance with the requirements of the UK Corporate Governance Code, the Board of Directors is required to monitor the Company's risk management and internal control systems and, at least annually, carry out a review of their effectiveness, and report on that review in the Annual Report. At Tullow, the Board has delegated responsibility for this assessment to the Audit Committee, and results of the assessment are described on page 73.
The Board has delegated responsibility for agreeing the remuneration policy for the Chairman, the Chief Executive Officer, the Executive Directors and the Senior Executives with the Remuneration Committee. Its role and activities are set out in the Directors' Remuneration Report on page 80.
At the AGM held on 28 April 2016, shareholders received presentations setting out the key developments in the business and put questions to the Chairman, the Chairmen of the Audit, Nominations and Remuneration Committees and other members of the Board.
A poll was used to vote for all resolutions at the 2016 AGM, and the final results (which included all votes cast for and against and those withheld) were announced via the London Stock Exchange and on the Company's corporate website. Notice of the AGM is sent to shareholders at least 20 working days before the meeting.
On behalf of the Board
7 February 2017
Risk management 44 Long-term viability statement 52
Maintaining a strong corporate governance and risk management practice is a key part of Tullow's business model and the Board and Audit Committee continue to be focused on maintaining high standards of governance and risk management across the Group. The Audit Committee oversees the financial reporting process in order to make sure that the information provided to the shareholders is fair, balanced and understandable and allows assessment of the Company's position, performance, business model and strategy.
The Audit Committee continued to oversee the risk management and internal control systems in 2016, which were particularly tested as the Company adjusted to a low oil price and reacted quickly to reduced production from the Jubilee field caused by an issue with the FPSO turret. In 2016, the focus of the Audit Committee was to ensure that the enhancements made to the risk management practices were sustainable and embedded as part of ongoing business performance management. We were pleased with greater integration of the risk management process with assurance planning which ensures greater alignment with strategic risks, while keeping ongoing focus on the material financial, operational and compliance controls. The Audit Committee plays an active role in that process by making sure it meets business needs and remains fit for purpose.
The internal control environment has also seen improvements during the year, predominantly due to the roll-out of a common Integrated Management System, which provided clarity around the control requirements, successful launch of the revised Code of Ethical Conduct, as well as a reduction in fraud risk by implementation of a formalised segregation of duties framework and an automated GRC solution to manage SAP system access risks.
The Audit Committee has also worked on adapting to the changes brought in 2016 to the regulatory framework regarding auditor independence and the requirements for the Audit Committee performance introduced by publication of the revisions of the Financial Reporting Council's UK Corporate Governance Code, Guidance on Audit Committees and the Ethical Standard.
Chairman of the Audit Committee
7 February 2017
"The Board's objective is to ensure that Tullow has appropriate systems in place for the identification and management of risks."
Chairman of the Audit Committee
| Committee members | Meetings attended |
|---|---|
| Steve Lucas | 4/4 |
| Tutu Agyare | 4/4 |
| Anne Drinkwater | 4/4 |
| Ann Grant | 4/4 |
| Jeremy Wilson | 4/4 |
| Mike Daly | 4/4 |
Steve Lucas has been Audit Committee Chairman since May 2012. Steve, who is a Chartered Accountant, was finance director at National Grid plc from 2002 to 2010. It is a requirement of the UK Corporate Governance Code that at least one Committee member has recent and relevant financial experience and Steve Lucas therefore meets this requirement. The other members of the Audit Committee are Ann Grant, Tutu Agyare, Anne Drinkwater, Jeremy Wilson and Mike Daly. Biographies of the Committee members are given on pages 42 and 43. Together the members of the Committee demonstrate competence in the oil and gas industry with Mike Daly, Anne Drinkwater and Steve Lucas having significant prior experience in oil and gas companies, while also bringing a wider range of industry, commercial and financial experience, which is vital in supporting effective governance. The Company Secretary serves as the secretary to the Committee.
The Chief Financial Officer, the Group Internal Audit Manager, the Vice President – Commercial & Finance and representatives of the external auditor are invited to attend each meeting of the Committee and participated in all of the meetings during 2016. The Chairman of the Board also attends meetings of the Committee by invitation and was present at all of the meetings in 2016. The external auditor and the Group Internal Audit Manager have unrestricted access to the Committee Chairman.
| Financial Results | 42% |
|---|---|
| Internal audit matters | 12% |
| Risk and controls | 32% |
| Governance | 14% |
In 2016, the Audit Committee met on four occasions. Meetings are scheduled to allow sufficient time for full discussion of key topics and to enable early identification and resolution of risks and issues. Meetings are aligned with the Group's financial reporting calendar.
The Committee reviewed and updated its terms of reference during the year. These are in line with best practice and reflect the requirements of the 2016 revision of the UK Corporate Governance Code, the FRC's 2016 Guidance on Audit Committees, the FRC's 2014 Guidance on Risk Management and Internal Control, the FRC's 2016 Ethical Standards, and the Competition and Markets Authority's The Statutory Audit Services for Large Companies Market Investigation (Mandatory Use of Competitive Tender Processes and Audit Committee Responsibilities) Order 2014. The Audit Committee's terms of reference can be accessed via the corporate website. The Board approved the terms of reference on 6 December 2016.
The Committee's detailed responsibilities are described in its terms of reference and include:
While the Ethics & Compliance Committee maintained responsibility for monitoring systems and controls to prevent bribery and corruption, the Audit Committee still received updates from the Group Ethics & Compliance Manager on any significant non-compliances.
The Committee fully discharged its responsibilities during the year and the following describes the work completed by the Audit Committee in 2016:
A key element of the governance requirements regarding the Group's Financial Statements is for the report and accounts to be fair, balanced and understandable. To ensure this requirement is met by Tullow, the Group takes a collaborative approach to creating its Annual Report and Accounts, with direct input from the Board throughout the process. The process of planning, writing and reviewing the report is run by a central project team, alongside a formal audit process undertaken by our external auditor. In order for the Audit Committee and the Board to be satisfied with the overall fairness, balance and clarity of the final report, the following steps are taken:
| Significant financial judgements for 2016 | How the Committee addressed these judgements |
|---|---|
| Recognition of finance lease liabilities: The Group has a contract with a supplier for the lease of the TEN FPSO. Management were required to exercise judgement in determining whether the FPSO should be recognised as a finance lease in accordance with IAS 17 as at December 2016. The key judgement involved in determining whether a finance lease should be recognised was an assessment of key contractual clauses, as due to the delays in commissioning the vessel the Certificate of Offshore Completion was not issued before 31 December 2016, and as such the non-cancellable lease period had not commenced. In addition, the Group had not obtained the right of use of the vessel in its intended form. |
The Committee and Deloitte LLP reviewed and challenged management's judgement that the TEN FPSO lease did not meet the IAS 17 finance lease recognition criteria at year end 31 December 2016. |
| Recognition of assets held for sale (see also note 18 to the Financial Statements): The Group signed a sales and purchase agreement to farm-down a portion of our interest in Uganda to Total on 9 January 2017. Management has exercised judgement in determining that this disposal met the requirements of IFRS 5 and that the associated assets and liabilities should be transferred to held for sale at 31 December 2016. |
The Committee and Deloitte LLP reviewed and challenged management's judgement that they were committed to the farm-down and the sale as highly probable ahead of the balance sheet date. |
| Carrying value of intangible exploration and evaluation assets (see also note 11 to the Financial Statements): The amounts for intangible exploration and evaluation assets represent active exploration projects. These amounts will be written off to the income statement as exploration costs unless commercial reserves are established or the determination process is not completed and there are no indications of impairment in accordance with the Group's accounting policy. The process of determining whether there is an indicator for impairment or calculating the impairment requires critical estimation. The key areas in which management has applied judgement and estimation are as follows: the Group's intention to proceed with a future work programme for a prospect or licence; the likelihood of licence renewal or extension; and the success of a well result or geological or geophysical survey. |
The Group has a very active exploration and appraisal work programme and the Committee reviews and challenges management assumptions and judgements underlying the calculation of intangible assets for each licence at each balance sheet date. In addition, Deloitte LLP has identified this as a significant area of focus for its audit and undertakes discussions with operational and finance staff to challenge evidence provided by management to support the value of intangible assets and provides detailed reporting to the Committee on the results of its work. This is a recurring area of judgement. |
| Carrying value of property, plant and equipment (see also note 12 to the Financial Statements): Management performs impairment reviews on the Group's property, plant and equipment assets at least annually with reference to indicators in IAS 36 Impairment of Assets. Where indicators are present and an impairment test is required, the calculation of the recoverable amount requires estimation of future cash flows within complex impairment models. Key assumptions and estimates in the impairment models relate to: commodity prices that are based on forward curves for two years, the mid-term price assumption for three years after this and the long-term corporate economic assumptions thereafter, pre-tax discount rates that are adjusted to reflect risks specific to individual assets, commercial reserves and the related cost profiles. |
Results of the impairment tests were discussed and challenged by the Committee. In addition, Deloitte LLP performs similar procedures and audits the underlying economic models to satisfy itself of the integrity of the process. This is a recurring area of judgement. |
| Presumption of going concern: The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group's producing assets and delays to development projects. In addition to the Group's operating cash flows, portfolio management opportunities and other funding options are reviewed to potentially enhance the financial capability and flexibility of the Group. In the current low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.0 billion of debt liquidity headroom and free cash at the end of 2016. The Group's forecast, taking into account the risks described above, shows that the Group will be able to operate within its current debt facilities and have sufficient financial headroom for the 12 months from the date of approval of the 2016 Annual Report and Accounts. |
The Committee reviewed and challenged the assumptions and judgements in the underlying going concern forecast cash flows by discussing and analysing the risks, sensitivities and mitigations identified by management. This is also an area of higher risk and as a result the Committee receives in-depth written and oral reporting from Deloitte LLP on its conclusions on management assessment of going concern. |
| Decommissioning costs (see also note 23 to the Financial Statements): Decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to the relevant legal requirements, the emergence of new technology or experience at other assets. The expected timing, work scope, amount of expenditure and risk weighting may also change. Therefore significant estimates and assumptions are made in determining the provision for decommissioning. |
A review of all decommissioning cost estimates is undertaken annually by internal experts. The results are then reviewed in the context of operator estimates for the purposes of the annual Financial Statements. Provision for environmental clean-up and remediation costs is based on current legal and contractual requirements, technology and price levels. The impact on decommissioning estimates was reviewed and challenged by the Committee. Deloitte LLP also reviewed the results as part of its audit. This is a recurring area of judgement. |
| Provisions for onerous service contracts (see also note 23 to the Financial Statements): Due to the reduction in planned future work programmes, the Group has identified a number of onerous service contracts. In order to calculate the provisions management has estimated the expected future usage of the contracts and its estimated liability under the contract. |
The Committee reviewed and challenged the assessment of the Group's onerous contracts with Deloitte LLP, including an assessment of the intended usage and assumed rates which underpinned the calculation of the provision. |
In 2016 Tullow's Annual Report and Accounts for 2015 have been subject to a review by the Financial Reporting Council. The review focused on the discount rate used to calculate recoverable amount of goodwill and PPE, goodwill and PPE impairment sensitivities and going concern disclosures. We are pleased with the outcome of the review as no material findings have been reported by the FRC. The FRC has, however, encouraged some improvement to Tullow's disclosure on discount rates, which we have implemented in our 2016 report and accounts. The FRC has also identified a number of other disclosure areas, which are less material for Tullow, which we keep under review to ensure that, if they become material, they are enhanced to meet FRC expectations.
Making recommendations to the Board on the appointment or re-appointment of the Group's external auditors with, where appropriate, the selection of a new external auditor, overseeing the Board's relationship with the external auditor and regular assessment of the effectiveness of the external audit process is a key responsibility of the Audit Committee.
partner throughout the year. These meetings provide an opportunity for open dialogue with the external auditor without management being present. Matters discussed included the auditor's assessment of significant financial risks and the performance of management in addressing these risks, the auditor's opinion of management's role in fulfilling obligations for the maintenance of internal controls, the transparency and responsiveness of interactions with management, confirmation that no restrictions have been placed on it by management, maintaining the independence of the audit and how it has exercised professional challenge.
Responsibility for reviewing the effectiveness of the Group's risk management and internal control systems is delegated to the Audit Committee by the Board.
The Audit Committee obtained comfort over the effectiveness of the Group's risk management and internal control systems through activities coordinated by the Internal Audit function. These activities comprised:
During the year, Group Internal Audit presented its findings to the Audit Committee, which monitored progress of issues raised and their timely resolution on a regular basis.
In addition, during the year, the Audit Committee received reports from the independent reserves auditor ERCE and reviewed the arrangements in place for managing information technology risk relating to the Group's critical information systems. The Committee also reviewed the arrangements for Company employees and contractors to raise concerns through the 'Speaking Up' programme.
Based on the results of the annual effectiveness review of risk management and internal control systems that was coordinated by Group Internal Audit, the Audit Committee concluded that the system of internal controls operated effectively throughout the financial year and up to the date on which the Financial Statements were signed.
Considering how the Group's Internal Audit requirements shall be satisfied and making recommendations to the Board.
in Ghana, Uganda and Kenya. Detailed results from these reviews were reported to management and in summary to the Audit Committee during the year. Where required the Audit Committee receives full details on any key findings. The Audit Committee receives regular reports on the status of the implementation of Internal Audit recommendations. The Group also undertook regular audits of non-operated Joint Ventures under the supervision of Business Unit management and the Group Internal Audit Manager.
Ensuring that an effective whistle-blowing procedure is in place.
• In line with best practice and to ensure Tullow works to the highest ethical standards, an independent whistle-blowing procedure was in operation throughout 2016 to allow staff to raise in confidence any concerns about business practices. This procedure complements established internal reporting processes. The whistle-blowing policy is included in the Code of Ethical Conduct which is available to all staff in printed form and on the corporate website. The Committee considers the whistle-blowing procedures to be appropriate for the size and scale of the Group.
• During the year, the Audit Committee commissioned an independent review of its own effectiveness with the results reported to the Board. The Committee was considered to be operating effectively and in accordance with the UK Corporate Governance Code and the relevant guidance.
The main task of the Nominations Committee is to ensure that the Board has the necessary skills and expertise to support the Company's current and future activities. In addition, we continue to focus on the recruitment, development and retention of a diverse pipeline of managers who will occupy the most senior positions in the Company in the future.
The majority of the Committee's time during the year was spent on CEO succession planning and implementation, and various resulting changes to the Board, its Committees and the Senior Management team. As announced in January 2017, the Committee recommended, and the Board approved, the appointment of Paul McDade as CEO following the AGM on 26 April 2017. At the same time, I will step down as Chairman of the Board and Aidan Heavey will succeed me as Chairman for a transition period of up to two years. These changes represent the culmination of a process of succession planning that has taken place over a number of years, and Aidan's appointment as Chairman reflects the Board's belief that, owing to the unique nature of Tullow's business and relationships across Africa, a phased transition of the leadership is appropriate.
During the course of 2017, the Committee will continue to review the structure, size and composition of the Board and the Senior Management team to ensure that they provide a balanced and diverse range of experience, knowledge and approaches to complement Paul in his new role.
Chairman of the Nominations Committee
7 February 2017
"The majority of the Committee's time during the year was spent on CEO succession planning and implementation."
Nominations Committee Chairman
| Committee members | Meetings attended |
|---|---|
| Simon R Thompson | 5/5 |
| Steve Lucas | 5/5 |
| Tutu Agyare | 5/5 |
| Anne Drinkwater | 5/5 |
| Ann Grant | 5/5 |
| Jeremy Wilson | 5/5 |
The Committee reviews the composition and balance of the Board and the senior executive team on a regular basis and also ensures robust succession plans are in place for all Directors and senior executives. When recruiting new Executive or non-executive Directors, the Committee appoints external search consultants to provide a list of possible candidates, from which a shortlist is produced. External consultants are instructed that diversity is one of the criteria that the Committee will take into consideration in their selection of the shortlist. The Committee's terms of reference are reviewed annually and are set out on the corporate website.
The Committee's main duties are:
The composition of the Committee changed at the beginning of 2016 to include all non-executive Directors. Simon Thompson was Chairman of the Committee throughout the year. The membership and attendance of members at Committee meetings held in 2016 are shown in the adjacent table.
In addition to five formal meetings, the Committee held a number of informal discussions, telephone conference calls and interviews during the year.
of this review the Committee recommended the appointment of Jeremy Wilson as Chairman of the Nominations Committee; Mike Daly as Chairman of the Ethics and Compliance Committee; and Tutu Agyare as Chairman of the Remuneration Committee. All of these changes were approved by the Board and will occur with effect from the conclusion of the 2017 AGM.
The Environment, Health and Safety (EHS) Committee monitors the performance and key risks the Company faces in relation to its occupational and process safety, security, health and environmental management.
The Committee has an ongoing focus on process safety. Following its site visit to the FPSO Kwame Nkrumah in October 2015, the Committee actively monitored the Jubilee Asset Integrity Plan throughout 2016. The Committee also reviewed the new operating and offtake procedures which were implemented following identification of an issue with the Jubilee turret bearing.
With the commissioning and start-up of a second FPSO in Ghana this year, the Committee was also involved in reviews of the readiness of equipment, processes, and the organisational structure and staff competence of the integrated operations team for both facilities.
During 2016, Tullow issued a new Human Rights Policy. This supports and enhances the Company's commitment to the UN Voluntary Principles on Security and Human Rights (VPSHR) in its operations.
Chair of the EHS Committee
7 February 2017
"The Committee has a forward-looking agenda, and provides appropriate advice about emerging risks that the business might face in its operations."
Anne Drinkwater Chair of the EHS Committee
| Committee member | Meetings attended |
|---|---|
| Anne Drinkwater (Chair) | 4/4 |
| Paul McDade | 4/4 |
| Simon Thompson | 4/4 |
| Mike Daly | 3/4 |
The Committee works to enhance the Board's engagement with EHS through appropriate in-depth reviews of strategically important EHS issues for the Group. The Committee has a forward-looking agenda, and provides appropriate advice about emerging risks that the business might face in its operations. It also reviews a wide range of EHS leading and lagging indicators to gain an insight into how EHS policies, standards and practices are being implemented in the Group's operations. In particular, the Committee reviews high-potential incidents, especially where they have occurred repeatedly in one location or activity. It also scrutinises the outcome of audits and investigations.
The Committee's terms of reference are reviewed annually and are available on the corporate website.
The Committee currently comprises three non-executive Directors and one Executive Director – Paul McDade, who has executive responsibility for EHS across the Group. Anne Drinkwater is Chair of the Committee and chaired all meetings throughout the year. Collectively, the Committee members have considerable operational EHS experience gained from diverse operating environments across the oil and gas and extractive industries.
In addition to the core Committee members, functional heads and senior managers from across the Group were invited to meetings to provide additional details and insights on specific agenda items. They also provide guidance on EHS issues and support discussions about how EHS can be embedded across their parts of the business. In 2016 those attending the meetings included Senior Management from Tullow's operations and management team members from the Safety, Sustainability & External Affairs function.
The Integrated Management System (IMS) was embedded in all of Tullow's businesses during 2016. The Committee monitored its implementation across all aspects relating to EHS and security.
During the year the Committee worked to ensure that lessons learnt from incident investigations and audits were incorporated into the IMS and business processes. An example of this work is the inclusion of environmental and social management plans in the Company's stage gate assurance and decision processes.
Tullow has built a very strong reputation for business integrity and we work hard to maintain this, knowing that it is one of our most valuable assets. Any behaviour which has a negative impact on this reputation could significantly affect our ability to operate and we recognise that this is one of the key risks we must manage.
In 2016, work on Ethics & Compliance continued to have a high profile across Tullow. The Ethics & Compliance Committee met regularly and provided support to the business by encouraging strong ethical behaviour and ensuring full compliance with all relevant legislation. We were encouraged by the strong leadership shown by our senior executives in these areas which has raised awareness across the organisation and provided a very clear message about their importance.
The Committee also undertook a number of specific actions including agreeing a new E-Learning module, approving a full revision to our expenditure related to a public official standard, and supporting increased engagement with the Tullow business.
We remain fully focused on continuing to promote Ethics & Compliance across everything we do and look forward to making further progress in 2017.
Chair of the Ethics & Compliance Committee
7 February 2017
"We remain fully focused on continuing to promote Ethics & Compliance across everything we do and look forward to making further progress in 2017."
Ann Grant Chair of the Ethics & Compliance Committee
| Committee members | Meetings attended |
|---|---|
| Ann Grant | 4/4 |
| Steve Lucas | 4/4 |
| Ian Springett | 4/4 |
The highest standards of ethics and compliance play a critical role in the continued success and integrity of Tullow's business and are an essential part of our risk management processes. The Committee supports the Board in promoting ethics and compliance both in Tullow and with those who work with us, and assures our stakeholders that our policies and approach are adequate and effective.
The term 'ethics' means the Tullow Values and culture, which require us to operate in a way that meets clear ethical standards. 'Compliance' means ensuring that we meet all the requirements of legislation applying to the business and specifically the UK Bribery Act.
The Committee's responsibilities are set out in its terms of reference and are to:
• review compliance performance across the Group using data from monitoring, auditing and investigations.
The Committee's terms of reference are available on the Tullow website and are reviewed annually.
The Committee currently comprises two non-executive Directors, Ann Grant, who chairs the Committee, and Steve Lucas, and one Executive Director, Ian Springett, who has executive responsibility for Ethics & Compliance across the Group. Ann Grant chaired all meetings in 2016. The Chairman of the Board also regularly attended the Committee's meetings.
The heads of key functions in the Group provided specific support for particular agenda items and discussions. In addition, during 2016, the Committee was supported by management team members from Ethics & Compliance, Legal, Organisation Strategy & Effectiveness, and Internal Audit.
The Committee was briefed on, and oversaw, a number of Ethics & Compliance initiatives across the Group. These included:
The Committee's work in 2017 will focus on:
The Remuneration Committee is focused on ensuring Executive Directors are rewarded for the long-term success of the Company rather than short-term returns.
On behalf of the Board, I am presenting the Remuneration Committee's ('Committee's') report for 2016 on Directors' remuneration. The report is again split into three main sections:
On 11 January 2017, Tullow announced a number of changes to its Board which will all become effective following the Company's AGM on 26 April 2017:
• Paul McDade, currently Chief Operating Officer, will be appointed Chief Executive Officer. This follows an internal and external process led by Tullow's Nominations Committee. Paul's base salary of £725,000 is around 18 per cent lower than his predecessor's, and the rest of his remuneration package has been set in line with the proposed 2017 Remuneration Policy – see pages 86 to 89.
"The Committee is particularly pleased with the achievement of strategic financing which ensured funding capacity for 2016 in a downside environment and the successful delivery of the TEN Project which produced first oil on-target in August 2016."
Jeremy Wilson Chairman of the Remuneration Committee
In 2016, assisted by our remuneration advisers PwC, the Committee has conducted a thorough review of the Remuneration Policy which was approved by shareholders in 2014 for the three-year period ending in December 2016 ('the 2014 Policy'). The review has taken into account feedback already received from major shareholders and emerging best practice, including the report of the Investment Association dated 3 July 2016 and the final report of the Executive Remuneration Working Group dated July 2016. As a result of this review, we are proposing a number of amendments to our Directors' Remuneration Policy for the period 2017 to 2019 ('the 2017 Policy').
The Committee believes that the basic structure and underlying principles of the 2014 Policy, including its link to the Group's ongoing strategy and business goals, remains appropriate for Tullow and is accordingly proposing that many components of the 2014 Policy remain the same for the 2017 Policy. However, we are recommending some specific amendments to increase flexibility, to simplify the remuneration structure and to provide challenging yet incentivising targets for our Executive Directors. As a result of a benchmarking exercise, we are also recommending that the maximum opportunity for performance-related pay be reduced. Set out below are the main features of the 2017 Policy highlighting the changes from the 2014 Policy, which are explained in greater detail in the Remuneration Policy Report.
The Committee believes that these proposals will better align the interests of management and shareholders, incentivise, motivate and retain our valued Executive Directors and help us move forward in what promises to be an exciting and challenging time for the industry. Further details of the rationale for the changes are shown in the Director's Remuneration Policy Report.
The Committee continues to monitor executive base salaries in an effort to remain competitive and appropriately placed in the international oil and gas industry. Base salaries are reviewed annually, taking into account the factors set out in the appended policy table. The Committee continued to use the approved 2014 Policy during 2016. At the start of 2016, and for the third consecutive year, Executive Director base salaries were frozen to reflect the continued streamlining and refocusing of the business and the ongoing difficulties of our business sector, representing a reduction in base salaries in real terms. For 2017, other than the salary increase for Paul McDade on appointment to his new role as Chief Executive Officer, in light of the current state of the oil and gas markets, the Committee believes it is appropriate to maintain the freeze on the base salaries for the fourth year running of the other Tullow Executive Directors for the coming year. This represents a further decrease in salaries in real terms.
The performance targets set for 2016 in respect of the TIP awards to be granted in 2017 were challenging in the context of the time and proved even more so as the year progressed.
Although Tullow's share price increased greatly during the year and relative TSR against the comparator group in 2016 was in the upper quartile, TSR is measured over three years for the purposes of the TIP. It is therefore again disappointing to report a nil contribution for the TSR measure, which made up 50 per cent of the corporate scorecard.
However, the Group again scored well on its financial, production, organisational and strategic targets for the year. The Committee is particularly pleased with the achievement of strategic financing which ensured funding capacity for 2016 in a downside environment and the successful delivery of the TEN Project which produced first oil on-target in August 2016.
The net result of these various factors produced an overall KPI performance of 38.8 per cent, resulting in a cash bonus of 97 per cent of salary and a further 97 per cent of salary awarded in shares deferred for five years. Full details of performance against the KPIs is shown on pages 16 and 21.
Your views are very important to the Board of Tullow and we are committed to providing you with clarity and transparency about these key changes to our 2017 Policy. The Committee will again consult major shareholders ahead of any significant future changes to policy, although it is intended that the 2017 Policy for which approval will be sought at the 2017 AGM will remain in operation for the forthcoming three years.
On behalf of the Committee, I would like to thank shareholders for their significant vote approving the 2015 Annual Statement and Annual Report on Remuneration at the last AGM and look forward to your continued support in approving the new remuneration policy for 2017 onwards.
As part of the Board changes coming into effect following the AGM in April, I will be stepping down as Remuneration Committee Chairman and will be replaced by my fellow non-executive Director, Tutu Agyare. For continuity, I will however continue to serve as a member of the Committee. Steve Lucas will also step down from the Committee, and will be replaced by Mike Daly, also from the conclusion of the AGM. I would like to thank Steve for his contributions to the Committee during his tenure, and wish Tutu well in his new role as Chairman.
If you have any comments or questions on any element of the report, please email me at [email protected].
.
Jeremy Wilson Chairman of the Remuneration Committee 7 February 2017
| AGM | Annual General Meeting |
|---|---|
| Capex | Capital expenditure |
| DSBP | Deferred Share Bonus Plan |
| EHS | Environment, Health & Safety |
| ESOS | 2000 Executive Share Option Scheme |
| HMRC | Her Majesty's Revenue and Customs |
| Opex | Operating expenses |
| PSP | Performance Share Plan |
| SIP | UK Share Incentive Plan |
| TIP | Tullow Incentive Plan |
| TSR | Total Shareholder Return |
This report has been prepared in accordance with the requirements of the Companies Act 2006, the Large and Medium-sized Companies and Groups (Accounts & Reports) (Amendment) Regulations 2013, which came into force on 1 October 2013 and which set out the reporting requirements in respect of Directors' remuneration and the Listing Rules. The legislation requires the external auditor to state whether, in its opinion, the parts of the report that are subject to audit have been properly prepared in accordance with the relevant legislation and these parts have been highlighted.
This part of the Remuneration Report sets out the proposed Remuneration Policy for the Company which is intended to be effective following approval from shareholders through a binding vote at the AGM to be held in April 2017. The previous Remuneration Policy for the Company commenced on 1 January 2014 and became formally effective following approval from shareholders through a binding vote at the AGM held in April 2014. This section also explains how the proposed Remuneration Policy will be operated during 2017.
The principles of the Remuneration Committee ('Committee') are to ensure that remuneration is linked to Tullow's strategy and promotes the attraction, motivation and retention of the highest quality executives who are key to delivering sustainable long-term value growth and substantial returns to shareholders.
The Committee considers shareholder feedback received at the AGM each year and, more generally, guidance from shareholder representative bodies. This feedback, plus any additional feedback received during any meetings from time to time, is considered as part of the Company's annual review of the continuing appropriateness of the Remuneration Policy.
In setting the Remuneration Policy and remuneration levels for Executive Directors, the Committee is cognisant of the approach to rewarding employees in the Group and levels of pay increases generally. The Committee does not formally consult directly with employees on the Executive pay policy, but it does receive regular updates from Claire Hawkings, Vice President, Organisational Strategy & Effectiveness (VP – OS&E).
The following differences exist between the Company's policy for the remuneration of Executive Directors, as detailed in the summary table overleaf, and its approach to the payment of employees generally:
In general, these differences exist to ensure that remuneration arrangements are market competitive for all levels of role in the Company. Whilst there is a performance link to remuneration for all employees, in the case of the Executive Directors and Senior Management, a greater emphasis tends to be placed on variable pay given their opportunity to impact directly upon Company performance.
The Committee believes that the basic structure of the previous Remuneration Policy has worked well to align the interests of our Executives and our shareholders. The changes proposed by the Committee are set out in the table overleaf and are designed to provide increased flexibility in the Remuneration Policy to respond to volatile market conditions and to re-align Executive compensation with peer companies, both in the international exploration and production sector and having regard to FTSE companies of similar current market capitalisation.
Significant changes in the 2017 Policy include:
The maximum annual award opportunity for the TIP to be reduced from 600 per cent of base salary to 400 per cent of base salary.
• The period from 2014 to 2016 saw a dramatic decline in oil prices and in Tullow's share price. We remain focused on increasing shareholder value and re-entering the FTSE 100 as soon as possible. However, following feedback from shareholders, consultation with PwC and completion of a benchmarking exercise, the Committee believes that a 600 per cent multiplier is inappropriate for Tullow's current position within the FTSE, despite stretching performance targets that make that level of reward achievable only in exceptional circumstances. We are therefore recommending a reduction in the maximum award opportunity to 400 per cent of base salary to better reflect our current market position. In the event that the Company returns to the FTSE 100 Index and remains there for an entire financial year, the Committee reserves the right, at its sole discretion, to increase the multiplier to 500 per cent of base salary for the subsequent year.
• In consultation with PwC, the Committee determined that a maximum vesting of the TSR performance condition at upper quartile performance was appropriate and in line with industry practice within the FTSE and internationally. Particularly in light of the 200 per cent reduction to the overall maximum award opportunity the Committee believes that this is an appropriate adjustment to provide a challenging yet achievable incentive to the Executive Directors.
Discretion to settle any portion of the annual cash bonus component of a Tullow Incentive Plan (TIP) award in deferred shares.
• TIP awards consist of a short-term bonus component (usually paid in cash) and a long-term incentive component (paid in deferred shares with a five-year vesting term). A number of institutional investor bodies, governance agencies and advisory firms encourage the deferral of a portion of cash bonus into deferred shares. The Committee believes that the TIP properly balances short-term cash incentives with long-term share-based awards but that in certain circumstances it may be appropriate for the cash component to be partially deferred into shares with a vesting period not less than one year from the date of grant. This discretion would provide the Committee with greater flexibility to craft awards that are appropriate to the performance of the Company in a given year while also ensuring proper alignment of the interests of the Executive Directors and our shareholders.
• Tullow's existing shareholding policy prohibits Executive Directors from selling more than 50 per cent of post-tax vesting share awards until such time as their shareholding exceeds 400 per cent of base salary (rising to 600 per cent on the first vesting of the TIP). It was previously Tullow's policy to include unvested and unexercised awards in this calculation and that was the basis for setting such an extraordinarily high shareholding requirement. Guidance has now clarified that unvested awards should not be counted in minimum shareholding requirements and accordingly the Committee has reduced the multiple of base salary for Executive Director shareholdings but specified that it will only include 'owned shares' in the calculation of these amounts. The Committee believes that, at 300 per cent of base salary, Tullow's minimum shareholding requirement still significantly exceeds the average minimum shareholding requirement across the FTSE.
Non-executive Director fees are reviewed annually and for 2017 the Committee and the Board (with each Director abstaining from any decision on their own remuneration) recommend that the current Chairman's fee be reduced from £310,500 to £280,000 and each of the non-executive Director fees be reduced from £69,500 to £60,000. Additional responsibility fees paid to Committee Chairs would remain unchanged, save that the fee paid to the Chair of the Ethics & Compliance Committee would increase from £5,000 to £10,000 to reflect the increased demands placed on that Committee. The above reductions in fees payable to the current Chairman and the non-executive Directors reflect the cost pressures in the oil and gas industry and Tullow's current position within the FTSE.
The Committee will operate the TIP (and legacy plans) according to their respective rules and in accordance with the Listing Rules and HMRC rules where relevant.
The Committee, consistent with market practice, retains discretion over a number of areas relating to the operation and administration of the plans in relation to Senior Management, including Executive Directors. These include (but are not limited to) the following (albeit with the level of award restricted as set out in the policy table overleaf):
The choice of the performance metrics applicable to the TIP, which are set by the Committee at the start of the relevant financial year, reflects the Committee's belief that any incentive compensation should be appropriately challenging and tied to the delivery of stretching financial, operational and TSR-related objectives, explicitly linked to the achievement of Tullow's long-term strategy.
As a result of the switch from: (i) a three-year PSP vesting period to a five-year TIP vesting period; and (ii) pre-vesting performance conditions to pre-grant performance conditions, the following transitional arrangements applied in the early years of the TIP's operation:
In addition to the TIP, Executive Directors are also eligible to participate in the UK SIP on the same terms as other employees. All employee share plans do not operate performance conditions.
In addition to base salary and other benefits described in the Remuneration Policy, each Executive Director shall be eligible to receive an award issued under the rules of the TIP (a 'TIP Award'). The TIP combines short and long-term incentive-based pay and includes a cash bonus component and a deferred share award component.
At the beginning of each financial year, the Committee will determine a multiple of base salary, subject to the limits established under this Policy, to apply to a TIP Award. At the same time the Committee will also determine a balanced corporate scorecard of performance metrics applicable to any TIP Award. The choice of the performance metrics and the weightings given to them, which are set by the Committee at the start of the relevant financial year, reflects the Committee's belief that any incentive compensation should be appropriately challenging and tied to the delivery of stretching financial, operational and total shareholder return ('TSR') related objectives, explicitly linked to the achievement of Tullow's long-term strategy.
Following completion of the financial year, the Committee will review the Company's performance against the corporate scorecard resulting in a percentage score. The multiple set by the Committee is then applied to the percentage score to determine the total TIP Award amount. A TIP Award is divided equally between cash bonus and deferred shares up to the first 200 per cent of base salary. Any portion of a TIP Award above 200 per cent of base salary shall be satisfied in deferred shares only. Deferred shares forming part of a TIP Award are normally deferred for five years and are normally subject to malus and clawback. In its discretion, the Committee may elect to satisfy any portion of the cash bonus element of a TIP Award in deferred shares which will be deferred for a period determined by the Committee, being not less than one year from the date of grant. Deferred shares issued in lieu of any portion of the cash bonus component of a TIP Award shall be subject to malus, clawback and the minimum shareholding requirements set out in the table overleaf.
For the avoidance of doubt, in approving this Directors' Remuneration Policy, authority was given to the Company to honour any commitments entered into with current or former Directors that have been disclosed to shareholders in previous remuneration reports. Details of any payments to former Directors will be set out in the Annual Report on Remuneration as they arise.
| Purpose and link to strategy |
Operation | Maximum opportunity | |
|---|---|---|---|
| Base salary | To provide an appropriate level of fixed cash income. To attract and retain individuals with the personal attributes, skills and experience required to deliver our strategy. |
Generally reviewed annually with increases normally effective from 1 January. Base salaries will be set by the Committee taking into account: • the scale, scope and responsibility of the role; • the skills and experience of the individual; • the base salary of other employees, including increases awarded to the wider population; and • the base salary of individuals undertaking similar roles in companies of comparable size and complexity. This may include international oil & gas sector companies or a broader group of FTSE-listed organisations. |
Any increases to current Executive Director salaries, presented in the 'Application of Policy in 2017' column to the right of this policy table, will not normally exceed the average increase awarded to other UK-based employees. Increases may be above this level in certain circumstances, for instance if there is an increase in the scale, scope or responsibility of the role or to allow the base salary of newly appointed executives to move towards market norms as their experience and contribution increase. |
| Pension and benefits |
To attract and retain individuals with the personal attributes, skills and experience required to deliver our strategy. |
Defined contribution pension scheme or salary supplement in lieu of pension. The Company does not operate or have any legacy defined benefit pension schemes. Medical insurance, income protection and life assurance. Additional benefits may be provided as appropriate. Executive Directors may participate in the Tullow UK Share Incentive Plan (SIP). |
Pension: 25% of base salary. Benefits: The range of benefits that may be provided is set by the Committee after taking into account local market practice in the country where the executive is based. No monetary maximum is given for benefits provided to the Executive Directors as the cost will depend on individual circumstances. Benefit values vary year on year depending on premiums and the maximum potential value is the cost of the provision of these benefits. Tullow UK SIP: Up to HM Revenue & Customs (HMRC) limits, currently £150 per month. Maximum participation levels and matching levels for all staff, including Executive Directors, are set by reference to the rules of the plan and relevant legislation. |
| Framework used to assess performance and provisions for the recovery of sums paid/payable |
Application of policy in 2017 (this forms part of the Annual Report on Remuneration and not part of the Policy Report) |
|
|---|---|---|
| A broad assessment of individual and business performance is used as | Current Executive Director base salaries: | |
| part of the salary review. No recovery provisions apply. | 2017 | |
| Aidan Heavey | £886,074 | |
| Angus McCoss | £501,106 | |
| Paul McDade | £501,106 | |
| Ian Springett | £532,073 | |
| On appointment as Chief Executive Officer after the AGM on 26 April 2017, Paul McDade's salary will increase to £725,000. Aidan Heavey's salary will continue to be paid for a period of 6 months after the AGM on 26 April 2017. No other changes for 2017. Salaries (other than for Paul McDade) frozen for fourth year running. |
Not applicable. No change.
| Purpose and link to strategy |
Operation | Maximum opportunity | |
|---|---|---|---|
| Tullow Incentive Plan (TIP) |
To provide a simple, competitive, performance-linked incentive plan that: • aligns the interests of management and shareholders; • promotes the long-term success of the Company; • provides a real incentive to achieve our strategic objectives and deliver superior shareholder returns; and • will attract, retain and motivate individuals with the required personal attributes, skills and experience. |
An annual TIP Award consisting of up to 400 per cent of base salary which is divided evenly between cash and deferred shares up to the first 200 per cent of base salary. Any amount above 200 per cent of base salary is awarded entirely in deferred shares1 Deferred shares are normally subject for deferral until the fifth anniversary of grant, normally subject to continued service. TIP Awards are non-pensionable and will be made in line with the Committee's assessment of performance targets. At the discretion of the Committee, any portion of the cash component of a TIP Award can be satisfied by granting deferred shares with a vesting date set by the Committee being not earlier than the first anniversary of grant. |
The maximum amount of any Award shall be established by the Committee at the beginning of each year of this policy, provided it shall not exceed 400 per cent of salary for Executive Directors. Dividend equivalents will accrue on TIP deferred shares over the vesting period, and will be payable in respect of shares that vest. In the event that Tullow is a member of the FTSE 100 Index for a full financial year during the term of this Remuneration Policy, the Committee reserves the discretion to increase the maximum TIP Award opportunity from 400 per cent of base salary to 500 per cent of base salary should the Committee determine it appropriate to do so in the circumstances. |
| Minimum shareholding requirement |
To align the interests of management and shareholders and promote a long-term approach to performance and risk management. |
Executive Directors are required to retain at least 50 per cent of post-tax share awards until a minimum shareholding equivalent to 300 per cent of base salary is achieved in owned shares. Unvested TIP shares will not count towards the minimum shareholding requirement. Shares included in this calculation are those held beneficially by the Executive Director and his or her spouse/civil partner. |
Not applicable. |
| Non-executive Directors |
To provide an appropriate fee level to attract individuals with the necessary experience and ability to make a significant contribution to the Group's activities while also reflecting the time commitment and responsibility of the role. |
The Chairman is paid an annual fee and the non-executive Directors are paid a base fee and additional responsibility fees for the role of Senior Independent Director or for chairing a Board Committee. Fees are normally reviewed annually. Each non-executive Director is also entitled to a reimbursement of necessary travel and other expenses. Non-executive Directors do not participate in any share scheme or annual bonus scheme and are not eligible to join the Group's pension schemes. |
Non-executive Director remuneration is determined within the limits set by the Articles of Association. There is no maximum prescribed fee increase although fee increases for non-executive Directors will not normally exceed the average increase awarded to Executive Directors. Increases may be above this level if there is an increase in the scale, scope or responsibility of the role. |
| Framework used to assess performance and provisions for the recovery of sums paid/payable |
Application of policy in 2017 (this forms part of the Annual Report on Remuneration and not part of the Policy Report) |
||
|---|---|---|---|
| A balanced scorecard of stretching financial and operational objectives, linked to the achievement of Tullow's long-term strategy will be used to assess TIP outcomes. Specific targets and their weighting will vary from year to year in accordance with strategic priorities but may include targets relating to: relative or absolute Total Shareholder Return (TSR); earnings per share (EPS); Environmental, Health and Safety (EHS); financial; production; operations; project; exploration; or specific strategic and personal objectives. At the end of each year the Committee will determine a performance score against each of the components of the corporate scorecard which will result in an aggregate performance score out of 100 per cent (KPI Score). At least 50 per cent of any TIP award will be based on financial measures including TSR. Performance will typically be measured over one year for all measures apart from TSR and EPS, which, if adopted, will normally be measured over the three financial years prior to grant. For relative TSR, no more than 25 per cent of the maximum TIP opportunity will be payable for threshold performance with 100 per cent payable on delivering upper quartile performance. Non-TSR targets will normally be based on a challenging sliding scale with 20 per cent of the maximum opportunity payable for threshold performance through to a maximum of 100 per cent payable for delivering stretch performance. The Committee reserves the right to exercise its discretion in the event of exceptional and unforeseen positive or negative developments during the performance period. In addition, the Committee reserves the right to reduce the TIP payment where the Committee considers that the level of payment is not commensurate with overall corporate performance and returns delivered to shareholders over the performance period. The Committee will review performance measures annually, in terms of the range of targets, the measures themselves and weightings applied to each element of the TIP. Any revisions to the measures and/or weightings will only take place if it is necessary because of developments in the Group's strategy and, where these are material, following appropriate consultation with shareholders. TIP awards are subject to malus and clawback. The Committee retains discretion to apply malus and clawback to both the cash and deferred share elements of the TIP during the five-year vesting period in the event of a material adverse restatement of the financial accounts or reserves or a catastrophic failure of operational, EHS and risk management. |
The corporate scorecard for 2017 will consist of: • 50 per cent based on relative TSR, over the three-year period prior to grant, against a comparator group of oil and gas exploration companies with a threshold (25 per cent of the award) vesting at median performance and a maximum (100 per cent) vesting at upper quartile performance; • 10 per cent based on strategic financing measures; • 12 per cent based on production, operational and safety measures; and • 18 per cent based on business development, growth and organisational objectives. The Committee has set specific targets for the above KPIs that are stretching and that are explicitly linked to the achievement of Tullow's long-term strategy. The Committee is of the opinion that, given the commercial sensitivity of Tullow's non-TSR-related KPIs, disclosing in advance precise targets for the TIP would not be in shareholders' interests. Except in circumstances where elements remain commercially sensitive, actual targets, performance achieved and awards made will be published at the end of the performance periods so shareholders can fully assess the basis for any pay-outs. • The final 10 per cent of the corporate scorecard will be determined at the discretion of the Committee, based on an overall assessment of Company performance during the year. Details of actual performance against KPIs will be given retrospectively in the 2017 Annual Report. |
||
| Not applicable. | No change. | ||
| Not applicable. | Current non-executive Director fees: | 2017 | (2016) |
| Chairman2 Non-executive base fee Senior Independent Director3 Senior Independent Director4 Audit Committee Chair Remuneration Committee Chair EHS Committee Chair E&C Committee Chair |
£280,000 £60,000 £10,000 £40,000 £20,000 £20,000 £15,000 £10,000 |
(£310,500) (£69,500) (£15,000) (£15,000) (£20,000) (£20,000) (£20,000) (£5,000) |
Aidan Heavey's current remuneration will continue for 6 months after the AGM on 26 April 2017. Thereafter, Aidan will receive a Chairman's fee of £280,000 per annum which is in line with the reduced Chairman's fee in effect as at 1 January 2017.
To 26 April 2017.
After 26 April 2017.
The charts below show how the composition of the Executive Directors' remuneration packages varies at different levels of performance under the remuneration policy, as a percentage of total remuneration opportunity and as a total value:
Base salaries are those effective as at 1 January 2017 (unchanged from 1 January 2016).
Each Executive Director entered into a new service agreement with Tullow Group Services Limited effective 1 January 2014, save for Paul McDade who will enter into a new service agreement prior to the 2017 AGM in respect of his new role as Chief Executive Officer. Each service agreement sets out restrictions on the ability of the Director to participate in businesses competing with those of the Group or to entice or solicit away from the Group any senior employees in the six months after ceasing employment. The above reflects the Committee's policy that service contracts should be structured to reflect the interests of the Group and the individuals concerned, while also taking due account of market and best practice.
The term of each service contract is not fixed. Each agreement is terminable by the Director on six months' notice and by the employing company on 12 months' notice.
The Board has not introduced a formal policy in relation to the number of external directorships that an Executive Director may hold, considering any potential appointments on a case-by-case basis. During 2016, Ian Springett sought the Board's permission, which was agreed, to take up a nonexecutive Director role with G4S plc, effective 1 January 2017. In this, and other requests from Executive Directors to take up external appointments, the Board considers the individual's aggregate time commitment anticipated by the new role against their current commitments to Tullow. In respect of Ian's appointment, the Board agreed that he would retain his fee of £61,750 per annum. Angus McCoss has been nominated by Tullow as its representative on the board of Ikon Science Limited, a company in which Tullow has a small equity stake. Any fees payable for his services have been waived by Tullow.
Base salary levels will take into account market data for the relevant role, internal relativities, the individual's experience and their current base salary. Where an individual is recruited at below market norms, they may be re-aligned over time (e.g. two to three years), subject to performance in the role. Benefits will generally be in accordance with the approved policy.
Individuals will participate in the TIP up to the normal annual limit subject to: (i) award levels in the year of appointment being pro-rated to reflect the proportion of the financial year worked; and (ii) where a performance metric is measured over more than one year, the proportion of awards based on that metric will normally be reduced to reflect the proportion of the performance period worked. The Committee may consider buying out incentive awards which an individual would forfeit upon leaving their current employer although any compensation would, be consistent with respect to currency (i.e. cash for cash, equity for equity), vesting periods (i.e. there would be no acceleration of payments), expected values and the use of performance targets.
For an internal Executive Director appointment, any variable pay element awarded in respect of the prior role may be allowed to pay out according to its terms, adjusted as relevant to take account of the appointment. In addition, any other ongoing remuneration obligations existing prior to appointment may continue. For external and internal appointments, the Committee may agree that the Company will meet certain relocation and/or incidental expenses as appropriate.
Fee levels for non-executive Director appointments will take into account the expected time commitment of the role and the current fee structure in place at that time.
Executive Directors' service contracts are terminable by the Director on six months' notice and by the relevant employing company on 12 months' notice. There are no specific provisions under which Executive Directors are entitled to receive compensation upon early termination, other than in accordance with the notice period.
On termination of an Executive Director's service contract, the Committee will take into account the departing Director's duty to mitigate his loss when determining the amount of any compensation. Disbursements such as legal and outplacement costs and incidental expenses may be payable where appropriate.
Any unvested awards held under the Tullow Oil 2005 DSBP (the last awards were granted to Executive Directors in 2013) will lapse at cessation of employment unless the individual is a good leaver (defined under the plan as death, injury or
disability, redundancy, retirement, his office or employment being either a company which ceases to be a Group member or relating to a business or part of a business which is transferred to a person who is not a Group member or any other reason the Committee so decides). For a good leaver, unvested awards will normally vest at cessation of employment (unless the Committee decides they should vest at the normal vesting date).
Any unvested awards held under the Tullow Oil 2005 PSP (the last awards were granted to Executive Directors in 2013) will lapse at cessation of employment unless the individual is a good leaver (defined as per the DSBP). For a good leaver, unvested awards will normally vest at the normal vesting date (unless the Committee decides they should vest at cessation of employment) subject to performance conditions and time pro-rating (unless the Committee decides that the application of time pro-rating is inappropriate).
The Committee's policy in respect of the treatment of Executive Directors leaving Tullow following the introduction of the TIP is described below:
| Cessation of employment due to death, injury, disability, retirement, redundancy, the participant's employing company or business for which they work being sold out of the Company's Group or in other circumstances at the discretion of the Committee |
Cessation of employment due to other reasons (e.g. termination for cause) |
|||
|---|---|---|---|---|
| TIP (cash) |
Cessation during a financial year, or after the year but prior to the normal TIP Award date, may, at the discretion of the Committee, result in the cash part of the TIP being paid following the date of cessation (pro-rated for the proportion of the year worked). |
No entitlement to the cash part of the TIP following the date notice is served |
||
| TIP (deferred shares) |
Cessation during a financial year, or after the year but prior to the normal TIP Award date, may, at the discretion of the Committee, result in an award of deferred shares being made (pro-rated for the proportion of the year worked). |
Unvested TIP Shares lapse. No entitlement to the deferred share element of the TIP following the |
||
| Unvested TIP Shares generally vest at the normal vesting date (except on death or retirement – see below) unless the Committee determines they should vest at cessation. |
date notice is served | |||
| On death, TIP Shares generally vest immediately unless the Committee determines that they should vest at the normal vesting date. |
||||
| On retirement (as evidenced to the satisfaction of the Committee), TIP Shares will vest at the earlier of the normal vesting date and three years from retirement unless the Committee determines they should vest at cessation. |
| Non-executive Director | Year appointed |
Number of complete years on the Board |
Date of current engagement commenced |
Expiry of current term |
|---|---|---|---|---|
| Simon Thompson | 2011 | 5 | 01.01.15 | 31.12.17 |
| Tutu Agyare | 2010 | 6 | 24.08.16 | 23.08.19 |
| Mike Daly | 2014 | 2 | 01.06.14 | 31.05.17 |
| Anne Drinkwater | 2012 | 4 | 10.02.15 | 09.02.18 |
| Ann Grant | 2008 | 8 | 15.05.14 | 30.04.17 |
| Steve Lucas | 2012 | 4 | 14.03.15 | 13.03.18 |
| Jeremy Wilson | 2013 | 3 | 21.10.16 | 20.10.19 |
In each case, the appointment is renewable thereafter if agreed by the Director and the Board. The appointment of any non-executive Director may be terminated by either party on three months' notice (six months for Simon Thompson). There are no arrangements under which any non-executive Director is entitled to receive compensation upon the early termination of his or her appointment.
This part of the report provides details of the operation of the Remuneration Committee, how the Remuneration Policy was implemented in 2016 (including payment and awards in respect of incentive arrangements) and how shareholders voted at the 2016 AGM. This part of the report also includes a summary of how the new Remuneration Policy, if approved by shareholders, will be operated for 2017, although, for ease of reference, this is also presented within the Remuneration Policy Report.
The Committee currently comprises five non-executive Directors and is chaired by Jeremy Wilson. The membership and attendance of members at Committee meetings held in 2016 are shown below.
| Committee member | Meetings attended |
|---|---|
| Jeremy Wilson (Chair) | 6/6 |
| Tutu Agyare¹ | 5/6 |
| Anne Drinkwater | 6/6 |
| Steve Lucas | 6/6 |
| Simon Thompson | 6/6 |
The Committee's terms of reference are reviewed annually and can be viewed on the Company's corporate website.
The Committee invites individuals to attend meetings to provide advice so as to ensure that the Committee's decisions are informed and take account of pay and conditions in the Group as a whole. Sources of advice include:
The total fees paid to PwC in respect of the advice provided for 2016 totalled £60,000 (excluding VAT) and related to the review and design of the Company's 2017 Remuneration Policy and related issues. PwC LLP is a member of the Remuneration Consultants Group and as such voluntarily operates under the code of conduct in relation to executive remuneration consulting in the UK. PwC LLP also provided tax and consulting services to Tullow during the year.
Fees paid to New Bridge Street, the previous advisers to the Remuneration Committee, totalled £6,015 (excluding VAT) and related to the provision of TSR calculations and advice with regards to the 2015 Directors' Remuneration Report.
The Committee has access to the Company Secretary at all times, who advises as necessary and, where appropriate, makes arrangements for the Committee to receive independent legal advice at the request of the Committee Chair.
The Committee also consults with the Company's major investors and investor representative groups as appropriate. No Director takes part in any decision directly affecting his or her own remuneration. The Company Chairman also absents himself during discussion relating to his own fees.
The remuneration of the Directors for the year ended 31 December 2016 payable by Group companies and comparative figures for 2015 are shown in the table below:
| Fixed pay | Tullow Incentive Plan | ||||||
|---|---|---|---|---|---|---|---|
| Taxable | Deferred TIP | ||||||
| Salary/fees1 £ |
Pensions2 £ |
benefits3 £ |
TIP cash £ |
shares4 £ |
Total £ |
||
| Executive Directors | |||||||
| Aidan Heavey | 2016 | 886,080 | 221,520 | 66,638 | 859,497 | 859,497 | 2,893,232 |
| 2015 | 886,080 | 221,520 | 57,849 | 835,130 | 835,130 | 2,835,709 | |
| Angus McCoss | 2016 | 501,110 | 125,278 | 10,758 | 486,076 | 486,076 | 1,609,298 |
| 2015 | 501,110 | 125,278 | 6,655 | 472,296 | 472,296 | 1,577,635 | |
| Paul McDade | 2016 | 501,110 | 125,278 | 9,017 | 486,076 | 486,076 | 1,607,557 |
| 2015 | 501,110 | 125,278 | 5,394 | 472,296 | 472,296 | 1,576,374 | |
| Ian Springett | 2016 | 532,080 | 133,020 | 15,751 | 516,117 | 516,117 | 1,713,085 |
| 2015 | 532,080 | 133,020 | 8,371 | 501,485 | 501,485 | 1,676,441 | |
| Graham Martin5 | 2016 | 167,037 | 41,759 | 3,614 | 162,025 | – | 374,435 |
| 2015 | 501,110 | 125,278 | 9,744 | 472,296 | 472,296 | 1,580,724 | |
| Subtotal | 2016 | 2,587,417 | 646,855 | 105,778 | 2,509,791 | 2,347,766 | 8,197,607 |
| 2015 | 2,921,490 | 730,374 | 88,013 | 2,753,503 | 2,753,503 | 9,246,883 | |
| Non-executive Directors | |||||||
| Tutu Agyare | 2016 | 69,500 | – | – | – | – | 69,500 |
| 2015 | 69,500 | – | – | – | – | 69,500 | |
| Mike Daly | 2016 | 69,500 | – | – | – | – | 69,500 |
| 2015 | 69,500 | – | – | – | – | 40,542 | |
| Anne Drinkwater | 2016 | 84,500 | – | – | – | – | 84,500 |
| 2015 | 84,500 | – | – | – | – | 84,500 | |
| Ann Grant | 2016 | 89,500 | – | – | – | – | 89,500 |
| 2015 | 89,500 | – | – | – | – | 79,500 | |
| Steve Lucas | 2016 | 89,500 | – | – | – | – | 89,500 |
| 2015 | 89,500 | – | – | – | – | 89,500 | |
| Simon Thompson | 2016 | 310,500 | – | – | – | – | 310,500 |
| 2015 | 310,500 | – | – | – | – | 310,500 | |
| Jeremy Wilson | 2016 | 89,500 | – | – | – | – | 89,500 |
| 2015 | 89,500 | – | – | – | – | 82,833 | |
| Subtotal | 2016 | 802,500 | – | – | – | – | 802,500 |
| 2015 | 802,500 | – | – | – | – | 756,875 | |
| Total | 2016 | 3,389,917 | 646,855 | 105,778 | 2,509,791 | 2,347,766 | 9,000,107 |
| 2015 | 3,723,990 | 730,374 | 88,013 | 2,753,503 | 2,753,503 | 10,049,383 |
Base salaries of the Executive Directors have been rounded up to the nearest £10 for payment purposes, in line with established policy.
None of the Executive Directors has a prospective entitlement to a defined benefit pension by reference to qualifying services.
Taxable benefits comprise private medical insurance for all Executive Directors; Aidan Heavey's taxable benefits comprised private medical insurance (£17,523) and car benefits/club membership (£47,550); Ian Springett also receives club membership.
These figures represent that part of the TIP award required to be deferred into shares.
Part year – Graham Martin resigned as an Executive Director effective 28 April 2016.
There have been no other contracts or arrangements during the financial year in which a Director of the Company was materially interested and/or which were significant in relation to the Group's business.
The principles governing compensation for loss of office payments are set out on page 91.
As previously announced on 9 December 2015, Graham Martin informed the board that he would retire as an Executive Director at the 2016 Annual General Meeting. Mr. Martin also resigned as Company Secretary effective 1 January 2016. Mr. Martin's appointment as an Executive Director and his employment with Tullow therefore ended on 28 April 2016.
Mr. Martin received his salary, benefits and pension allowance as usual in respect of his employment until 28 April 2016. Mr. Martin worked for part of the 2016 financial year and the Committee therefore determined that he will remain eligible to receive the cash part of the Tullow Incentive Plan in respect of the portion of the year worked.
Under the rules of the various Tullow incentive arrangements, Mr. Martin left Tullow as a good leaver and as such his existing share awards were treated in the following way:
Mr. Martin will continue to be covered by the Company's directors' and officers' insurance and his indemnity in respect of third party liabilities will continue in force, each according to their terms. On retiring and ceasing employment with Tullow, Mr. Martin was not entitled to any other payments or any payment for loss of office.
There have been no termination payments to Graham Martin or previously to any other Executive Directors.
The Group's progress against its corporate scorecard is tracked during the year to assess our performance against our strategy. The corporate scorecard is made up of a collection of Key Performance Indicators ('KPIs') which indicate the company's overall health and performance across a range of operational, financial and non-financial measures.
The corporate scorecard is central to Tullow's approach to performance management and the 2016 indicators were agreed with the Board and focus on targets that were deemed important for the year.
Each KPI measured has a percentage weighting and financial indicators have trigger, base and stretch performance targets.
Following the end of the 2016 financial year, the corporate scorecard KPI performance was 38.8 per cent of the maximum and the Committee awarded Executive Directors a total TIP award equating to 194 per cent of base salary. This will be payable 50 per cent in cash and 50 per cent in shares deferred for five years (i.e. vesting in 2022). Details of the performance targets which operated and performance against those targets are as follows:
| Performance metric | Performance | % of award (% of salary maximum) |
Actual |
|---|---|---|---|
| Strategic Financing Two key targets relating to Capacity Funding and Strategic Solution to Deleverage. |
The Capacity Funding target includes maintaining liquidity through the bi-annual redetermination of our Senior Reserves Based Lending (RBL) debt capacity; extending the Rolling Corporate Facility by one year; and amending the gearing covenant - 2016 funding capacity was achieved by securing a year's extension to our Corporate Facility, amending the financial covenant under the RBL and Corporate Facility and the issuance of \$300m convertible bonds. |
13.5% (67.5%) |
|
| The second longer-term Strategic target focuses on deleveraging and rebasing our balance sheet – Positive free cash flow in Q4 began the gradual deleveraging process, and the farm-down of our Uganda assets will fully fund our future capital commitments associated with this project once the deal is complete. Based on a review of the two Strategic Financing targets, the Committee accordingly agreed a payout of 13.5% out of the potential 15% allocation. |
| Performance metric | Performance | % of award (% of salary maximum) |
Actual |
|---|---|---|---|
| Safe & Efficient Business Operations Quantitative Targets relating to Production, Opex, Net G&A and Capex. SSEA Targets. |
Production: trigger target of 77.3kboepd pays 0%; base target of 81.4k boepd pays 50%; and stretch of 85.3kbopd pays 100% – 2016 Production of 71.1kboepd, which includes 4,600 boepd of net lost production covered by insurance, was below the trigger target of 77.3k boepd and therefore 0% pay-out (maximum 5%) was achieved. Opex: trigger target of \$16.5 underlying cash opex/boe pays 0%; base target of \$15.7 opex/boe pays 50%; and stretch target of \$14.9 pays 100% – 2016 Opex of \$14.3 per barrel of oil (including insurance pay-outs) overachieved the stretch target of \$14.9 and therefore the maximum 1.25% was awarded. Net G&A: trigger target of \$147 million pays 0%; base target of \$127 million pays 50%; and stretch target of \$100 million pays 100% – 2016 Net G&A was \$116.4 million which was between the base target of \$127 million and our stretch target of \$100 million achieving a 0.9% pay-out of the 1.25% allocation. Capex: trigger target of \$1,100 million pays 0% and the stretch target of \$900 million pays 100% – 2016 Capex of \$857m overachieved the stretch target of \$942 million and therefore the maximum 2.5% |
15% (75%) |
8.8% (44.0%) |
| was awarded. Tullow's SSEA targets are focused on reducing process safety events; making improvements to our asset integrity; occupational health and safety focused on Long Time Injury Frequency (LTIF) reduction and malaria prevention; and sustainability, including metrics such as environmental and social performance – In 2016 there were no Tier 1 and Tier 2 incidents. The Jubilee Asset Integrity improvement plan progress is on schedule. The LTIF rate was 0, beating the stretch target of 0.24. There were no serious malaria cases reported and no significant work disruptions reported the year to date. In view of the above SSEA performance, the Committee determined a 4.1% achievement out of a maximum 5% allocation. |
|||
| Business Development and Growth Targets relating to the TEN Project, East Africa and Exploration. |
The KPI for the TEN Project was based on the following targets: timing of achieving first oil; ramp-up of production; production attainment and operability – First oil was achieved in August 2016; ramp-up Production was 5.5mmbbls; and the capacity of the FPSO has been successfully tested at an average rate of over 80,000 boepd. The TEN Project has been classified as a 'world class' project and ranks in the top 10% of global projects for both schedule delivery and capex budget (per Independent Project Analysis (IPA)). Based on these achievements, the Committee determined a score of 4.5% out of the maximum 5%. The East Africa KPI comprised the following targets: implementing a material transaction on our East Africa Portfolio; maintaining East Africa development for Final Investment Decision by the end 2017; and presenting Kenya Early Oil Investment Proposal. The farm-down of our Uganda assets to Total was announced in early 2017. Also in Uganda, eight production licences were awarded; the pipeline is progressing upstream and pipeline FEED are commencing in 2017; and upstream ESIA scoping studies are approved. In Kenya, our licences have been extended; water injection testing has commenced; and the Kenya Early Oil Pilot Scheme has been approved by the upstream partners. Based on these achievements, the Committee determined a score of 4.5% out of the maximum 5%. The exploration KPI is made up of the following three targets: accessing material acreage positions; progressing quality prospects; and discovering |
15% (75%) |
12.4% (62.0%) |
| predicted risked volumes through exploration. In 2016, two material licences in Guyana and Zambia were signed and 13 quality prospects were progressed across Kenya, Namibia, Norway, Suriname and Mauritania. In Norway, the Cara discovery and the Wisting appraisal well added a combined P50 resource of approximately 41mmboe net. Based on these achievements, the Committee determined a score of 3.4% out of the maximum 5%. |
Determination of 2017 TIP Award based on performance to 31 December 2016 (audited) continued
| Performance metric | Performance | % of award (% of salary maximum) |
Actual |
|---|---|---|---|
| Organisation Targets relating to Organisational Efficiency & Effectiveness, Diversity and Ethics & Compliance and fully implementing the Integrated Management System (IMS) |
Highlights from the progress against the Organisation KPI included in 2016: IMS implementation is on track; the employee survey ran with high participation and action plans were developed to address feedback; all key risks have controls in place to manage them, and are monitored quarterly; all recommendations from an external audit on SAP effectiveness have been implemented; aspirational diversity targets have been agreed and senior leadership engaged; and an Ethics & Compliance e-learning module has been rolled out. Based on these achievements, the Committee determined a score of 4.1% out of the maximum 5%. |
5% (25%) |
4.1% (20.5%) |
| Relative TSR | Performance against a bespoke group of listed exploration and production companies¹ measured over three years to 31 December 2016 – 25% is payable at median, increasing to 100% payable at upper quintile. Tullow's share price performed well in 2016 closing 97% up since it opened on 4 January 2016 at 165.7p. Whilst this annual performance puts Tullow in the upper quintile of the comparator group, because TSR is measured on a rolling three-year basis, Tullow's performance was below median and therefore this KPI has no pay-out. |
50% (250%) |
0% (0%) |
| Total | 100% (500%) |
38.8% (194.0%) |
Further information on Tullow Group's performance against the corporate scorecard is shown on pages 16 to 21 of the Annual Report and Accounts.
The third set of TIP awards were granted to Executive Directors on 11 February 2016, based on the performance period ended 31 December 2015, as follows:
| Executive | Number of TIP shares awarded1 |
Face value of awards at grant date |
Normal vesting dates (end of exercise window) |
Pre-grant performance period |
|---|---|---|---|---|
| Aidan Heavey | 565,423 | £835,130 | ||
| Angus McCoss | 319,767 | £472,296 | 11.02.2021 to | 01.01.2015 to 31.12.2015 |
| Paul McDade | 319,767 | £472,296 | 11.02.26 | (TSR 01.01.2014 to 31.12.2016) |
| Ian Springett | 339,529 | £501,485 | ||
| Graham Martin | 319,767 | £472,296 |
The UK SIP is a tax-favoured all-employee plan that enables UK employees to save out of pre-tax salary. Quarterly contributions are used by the Plan trustee to buy Tullow Oil plc shares (partnership shares). The Group funds an award of an equal number of shares (matching shares). The current maximum contribution is £150 per month. Details of shares purchased and awarded to Executive Directors under the UK SIP are as follows:
| Director | Shares held 01.01.16 |
Partnership shares acquired in year |
Matching shares awarded in year |
Total shares held 31.12.16 |
SIP shares that became unrestricted in the year |
Total unrestricted shares held at 31.12.161 |
|---|---|---|---|---|---|---|
| Angus McCoss | 4,532 | 979 | 979 | 6,490 | 238 | 2,324 |
| Paul McDade | 9,502 | 980 | 980 | 11,462 | 238 | 7,294 |
| Ian Springett | 3,010 | 979 | 979 | 4,968 | 240 | 802 |
| Graham Martin | 9,502 | 574 | 574 | – | 10,650 | – |
As a member of both indices in recent times, the Remuneration Committee has chosen to compare the TSR of the Company's ordinary shares against both the FTSE 100 and FTSE 250 indices.
The values indicated in the graph overleaf show the share price growth plus reinvested dividends over an eight-year period from a £100 hypothetical holding of ordinary shares in Tullow Oil plc and in the two indices. The total remuneration figures for the Chief Executive during each of the last eight financial years are shown in the table below. The total remuneration figure includes the annual bonus based on that year's performance (2009 to 2012), PSP awards based on three-year performance periods ending in the relevant year (2009 to 2015) and the value of TIP awards based on the performance period ending in the relevant year (2013 to 2016). The annual bonus pay-out, PSP vesting level and TIP award, as a percentage of the maximum opportunity, are also shown for each of these years.
| Year ending in | ||||||||
|---|---|---|---|---|---|---|---|---|
| 2009 | 2010 | 2011 | 2012 | 2013 | 2014 | 2015 | 2016 | |
| Total remuneration | £4,516,580 | £3,558,698 | £4,688,541 | £2,623,116 | £2,750,273 | £2,378,316 | £2,835,709 | £2,893,232 |
| Annual bonus | 86% | 58% | 80% | 70% | – | – | – | – |
| PSP vesting | 100% | 100% | 100% | 23% | – | – | – | – |
| TIP | – | – | – | – | 30% | 23% | 38% | 39% |
The table below shows the percentage change in the Chief Executive's total remuneration (excluding the value of any pension benefits receivable in the year) between the financial year ended 31 December 2015 and 31 December 2016, compared to that of the average for all employees of the Group.
| % change from 2015 to 2016 | |||
|---|---|---|---|
| Salary | Benefits | Bonus | |
| Chief Executive | 0% | 15.2% | 3% |
| Average employees | 5.2% | – | 19% |
The following table shows the Group's actual spend on pay for all employees relative to dividends, tax and retained profits.
| 2015 | 2016 | % change |
|---|---|---|
| 218 | 168 | -23 |
| – | – | – |
| (158) | (230) | -46 |
| 860 | 630 | -27 |
* Voluntary disclosure.
The dividend figures relate to amounts payable in respect of the relevant financial year.
At last year's AGM on 28 April 2016 the remuneration-related resolutions received the following votes from shareholders:
| 2015 Annual Statement & Annual Report on Remuneration | ||
|---|---|---|
| Total number of votes | % of votes cast | |
| For | 577,361,715 | 90.68 |
| Against | 59,345,941 | 9.32 |
| Total votes cast (for and against) | 636,707,656 | 100 |
| Votes withheld | 3,485,321 |
At the 2014 AGM, held on 30 April 2014, the 2014 Remuneration Policy Report received the following votes from shareholders:
| 2014 Remuneration Policy Report | ||
|---|---|---|
| Total number of votes | % of votes cast | |
| For | 585,950,806 | 90.79 |
| Against | 59,419,570 | 9.21 |
| Total votes cast (for and against) | 636,707,656 | 100 |
| Votes withheld | 1,183,901 |
Details of nil-cost options granted to Executive Directors under the TIP:
| Earliest date | Latest date | ||||||
|---|---|---|---|---|---|---|---|
| Award grant | Share price on | Granted during | shares can be | shares can be | |||
| Director | date | grant date | As at 01.01.16 | year | As at 31.12.16 | acquired1 | acquired |
| Aidan Heavey | 19.02.14 | 774p | 102,992 | – | 102,992 | 19.02.17 | 19.02.24 |
| 18.02.15 | 400p | 152,772 | – | 152,772 | 18.02.19 | 17.02.25 | |
| 11.02.16 | 148p | – | 565,423 | 565,423 | 11.02.21 | 11.02.26 | |
| 255,764 | 821,187 | ||||||
| Angus McCoss | 19.02.14 | 774p | 58,246 | – | 58,246 | 19.02.17 | 19.02.24 |
| 18.02.15 | 400p | 86,398 | – | 86,398 | 18.02.19 | 17.02.25 | |
| 11.02.16 | 148p | – | 319,767 | 319,767 | 11.02.21 | 11.02.26 | |
| 144,644 | 464,411 | ||||||
| Paul McDade | 19.02.14 | 774p | 58,246 | – | 58,246 | 19.02.17 | 19.02.24 |
| 18.02.15 | 400p | 86,398 | – | 86,398 | 18.02.19 | 17.02.25 | |
| 11.02.16 | 148p | – | 319,767 | 319,767 | 11.02.21 | 11.02.26 | |
| 144,644 | 464,411 | ||||||
| Ian Springett | 19.02.14 | 774p | 61,845 | – | 61,845 | 19.02.17 | 19.02.24 |
| 18.02.15 | 400p | 91,737 | – | 91,737 | 18.02.19 | 17.02.25 | |
| 11.02.16 | 148p | – | 339,529 | 339,529 | 11.02.21 | 11.02.26 | |
| 153,582 | 493,111 | ||||||
| Graham Martin2 | 19.02.14 | 774p | 58,246 | – | 58,246 | 19.02.17 | 19.02.24 |
| 18.02.15 | 400p | 86,398 | – | 86,398 | 18.02.19 | 17.02.25 | |
| 11.02.16 | 148p | – | 319,767 | 319,767 | 11.02.21 | 11.02.26 | |
| 144,644 | 464,411 |
50 per cent of the 2014 award vests on 19.02.17 and 50 per cent vests on 19.02.18; 50 per cent of 2015 award vests on 18.02.19 and 50 per cent vests on 18.02.20.
As at leaving date on 28 April 2016.
Details of shares granted to Executive Directors for nil consideration under the PSP:
| Director | Award grant date |
Share price on grant date |
As at 01.01.16 | Exercised during year |
As at 31.12.16 | Earliest date shares can be acquired |
Latest date shares can be acquired |
|---|---|---|---|---|---|---|---|
| Paul McDade | 15.05.08 | 924.5 | 80,277 | – | 80,277 | 15.05.11 | 14.05.18 |
| 18.03.09 | 778 | 98,355 | – | 98,355 | 18.03.12 | 17.03.19 | |
| 17.03.10 | 1,281 | 13,972 | – | 13,972 | 17.03.13 | 16.03.20 | |
| 192,604 | – | 192,604 | |||||
| Ian Springett | 01.09.08 | 791 | 68,873 | – | 68,873 | 01.09.11 | 31.08.18 |
| 18.03.09 | 778 | 104,438 | – | 104,438 | 18.03.12 | 17.03.19 | |
| 17.03.10 | 1,281 | 14,836 | – | 14,836 | 17.03.13 | 16.03.20 | |
| 188,147 | – | 188,147 | |||||
| Graham Martin1 | 15.05.08 | 924.5 | 80,277 | – | 80,277 | 15.05.11 | 14.05.18 |
| 18.03.09 | 778 | 98,355 | – | 98,355 | 18.03.12 | 17.03.19 | |
| 17.03.10 | 1,281 | 13,972 | – | 13,972 | 17.03.13 | 16.03.20 | |
| 192,604 | – | 192,604 |
All of the PSP awards listed are based on relative three-year TSR performance and the Committee considering that both the Group's underlying financial performance and its performance against other key factors (e.g. Health & Safety) over the relevant period are satisfactory. 50 per cent of awards are/were measured against an international oil sector comparator group (see past Remuneration Reports for details of specific companies) and 50 per cent of awards are/were measured against the FTSE 100. All outstanding awards under PSP have been granted as, or converted into, nil exercise price options. To the extent that they vest, they are normally exercisable from three to 10 years from grant.
Details of nil exercise cost options granted to Executive Directors for nil consideration under the DSBP:
| Director | Award grant date | As at 01.01.16 | Exercised during year |
As at 31.12.16 | Earliest date shares can be acquired |
Latest date shares can be acquired |
|---|---|---|---|---|---|---|
| Aidan Heavey | 18.03.11 | 19,995 | 19,995 | – | 01.01.14 | 17.03.21 |
| 21.03.12 | 45,654 | 45,654 | – | 01.01.15 | 20.03.22 | |
| 22.02.13 | 45,649 | 45,649 | – | 01.01.16 | 21.02.23 | |
| 111,298 | 111,298 | – | ||||
| Angus McCoss | 22.02.13 | 25,816 | – | 25,816 | 01.01.16 | 21.02.23 |
| 25,816 | – | 25,816 | ||||
| Paul McDade | 13.03.08 | 14,686 | – | 14,686 | 01.01.11 | 12.03.18 |
| 18.03.09 | 28,374 | – | 28,374 | 01.01.12 | 17.03.19 | |
| 17.03.10 | 15,941 | – | 15,941 | 01.01.13 | 16.03.20 | |
| 18.03.11 | 11,308 | – | 11,308 | 01.01.14 | 17.03.21 | |
| 21.03.12 | 25,819 | – | 25,819 | 01.01.15 | 20.03.22 | |
| 22.02.13 | 25,816 | – | 25,816 | 01.01.16 | 21.02.23 | |
| 121,944 | – | 121,944 | ||||
| Ian Springett | 17.03.10 | 16,927 | – | 16,927 | 01.01.13 | 16.03.20 |
| 18.03.11 | 12,007 | – | 12,007 | 01.01.14 | 17.03.21 | |
| 21.03.12 | 27,415 | – | 27,415 | 01.01.15 | 20.03.22 | |
| 22.02.13 | 27,411 | – | 27,411 | 01.01.16 | 21.02.23 | |
| 83,760 | – | 83,760 | ||||
| Graham Martin1 | 13.03.08 | 16,021 | – | 16,021 | 01.01.11 | 12.03.18 |
| 18.03.09 | 28,374 | – | 28,374 | 01.01.12 | 17.03.19 | |
| 17.03.10 | 15,941 | – | 15,941 | 01.01.13 | 16.03.20 | |
| 18.03.11 | 11,308 | – | 11,308 | 01.01.14 | 17.03.21 | |
| 21.03.12 | 25,819 | – | 25,819 | 01.01.15 | 20.03.22 | |
| 22.02.13 | 25,816 | – | 25,816 | 01.01.16 | 21.02.23 | |
| 123,279 | – | 123,279 |
All outstanding awards under the DSBP were granted as, or have been converted into, nil exercise price options. To the extent that they vest, they are exercisable from three to 10 years from grant.
2
The aggregate gain made by Directors on the exercise of nil exercise price options under the DSBP during the year was £292,702 (gross) (2015: £99,332). On 11 February 2016, being the date that Angus McCoss exercised his options in the table overleaf, the middle market quoted price of a Tullow share was £1.48. On 22 August 2016, being the date Aidan Heavey exercised his options in the table above, the middle market quoted price of a Tullow share was £2.29.
During 2016, the highest mid-market price of the Company's shares was 332.4p and the lowest was 118.2p. The year-end price was 312.7p.
The interests of the Directors (all of which were beneficial), who held office at 31 December 2016, are set out in the table below:
| % of salary under 2017 Remuneration |
||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Ordinary shares held | Policy | TIP awards | PSP awards | DSBP awards | SIP | Total | ||||||
| 31.12.15 | 31.12.16 | shareholding guidelines1 |
Unvested | Vested | Unvested | Vested | Unvested | Vested | Restricted | Unrestricted | 31.12.16 | |
| Aidan | ||||||||||||
| Heavey | 6,401,511 | 6,178,813 | 2,181 | – | – | – | – | – | – | – | – | 7,000,000 |
| Angus | ||||||||||||
| McCoss | 261,078 | 274,702 | 171 | 464,411 | – | – | – | – | – | 4,166 | 2,324 | 745,603 |
| Paul | ||||||||||||
| McDade | 305,801 | 305,801 | 191 | – | – | – | 192,604 | – | 121,944 | 4,168 | 7,294 | 1,096,222 |
| Ian Springett | 12,000 | 12,000 | 7 | – | – | – | 188,147 | – | 83,760 | 4,166 | 802 | 781,986 |
| Graham | ||||||||||||
| Martin | 2,030,392 | 2,030,392² | n/a | 464,411 | – | – | 192,604² | – | 123,279² | – | 10,650² | 2,821,336² |
| Non-executive Directors | ||||||||||||
| Simon | ||||||||||||
| Thompson | 27,119 | 27,119 | – | – | – | – | – | – | – | – | – | 27,119 |
| Tutu Agyare | 1,940 | 1,940 | – | – | – | – | – | – | – | – | – | 1,940 |
| Mike Daly | 3,175 | 3,175 | – | – | – | – | – | – | – | – | – | 3,175 |
| Anne | ||||||||||||
| Drinkwater | 7,000 | 7,000 | – | – | – | – | – | – | – | – | – | 7,000 |
| Ann Grant | 3,171 | 3,171 | – | – | – | – | – | – | – | – | – | 3,171 |
| Steve Lucas | 600 | 600 | – | – | – | – | – | – | – | – | – | 600 |
| Jeremy | ||||||||||||
| Wilson | 15,000 | 45,000 | – | – | – | – | – | – | – | – | – | 45,000 |
Calculated using share price of 312.7p at year end. Under the Company's shareholding guidelines, each Executive Director is required to build up their shareholdings in the Company's shares to at least 300 per cent of their salary. Further details of the minimum shareholding requirement is set out in the Remuneration Policy Report.
As at leaving date on 28 April 2016.
On 5 January 2017 Angus McCoss, Paul McDade and Ian Springett were each awarded 356 SIP shares, all of which are restricted. Accounting for certain restricted SIP shares becoming unrestricted SIP shares in the period between 1 January 2017 and the date of this report, Angus McCoss holds 4,462 restricted SIP shares and 2,384 unrestricted SIP shares (total 6,846), Paul McDade holds 4,466 restricted SIP shares and 7,352 unrestricted SIP shares (total 11,818) and Ian Springett holds 4,464 restricted SIP shares and 860 unrestricted SIP shares (total 5,324).
There have been no other changes in the interests of any Director between 1 January 2017 and the date of this report.
This report was approved by the Board of Directors on 7 February 2017 and signed on its behalf by:
.
Jeremy Wilson Chairman of the Remuneration Committee
The loss on ordinary activities after taxation of the Group for the year ended 31 December 2016 was \$597.3 million (2015: loss of \$1,036.9 million).
No dividends have been recommended by the Board in 2016 (2015: £nil).
On 5 January 2017, Tullow announced that Ian Springett, CFO, had taken an extended leave of absence in order to undergo treatment for a medical condition with Les Wood, Vice President Finance and Commercial, appointed Interim CFO.
On 9 January 2017, Tullow announced that it had agreed a substantial farm-down of its assets in Uganda to Total. For further details please see the Strategic Report.
On 11 January 2017, the Group announced that Paul McDade, currently Chief Operating Officer, will be appointed Chief Executive Officer following Tullow's Annual General Meeting on 26 April 2017. This follows an internal and external process led by Tullow's Nominations Committee. At the same time, after six years on Tullow's Board and five as Chairman, Simon Thompson will step down from the Board. Aidan Heavey, Chief Executive Officer and founder of Tullow Oil, will succeed Mr. Thompson as Chairman of the Group for a transitional period of up to two years. Ann Grant, Senior Independent Director, will retire at the AGM after nine years' service on the Board. Jeremy Wilson, a non-executive Director of Tullow Oil and Chairman of the Remuneration Committee, will succeed Ms Grant as Senior Independent Director.
On 17 January 2017, the Group announced that the Erut-1 well in Block 13T, Northern Kenya, had discovered a gross oil interval of 55 metres with 25 metres of net oil pay at a depth of 700 metres. The overall oil column for the field is considered to be 100 to 125 metres.
As at 1 February 2017, the Company had an allotted and fully paid up share capital of 914,481,960 each with a nominal value of £0.10.
As at 7 February 2017, the Company had been notified in accordance with the requirements of provision 5.1.2 of the Financial Conduct Authority's Disclosure Rules and Transparency Rules of the following significant holdings in the Company's ordinary share capital:
| Shareholder | Number of shares |
% of issued capital |
|---|---|---|
| The Capital Group Companies, Inc. | 132,051,991 | 14.44 |
| Deutsche Bank AG | 73,138,818 | 8.02 |
| Genesis Asset Managers, LLP | 54,857,056 | 5.99 |
| Majedie Asset Management Limited | 45,815,547 | 5.02 |
| Oppenheimer Funds, Inc.1 | 45,191,459 | 4.96 |
| IFG International Trust Company Ltd 2 | 38,960,366 | 5.98 |
Following requests under section 793 of the Companies Act 2006, the Company understands that the percentage of its issued share capital held by Oppenheimer Funds, Inc. as at 31 January 2016 was 0 per cent. No further notifications under DTR5 have been received from Oppenheimer Funds, Inc. during the year ended 31 December 2016, or to the date of publication.
Based on notification received 14 November 2006. IFG is now known as First Names Trust Company.
The rights and obligations of shareholders are set out in the Company's Articles of Association (which can be amended by special resolution). The rights and obligations attaching to the Company's shares are as follows:
There are no UK foreign exchange control restrictions on the payment of dividends to US persons on the Company's ordinary shares.
The following significant agreements will, in the event of a 'change of control' of the Company, be affected as follows:
under the \$3.4 billion (or up to \$3.9 billion in the event that the Company exercises its option to increase the commitments by up to an additional \$500 million and the lenders provide such additional commitments) senior secured revolving credit facility agreement between, among others, the Company and certain subsidiaries of the Company, BNP Paribas, HSBC Bank plc, Standard Chartered Bank, Lloyds TSB Bank plc and Crédit Agricole Corporate and Investment Bank and the lenders specified therein, each lender thereunder may cancel its commitments immediately and demand repayment of all outstanding amounts owed by the Company and certain subsidiaries of the Company to it under the agreement and any connected finance document, which amount will become due and payable within 15 business days and, in respect of each letter of credit issued under the agreement, full cash cover will be required within 15 business days;
under the \$300 million secured revolving credit facility agreement between, among others, the Company and certain subsidiaries of the Company, BNP Paribas, HSBC Bank plc, Standard Chartered Bank, Lloyds TSB Bank plc and Crédit Agricole Corporate and Investment Bank and the lenders specified therein, each lender thereunder may cancel its commitments immediately and demand repayment of all outstanding amounts owed by the Company and certain subsidiaries of the Company to it under the agreement and any connected finance document, which amount will become due and payable within 15 business days; and
under an indenture relating to \$650 million of 6 per cent Senior Notes due in 2020 between, among others, the Company, certain subsidiaries of the Company and Deutsche Trustee Company Limited as the Trustee, the Company must make an offer to noteholders to repurchase all the notes at 101 per cent of the aggregate principal amount of the notes, plus accrued and unpaid interest. The repurchase offer must be made by the Company to all noteholders within 30 days following the 'change of control' and the repurchase must take place no earlier than 10 days and no later than 60 days from the date the repurchase offer is made. Each noteholder may take up the offer in respect of all or part of its notes; and
under an indenture relating to \$650 million of 6.25 per cent Senior Notes due in 2022 between, among others, the Company, certain subsidiaries of the Company and Deutsche Trustee Company Limited as the Trustee, the Company must make an offer to noteholders to repurchase all the notes at 101 per cent of the aggregate principal amount of the notes, plus accrued and unpaid interest in the event that a change of control of the Company occurs. The repurchase offer must be made by the Company to all noteholders within 30 days following the change of control and the repurchase must take place no earlier than 10 days and no later than 60 days from the date the repurchase offer is made. Each noteholder may take up the offer in respect of all or part of its notes; and
The biographical details of the Directors of the Company at the date of this report are given on pages 42 and 43.
Details of Directors' service agreements and letters of appointment can be found on pages 90 and 91. Details of the Directors' interests in the ordinary shares of the Company and in the Group's long-term incentive and other share option schemes are set out on page 96 and pages 98 to 100 in the Directors' Remuneration Report.
As at the date of this report, indemnities are in force under which the Company has agreed to indemnify the Directors, to the extent permitted by the Companies Act 2006, against claims from third parties in respect of certain liabilities arising out of, or in connection with, the execution of their powers, duties and responsibilities as Directors of the Company or any of its subsidiaries. The Directors are also indemnified against the cost of defending a criminal prosecution or a claim by the Company, its subsidiaries or a regulator provided that where the defence is unsuccessful the Director must repay those defence costs. The Company also maintains Directors' and Officers' Liability insurance cover, the level of which is reviewed annually.
A Director has a duty to avoid a situation in which he or she has, or can have, a direct or indirect interest that conflicts, or possibly may conflict, with the interests of the Group. The Board requires Directors to declare all appointments and other situations that could result in a possible conflict of interest and has adopted appropriate procedures to manage and, if appropriate, approve any such conflicts. The Board is satisfied that there is no compromise to the independence of those Directors who have appointments on the boards of, or relationships with, companies outside the Group.
The general powers of the Directors are set out in Article 104 of the Articles of Association of the Company. It provides that the business of the Company shall be managed by the Board which may exercise all the powers of the Company whether relating to the management of the business of the Company or not. This power is subject to any limitations imposed on the Company by applicable legislation. It is also limited by the provisions of the Articles of Association of the Company and any directions given by special resolution of the shareholders of the Company which are applicable on the date that any power is exercised.
Please note the following specific provisions relevant to the exercise of power by the Directors:
The Company shall appoint (disregarding Alternate Directors) no fewer than two and no more than 15 Directors. The appointment and replacement of Directors may be made as follows:
Tullow is committed to eliminating discrimination and encouraging diversity amongst its workforce. Decisions related to recruitment selection, development or promotion are based upon merit and ability to adequately meet the requirements of the job, and are not influenced by factors such as gender, marital status, race, ethnic origin, colour, nationality, religion, sexual orientation, age or disability.
We want our workforce to be truly representative of all sections of society and for all our employees to feel respected and able to reach their potential. Our commitment to these aims and detailed approach are set out in Tullow's Code of Ethical Conduct and Equal Opportunities Policy.
We aim to provide an optimal working environment to suit the needs of all employees, including those of employees with disabilities. For employees who become disabled during their time with the Group, Tullow will provide support to help them remain safely in continuous employment.
We use a range of methods to inform and consult with employees about significant business issues and our performance. These include webcasts, the Group's intranet, town hall meetings and Tullow World, our in-house magazine.
We have an employee share plan for all permanent employees, which gives employees a direct interest in the business' success.
In line with Group policy, no donations were made for political purposes.
The Group works to achieve high standards of environmental, health and safety management. Our performance in these areas can be found on pages 38 and 39 of this report. Further information is available on the Group website: www.tullowoil. com, including archived copies of the separate Corporate Responsibility Report which was published in previous years.
Having made the requisite enquiries, so far as the Directors are aware, there is no relevant audit information (as defined by section 418(3) of the Companies Act 2006) of which the Company's auditor is unaware and each Director has taken all steps that ought to have been taken to make him or herself aware of any relevant audit information and to establish that the Company's auditor is aware of that information.
A resolution to re-appoint Deloitte LLP as the Company's auditor will be proposed at the AGM. More information can be found in the Audit Committee Report on page 72.
The Notice of Annual General Meeting will be mailed to shareholders separately and will set out the resolutions to be proposed at the forthcoming AGM. The meeting will be held on 26 April 2017 at Tullow Oil's Head Office, 9 Chiswick Park, 566 Chiswick High Road, London W4 5XT from 12 noon.
This Corporate Governance Report (which includes the Directors' Remuneration Report) and the information referred to herein has been approved by the Board and signed on its behalf by:
Kevin Massie Corporate Counsel and Company Secretary
7 February 2017
Registered office: 9 Chiswick Park 566 Chiswick High Road London W4 5XT
Company registered in England and Wales No. 3919249
Aerial view of the TEN FPSO, Prof. John Evans Atta Mills, offshore Ghana
| Statement of Directors' responsibilities | 108 |
|---|---|
| Independent auditor's report for the | |
| Group Financial Statements | 109 |
| Group Financial Statements | 116 |
| Company Financial Statements | 150 |
| Five-year financial summary | 159 |
| Supplementary information | |
| Shareholder information | 160 |
| Licence interests | 161 |
| Commercial reserves and resources | 166 |
| Transparency disclosure | 167 |
| Sustainability data | 172 |
| Tullow Oil plc subsidiaries | 175 |
| Glossary | 177 |
The Directors are responsible for preparing the Annual Report and the Financial Statements in accordance with applicable law and regulations.
Company law requires the Directors to prepare Financial statements for each financial year. Under that law the directors are required to prepare the Group Financial Statements in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union and Article 4 of the IAS Regulation and have elected to prepare the Parent Company Financial Statements in accordance with United Kingdom Generally Accepted Accounting Practice (United Kingdom Accounting Standards and applicable law), including FRS 101 "Reduced Disclosure Framework". Under company law the Directors must not approve the accounts unless they are satisfied that they give a true and fair view of the state of affairs of the company and of the profit or loss of the Company for that period.
In preparing the Parent Company Financial Statements, the Directors are required to:
In preparing the Group Financial Statements, International Accounting Standard 1 requires that Directors:
The Directors are responsible for keeping adequate accounting records that are sufficient to show and explain the Company's transactions and disclose with reasonable accuracy at any time the financial position of the Company and enable them to ensure that the Financial Statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of the Company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.
The Directors are responsible for the maintenance and integrity of the corporate and financial information included on the Company's website. Legislation in the United Kingdom governing the preparation and dissemination of Financial Statements may differ from legislation in other jurisdictions.
We confirm that to the best of our knowledge:
By order of the Board
Aidan Heavey Les Wood
7 February 2017 7 February 2017
Chief Executive Officer Interim Chief Financial Officer
In our opinion:
The Financial Statements that we have audited comprise:
The financial reporting framework that has been applied in the preparation of the Group Financial Statements is applicable law and IFRSs as adopted by the European Union. The financial reporting framework that has been applied in the preparation of the Parent Company Financial Statements is applicable law and United Kingdom Accounting Standards (United Kingdom Generally Accepted Accounting Practice), including FRS 101 'Reduced Disclosure Framework'.
| Key risks | The key risks that we identified in the current year were: |
|---|---|
| • the carrying value of Exploration and Evaluation ('E&E') assets; | |
| • the carrying value of Property, Plant and Equipment ('PP&E') assets; | |
| • the going concern assumption; and | |
| • provision for onerous service contracts. | |
| In the prior year provision for tax claims was also included as a key risk in our audit opinion. Whilst this remains a judgemental area, following the resolution over the past two years of some of the largest exposures, the impact on audit strategy and allocation of resources was lower in 2016. |
|
| In addition, there is a new key risk relating to the provision for onerous service contracts. | |
| Materiality | The materiality that we used in the current year was \$44 million (2015: \$60 million) which is less than 2 per cent of net assets. This equates to less than 5 per cent of pre-tax loss. |
| Scoping | Our Group audit scope included a full audit of all three reporting units which account for 100 per cent of the Group's total revenue, loss before tax and net assets. The materialities used for these components ranged from \$20 million to \$30 million. |
| Significant changes in our approach |
There have been no significant changes in our approach to the audit. |
As required by the Listing Rules we have reviewed the Directors' statement regarding the appropriateness of the going concern basis of accounting contained within note (ah) to the Financial Statements and the Directors' statement on the longer-term viability of the group on page 52.
We are required to state whether we have anything material to add or draw attention to in relation to:
We confirm that we have nothing material to add or draw attention to in respect of these matters.
We agree with the Directors' adoption of the going concern basis of accounting and we did not identify any such material uncertainties. However, because not all future events or conditions can be predicted, this statement is not a guarantee as to the Group's ability to continue as a going concern.
We are required to comply with the Financial Reporting Council's Ethical Standards for Auditors and confirm that we are independent of the Group and we have fulfilled our other ethical responsibilities in accordance with those standards.
We confirm that we are independent of the Group and we have fulfilled our other ethical responsibilities in accordance with those standards. We also confirm we have not provided any of the prohibited non-audit services referred to in those standards.
The assessed risks of material misstatement described below are those that had the greatest effect on our audit strategy, the allocation of resources in the audit and directing the efforts of the engagement team.
| Risk description See note 11 and the Audit Committee Report on page 69 for further details |
The carrying value of E&E assets as at 31 December 2016 is \$2,025.8 million, and the group has written off E&E expenditure totalling \$723.0 million in the year. |
|---|---|
| The assessment of the carrying value requires management to exercise judgement as described in the 'critical accounting judgements' section of the Annual Report on page 124. 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 for a prospect or licence, the likelihood of licence renewal, and the success of drilling and geological analysis to date. |
|
| As disclosed in note 9, the sale of a portion of the group's interest in E&E assets in Uganda was announced subsequent to the year end. This resulted in a write down of \$330.4 million to both the portion held for sale and the retained interest based on the fair value of the total expected consideration. |
| How the scope of our audit responded to the risk |
We evaluated management's assessment of E&E assets carried forward with reference to the criteria of IFRS 6: Exploration for and Evaluation of Mineral Resources and the Group's accounting policy (see page 121). |
|---|---|
| The audit procedures we performed included obtaining an understanding of the Group's ongoing E&E activity by interviewing operational and finance staff covering all key locations, and gathering audit evidence to assess the value of E&E assets carried forward. Such evidence included approved project budgets, and confirmations of ongoing appraisal activity and the licence phase. |
|
| Where an asset has demonstrated indicators of impairment but has been retained on the balance sheet, we have gathered evidence to assess the status of appraisal activity, allocation of budget and any conclusion on commerciality. |
|
| Where an asset has been impaired we have challenged management on the events that led to the impairment, including by reference to future budgeted expenditure. We have also challenged management on the inputs to the fair value calculation of the consideration receivable from the Uganda farm-down with specific focus on the expected timing of receipt of the consideration. |
|
| Key observations | We are satisfied that the assets have been treated in accordance with the criteria of IFRS 6 and Tullow's E&E accounting policy. |
| In some circumstances the costs of wells from exploration continue to be held on the balance sheet for a significant period of time while development plans are finalised and government consent is obtained, for example in Kenya and Uganda where development is considered to be highly likely. |
|
| Based on the audit evidence we have gathered we are satisfied that management has reached these conclusions appropriately. |
| Risk description See note 12 and the Audit Committee Report on page 69 for further information. |
The Group holds PP&E assets of \$5,362.9 million as at 31 December 2016 and has recorded PP&E impairments of \$167.6 million in 2016. |
||||
|---|---|---|---|---|---|
| As described in the 'critical accounting judgements' section of the Annual Report on page 124, the assessment of the carrying value of PP&E assets requires management to exercise judgement in identifying indicators of impairment, such as a decrease in oil price or a downgrade of proved and probable reserves. |
|||||
| When such indicators are identified, management must make an estimate of the recoverable amount of the asset, which is then compared against the carrying value. The calculation of the recoverable amount requires judgement in estimating future oil and gas prices, the applicable asset discount rate, and the cost and production profiles of reserves estimates. |
|||||
| How the scope of our audit responded to the risk |
We examined management's assessment of impairment indicators, which concluded that the continuation of low oil prices during the year represented an indicator of impairment for a number of assets with limited headroom. |
||||
| The assumptions that underpin management's calculation of the recoverable amount of oil and gas assets are inherently judgemental. Our audit work therefore assessed the reasonableness of management's key assumptions in calculating the recoverable amount of each asset. Specifically our work included, but was not limited to, the following procedures: |
|||||
| • benchmarking and analysis of oil and gas price assumptions against forward curves, peer information and other market data; |
|||||
| • recalculation of the recoverable amount of the assets using a reasonable range of oil prices developed from third-party forecasters; |
|||||
| • agreement of hydrocarbon production profiles and proved and probable reserves to third-party reserve reports; |
|||||
| • verification of estimated future costs by agreement to approved budgets and where applicable, third-party data; and |
|||||
| • the recalculation and benchmarking of discount rates applied, with involvement from Deloitte industry valuation specialists. |
| Key observations | Our recalculation of the recoverable amount of the assets resulted in a judgemental misstatement just above our reporting threshold that arose as a result of the oil price assumptions adopted by management falling outside of what we consider to be a reasonable range at various points in the forecast. |
|---|---|
| Notwithstanding the matter noted above, we are satisfied that the recoverability of the assets has been assessed in accordance with the requirements of IAS 36: Impairment of Assets. |
|
| Management has disclosed the impact of sensitivities of both the discount rate and commodity prices in the PP&E note on page 134. |
|
| Going concern assumption | |
| Risk description See note (ah) and the Audit Committee Report on page 69 for further information. |
The group is dependent upon its ability to generate sufficient cashflows to meet scheduled loan repayments and covenant requirements and hence to operate within its existing debt facilities. Commodity price volatility in the oil and gas sector continues to place increased pressure on these cashflows and the ability of the Group to comply in the future with covenant ratios. |
| The going concern assumption is also dependent upon group specific considerations, such as the contractual amortisation of debt facilities, performance of the Group's operating assets, the continued receipt of insurance proceeds relating to the Jubilee field in Ghana and the timing of cash outflows in respect of onerous service contracts. |
|
| How the scope of our audit responded to the risk |
Management's going concern forecasts include a number of assumptions related to future cashflows and associated risks. Our audit work has focused on evaluating and challenging the reasonableness of these assumptions and their impact on the forecast period. |
| Specifically, we obtained, challenged and assessed management's going concern forecasts, and performed procedures, including: |
|
| • Challenging management as to the reasonableness of pricing assumptions applied, based on benchmarking to market data; |
|
| • Verifying the consistency of key inputs relating to future costs and production to other financial and operational information obtained during our audit; and |
|
| • Performing sensitivity analysis on management's "base case", including applying downside scenarios such as lower oil prices, reduced production and restricted insurance proceeds, and considering the mitigating actions highlighted by management in the event that they were required. |
|
| Key observations | Management has concluded that the going concern basis remains appropriate after performing a detailed forecast of liquidity and covenant compliance for a period of 12 months from the date of approval of the 2016 Annual Report and Accounts. |
| We are satisfied that the going concern assumption remains appropriate given the headroom available in management's base case, together with the mitigating actions available to management should a liquidity shortfall arise in reasonable downside scenarios as discussed in note (ah). |
|
| Provision for onerous service contracts | |
| Risk description See note 23 and the Audit Committee Report on page |
In response to lower commodity prices and certain legal restrictions, the group has reduced its planned future work programmes and in consequence a number of service contracts have become onerous. |
| 69 for further information. | Judgement is required to estimate the appropriate level of provision required for the onerous element of the contracts and the ultimate outcome of contract claims. The assumptions made include the estimate of usage under the contract, likelihood of cash outflows and the valuation of any liability arising, including consideration of any contract claims and disputes. |
| The Group has included contract provisions in their disclosure of key sources of uncertainty on page 125. |
|
| Management has disclosed a charge of \$114.9 million in note 23 to the financial statements. |
| How the scope of our audit | Our audit work included challenging the key assumptions through consideration of correspondence |
|---|---|
| responded to the risk | with the counterparties and review of internal and external legal opinions as applicable. |
| Key observations | We are satisfied that the judgements made by management are reasonable, based on the audit evidence gathered. |
These matters were addressed in the context of our audit of the Financial Statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.
We define materiality as the magnitude of misstatement in the Financial Statements that makes it probable that the economic decisions of a reasonably knowledgeable person would be changed or influenced. We use materiality both in planning the scope of our audit work and in evaluating the results of our work.
Based on our professional judgement, we determined materiality for the Financial Statements as a whole as follows:
| Group materiality | \$44 million (2015: \$60 million) |
|---|---|
| Basis for determining materiality |
This is below 2 per cent of net assets and this base is consistent with the prior year. The absolute decrease is driven by the decrease in the Group's net assets. |
| Rationale for the benchmark applied |
We have determined materiality based on the net asset position of the group, reflecting the long-term value of the Group in its portfolio of exploration and development assets and their associated reserves and resources. It is not currently appropriate to determine materiality based on a profit metric given the Group's loss-making position, driven by the sustained low oil price environment; however, materiality equates to less than 5 per cent of pre-tax loss. |
We agreed with the Audit Committee that we would report to the Committee all audit differences in excess of \$2.2 million (2015: \$1.6 million), as well as differences below that threshold that, in our view, warranted reporting on qualitative grounds. We also report to the Audit Committee on disclosure matters that we identified when assessing the overall presentation of the financial statements. The threshold has increased relative to 2015 to align with industry practice.
Our group audit scope for the current and prior year included a full audit of all (2015: all) reporting unit locations based on our assessment of the risks of material misstatement and of the materiality of the Group's business operations at those locations. These reporting units account for 100 per cent of the Group's total revenue, loss before tax and net assets (2015: 100 per cent). The materialities used for these components ranged from \$20 million to \$30 million (2015: \$20 million to \$35 million).
The group team audits the UK, Kenya and Uganda reporting units directly. Their involvement in the work performed by component auditors varies by location and includes, at a minimum, a review of the reports provided on the results of the work undertaken by the component audit teams.
In addition, the senior statutory auditor or senior members of his group audit team visited the: Gabon and Ghana to direct and review the audit work performed by the component auditors. In addition, we visited Kenya and Uganda as part of our work on these components.
At the Parent Company level we also tested the consolidation process.
In our opinion, based on the work undertaken in the course of the audit:
In light of the knowledge and understanding of the Company and its environment obtained in the course of the audit, we have not identified any material misstatements in the Strategic Report and the Directors' Report.
| Adequacy of explanations received and accounting records Under the Companies Act 2006 we are required to report to you if, in our opinion: |
We have nothing to report in respect of these matters. |
|---|---|
| • we have not received all the information and explanations we require for our audit; or |
|
| • adequate accounting records have not been kept by the Parent Company, or returns adequate for our audit have not been received from branches not visited by us; or |
|
| • the Parent Company Financial Statements are not in agreement with the accounting records and returns. |
|
| Directors' remuneration Under the Companies Act 2006 we are also required to report if in our opinion certain disclosures of Directors' remuneration have not been made or the part of the Directors' Remuneration Report to be audited is not in agreement with the accounting records and returns. |
We have nothing to report arising from these matters. |
| Corporate Governance Statement Under the Listing Rules we are also required to review part of the Corporate Governance Statement relating to the Company's compliance with certain provisions of the UK Corporate Governance Code. |
We have nothing to report arising from our review. |
| Our duty to read other information in the Annual Report Under International Standards on Auditing (UK and Ireland), we are required to report to you if, in our opinion, information in the Annual Report is: |
We confirm that we have not identified any such inconsistencies or misleading statements. |
| • materially inconsistent with the information in the audited Financial Statements; or | |
| • apparently materially incorrect based on, or materially inconsistent with, our knowledge of the Group acquired in the course of performing our audit; or |
|
| • otherwise misleading. | |
| In particular, we are required to consider whether we have identified any inconsistencies between our knowledge acquired during the audit and the Directors' statement that they consider the Annual Report is fair, balanced and understandable and whether the annual report appropriately discloses those matters that we communicated to the Audit Committee which we consider should have been disclosed. |
As explained more fully in the Directors' Responsibilities Statement, the Directors are responsible for the preparation of the Financial Statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on the financial Statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). We also comply with International Standard on Quality Control 1 (UK and Ireland). Our audit methodology and tools aim to ensure that our quality control procedures are effective, understood and applied. Our quality controls and systems include our dedicated professional standards review team and independent partner reviews.
This report is made solely to the Company's members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the Company's members those matters we are required to state to them in an Auditor's Report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company's members, as a body, for our audit work, for this report, or for the opinions we have formed.
An audit involves obtaining evidence about the amounts and disclosures in the Financial Statements sufficient to give reasonable assurance that the Financial Statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting policies are appropriate to the Group's and the Parent Company's circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant accounting estimates made by the Directors; and the overall presentation of the Financial Statements. In addition, we read all the financial and non-financial information in the Annual Report to identify material inconsistencies with the audited Financial Statements and to identify any information that is apparently materially incorrect based on, or materially inconsistent with, the knowledge acquired by us in the course of performing the audit. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.
Dean Cook MA FCA (Senior statutory auditor) for and on behalf of Deloitte LLP Chartered Accountants and Statutory Auditor London, United Kingdom
7 February 2017
| , | Notes | 2016 \$m |
2015 \$m |
|---|---|---|---|
| Continuing activities | |||
| Sales revenue | 2 | 1,269.9 | 1,606.6 |
| Other operating income – lost production insurance proceeds | 6 | 90.1 | – |
| Cost of sales | 4 | (813.1) | (1,015.3) |
| Gross profit | 546.9 | 591.3 | |
| Administrative expenses | 4 | (116.4) | (193.6) |
| Restructuring costs | 4 | (12.3) | (40.8) |
| Loss on disposal | 9 | (3.4) | (56.5) |
| Goodwill impairment | 10 | (164.0) | (53.7) |
| Exploration costs written off | 11 | (723.0) | (748.9) |
| Impairment of property, plant and equipment, net | 12 | (167.6) | (406.0) |
| Provision for onerous service contracts, net | 23 | (114.9) | (185.5) |
| Operating loss | (754.7) | (1,093.7) | |
| Gain/(loss) on hedging instruments | 21 | 18.2 | (58.8) |
| Finance revenue | 2 | 26.4 | 4.2 |
| Finance costs | 5 | (198.2) | (149.0) |
| Loss from continuing activities before tax | (908.3) | (1,297.3) | |
| Income tax credit | 7 | 311.0 | 260.4 |
| Loss for the year from continuing activities | (597.3) | (1,036.9) | |
| Attributable to: | |||
| Owners of the Company | (599.9) | (1,034.8) | |
| Non-controlling interest | 26 | 2.6 | (2.1) |
| (597.3) | (1,036.9) | ||
| Loss per ordinary share from continuing activities | 8 | ¢ | ¢ |
| Basic | (65.8) | (113.6) | |
| Diluted | (65.8) | (113.6) |
| Notes | 2016 \$m |
2015 \$m |
|
|---|---|---|---|
| Loss for the year | (597.3) | (1,036.9) | |
| Items that may be reclassified to the income statement in subsequent periods | |||
| Cash flow hedges | |||
| (Loss)/gains arising in the year | 21 | (135.3) | 513.0 |
| Reclassification adjustments for items included in (loss)/profit on realisation | 21 | (415.2) | (302.4) |
| Exchange differences on translation of foreign operations | 17.1 | (43.6) | |
| Other comprehensive (loss)/income | (533.4) | 167.0 | |
| Tax relating to components of other comprehensive (loss)/income | 21 | 108.8 | (42.3) |
| Net other comprehensive (loss)/income for the year | (424.6) | 124.7 | |
| Total comprehensive expense for the year | (1,021.9) | (912.2) | |
| Attributable to: | |||
| Owners of the Company | (1,024.5) | (910.1) | |
| Non-controlling interest | 2.6 | (2.1) | |
| (1,021.9) | (912.2) |
| Notes | 2016 \$m |
2015 \$m |
|
|---|---|---|---|
| ASSETS | |||
| Non-current assets | |||
| Goodwill | 10 | – | 164.0 |
| Intangible exploration and evaluation assets | 11 | 2,025.8 | 3,400.0 |
| Property, plant and equipment | 12 | 5,362.9 | 5,204.4 |
| Investments | 13 | 1.0 | 1.0 |
| Other non-current assets | 14 | 175.7 | 223.4 |
| Derivative financial instruments | 21 | 15.8 | 218.7 |
| Deferred tax assets | 24 | 758.9 | 295.3 |
| 8,340.1 | 9,506.8 | ||
| Current assets | |||
| Inventories | 15 | 155.3 | 107.2 |
| Trade receivables | 16 | 118.4 | 80.8 |
| Other current assets | 14 | 838.9 | 763.2 |
| Current tax assets | 7 | 138.3 | 127.6 |
| Derivative financial instruments | 21 | 91.7 | 406.5 |
| Cash and cash equivalents | 17 | 281.9 | 355.7 |
| Assets classified as held for sale | 18 | 837.1 | – |
| 2,461.6 | 1,841.0 | ||
| Total assets | 10,801.7 | 11,347.8 | |
| LIABILITIES | |||
| Current liabilities | |||
| Trade and other payables | 19 | (916.1) | (1,110.6) |
| Provisions | 23 | (51.9) | (187.0) |
| Borrowings | 20 | (591.5) | (73.8) |
| Current tax liabilities | (83.1) | (208.3) | |
| Derivative financial instruments | 21 | (5.9) | (2.1) |
| (1,648.5) | (1,581.8) | ||
| Non-current liabilities | |||
| Trade and other payables | 19 | (112.3) | (99.3) |
| Borrowings | 20 | (4,388.4) | (4,262.4) |
| Provisions | 23 | (1,106.7) | (1,065.1) |
| Deferred tax liabilities | 24 | (1,292.4) | (1,164.5) |
| Derivative financial instruments | 21 | (10.9) | – |
| (6,910.7) | (6,591.3) | ||
| Total liabilities | (8,559.2) | (8,173.1) | |
| Net assets | 2,242.5 | 3,174.7 | |
| EQUITY | |||
| Called-up share capital | 25 | 147.5 | 147.2 |
| Share premium | 25 | 619.3 | 609.8 |
| Equity component of convertible bonds | 48.4 | – | |
| Foreign currency translation reserve | (232.2) | (249.3) | |
| Hedge reserve | 21 | 128.2 | 569.9 |
| Other reserves | 740.9 | 740.9 | |
| Retained earnings | 778.0 | 1,336.4 | |
| Equity attributable to equity holders of the Company | 2,230.1 | 3,154.9 | |
| Non-controlling interest | 26 | 12.4 | 19.8 |
| Total equity | 2,242.5 | 3,174.7 |
Approved by the Board and authorised for issue on 7 February 2017.
Aidan Heavey Les Wood
Chief Executive Officer Interim Chief Financial Officer
| Equity component |
Foreign | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Notes | Share capital \$m |
Share premium \$m |
of convertible bonds \$m |
currency translation reserve1 \$m |
Hedge reserve2 \$m |
Other reserves3 \$m |
Retained earnings \$m |
Total \$m |
Non controlling interest4 \$m |
Total equity \$m |
|
| At 1 January 2015 | 147.0 | 606.4 | – | (205.7) | 401.6 | 740.9 | 2,305.8 | 3,996.0 | 24.3 | 4,020.3 | |
| Loss for the year | – | – | – | – | – | – | (1,034.8) | (1,034.8) | (2.1) | (1,036.9) | |
| Hedges, net of tax | 21 | – | – | – | – | 168.3 | – | – | 168.3 | – | 168.3 |
| Currency translation adjustments |
– | – | – | (43.6) | – | – | – | (43.6) | – | (43.6) | |
| Issue of employee share options |
25 | 0.2 | 3.4 | – | – | – | – | – | 3.6 | – | 3.6 |
| Vesting of PSP shares | – | – | – | – | – | – | (1.9) | (1.9) | – | (1.9) | |
| Share-based payment charges |
27 | – | – | – | – | – | – | 67.3 | 67.3 | – | 67.3 |
| Distribution to non | |||||||||||
| controlling interests | 26 | – | – | – | – | – | – | – | – | (2.4) | (2.4) |
| At 1 January 2016 | 147.2 | 609.8 | – | (249.3) | 569.9 | 740.9 | 1,336.4 | 3,154.9 | 19.8 | 3,174.7 | |
| Loss for the year | – | – | – | – | – | – | (599.9) | (599.9) | 2.6 | (597.3) | |
| Hedges, net of tax | 21 | – | – | – | – | (441.7) | – | – | (441.7) | – | (441.7) |
| Currency translation adjustments |
– | – | – | 17.1 | – | – | – | 17.1 | – | 17.1 | |
| Issue of convertible bonds |
20 | – | – | 48.4 | – | – | – | – | 48.4 | – | 48.4 |
| Issue of employee | |||||||||||
| share options | 25 | 0.3 | 9.5 | – | – | – | – | – | 9.8 | – | 9.8 |
| Vesting of PSP shares | – | – | – | – | – | – | (9.4) | (9.4) | – | (9.4) | |
| Share-based payment charges |
27 | – | – | – | – | – | – | 50.9 | 50.9 | – | 50.9 |
| Distribution to non controlling interests |
26 | – | – | – | – | – | – | – | – | (10.0) | (10.0) |
| At 31 December 2016 | 147.5 | 619.3 | 48.4 | (232.2) | 128.2 | 740.9 | 778.0 | 2,230.1 | 12.4 | 2,242.5 |
The foreign currency translation reserve represents exchange gains and losses arising on translation of foreign currency subsidiaries, monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur, which form part of the net investment in a foreign operation, and exchange gains or losses arising on long-term foreign currency borrowings which are a hedge against the Group's overseas investments.
The hedge reserve represents gains and losses on derivatives classified as effective cash flow hedges.
Other reserves include the merger reserve and the treasury shares reserve which represents the cost of shares in Tullow Oil plc purchased in the market and held by the Tullow Oil Employee Trust to satisfy awards held under the Group's share incentive plans (note 27).
Non-controlling interest is described further in note 26.
| 3 |
|---|
| (908.3) (1,297.3) 4 466.9 580.1 3.4 9 56.5 10 164.0 53.7 723.0 11 748.9 167.6 12 406.0 114.9 23 185.5 23 (132.0) – – 15 22.2 (23.0) 23 (40.8) 27 43.9 48.7 (18.2) 21 58.8 (26.4) 2 (4.2) 5 198.2 149.0 774.0 967.1 (99.4) (26.5) (47.8) 9.0 (29.8) (6.3) Cash generated from operating activities 597.0 943.3 (84.5) Income taxes (paid)/received 34.9 512.5 978.2 Cash flows from investing activities Proceeds from disposals 9 62.8 55.8 (275.2) Purchase of intangible exploration and evaluation assets (647.6) (756.0) Purchase of property, plant and equipment (1,092.0) 1.2 4.2 Net cash used in investing activities (967.2) (1,679.6) Cash flows from financing activities Net proceeds from issue of share capital 9.9 3.5 Debt arrangement fees (31.7) (25.7) (769.1) Repayment of borrowings (191.8) 1,187.5 Drawdown of borrowings 1,168.8 Issue of convertible bond 300.0 – (3.3) Repayment of obligations under finance leases (3.3) (284.0) Finance costs paid (203.6) Distribution to non-controlling interests 26 (10.0) (2.4) 399.3 745.5 (55.4) 44.1 Net (decrease)/increase in cash and cash equivalents 17 355.7 319.0 Cash and cash equivalents at beginning of year (18.3) (7.4) 281.9 17 355.7 Cash and cash equivalents at end of year |
Notes | 2016 \$m |
20151 \$m |
|
|---|---|---|---|---|
| Cash flows from operating activities | ||||
| Loss before taxation | ||||
| Adjustments for: | ||||
| Depreciation, depletion and amortisation | ||||
| Loss on disposal | ||||
| Goodwill impairment | ||||
| Exploration costs written off | ||||
| Impairment of property, plant and equipment, net | ||||
| Provision for onerous service contracts, net | ||||
| Payment under onerous service contracts | ||||
| Provision for inventory | ||||
| Decommissioning expenditure | ||||
| Share-based payment charge | ||||
| (Gain)/loss on hedging instruments | ||||
| Finance revenue | ||||
| Finance costs | ||||
| Operating cash flow before working capital movements | ||||
| Increase in trade and other receivables | ||||
| (Increase)/decrease in inventories | ||||
| Decrease in trade payables | ||||
| Net cash from operating activities | ||||
| Interest received | ||||
| Net cash generated by financing activities | ||||
| Foreign exchange loss | ||||
Tullow Oil plc is a company incorporated and domiciled in the United Kingdom under the Companies Act 2006. The address of the registered office is Tullow Oil plc, Building 9, Chiswick Park, 566 Chiswick High Road, London W4 5XT. The primary activity of the Group is the discovery and production of oil and gas.
New and revised Standards and Interpretations adopted in the current year did not have any significant impact on the amounts reported in these Financial Statements.
At the date of authorisation of these Financial Statements, the following Standards and Interpretations which have not been applied in these Financial Statements, but will have an impact on future Financial Statements, were in issue but not yet effective (and in some cases had not yet been adopted by the EU):
| IFRS 9 | Financial Instruments |
|---|---|
IFRS 16 Leases
The adoption of IFRS 9 Financial Instruments, which the Group will adopt for the year commencing 1 January 2018, will impact both the measurement and disclosures of financial instruments. The adoption of IFRS 16 Leases, which the Group will adopt for the year commencing 1 January 2019, will impact both the measurement and disclosures of leases.
The Group's accounting policies are consistent with the prior year.
The Financial Statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). The Financial Statements have also been prepared in accordance with IFRS as adopted by the European Union and therefore the Group Financial Statements comply with Article 4 of the EU IAS Regulation.
The Financial Statements have been prepared on the historical cost basis, except for derivative financial instruments that have been measured at fair value and assets classified as held for sale which are carried at fair value less cost to sell. The Financial Statements are presented in US dollars and all values are rounded to the nearest \$0.1 million, except where otherwise stated. The Financial Statements have been prepared on a going concern basis.
The principal accounting policies adopted by the Group are set out below.
The consolidated Financial Statements incorporate the Financial Statements of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power over an investee entity, is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to use its power to affect its returns.
Non-controlling interests in the net assets of consolidated subsidiaries are identified separately from the Group's equity therein. Non-controlling interests consist of the amount of those interests at the date of the original business combination (see below) and the non-controlling share of changes in equity since the date of the combination. Losses within a subsidiary are attributed to the non-controlling interest even if that results in a deficit balance. The Group does not have any material non-controlling interests.
The results of subsidiaries acquired or disposed of during the year are included in the Group income statement from the transaction date of acquisition, being the date on which the Group gains control, and will continue to be included until the date that control ceases.
Where necessary, adjustments are made to the Financial Statements of subsidiaries to bring the accounting policies used into line with those used by the Group.
All intra-Group transactions, balances, income and expenses are eliminated on consolidation.
The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classified as joint operations in accordance with IFRS 11. The Group accounts for its share of the results and net assets of these joint operations. In addition, where Tullow acts as Operator to the joint operation, the gross liabilities and receivables (including amounts due to or from non-operating partners) of the joint operation are included in the Group's balance sheet.
Non-current assets (or disposal groups) classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell. Non-current assets and disposal groups are classified as held for sale if their carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset (or disposal group) is available for immediate sale in its present condition, management views this trigger as signature of a Sales and Purchase Agreement or Board approval. Management must be committed to the sale which should be expected to qualify for recognition as a completed sale within one year from the date of classification. Assets classified as held for sale and the corresponding liabilities are classified with current assets and liabilities on a separate line in the balance sheet.
Sales revenue represents the sales value, net of VAT, of the Group's share of liftings in the year together with the gain/loss on realisation of cash flow hedges and tariff income. Revenue is recognised when goods are delivered and title has passed.
Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount.
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 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 adjusted through cost of sales such that gross profit is recognised on an entitlements basis.
In respect of redeterminations, any adjustments to the Group's net entitlement of future production are accounted for prospectively in the period in which the make-up oil is produced. Where the make-up period extends beyond the expected life of a field an accrual is recognised for the expected shortfall.
Inventories, other than oil products, are stated at the lower of cost and net realisable value. Cost is determined by the firstin first-out method and comprises direct purchase costs, costs of production and transportation and manufacturing expenses. Net realisable value is determined by reference to prices existing at the balance sheet date.
Oil product is stated at net realisable value and changes in net realisable value are recognised in the income statement.
The US dollar is the presentation currency of the Group. For the purpose of presenting consolidated Financial Statements, the assets and liabilities of the Group's non-US dollardenominated functional entities are translated at exchange rates prevailing on the balance sheet date. Income and expense items are translated at the average exchange rates for the period. Currency translation adjustments arising on the restatement of opening net assets of non-US dollar subsidiaries, together with differences between the subsidiaries' results translated at average rates versus closing rates, are recognised in the statement of comprehensive income and expense and transferred to the foreign currency translation reserve. All resulting exchange differences are classified as equity until disposal of the subsidiary. On disposal, the cumulative amounts of the exchange differences are recognised as income or expense.
Transactions in foreign currencies are recorded at the rates of exchange ruling at the transaction dates. Monetary assets and liabilities are translated into functional currency at the exchange rate ruling at the balance sheet date, with a corresponding charge or credit to the income statement. However, exchange gains and losses arising on monetary items receivable from or payable to a foreign operation for which settlement is neither planned nor likely to occur, which form part of the net investment in a foreign operation, are recognised in the foreign currency translation reserve and recognised in profit or loss on disposal of the net investment. In addition, exchange gains and losses arising on long-term foreign currency borrowings which are a hedge against the Group's overseas investments are dealt with in reserves.
The Group allocates goodwill to cash-generating units (CGUs) or groups of CGUs that represent the assets acquired as part of the business combination.
Goodwill is tested for impairment annually as at 31 December and when circumstances indicate that the carrying value may be impaired.
Impairment is determined for goodwill by assessing the recoverable amount, using the 'Fair value less cost to sell' method, of each CGU (or group of CGUs) to which goodwill relates. When the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognised. Impairment losses relating to goodwill cannot be reversed in future periods.
The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Pre-licence costs are expensed in the period in which they are incurred. All licence acquisition, exploration and evaluation costs and directly attributable administration costs are initially capitalised in cost centres by well, field or exploration area, as appropriate. Interest payable is capitalised insofar as it relates to specific development activities.
These costs are then written off as exploration costs in the income statement unless commercial reserves have been established or the determination process has not been completed and there are no indications of impairment.
All field development costs are capitalised as property, plant and equipment. Property, plant and equipment related to production activities is amortised in accordance with the Group's depletion and amortisation accounting policy.
Cash consideration received on farm-down of exploration and evaluation assets is credited against the carrying value of the asset.
Commercial reserves are proven and probable oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 per cent statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proven and probable reserves and a 50 per cent statistical probability that it will be less.
All expenditure carried within each field is amortised from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field-by-field basis or by a group of fields which are reliant on common infrastructure. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs required to recover the commercial reserves remaining. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively.
Where there has been a change in economic conditions that indicates a possible impairment in a discovery field, the recoverability of the net book value relating to that field is assessed by comparison with the estimated discounted future cash flows based on management's expectations of future oil and gas prices and future costs.
In order to discount the future cash flows the Group calculates CGU-specific discount rates. The discount rates are based on an assessment of the Group's and a relevant peer group's post-tax Weighted Average Cost of Capital (WACC). The post-tax WACC is subsequently grossed up to a pre-tax rate. The Group then deducts any exploration risk premium which is implicit within the Group's and peer group's WACC and subsequently applies additional country risk premium for CGUs in Gabon and Congo, an element of which is determined by whether the assets are onshore or offshore.
Where there is evidence of economic interdependency between fields, such as common infrastructure, the fields are grouped as a single CGU for impairment purposes.
Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the income statement, net of any amortisation that would have been charged since the impairment.
Provision for decommissioning is recognised in full when the related facilities are installed. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated cost of decommissioning, discounted to its net present value, and is reassessed each year in accordance with local conditions and requirements. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. The unwinding of the discount on the decommissioning provision is included as a finance cost.
Property, plant and equipment is stated in the balance sheet at cost less accumulated depreciation and any recognised impairment loss. Depreciation on property, plant and equipment other than production assets is provided at rates calculated to write off the cost less the estimated residual value of each asset on a straight line basis over its expected useful economic life of between three and five years.
Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.
Finance costs of debt are allocated to periods over the term of the related debt at a constant rate on the carrying amount. Arrangement fees and issue costs are deducted from the debt proceeds on initial recognition of the liability and are amortised and charged to the income statement as finance costs over the term of the debt.
Costs of share issues are written off against the premium arising on the issues of share capital.
Current and deferred tax, including UK corporation tax and overseas corporation tax, are provided at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred corporation tax is recognised on all temporary differences that have originated but not reversed at the balance sheet date where transactions or events that result in an obligation to pay more, or right to pay less, tax in the future have occurred at the balance sheet date. Deferred tax assets are recognised only to the extent that it is considered more likely than not that there will be suitable taxable profits from which the underlying temporary differences can be deducted. Deferred tax is measured on a non-discounted basis.
Deferred tax is provided on temporary differences arising on acquisitions that are categorised as Business Combinations. Deferred tax is recognised at acquisition as part of the assessment of the fair value of assets and liabilities acquired. Any deferred tax is charged or credited in the income statement as the underlying temporary difference is reversed.
Petroleum Revenue Tax (PRT) is treated as an income tax and deferred PRT is accounted for under the temporary difference method. Current UK PRT is charged as a tax expense on chargeable field profits included in the income statement and is deductible for UK corporation tax.
Contributions to the Group's defined contribution pension schemes are charged to operating profit on an accruals basis.
The Group uses derivative financial instruments to manage its exposure to fluctuations in foreign exchange rates, interest rates and movements in oil and gas prices.
Derivative financial instruments are stated at fair value.
The purpose for which a derivative is used is established at inception. To qualify for hedge accounting, the derivative must be highly effective in achieving its objective and this effectiveness must be documented at inception and throughout the period of the hedge relationship. The hedge must be assessed on an ongoing basis and determined to have been highly effective throughout the financial reporting periods for which the hedge was designated.
For the purpose of hedge accounting, hedges are classified as either fair value hedges, when they hedge the exposure to changes in the fair value of a recognised asset or liability, or cash flow hedges, where they hedge exposure to variability in cash flows that is either attributable to a particular risk associated with a recognised asset or liability or forecast transaction.
For cash flow hedges, the portion of the gains and losses on the hedging instrument that is determined to be an effective hedge is taken to other comprehensive income and the ineffective portion, as well as any change in time value, is recognised in the income statement. The gains and losses taken to other comprehensive income are subsequently transferred to the income statement during the period in which the hedged transaction affects the income statement.
A similar treatment applies to foreign currency loans which are hedges of the Group's net investment in the net assets of a foreign operation.
Gains or losses on derivatives that do not qualify for hedge accounting treatment (either from inception or during the life of the instrument) are taken directly to the income statement in the period.
Where bonds issued with certain conversion rights are identified as compound instruments, the liability and equity components are separately recognised.
The fair value of the liability component on initial recognition is calculated by discounting the contractual stream of future cash flows using the prevailing market interest rate for similar non-convertible debt.
The difference between the fair value of the liability component and the fair value of the whole instrument is recorded as equity.
Transaction costs are apportioned between the liability and the equity components of the instrument based on the amounts initially recognised.
The liability component is subsequently measured at amortised cost using the effective interest rate method, in line with our other financial liabilities.
The equity component is not remeasured.
On conversion of the instrument, equity is issued and the liability component is derecognised. The original equity component recognised at inception remains in equity. No gain or loss is recognised on conversion.
Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. A finance lease is recognised when the Group enters the uncancellable lease period and obtains the right to use the asset as intended. All other leases are classified as operating leases and are charged to the income statement on a straight line basis over the term of the lease.
From the commencement of the lease assets held under finance leases are recognised as assets of the Group at their fair value or, if lower, at the present value of the minimum lease payments, each determined at the inception of the lease. The corresponding liability to the lessor is included in the balance sheet as a finance lease obligation. Lease payments are apportioned between finance charges and reduction of the lease obligation so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are charged directly against income, unless they are directly attributable to qualifying assets, in which case they are capitalised in accordance with the Group's policy on borrowing costs.
The Group has applied the requirements of IFRS 2 Sharebased Payments. The Group has share-based awards that are equity settled and cash settled as defined by IFRS 2. The fair value of the equity settled awards has been determined at the date of grant of the award allowing for the effect of any market-based performance conditions. This fair value, adjusted by the Group's estimate of the number of awards
that will eventually vest as a result of non-market conditions, is expensed uniformly over the vesting period.
The fair values were calculated using a binomial option pricing model with suitable modifications to allow for employee turnover after vesting and early exercise. Where necessary, this model is supplemented with a Monte Carlo model. The inputs to the models include: the share price at date of grant; exercise price; expected volatility; expected dividends; risk-free rate of interest; and patterns of exercise of the plan participants.
For cash settled awards, a liability is recognised for the goods or service acquired, measured initially at the fair value of the liability. At each balance sheet date until the liability is settled, and at the date of settlement, the fair value of the liability is remeasured, with any changes in fair value recognised in the income statement.
All financial assets are recognised and derecognised on a trade date where the purchase or sale of a financial asset is under a contract whose terms require delivery of the investment within the timeframe established by the market concerned, and are initially measured at fair value, plus transaction costs.
Financial assets are classified into the following specified categories: financial assets 'at fair value through profit or loss' (FVTPL); 'held-to-maturity' investments; 'availablefor-sale' (AFS) financial assets; and 'loans and receivables'. The classification depends on the nature and purpose of the financial assets and is determined at the time of initial recognition.
Cash and cash equivalents comprise cash at bank, demand deposits and other short-term highly liquid investments that are readily convertible to a known amount of cash and are subject to an insignificant risk of changes in value.
Trade receivables, loans and other receivables that have fixed or determinable payments that are not quoted in an active market are classified as loans and receivables. Loans and receivables are measured at amortised cost using the effective interest method, less any impairment. Interest income is recognised by applying the effective interest rate, except for short-term receivables when the recognition of interest would be immaterial.
The effective interest method is a method of calculating the amortised cost of a financial asset and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees on points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial asset, or, where appropriate, a shorter period.
Income is recognised on an effective interest basis for debt instruments other than those financial assets classified as at FVTPL. The Group chooses not to disclose the effective interest rate for debt instruments that are classified as at fair value through profit or loss.
Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into.
An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities. Equity instruments issued by the Group are recorded at the proceeds received, net of direct issue costs.
Other financial liabilities, including borrowings, are initially measured at fair value, net of transaction costs. Other financial liabilities are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis.
Insurance proceeds related to lost production under the Business Interruption insurance policy are recorded as other operating income in the income statement. Proceeds related to compensation for incremental operating costs under the Business Interruption and Hull and Machinery insurance policies are recorded within the operating costs line of cost of sales. Proceeds related to compensation for capital costs under the Hull and Machinery insurance policy where no asset is disposed are recorded within additions to property, plant and equipment.
The Group assesses critical accounting judgements annually. The following are the critical judgements, apart from those involving estimations which are dealt with in policy (ah), that the Directors have made in the process of applying the Group's accounting policies and that have the most significant effect on the amounts recognised in the Financial Statements.
• Recognition of finance lease liabilities:
The Group has a contract with a supplier for the lease of the TEN field (Ghana) FPSO. Management was required to exercise judgement determining whether the FPSO should be recognised as a finance lease in accordance with IAS 17 as at 31 December 2016.
The key judgement involved in determining that a finance lease should not be recognised was assessment of key contractual clauses that due to the delays in commissioning and the fact that the Certificate of Offshore Completion was not issued before 31 December 2016 the non-cancellable lease period had not commenced and the Group had not obtained the right of use of the vessel in its intended form. Therefore commencement of the lease had not occurred and the finance lease asset and liability were not recognised at the balance sheet date. If management had concluded the recognition criteria had been met then a \$1.6 billion finance lease would have been recognised on the balance sheet.
• Recognition of assets held for sale (note 18):
The Group signed a sales and purchase agreement for farmdown of a portion of its interest in Uganda to Total on 9 January 2017. Management has exercised judgement in determining that this disposal met the requirements of IFRS 5 and that the associated assets and liabilities should be transferred to held for sale.
The critical judgement in determining that the assets were held for sale was regarding the point that management were committed to the sale. The sales and purchase agreement was signed after the balance sheet date on 9 January 2017; however, the Board had approved the transaction in December 2016, at which point the sale was highly probable. If management had concluded that the sale was not highly probable this would result in the reclassification of \$829.7 million assets held for sale back into intangible exploration and evaluations assets.
The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.
• Carrying value of intangible exploration and evaluation assets (note 11):
The amounts for intangible exploration and evaluation assets represent active exploration projects. These amounts will be written off to the income statement as exploration costs unless commercial reserves are established or the determination process is not completed and there are no indications of impairment in accordance with the Group's accounting policy. The process of determining whether there is an indicator for impairment or calculating the impairment requires critical estimation.
The key areas in which management has applied judgement and estimation are as follows: the Group's intention to proceed with a future work programme for a prospect or licence; the likelihood of licence renewal or extension; and the success of a well result or geological or geophysical survey.
• Carrying value of property, plant and equipment (note 12):
Management performs impairment reviews on the Group's property, plant and equipment assets at least annually with reference to indicators in IAS 36 Impairment of Assets. Where indicators are present and an impairment test is required, the calculation of the recoverable amount requires estimation of future cash flows within complex impairment models.
Key assumptions and estimates in the impairment models relate to: commodity prices that are based on forward curves for two years, the mid-term price assumption for three years after this and the long-term corporate economic assumptions thereafter, pre-tax discount rates that are adjusted to reflect risks specific to individual assets, commercial reserves and the related cost profiles.
• Commercial reserves estimates used in the calculation of DD&A and impairment of property, plant and equipment (note 12):
Proven and probable reserves are estimates of the amount of oil and gas that can be economically extracted from the Group's oil and gas assets. The Group estimates its reserves using standard recognised evaluation techniques. The estimate is reviewed at least twice annually by management and is regularly reviewed by independent consultants.
Proven and probable reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves and the proportion of the gross reserves which are attributable to host governments under the terms of the Production Sharing Contracts. Future development costs are estimated taking into account the level of development required to produce the reserves by reference to operators, where applicable, and internal engineers.
• Presumption of going concern:
The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices and different production rates from the Group's producing assets. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.0 billion of debt liquidity headroom and free cash at the end of 2016. The Group's forecasts show that the Group will be able to operate within its current debt facilities and have sufficient financial headroom for the 12 months from the date of approval of the 2016 Annual Report and Accounts.
Notwithstanding our forecasts of liquidity headroom throughout the 12-month period, risk remains in relation to the volatility of the oil price environment, operational performance of the Group's assets, their impact on operating cash flows and the Group's currently contracted debt maturity profiles, such that the Group's liquidity position may deteriorate within the assessment period.
To mitigate these risks and to fulfil the Group's objective to reduce net debt, the Group continues to closely monitor cash flow projections and will take mitigating actions in advance to maintain our liquidity. Actions available to the Group include additional funding options, further rationalisation of our cost base, including cuts to discretionary capital expenditure, and portfolio management.
Based on the analysis above and the level of mitigating actions available, the Directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing the annual Financial Statements.
• Decommissioning costs (note 23):
Decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to the relevant legal requirements, the emergence of new technology or experience at other assets. The expected timing, work scope, amount of expenditure and risk weighting may also change. Therefore significant estimates and assumptions are made in determining the provision for decommissioning.
The estimated decommissioning costs are reviewed annually by an internal expert and the results of this review are then assessed alongside estimates from Operators. Provision for environmental clean-up and remediation costs is based on current legal and contractual requirements, technology and price levels.
• Provisions for onerous service contracts (note 23):
Due to the reduction in planned future work programmes the Group has identified a number of onerous service contracts. In order to calculate the provisions management has estimated the expected future usage of the contracts and its estimated liability under the contract.
The information reported to the Group's Chief Executive Officer for the purposes of resource allocation and assessment of segment performance is focused on three Business Delivery Teams, West Africa (including non-operated producing European assets), East Africa and New Ventures. Therefore the Group's reportable segments under IFRS 8 are West Africa; East Africa; and New Ventures. The following tables present revenue, loss and certain asset and liability information regarding the Group's reportable business segments for the years ended 31 December 2016 and 31 December 2015.
| Notes | West Africa \$m |
East Africa \$m |
New Ventures \$m |
Unallocated \$m |
Total \$m |
|
|---|---|---|---|---|---|---|
| 2016 | ||||||
| Sales revenue by origin | 1,269.9 | – | – | – | 1,269.9 | |
| Other operating income – lost production | ||||||
| insurance proceeds | – | – | – | 90.1 | 90.1 | |
| Segment result | 269.9 | (341.0) | (512.3) | (39.2) | (622.6) | |
| Loss on disposal | (3.4) | |||||
| Unallocated corporate expenses | (128.7) | |||||
| Operating loss | (754.7) | |||||
| Gain on hedging instruments | 18.2 | |||||
| Finance revenue | 26.4 | |||||
| Finance costs | (198.2) | |||||
| Loss before tax | (908.3) | |||||
| Income tax credit | 311.0 | |||||
| Loss after tax | (597.3) | |||||
| Total assets | 7,701.7 | 2,383.5 | 467.2 | 249.3 | 10,801.7 | |
| Total liabilities | (3,200.9) | (157.6) | (142.0) | (5,058.7) | (8,559.2) | |
| Other segment information | ||||||
| Capital expenditure: | ||||||
| Property, plant and equipment | 12 | 817.0 | 0.3 | 0.4 | 0.8 | 818.5 |
| Intangible exploration and evaluation assets | 11 | 9.9 | 137.4 | 144.1 | – | 291.4 |
| Depreciation, depletion and amortisation | 12 | (450.4) | (0.9) | (1.0) | (14.6) | (466.9) |
| Impairment of property, plant and equipment | 12 | (167.2) | – | (0.4) | – | (167.6) |
| Exploration costs written off | 11 | (7.7) | (341.0) | (374.3) | – | (723.0) |
| Goodwill impairment | 10 | – | – | (164.0) | – | (164.0) |
All sales are to external customers. Included in revenue arising from West Africa are revenues of approximately \$213.0 million and \$92.7 million relating to the Group's largest customers (2015: \$314.9 million and \$164.2 million relating to the Group's largest customers). As the sales of oil and gas are made on global markets and are highly liquid, the Group does not place reliance on the largest customers mentioned above.
Unallocated expenditure and net liabilities include amounts of a corporate nature and not specifically attributable to a reportable segment. The liabilities comprise the Group's external debt and other non-attributable corporate liabilities. The unallocated capital expenditure for the period comprises the acquisition of non-attributable corporate assets.
| Notes | West Africa \$m |
East Africa \$m |
New Ventures \$m |
Unallocated \$m |
Total \$m |
|
|---|---|---|---|---|---|---|
| 2015 | ||||||
| Sales revenue by origin | 1,606.6 | – | – | – | 1,606.6 | |
| Segment result | (189.7) | (28.3) | (461.2) | (123.6) | (802.8) | |
| Loss on disposal | (56.5) | |||||
| Unallocated corporate expenses | (234.4) | |||||
| Operating loss | (1,093.7) | |||||
| Loss on hedging instruments | (58.8) | |||||
| Finance revenue | 4.2 | |||||
| Finance costs | (149.0) | |||||
| Loss before tax | (1,297.3) | |||||
| Income tax credit | 260.4 | |||||
| Loss after tax | (1,036.9) | |||||
| Total assets | 7,510.5 | 2,601.6 | 1,011.2 | 224.5 | 11,347.8 | |
| Total liabilities | (3,085.8) | (341.4) | (331.8) | (4,414.1) | (8,173.1) | |
| Other segment information | ||||||
| Capital expenditure: | ||||||
| Property, plant and equipment | 12 | 1,245.0 | 0.5 | 1.5 | 11.2 | 1,258.2 |
| Intangible exploration and evaluation assets | 11 | 23.1 | 399.6 | 203.6 | – | 626.3 |
| Depreciation, depletion and amortisation | 12 | (553.2) | (1.1) | (1.2) | (24.6) | (580.1) |
| Impairment of property, plant and equipment | 12 | (406.0) | – | – | – | (406.0) |
| Exploration costs written off | 11 | (380.0) | (28.3) | (340.6) | – | (748.9) |
| Goodwill impairment | 10 | – | – | (53.7) | – | (53.7) |
| Sales revenue and non-current assets by origin | Sales revenue 2016 \$m |
Sales revenue 2015 \$m |
Non-current assets 2016 \$m |
Non-current assets 2015 \$m |
|---|---|---|---|---|
| Congo | 22.8 | 39.7 | – | 12.2 |
| Côte d'Ivoire | 61.3 | 91.8 | 108.6 | 159.1 |
| Equatorial Guinea | 141.4 | 176.1 | 166.1 | 218.6 |
| Gabon | 241.2 | 284.3 | 206.0 | 234.5 |
| Ghana | 666.6 | 869.1 | 5,188.8 | 4,891.0 |
| Mauritania | 23.9 | 18.9 | – | – |
| Netherlands | 31.5 | 57.5 | 113.0 | 115.5 |
| UK | 81.2 | 69.2 | 0.4 | 6.0 |
| Other | – | – | – | 0.5 |
| Total West Africa | 1,269.9 | 1,606.6 | 5,782.9 | 5,637.4 |
| Kenya | – | – | 936.9 | 880.6 |
| Uganda | – | – | 489.1 | 1,593.5 |
| Total East Africa | – | – | 1,426.0 | 2,474.1 |
| Norway | – | – | 12.1 | 474.8 |
| Other | – | – | 264.1 | 297.7 |
| Total New Ventures | – | – | 276.2 | 772.5 |
| Unallocated | – | – | 80.3 | 108.8 |
| Total revenue / non-current assets | 1,269.9 | 1,606.6 | 7,565.4 | 8,992.8 |
Non-current assets excludes derivative financial instruments and deferred tax assets.
| Notes | 2016 \$m |
2015 \$m |
|---|---|---|
| Sales revenue (excluding tariff income) | ||
| Oil and gas revenue from the sale of goods | 886.2 | 1,225.6 |
| Gain on realisation of cash flow hedges 21 |
363.0 | 365.2 |
| 1,249.2 | 1,590.8 | |
| Tariff income | 20.7 | 15.8 |
| Total sales revenue | 1,269.9 | 1,606.6 |
| Other operating income – lost production insurance proceeds 6 |
90.1 | – |
| Finance revenue | 26.4 | 4.2 |
| Total revenue | 1,386.4 | 1,610.8 |
The average monthly number of employees and contractors (including Executive Directors) employed by the Group worldwide was:
| 2016 Number |
2015 Number |
|
|---|---|---|
| Administration | 628 | 785 |
| Technical | 710 | 928 |
| Total | 1,338 | 1,713 |
| Staff costs in respect of those employees were as follows: | ||
| 2016 \$m |
2015 \$m |
|
| Salaries | 203.3 | 325.5 |
| Social security costs | 7.5 | 13.0 |
| Pension costs | 16.6 | 20.9 |
| 227.4 | 359.4 |
The decrease in staff costs is due to decreased employee numbers as a result of the Major Simplification Project. A proportion of the Group's staff costs shown above is recharged to the Group's Joint Venture partners, a proportion is allocated to operating costs and a proportion is capitalised into the cost of fixed assets under the Group's accounting policy for exploration, evaluation and production assets with the remainder classified as an administrative overhead cost in the income statement. The net staff cost recognised in the income statement was \$59.8 million (2015: \$124.7 million).
Details of Directors' remuneration, Directors' transactions and Directors' interests are set out in the part of the Directors' Remuneration Report described as having been audited, which forms part of these Financial Statements.
| Notes | 2016 \$m |
2015 \$m |
|
|---|---|---|---|
| Operating loss is stated after charging: | |||
| Operating costs | 377.2 | 406.3 | |
| Operating lease payments | 21.0 | – | |
| Depletion and amortisation of oil and gas assets | 12 | 448.5 | 551.2 |
| Underlift, overlift and oil stock movements | (76.5) | (1.5) | |
| Share-based payment charge included in cost of sales | 27 | 2.7 | 0.8 |
| Other cost of sales | 40.2 | 58.5 | |
| Total cost of sales | 813.1 | 1,015.3 | |
| Share-based payment charge included in administrative expenses | 27 | 41.2 | 47.9 |
| Depreciation of other fixed assets | 12 | 18.4 | 28.9 |
| Relocation costs associated with Major Simplification Project | (0.5) | 5.9 | |
| Cash administrative costs | 57.3 | 110.9 | |
| Total administrative expenses | 116.4 | 193.6 | |
| Total restructuring costs | 23 | 12.3 | 40.8 |
| Fees payable to the Company's auditor for: | |||
| The audit of the Company's annual accounts | 0.3 | 0.4 | |
| The audit of the Company's subsidiaries pursuant to legislation | 1.8 | 2.1 | |
| Total audit services | 2.1 | 2.5 | |
| Non-audit services: | |||
| Audit-related assurance services – half-year review | 0.4 | 0.4 | |
| Tax compliance services | – | 0.1 | |
| Corporate finance services | – | 0.1 | |
| Other services | 0.2 | 0.2 | |
| Total non-audit services | 0.6 | 0.8 | |
| Total | 2.7 | 3.3 |
Fees payable to Deloitte LLP and their associates for non-audit services to the Company are not required to be disclosed because the consolidated Financial Statements are required to disclose such fees on a consolidated basis.
Tax compliance services include assistance in connection with enquiries from local fiscal authorities. Other services include adhoc assurance services in relation to the Group's JV agreements. The ratio of audit services to non-audit services is 3.5:1.
Details of the Company's policy on the use of the auditor for non-audit services, the reasons why the auditor was used rather than another supplier and how the auditor's independence and objectivity are safeguarded are set out in the Audit Committee Report on pages 69 to 73. No services were provided pursuant to contingent fee arrangements.
| Notes | 2016 \$m |
2015 \$m |
|---|---|---|
| Interest on bank overdrafts and borrowings | 304.7 | 246.3 |
| Interest on obligations under finance leases | 1.8 | 2.0 |
| Total borrowing costs | 306.5 | 248.3 |
| Less amounts included in the cost of qualifying assets 11,12 |
(138.8) | (160.1) |
| 167.7 | 88.2 | |
| Finance and arrangement fees | 5.4 | 16.8 |
| Other interest expense | – | 2.7 |
| Foreign exchange losses | – | 13.0 |
| Unwinding of discount on decommissioning provisions 23 |
25.1 | 28.3 |
| Total finance costs | 198.2 | 149.0 |
Borrowing costs included in the cost of qualifying assets during the year arose on the general borrowing pool and are calculated by applying a capitalisation rate of 6.5% (2015: 6.15%) to cumulative expenditure on such assets.
During 2016 the Group issued insurance claims in respect of the Jubilee turret remediation project. Insurance proceeds of \$145.0 million were recorded in the year ended 31 December 2016 (2015: \$nil). Proceeds related to lost production under the Business Interruption insurance policy of \$90.1 million (2015 \$nil) were recorded as other operating income – lost production insurance proceeds in the income statement. Proceeds related to compensation for incremental operating costs under the Business Interruption and Hull and Machinery insurance policies of \$31.8 million (2015: \$nil) were recorded within the operating costs line of cost of sales (see note 4). Proceeds related to compensation for capital costs under the Hull and Machinery insurance policy of \$23.1 million (2015: \$nil) were recorded within additions to property, plant and equipment (see note 12).
Analysis of credit for the year
| Notes | 2016 \$m |
2015 \$m |
|---|---|---|
| Current tax | ||
| UK corporation tax | 67.3 | (3.5) |
| Foreign tax | (18.5) | 94.9 |
| Total corporate tax | 48.8 | 91.4 |
| UK petroleum revenue tax | (1.1) | (0.3) |
| Total current tax | 47.7 | 91.1 |
| Deferred tax | ||
| UK corporation tax | 9.4 | 6.9 |
| Foreign tax | (369.8) | (354.0) |
| Total deferred corporate tax | (360.4) | (347.1) |
| Deferred UK petroleum revenue tax | 1.7 | (4.4) |
| 24 Total deferred tax |
(358.7) | (351.5) |
| Total tax credit | (311.0) | (260.4) |
The tax rate applied to profit on ordinary activities in preparing the reconciliation below is the UK corporation tax rate applicable to the Group's non-upstream UK profits. The difference between the total current tax credit shown above and the amount calculated by applying the standard rate of UK corporation tax applicable to UK profits of 20% (2015: 20%) to the loss before tax is as follows:
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Group loss on ordinary activities before tax | (908.3) | (1,297.3) |
| Tax on Group loss on ordinary activities at the standard UK corporation tax rate of 20% (2015: 20%) |
(181.7) | (259.5) |
| Effects of: | ||
| Non-deductible exploration expenditure | 25.8 | 114.7 |
| Other non-deductible expenses | 22.7 | 97.7 |
| Derecognition of deferred tax previously recognised | 30.2 | – |
| Impairment of goodwill | 127.9 | 10.7 |
| Utilisation – tax losses not previously recognised | (9.5) | – |
| Net losses not recognised | 61.7 | 15.8 |
| Petroleum revenue tax (PRT) | (6.7) | (4.4) |
| UK corporation tax deductions for current PRT | – | 2.2 |
| Adjustment relating to prior years | (2.1) | (14.9) |
| Adjustments to deferred tax relating to change in tax rates | (0.8) | (1.0) |
| Higher rate of taxation on Norway losses | (286.4) | (132.7) |
| Other tax rates applicable outside the UK and Norway | (86.8) | (164.6) |
| PSC income not subject to corporation tax | (1.6) | (28.5) |
| Uganda capital gains tax | – | 108.2 |
| Tax incentives for investment | (3.7) | (4.1) |
| Group total tax credit for the year | (311.0) | (260.4) |
The Finance Act 2016 further reduced the main rate of UK corporation tax applicable to all companies subject to corporation tax, except for those within the oil and gas ring fence, to 19% from 1 April 2017 and 17% from 1 April 2020. These changes were substantively enacted on 6 September 2016 and hence the effect of the change on the deferred tax balances has been included, depending upon when deferred tax is expected to reverse.
The Group's profit before taxation will continue to arise in jurisdictions where the effective rate of taxation differs from that in the UK. Furthermore, unsuccessful exploration expenditure is often incurred in jurisdictions where the Group has no taxable profits, such that no related tax benefit arises. Accordingly, the Group's tax charge will continue to vary according to the jurisdictions in which pre-tax profits and exploration costs written off arise.
The Group has tax losses of \$2,844.0 million (2015: \$1,802.0 million) that are available for offset against future taxable profits in the companies in which the losses arose. Deferred tax assets have not been recognised in respect of these losses as they may not be used to offset taxable profits elsewhere in the Group due to uncertainty of recovery.
No deferred tax liability is recognised on temporary differences of \$8.2 million (2015: \$8.5 million) relating to unremitted earnings of overseas subsidiaries as the Group is able to control the timing of the reversal of these temporary differences and it is probable that they will not reverse in the foreseeable future.
During 2016 \$108.8 million (2015: \$42.3 million) of tax has been recognised through other comprehensive income of which \$107.8 million (2015: \$43.2 million) is current and \$0.9 million (2015: \$0.9 million) is deferred tax relating to all credits (2015: charges) on cash flow hedges arising in the year.
As at 31 December 2016, current tax assets were \$138.3 million (2015: \$127.6 million) of which \$90.0 million (2015: \$55.0 million) relates to Norway, where 78% of exploration expenditure is refunded as a tax refund in the year following the incurrence of such expenditure.
Basic loss per ordinary share amounts are calculated by dividing net loss for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year.
Diluted loss per ordinary share amounts are calculated by dividing net loss for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued if employee and other share options or the convertible bonds were converted into ordinary shares. Due to losses made in 2016 and 2015 all potential ordinary shares are antidilutive.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Loss | ||
| Net loss attributable to equity shareholders | (599.9) | (1,034.8) |
| Effect of dilutive potential ordinary shares | – | – |
| Diluted net loss attributable to equity shareholders | (599.9) | (1,034.8) |
| 2016 Number |
2015 Number |
|
| Number of shares | ||
| Basic weighted average number of shares | 911,936,308 | 911,252,238 |
| Dilutive potential ordinary shares | 121,082,933 | 25,070,398 |
| Diluted weighted average number of shares | 1,033,019,241 | 936,322,636 |
The divestment of the Norway business is progressing well with two deals completed before year end and one in January 2017. Four licences, including the Wisting oil discovery, have been sold to Statoil, eight licences, including the Oda asset, have been sold to Aker BP ASA and two further licences have been sold to ConocoPhillips. A further two sales were executed in December 2016 with two separate parties. These sales, covering a further 13 licences and which include the 2016 Cara oil and gas discovery, are on track to complete in the first quarter of 2017. In aggregate, the Norway asset sales are expected to yield proceeds of up to \$0.2 billion. Once completed, the Group will no longer hold any licences on the Norwegian Continental Shelf. These plus other disposals result in an income statement loss of \$3.4 million and a cash inflow of \$62.8 million.
On 30 April 2015, Tullow completed the sale of its operated and non-operated interests in the L12/15 area and Blocks Q4 and Q5 to AU Energy. The consideration was €64 million (\$53.5 million), producing a profit after tax of \$7.4 million and a loss before tax of \$46.3 million. On 5 June 2015, Tullow completed the farm-down to GDF Suez E&P Nederland of 30% equity and the operatorship of Exploration Licences E10, E11 (including Tullow's Vincent discovery), E14, E15c and E18b. These plus other disposals result in an income statement loss of \$56.5 million and a cash inflow of \$55.8 million.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| At 1 January | 164.0 | 217.7 |
| Impairment | (164.0) | (53.7) |
| At 31 December | – | 164.0 |
| Related deferred tax at 31 December | – | (89.0) |
| Goodwill net of associated deferred tax | – | 75.0 |
The Group's goodwill of \$350.5 million arose from the acquisition of Spring Energy in 2013 and is allocated to the group of cash-generating units (CGUs) that represent the assets acquired. Goodwill is tested for impairment annually as at 31 December and when circumstances indicate that the carrying value may be impaired. The goodwill balance results solely from the requirement to recognise a deferred tax liability on an acquisition, calculated as the difference between the tax effect of the fair value of the acquired assets and liabilities and their tax bases. As a result, for the purposes of testing goodwill for impairment, the related deferred tax liabilities recognised on acquisition are included in the group of CGUs. The above table details the net impact of goodwill and the related deferred tax on the CGU.
In assessing goodwill for impairment the Group has compared the carrying value of goodwill and the carrying value of the related group of CGUs with the recoverable amounts of those CGUs. The carrying value of goodwill and the related group of CGUs together was \$171.4 million (2015: \$264.5 million) and the recoverable amount, assessed as fair value less cost to sell, of the CGUs was \$7.4 million (2015: \$210.8 million), resulting in an impairment of \$164.0 million (2015: \$53.7 million). The cumulative impairment is \$350.5 million (2015: \$186.5 million).
During 2016, sales agreements were signed for a number of the Group's Norwegian licences with the remainder being relinquished. As a result, the related exploration and evaluation assets were written down to their fair values, which were equal to the consideration per the sales agreements, at 31 December 2016. These fair values did not support the remaining goodwill recorded that arose from the acquisition of Spring Energy.
| Notes | 2016 \$m |
2015 \$m |
|---|---|---|
| At 1 January | 3,400.0 | 3,660.8 |
| Additions 1 |
291.4 | 626.3 |
| Disposals 9 |
– | (5.2) |
| Amounts written-off | (723.0) | (748.9) |
| Write-off associated with Norway-contingent consideration provision | (36.5) | – |
| Net transfer to assets held for sale 18 |
(912.3) | – |
| Transfer to property, plant and equipment 12 |
– | (63.6) |
| Currency translation adjustments | 6.2 | (69.4) |
| At 31 December | 2,025.8 | 3,400.0 |
Included within 2016 additions is \$50.2 million (note 5) of capitalised interest (2015: \$49.7 million). The Group only capitalises interest in respect of intangible exploration and evaluation assets where it is considered that development is ongoing.
The below table provides a summary of the exploration costs written off on a pre and post-tax basis by country.
| Country | CGU | Rationale for 2016 write-off |
2016 Current year expenditure written off \$m |
2016 Prior year expenditure written off \$m |
2016 Post-tax write-off \$m |
2016 Pre-tax write-off \$m |
2016 Remaining recoverable amount \$m |
|---|---|---|---|---|---|---|---|
| Ethiopia | Country | b | 1.9 | – | 1.9 | 1.9 | – |
| Gabon | Arouwe licence | b | 1.0 | – | 1.0 | 1.6 | – |
| Ghana | New Ventures | f | 2.3 | – | 2.3 | 3.5 | – |
| Guinea | Country | b | 5.6 | – | 5.6 | 5.6 | – |
| Greenland | Country | b | 1.0 | – | 1.0 | 1.0 | – |
| Kenya | Blocks 10A & L8 | b | (2.6) | – | (2.6) | (2.6) | – |
| Madagascar | Country | b, d | 4.1 | 21.5 | 25.6 | 25.6 | – |
| Mauritania | Blocks C6, C7 & C18 | b, c | 0.2 | 9.3 | 9.5 | 9.5 | – |
| Mozambique | Country | b | (1.0) | – | (1.0) | (1.0) | – |
| Netherlands | Licence E18 & F16 | b | 0.8 | – | 0.8 | 1.5 | 49.0 |
| Norway | Country | a, b, c, d, e | 17.8 | 61.0 | 78.8 | 286.9 | 7.1 |
| Pakistan | Kup well | a | 1.9 | 8.8 | 10.7 | 10.7 | – |
| Suriname | Block 31 & Coronie | b, c | 1.3 | 18.0 | 19.3 | 19.3 | – |
| Uganda | Country | e | – | 247.8 | 247.8 | 330.4 | 453.1 |
| Other | Various | b | 4.9 | – | 4.9 | 4.9 | – |
| New Ventures | Various | f | 18.4 | – | 18.4 | 24.2 | – |
| Total write-off | 57.6 | 366.4 | 424.0 | 723.0 |
a. Current year unsuccessful drilling results.
b. Current year expenditure and actualisation of accruals associated with CGUs previously written off.
c. Licence relinquishments.
d. Country exit.
| Notes | 2016 Oil and gas assets \$m |
2016 Other fixed assets \$m |
2016 Total \$m |
2015 Oil and gas assets \$m |
2015 Other fixed assets \$m |
2015 Total \$m |
|
|---|---|---|---|---|---|---|---|
| Cost | |||||||
| At 1 January | 10,439.9 | 289.5 | 10,729.4 | 9,240.3 | 283.7 | 9,524.0 | |
| Additions | 1,5 | 816.9 | 1.6 | 818.5 | 1,235.1 | 23.1 | 1,258.2 |
| Disposals | (276.1) | (2.7) | (278.8) | (6.2) | (3.6) | (9.8) | |
| Transfer from intangible assets | 11 | – | – | – | 63.6 | – | 63.6 |
| Currency translation adjustments | (208.2) | (36.5) | (244.7) | (92.9) | (13.7) | (106.6) | |
| At 31 December | 10,772.5 | 251.9 | 11,024.4 | 10,439.9 | 289.5 | 10,729.4 | |
| Depreciation, depletion and amortisation | |||||||
| At 1 January | (5,360.0) | (165.0) | (5,525.0) | (4,489.1) | (147.9) | (4,637.0) | |
| Charge for the year | 4 | (448.5) | (18.4) | (466.9) | (551.2) | (28.9) | (580.1) |
| Impairment loss | (184.3) | (0.4) | (184.7) | (467.2) | – | (467.2) | |
| Reversal of impairment loss | 10.9 | – | 10.9 | 61.2 | – | 61.2 | |
| Disposal | 276.1 | 2.6 | 278.7 | 6.4 | 3.6 | 10.0 | |
| Currency translation adjustments | 205.0 | 20.5 | 225.5 | 79.9 | 8.2 | 88.1 | |
| At 31 December | (5,500.8) | (160.7) | (5,661.5) | (5,360.0) | (165.0) | (5,525.0) | |
| Net book value at 31 December | 5,271.7 | 91.2 | 5,362.9 | 5,079.9 | 124.5 | 5,204.4 |
The 2016 additions include capitalised interest of \$88.6 million (note 5) in respect of the TEN development project (2015: \$110.4 million). The carrying amount of the Group's oil and gas assets includes an amount of \$17.8 million (2015: \$27.4 million) in respect of assets held under finance leases. The currency translation adjustments arose due to the movement against the Group's presentation currency, USD, of the Group's UK and Dutch assets which have functional currencies of GBP and EUR respectively. The 2016 income statement impairment charge includes \$6.2 million of insurance proceeds.
| Trigger for 2016 impairment |
2016 Impairment \$m |
Pre-tax discount rate |
assumption Short-term price assumption | Mid-term price assumption |
Long-term price assumption |
|
|---|---|---|---|---|---|---|
| UK "CGU"d | b | 48.0 | n/a | n/a | n/a | n/a |
| Limande CGUe (Gabon) | a | 3.1 | 13% | 2 yr forward curve | \$70/bbl | \$90/bbl |
| Echira CGUe (Gabon) | a | 2.2 | 15% | 2 yr forward curve | \$70/bbl | \$90/bbl |
| Etame CGUe (Gabon) | a | 1.5 | 13% | 2 yr forward curve | \$70/bbl | \$90/bbl |
| Oba CGU e (Gabon) | a | (10.9) | 15% | 2 yr forward curve | \$70/bbl | \$90/bbl |
| M'boundi (Congo) | a | 6.4 | 12% | 2 yr forward curve | \$70/bbl | \$90/bbl |
| Espoir (Côte d'Ivoire) | a | 12.3 | 10% | 2 yr forward curve | \$70/bbl | \$90/bbl |
| TEN (Ghana) | a | 97.0 | 10% | 2 yr forward curve | \$70/bbl | \$90/bbl |
| Jubilee (Ghana) | c | 3.7 | n/a | n/a | n/a | n/a |
| Chinguetti (Mauritania) | b | 10.1 | n/a | n/a | n/a | n/a |
| Impairment | 173.4 |
a. Delay in estimated step up to oil and gas mid-term and long-term price assumptions (refer to accounting policy on significant estimates).
b. Increase in decommissioning estimate.
c. Impairment of a component of the asset which is covered by insurance proceeds.
d. The fields in the UK are grouped into one CGU as all fields within those countries share critical gas infrastructure.
e. The Limande, Echira, Etame and Oba CGUs in Gabon comprise a number of fields which share export infrastructure.
All impairment assessments are prepared on a value-in-use basis using discounted future cash flows based on 2P reserves profiles. The principal assumptions are oil price and the pre-tax discount rate, which are nominal. Oil prices stated above are benchmark prices to which an individual field price differential is applied.
Based on the approximate volatility of the 2016 oil price, a reduction in the forward curve of \$20/bbl is considered to be a reasonably possible change for the purposes of sensitivity analysis. This would increase the impairment charge by \$487.8 million. A \$15/bbl reduction in both the mid-term and the long-term price assumption assumed, which is based on the range seen in external oil price market forecasts, would increase the impairment charge by \$744.4 million.
A 1% increase in the pre-tax discount rate would increase the impairment by \$129.3 million. The Group believes a 1% increase in the pre-tax discount rate to be a reasonable possibility based on historical analysis of the Group's and a peer group of companies' impairment discount rates.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Unlisted investments | 1.0 | 1.0 |
The fair value of these investments is not materially different from their carrying value.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Non-current | ||
| Amounts due from joint venture partners | 127.3 | 161.8 |
| Uganda VAT recoverable | 35.9 | 50.3 |
| Other non-current assets | 12.5 | 11.3 |
| 175.7 | 223.4 | |
| Current | ||
| Amounts due from joint venture partners | 560.4 | 584.4 |
| Underlifts | 34.9 | 2.4 |
| Prepayments | 26.3 | 77.9 |
| VAT and WHT recoverable | 5.7 | 9.2 |
| Other current assets | 211.6 | 89.3 |
| 838.9 | 763.2 |
The decrease in amounts due from joint venture partners relates to the decrease in operated current liabilities, which are recorded gross with the corresponding debit recognised as an amount due from joint venture partners, in Kenya and Ghana. Other current assets have increased due to accrued insurance proceeds.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Warehouse stocks and materials | 57.6 | 66.0 |
| Oil stocks | 97.7 | 41.2 |
| 155.3 | 107.2 |
Inventories include a provision of \$31.4 million (2015: \$65.2 million) for warehouse stock and materials where it is considered that the net realisable value is lower than the original cost. The decrease in the provision during 2016 is associated with disposal of inventory provided for in previous periods, resulting in an income statement charge of \$nil (2015: \$22.2 million, included in exploration costs written off).
Trade receivables comprise amounts due for the sale of oil and gas. No current receivables are overdue, therefore none have been impaired and no allowance for doubtful debt has been recognised (2015: \$nil).
| Notes | 2016 \$m |
2015 \$m |
|
|---|---|---|---|
| Cash at bank | 21 | 281.9 | 355.7 |
Cash and cash equivalents includes an amount of \$140.9 million (2015: \$169.5 million) which the Group holds as operator in joint venture bank accounts. In addition to the cash held in joint venture bank accounts the Group has \$20.3 million (2015: \$16.1 million) held in restricted bank accounts.
On 9 January 2017, Tullow announced that it had agreed a substantial farm-down of its assets in Uganda to Total. Under the Sale and Purchase Agreement, Tullow has agreed to transfer 21.57% of its 33.33% Uganda interests to Total for a total consideration of \$900 million. Upon completion, the farm-down will leave Tullow with an 11.76% interest in the upstream and pipeline projects. This is expected to reduce to a 10% interest in the upstream project when the Government of Uganda formally exercises its back-in right. Although it has not yet been determined what interests the Governments of Uganda and Tanzania will take in the pipeline project, Tullow expects its interests in the upstream and pipeline projects to be aligned.
The consideration is split into \$200 million in cash, consisting of \$100 million payable on completion of the transaction, \$50 million payable at FID and \$50 million payable at first oil. The remaining \$700 million is in deferred consideration and represents reimbursement by Total in cash of a proportion of Tullow's past exploration and development costs. The deferred consideration is payable to Tullow as the upstream and pipeline projects progress and these payments will be used by Tullow to fund its share of the development costs. Tullow expects the deferred consideration to cover its share of upstream and pipeline development capex to first oil and beyond. Completion of the transaction is subject to certain conditions, including the approval of the Government of Uganda, after which Tullow will cease to be an operator in Uganda. The disposal is expected to complete in 2017.
The estimated fair value of the consideration is \$829.7 million which, when compared to the carrying value of the Group's interest in Uganda, resulted in an exploration write-off of \$330.4 million. The fair value of the deferred consideration was calculated using expected timing of receipts based on management's best estimate of the expected capital profile of the project discounted at Total's cost of borrowing. This represents a level 3 financial asset.
The divestment of the Norway business is progressing well with two deals completed before year end and one in January 2017. Four licences, including the Wisting oil discovery, have been sold to Statoil, eight licences, including the Oda asset, have been sold to Aker BP ASA and two further licences have been sold to ConocoPhillips. A further two sales were executed in December 2016 with two separate parties. These sales, covering a further 13 licences and which include the 2016 Cara oil and gas discovery, are on track to complete in the first quarter of 2017. In aggregate, the Norway asset sales are expected to yield proceeds of up to \$0.2 billion. Once completed, the Group will no longer hold any licences on the Norwegian Continental Shelf. Combined with the transactions that completed in 2016, transfer to assets held for sale of the Norwegian assets was \$82.6 million of which \$7.4 million remained as held for sale at 31 December 2016.
The major classes of assets and liabilities comprising the assets classified as held for sale as at 31 December 2016 are as follows:
| Uganda 2016 \$m |
Norway 2016 \$m |
Total 2016 \$m |
|
|---|---|---|---|
| Intangible exploration and evaluation assets | 829.7 | 7.4 | 837.1 |
| Total assets classified as held for sale | 829.7 | 7.4 | 837.1 |
| Net assets of disposal groups | 829.7 | 7.4 | 837.1 |
| Notes | 2016 \$m |
2015 \$m |
|---|---|---|
| Trade payables | 46.9 | 24.0 |
| Other payables | 124.6 | 61.2 |
| Overlifts | 6.9 | 3.7 |
| Accruals | 721.2 | 993.3 |
| VAT and other similar taxes | 14.6 | 26.9 |
| Current portion of finance lease 22 |
1.9 | 1.5 |
| 916.1 | 1,110.6 |
Payables related to operated joint ventures (primarily related to Ghana and Kenya) are recorded gross with the debit representing the partners' share recognised in amounts due from joint venture partners (note 14). The increase in trade payables and in other payables predominantly represents timing differences.
| Notes | 2016 \$m |
2015 \$m |
|---|---|---|
| Other non-current liabilities | 87.7 | 72.8 |
| Non-current portion of finance lease 22 |
24.6 | 26.5 |
| 112.3 | 99.3 |
Trade and other payables are non-interest bearing except for finance leases (note 22).
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Current | ||
| Short-term borrowings – Revolving Norwegian Exploration Finance facility | 83.4 | 59.6 |
| Bank loans – Reserve-Based lending credit facility | 508.1 | 14.2 |
| 591.5 | 73.8 | |
| Non-current | ||
| Bank borrowings – after one year but within two years | ||
| Reserve-Based lending credit facility | 906.2 | 800.0 |
| Revolving credit facility | 364.6 | – |
| Bank borrowings – after two years but within five years | ||
| Reserve-Based lending credit facility | 1,561.7 | 2,165.6 |
| 6.0% Senior Notes due 2020 | 647.6 | 646.4 |
| 6.25% Senior Notes due 2022 | 651.0 | 650.4 |
| 6.625% Convertible bonds due 2021 | 257.3 | – |
| 4,388.4 | 4,262.4 | |
| Carrying value of total borrowings | 4,979.9 | 4,336.2 |
The Group has provided security in respect of certain of these borrowings in the form of share pledges, as well as fixed and floating charges over the assets of the Group.
During the year, the commitments on the Reserve-Based lending credit facility (RBL) were reduced from \$3,700 million to \$3,255 million in line with the amortisation schedule. The Company also secured \$345 million of new commitments on this facility from our existing lenders which will take effect from 1 April 2017 by exercising an accordion facility.
The facility incurs interest on outstanding debt at Sterling or US dollar LIBOR plus an applicable margin. The outstanding debt is repayable in line with the amortisation of bank commitments over the period to the final maturity date of 6 November 2019, or such time as is determined by reference to the remaining reserves of the assets, whichever is earlier.
In April 2016, the Company agreed a 12 month extension to the maturity of the Revolving credit facility (RCF) to April 2018. The commitments remain at \$1 billion until April 2017, when commitments reduce to \$800 million. The facility incurs interest on outstanding debt at US dollar LIBOR plus an applicable margin.
In July 2016, the Company completed an offering of \$300 million of convertible bonds due in 2021, with a coupon of 6.625% per annum payable semi-annually. The net proceeds were used for general corporate purposes and to fund capital investment. The bonds are convertible into fully paid ordinary shares of the Company at a fixed exchange price of \$3.52 during the conversion period, subject to customary adjustment provisions.
At initial recognition, the liability and equity component of the convertible bonds have been separately recognised, and the carrying value of the liability component as at 31 December 2016 is \$257.3 million. The equity component at initial recognition is \$48.4 million, and is not subsequently remeasured. Transaction costs are apportioned between the liability and the equity components of the instrument based on the amounts initially recognised.
In December 2016, the commitments on the Revolving Norwegian Exploration Finance facility (EFF) were reduced from NOK 2,250 million to NOK 1,000 million. The facility is used to finance certain exploration activities on the Norwegian Continental Shelf which are eligible for a tax refund. The facility is available for drawings until 31 December 2017, and its final maturity date is either the date when the 2017 tax reimbursement claims are received or 31 December 2018, whichever is the earlier. The facility incurs interest on outstanding debt at NIBOR plus an applicable margin.
At 31 December 2016, the undrawn borrowings under the three facilities amounted to \$875 million; \$255 million under the RBL, \$620 million under the RCF and \$nil under the EFF. At 31 December 2015, the available headroom under the three facilities amounted to \$1,686 million; \$686 million under the RBL, \$1,000 million under the RCF and \$nil under the EFF.
The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders and benefits to stakeholders and to safeguard the Group's ability to continue as a going concern. Tullow is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, the Group may put in place new debt facilities, issue new shares for cash, repay debt, engage in active portfolio management, adjust the dividend payment to shareholders, or undertake other such restructuring activities as appropriate. No significant changes were made to the capital management objectives, policies or processes during the year ended 31 December 2016. The Group monitors capital on the basis of the net debt to adjusted EBITDAX ratio; a summary of this calculation can be found in the finance review on page 36.
The Group is exposed to a variety of risks including commodity price risk, interest rate risk, credit risk, foreign currency risk and liquidity risk. The Group holds a portfolio of commodity derivative contracts, with various counterparties, covering its underlying oil and gas businesses. The Group holds a mix of fixed and floating rate debt as well as a portfolio of interest rate derivatives. The use of derivative financial instruments (derivatives) is governed by the Group's policies approved by the Board of Directors. Compliance with policies and exposure limits are monitored and reviewed internally on a regular basis. The Group does not enter into or trade financial instruments, including derivatives, for speculative purposes.
With the exception of the Senior Notes and the convertible bonds, the Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value. The fair value of the Senior Notes, as determined using market values at 31 December 2016, was \$1,223.1 million (2015: \$884.0 million) compared to carrying values of \$1,555.9 million (2015: \$1,296.8 million).
The fair value of the convertible bonds, as determined using market values, as at 31 December 2016, was \$395.5 million (2015: \$nil) compared to the carrying value of \$257.3 million.
The Group has no material financial assets that are past due. No financial assets are impaired at the balance sheet date. All financial assets and liabilities with the exception of derivatives are measured at amortised cost.
All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as a cash flow hedge. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved.
The Group's derivative carrying and fair values were as follows:
| Assets/liabilities | 2016 Less than 1 year \$m |
2016 1-3 years \$m |
2016 Total \$m |
2015 Less than 1 year \$m |
2015 1-3 years \$m |
2015 Total \$m |
|---|---|---|---|---|---|---|
| Cash flow hedges | ||||||
| Oil derivatives | 139.7 | 40.2 | 179.9 | 458.9 | 265.2 | 724.1 |
| Gas derivatives | (1.4) | – | (1.4) | 1.1 | – | 1.1 |
| Interest rate derivatives | (1.0) | 0.6 | (0.4) | (2.1) | 1.1 | (1.0) |
| 137.3 | 40.8 | 178.1 | 457.9 | 266.3 | 724.2 | |
| Deferred premium | ||||||
| Oil derivatives | (51.5) | (35.9) | (87.4) | (53.5) | (47.6) | (101.1) |
| (51.5) | (35.9) | (87.4) | (53.5) | (47.6) | (101.1) | |
| Total assets | 91.7 | 15.8 | 107.5 | 406.5 | 218.7 | 625.2 |
| Total liabilities | (5.9) | (10.9) | (16.8) | (2.1) | – | (2.1) |
Derivatives' maturity and the timing of their recycling into income or expense coincide.
The following provides an analysis of the Group's financial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable:
Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities;
Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and
Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data.
All the Group's derivatives are Level 2 (2015: Level 2). There were no transfers between fair value levels during the year.
For financial instruments which are recognised on a recurring basis, the Group determines whether transfers have occurred between levels by reassessing categorisation (based on the lowest-level input which is significant to the fair value measurement as a whole) at the end of each reporting period.
Deferred premiums on derivatives are settled at the same time as the maturity of the derivative contracts, with the cash flows settled on a net basis. Netting agreements are also in place to enable the Group and its counterparties to set-off liabilities against available assets in the event that either party is unable to fulfil its contractual obligations. The following table provides the offsetting relationship within assets and liabilities in the balance sheet.
| Gross | |||
|---|---|---|---|
| amounts | Net amounts | ||
| Gross | offset in | presented in | |
| amounts | Group | Group | |
| recognised | balance sheet | balance sheet | |
| 31 December 2016 | \$m | \$m | \$m |
| Derivative assets | 165.7 | (58.2) | 107.5 |
| Derivative liabilities | 12.4 | (29.2) | (16.8) |
| Deferred premiums | (87.4) | 87.4 | – |
| 31 December 2015 | Gross amounts recognised \$m |
Gross amounts offset in Group balance sheet \$m |
Net amounts presented in Group balance sheet \$m |
|---|---|---|---|
| Derivative assets | 726.3 | (101.1) | 625.2 |
| Derivative liabilities | (2.1) | – | (2.1) |
| Deferred premiums | (101.1) | 101.1 | – |
The Group uses a number of derivatives to mitigate the commodity price risk associated with its underlying oil and gas revenues. Such commodity derivatives will tend to be priced using benchmarks, such as Dated Brent, D-1 Heren and M-1 Heren, which correlate as far as possible to the underlying oil and gas revenues respectively. The Group hedges its estimated oil and gas revenues on a portfolio basis, aggregating its oil revenues from substantially all of its African oil interests and its gas revenues from substantially all of its UK gas interests.
As at 31 December 2016 and 31 December 2015, all of the Group's oil and gas derivatives have been designated as cash flow hedges. The Group's oil and gas hedges have been assessed to be 'highly effective' within the range prescribed under IAS 39 using regression analysis. There is, however, the potential for a degree of ineffectiveness inherent in the Group's oil hedges arising from, among other factors, the discount on the Group's underlying African crude relative to Brent and the timing of oil liftings relative to the hedges. There is also the potential for a degree of ineffectiveness inherent in the Group's gas hedges which arises from, among other factors, daily field production performance.
The following table demonstrates the timing, volumes and the average floor price protected for the Group's commodity hedges:
| Hedging position as at 31 December 2016 | 2017 | 2018 | 2019 |
|---|---|---|---|
| Oil volume (bopd) | 42,500 | 22,000 | 7,979 |
| Average floor price protected (\$/bbl) | 60.23 | 51.88 | 45.53 |
| Gas volume (mmscfd) | 3.67 | – | – |
| Average floor price protected (p/therm) | 40.47 | – | – |
| Hedging position as at 31 December 2015 | 2016 | 2017 | 2018 |
| Oil volume (bopd) | 36,511 | 23,000 | 9,500 |
| Average floor price protected (\$/bbl) | 75.15 | 72.94 | 62.09 |
| Gas volume (mmscfd) | 0.61 | – | – |
| Average floor price protected (p/therm) | 63.00 | – | – |
The following table demonstrates the sensitivity of the Group's derivative financial instruments to reasonable possible movements in Dated Brent oil price and UK D-1 Heren and M-1 Heren natural gas prices:
| Effect on equity | |||
|---|---|---|---|
| Market movement |
2016 \$m |
2015 \$m |
|
| Brent oil price | 25% | (145.0) | (256.5) |
| Brent oil price | (25%) | 183.6 | 286.0 |
| UK D-1 Heren and M-1 Heren natural gas price | 25% | (2.3) | (0.3) |
| UK D-1 Heren and M-1 Heren natural gas price | (25%) | 2.3 | 0.3 |
The following assumptions have been used in calculating the sensitivity in movement of oil and gas prices: the pricing adjustments relate only to the point forward mark-to-market (MTM) valuations, the price sensitivities assume there is no ineffectiveness related to the oil and gas hedges and the sensitivities have been run only on the intrinsic element of the hedge as management considers this to be the material component of oil and gas hedge valuations.
Fair value movements relating to the non-intrinsic element of the commodity derivatives have been immediately recognised in the income statement during the year, and were as follows:
| Profit/(loss) on hedging instruments | 2016 \$m |
2015 \$m |
|---|---|---|
| Cash flow hedges | ||
| Gas derivatives | ||
| Time value | – | (0.2) |
| – | (0.2) | |
| Oil derivatives | ||
| Time value | 18.2 | (58.6) |
| 18.2 | (58.6) | |
| Total net profit/(loss) for the year in the income statement | 18.2 | (58.8) |
The hedge reserve represents the portion of deferred gains and losses on hedging instruments deemed to be effective cash flow hedges. The movement in the reserve for the period is recognised in other comprehensive income.
The following table summarises the hedge reserve by type of derivative, net of tax effects:
| Hedge reserve by derivative type | 2016 \$m |
2015 \$m |
|---|---|---|
| Cash flow hedges | ||
| Gas derivatives | (1.1) | 0.4 |
| Oil derivatives | 129.7 | 570.6 |
| Interest rate derivatives | (0.4) | (1.1) |
| 128.2 | 569.9 |
The deferred gains and losses in the hedge reserve are subsequently transferred to the income statement during the period in which the hedged transaction affects the income statement. The tables below show the impact on the hedge reserve and on sales revenue during the year:
| Deferred amounts in the hedge reserve | 2016 \$m |
2015 \$m |
|---|---|---|
| At 1 January | 569.9 | 401.6 |
| Reclassification adjustments for items included in the income statement on realisation: | ||
| Gas derivatives – transferred to sales revenue | (0.9) | (3.4) |
| Oil derivatives – transferred to sales revenue | (416.7) | (412.9) |
| Interest rate derivatives – transferred to finance costs | 2.4 | 3.5 |
| Subtotal | (415.2) | (412.8) |
| Revaluation (losses)/gains arising in the year | (135.3) | 623.4 |
| Movement in current and deferred tax | 108.8 | (42.3) |
| (441.7) | 168.3 | |
| At 31 December | 128.2 | 569.9 |
| Reconciliation to sales revenue | 2016 \$m |
2015 \$m |
|---|---|---|
| Gas derivatives – transferred to sales revenue | (0.9) | (3.4) |
| Oil derivatives – transferred to sales revenue | (416.7) | (412.9) |
| Deferred premium paid | 54.6 | 51.1 |
| Net gains from commodity derivatives in sales revenue (note 2) | (363.0) | (365.2) |
Subject to parameters set by management the Group seeks to minimise interest costs by using a mixture of fixed and floating debt. Floating rate debt comprises bank borrowings at interest rates fixed in advance from overnight to three months at rates determined by US dollar LIBOR, Sterling LIBOR and Norwegian NIBOR. Fixed rate debt comprises Senior Notes, convertible bonds, bank borrowings at interest rates fixed in advance for periods greater than three months or bank borrowings where the interest rate has been fixed through interest rate hedging. The Group hedges its floating interest rate exposure on an ongoing basis through the use of interest rate swaps. The mark-to-market position of the Group's interest rate portfolio as at 31 December 2016 is a liability of \$0.4 million (2015: \$1.0 million liability). Interest rate hedges are included in fixed rate debt in the table below.
The interest rate profile of the Group's financial assets and liabilities, excluding trade and other receivables and trade and other payables, at 31 December 2016 and 2015 was as follows:
| 2016 Cash at bank \$m |
2016 Fixed rate debt \$m |
2016 Floating rate debt \$m |
2016 Total \$m |
2015 Cash at bank \$m |
2015 Fixed rate debt \$m |
2015 Floating rate debt \$m |
2015 Total \$m |
|
|---|---|---|---|---|---|---|---|---|
| US\$ | 200.8 | (1,900.0) | (3,080.0) | (4,779.2) | 258.2 | (1,600.0) | (2,557.3) | (3,899.1) |
| Euro | 8.6 | – | – | 8.6 | 28.4 | – | – | 28.4 |
| Sterling | 33.1 | – | – | 33.1 | 19.1 | – | (156.9) | (137.8) |
| Other | 39.4 | – | (83.8) | (44.4) | 50.0 | – | (60.8) | (10.8) |
| 281.9 | (1,900.0) | (3,163.8) | (4,781.9) | 355.7 | (1,600.0) | (2,775.0) | (4,019.3) |
Cash at bank consisted mainly of deposits which earn interest at rates set in advance for periods ranging from overnight to one month by reference to market rates.
The following table demonstrates the sensitivity of the Group's financial instruments to reasonably possible movements in interest rates:
| Effect on finance costs | Effect on equity | ||||
|---|---|---|---|---|---|
| Market movement | 2016 \$m |
2015 \$m |
2016 \$m |
2015 \$m |
|
| Interest rate | 100 basis points | (31.6) | (27.7) | (26.5) | (20.3) |
| Interest rate | (25) basis points | 7.9 | 6.9 | 6.1 | 3.5 |
The Group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. The primary credit exposures for the Group are its receivables generated by the marketing of crude oil and amounts due from JV partners. These exposures are managed at the corporate level. The Group's crude sales are predominantly made to international oil market participants including the oil majors, trading houses and refineries. JV partners are predominantly international major oil and gas market participants. Counterparty evaluations are conducted utilising international credit rating agency and financial assessments. Where considered appropriate, security in the form of trade finance instruments from financial institutions with an appropriate credit ratings, such as letters of credit, guarantees and credit insurance, are obtained to mitigate the risks.
The Group generally enters into derivative agreements with banks who are lenders under the Reserve-Based lending credit facility. Security is provided under the facility agreement which mitigates non-performance risk. The Group does not have any significant credit risk exposure to any single counterparty or any group of counterparties. The maximum financial exposure due to credit risk on the Group's financial assets, representing the sum of cash and cash equivalents, investments, derivative assets, trade receivables, current tax assets and other current assets, as at 31 December 2016 was \$1,661.7 million (2015: \$2,176.9 million).
The Group conducts and manages its business predominately in US dollars, the operating currency of the industry in which it operates. The Group also purchases the operating currencies of the countries in which it operates routinely on the spot market. From time to time the Group undertakes certain transactions denominated in other currencies. These exposures are often managed by executing foreign currency financial derivatives. There were no material foreign currency financial derivatives in place at the 2016 year end (2015: \$nil). Cash balances are held in other currencies to meet immediate operating and administrative expenses or to comply with local currency regulations.
As at 31 December 2016, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were \$16.9 million in non-US-dollar denominated cash and cash equivalents (2015: \$49.7 million) and £nil cash drawings under the Group's borrowing facilities (2015: £106.0 million). The carrying amounts of the Group's foreign currency-denominated monetary assets and monetary liabilities at the reporting date are net assets of \$16.9 million (2015: net liabilities of \$107.2 million).
The following table demonstrates the sensitivity of the Group's financial instruments to reasonably possible movements in US dollar exchange rates:
Foreign currency risk continued
| Effect on profit before tax | Effect on equity | ||||
|---|---|---|---|---|---|
| Market movement | 2016 \$m |
2015 \$m |
2016 \$m |
2015 \$m |
|
| US\$/foreign currency exchange rates | 20% | (2.7) | (7.7) | (2.7) | 23.7 |
| US\$/foreign currency exchange rates | (20%) | 4.0 | 11.5 | 4.0 | (19.9) |
The Group manages its liquidity risk using both short and long-term cash flow projections, supplemented by debt financing plans and active portfolio management. Ultimate responsibility for liquidity risk management rests with the Board of Directors, which has established an appropriate liquidity risk management framework covering the Group's short, medium and long-term funding and liquidity management requirements.
The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices, different production rates from the Group's producing assets and delays to development projects. In addition to the Group's operating cash flows, portfolio management opportunities are reviewed to potentially enhance the financial capability and flexibility of the Group. The Group had \$1.0 billion (2015: \$1.9 billion) of total facility headroom and free cash as at 31 December 2016. The Group's forecast, taking into account the risks described above, show that the Group will be able to operate within its current debt facilities and have sufficient financial headroom for the 12 months from the date of approval of the 2016 Annual Report and Accounts.
The following table details the Group's remaining contractual maturity for its non-derivative financial liabilities with agreed repayment periods. The tables have been drawn up based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Group can be required to pay.
| Weighted average effective interest rate |
Less than 1 month \$m |
1-3 months \$m |
3 months to 1 year \$m |
1-5 years \$m |
5+ years \$m |
Total \$m |
|
|---|---|---|---|---|---|---|---|
| 31 December 2016 | |||||||
| Non-interest bearing | n/a | 21.0 | 167.3 | 4.7 | – | 87.7 | 280.7 |
| Finance lease liabilities | 6.5% | 0.3 | 0.8 | 2.4 | 14.5 | 17.6 | 35.6 |
| Fixed interest rate instruments | 7.5% | ||||||
| Principal repayments | – | – | – | 950.0 | 650.0 | 1,600.0 | |
| Interest charge | 9.9 | – | 89.6 | 359.0 | 20.3 | 478.8 | |
| Variable interest rate instruments | 5.9% | ||||||
| Principal repayments | – | 55.0 | 536.9 | 2,871.9 | – | 3,463.8 | |
| Interest charge | 14.4 | 28.6 | 120.2 | 151.9 | – | 315.1 | |
| 45.6 | 251.7 | 753.8 | 4,347.3 | 775.6 | 6,174.0 |
| Weighted average effective interest rate |
Less than 1 month \$m |
1-3 months \$m |
3 months to 1 year \$m |
1-5 years \$m |
5+ years \$m |
Total \$m |
|
|---|---|---|---|---|---|---|---|
| 31 December 2015 | |||||||
| Non-interest bearing | n/a | 46.9 | 47.4 | 21.5 | – | 72.8 | 188.6 |
| Finance lease liabilities | 6.5% | 0.3 | 0.8 | 2.2 | 14.5 | 21.3 | 39.1 |
| Fixed interest rate instruments | 6.5% | ||||||
| Principal repayments | – | – | – | 650.0 | 650.0 | 1,300.0 | |
| Interest charge | – | – | 79.6 | 318.5 | 60.9 | 459.0 | |
| Variable interest rate instruments | 6.0% | ||||||
| Principal repayments | – | – | 75.0 | 3,000.0 | – | 3,075.0 | |
| Interest charge | 10.0 | 20.1 | 90.1 | 206.0 | – | 326.2 | |
| 57.2 | 68.3 | 268.4 | 4,189.0 | 805.0 | 5,387.9 |
The Group has interest rate swaps that fix \$300.0 million (2015: \$300.0 million) of variable interest rate risk. The impact of these derivatives on the classification of fixed and variable rate instruments has been excluded from the above tables.
| Notes | 2016 \$m |
2015 \$m |
|---|---|---|
| Amounts payable under finance leases: | ||
| – Within one year | 3.5 | 3.3 |
| – Within two to five years | 14.5 | 14.5 |
| – After five years | 17.6 | 21.3 |
| 35.6 | 39.1 | |
| Less future finance charges | (9.1) | (11.1) |
| Present value of lease obligations | 26.5 | 28.0 |
| 19 Amount due for settlement within 12 months |
1.9 | 1.5 |
| 19 Amount due for settlement after 12 months |
24.6 | 26.5 |
The Group's only finance lease is the Espoir FPSO (2015: Espoir FPSO). The fair value of the Group's lease obligations approximates the carrying amount. The average remaining lease term as at 31 December 2016 was 10 years (2015: 11 years). For the year ended 31 December 2016, the effective borrowing rate was 6.5% (2015: 6.15%).
| Other | Other | ||||||
|---|---|---|---|---|---|---|---|
| Decommissioning | provisions | Total | Decommissioning | provisions | Total | ||
| 2016 | 2016 | 2016 | 2015 | 2015 | 2015 | ||
| Notes | \$m | \$m | \$m | \$m | \$m | \$m | |
| At 1 January | 1,008.8 | 243.3 | 1,252.1 | 1,192.9 | 67.5 | 1,260.4 | |
| New provisions and changes | |||||||
| in estimates | 57.1 | 71.4 | 128.5 | (147.4) | 177.1 | 29.7 | |
| Disposals | – | – | – | 0.8 | 0.3 | 1.1 | |
| Payments | (23.0) | (132.0) | (155.0) | (40.8) | – | (40.8) | |
| Transfer to accruals | – | (35.0) | (35.0) | – | – | – | |
| Unwinding of discount 5 |
25.1 | – | 25.1 | 28.3 | 0.1 | 28.4 | |
| Currency translation adjustment | (53.6) | (3.5) | (57.1) | (25.0) | (1.7) | (26.7) | |
| At 31 December | 1,014.4 | 144.2 | 1,158.6 | 1,008.8 | 243.3 | 1,252.1 | |
| Current provisions | 49.0 | 2.9 | 51.9 | – | 187.0 | 187.0 | |
| Non-current provisions | 965.4 | 141.3 | 1,106.7 | 1,008.8 | 56.3 | 1,065.1 |
Included within other provisions is provision for onerous service contracts and provision for restructuring costs. Due to the reduction in planned future work programmes the Group has identified a number of onerous service contracts. The expected unutilised capacity has been provided for in 2015 and 2016 resulting in an income statement charge of \$114.9 million (2015: \$185.5 million). During 2016, the Group incurred \$12.3 million (2015: \$44.9 million) in respect of restructuring costs. A provision in respect of contingent consideration due on the acquisition of Spring Energy has been released in 2016 (\$43.5 million) as the Group concluded that payment of such consideration is not probable.
The decommissioning provision represents the present value of decommissioning costs relating to the European and African oil and gas interests.
| Inflation assumption |
Discount rate assumption |
Cessation of production assumption |
2016 \$m |
2015 \$m |
|
|---|---|---|---|---|---|
| Congo | 2% | 3% | 2027 | 18.3 | 15.2 |
| Côte d'Ivoire | 2% | 3% | 2026 | 48.1 | 53.3 |
| Equatorial Guinea | 2% | 3% | 2028-2029 | 130.0 | 126.2 |
| Gabon | 2% | 3% | 2021-2034 | 54.2 | 61.0 |
| Ghana | 2% | 3% | 2034-2036 | 267.6 | 257.7 |
| Mauritania | 2% | 3% | 2017 | 130.9 | 121.4 |
| Netherlands | 2% | 3% | 2020-2036 | 100.7 | 90.5 |
| UK | 2% | 3% | 2015-2018 | 264.6 | 283.5 |
| 1,014.4 | 1,008.8 |
| Accelerated tax depreciation \$m |
Decommissioning \$m |
Revaluation of financial assets \$m |
Tax losses \$m |
Other timing differences \$m |
Provision for onerous contracts \$m |
Deferred PRT \$m |
Total \$m |
|
|---|---|---|---|---|---|---|---|---|
| At 1 January 2015 | (1,480.4) | 131.8 | (1.6) | 95.5 | (4.6) | – | 6.7 | (1,252.6) |
| Credit/(debit) to income statement |
217.8 | 73.1 | 0.2 | 139.7 | (83.7) | – | 4.4 | 351.5 |
| Credit to other comprehensive income |
– | – | 0.9 | – | – | – | – | 0.9 |
| Exchange differences | 37.8 | (6.7) | – | 0.2 | 0.2 | (0.5) | 31.0 | |
| At 1 January 2016 | (1,224.8) | 198.2 | (0.5) | 235.4 | (88.1) | – | 10.6 | (869.2) |
| Credit/(debit) to income statement |
10.2 | (67.4) | – | 300.0 | 72.9 | 44.7 | (1.7) | 358.7 |
| Credit to other comprehensive income |
– | – | 1.0 | – | – | – | – | 1.0 |
| Exchange differences | (2.7) | (20.0) | – | (0.1) | 0.4 | – | (1.6) | (24.0) |
| At 31 December 2016 | (1,217.3) | 110.8 | 0.5 | 535.3 | (14.8) | 44.7 | 7.3 | (533.5) |
| 2016 \$m |
2015 \$m |
|||||||
| Deferred tax liabilities | (1,292.4) | (1,164.5) | ||||||
| Deferred tax assets | 758.9 | 295.3 | ||||||
| (533.5) | (869.2) |
No deferred tax has been provided on unremitted earnings of overseas subsidiaries, as the Group has no plans to remit these to the UK in the foreseeable future. Deferred tax assets are recognised only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse, and a judgement as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the level of deferred tax assets recognised which can result in a charge or credit in the period in which the change occurs.
Allotted equity share capital and share premium
| Equity share capital allotted and fully paid |
Share premium |
||
|---|---|---|---|
| Number | \$m | \$m | |
| Ordinary shares of 10 pence each | |||
| At 1 January 2015 | 910,661,631 | 147.0 | 606.4 |
| Issued during the year | |||
| – Exercise of share options | 915,075 | 0.2 | 3.4 |
| At 1 January 2016 | 911,576,706 | 147.2 | 609.8 |
| Issued during the year | |||
| – Exercise of share options | 2,905,254 | 0.3 | 9.5 |
| At 31 December 2016 | 914,481,960 | 147.5 | 619.3 |
The Company does not have a maximum authorised share capital.
The non-controlling interest relates to Tulipe Oil SA (Tulipe), where the Group has a 50% controlling shareholding, whose place of business is Gabon. Distributions to non-controlling interests were \$10.0 million (2015: \$2.4 million).
Analysis of share-based payment charge
| Notes | 2016 \$m |
2015 \$m |
|---|---|---|
| Tullow Incentive Plan | 9.3 | 12.3 |
| 2005 Performance Share Plan | 0.9 | 7.9 |
| 2005 Deferred Share Bonus Plan | – | 1.0 |
| Employee Share Award Plan | 38.3 | 30.8 |
| 2010 Share Option Plan and 2000 Executive Share Option Scheme | 1.5 | 14.8 |
| UK & Irish Share Incentive | 0.9 | 0.5 |
| Total share-based payment charge | 50.9 | 67.3 |
| Capitalised to intangible and tangible assets | 7.0 | 18.6 |
| Expensed to operating costs 4 |
2.7 | 0.8 |
| Expensed as administrative cost 4 |
41.2 | 47.9 |
| Total share-based payment charge | 50.9 | 67.3 |
Under the TIP, Senior Management can be granted nil exercise price options, normally exercisable from three (five years in the case of the Company's Directors) to 10 years following grant provided an individual remains in employment. The size of awards depends on both annual performance measures and Total Shareholder Return (TSR) over a period of up to three years. There are no post-grant performance conditions. No dividends are paid over the vesting period; however, an amount equivalent to the dividends that would have been paid on the TIP shares during the vesting period if they were 'real' shares, will also be payable on exercise of the award. There are further details of the TIP in the Remuneration Report on pages 80 to 100.
The weighted average remaining contractual life for TIP awards outstanding at 31 December 2016 was 7.7 years.
Under the PSP, Senior Management could be granted nil exercise price options, normally exercisable between three and 10 years following grant. Awards made before 8 March 2010 were made as conditional awards to acquire free shares on vesting. To provide flexibility to participants, those awards were converted into nil exercise price options. Awards vest subject to a Total Shareholder Return (TSR) performance condition; 50% (70% for awards granted to Directors in 2013, 2012 and 2011) of an award is tested against a comparator group of oil and gas companies. The remaining 50% (30% for awards granted to Directors in 2013, 2012 and 2011) is tested against constituents of the FTSE 100 index (excluding investment trusts). Performance is measured over a fixed three-year period starting on 1 January prior to grant, and an individual must normally remain in employment for three years from grant for the shares to vest. No dividends are paid over the vesting period. There are further details of PSP award performance measurement in the Remuneration Report on pages 80 to 100. From 2014, Senior Executives participate in the TIP instead of the PSP.
The weighted average remaining contractual life for PSP awards outstanding at 31 December 2016 was 1.8 years.
Under the DSBP, the portion of any annual bonus above 75% of the base salary of a Senior Executive nominated by the Remuneration Committee was deferred into shares. Awards normally vest following the end of three financial years commencing with that in which they were granted. They were granted as nil exercise price options, normally exercisable from when they vest until 10 years from grant. Awards granted before 8 March 2010 as conditional awards to acquire free shares were converted into nil exercise price options to provide flexibility to participants. A dividend equivalent is paid over the period from grant to vesting. From 2014, Senior Executives participate in the TIP instead of the DSBP.
The weighted average remaining contractual life for DSBP awards outstanding at 31 December 2016 was 4.3 years.
Most Group employees are eligible to be granted nil exercise price options under the ESAP. These are normally exercisable from three to 10 years following grant. An individual must normally remain in employment for three years from grant for the share to vest. Awards are not subject to post-grant performance conditions.
Phantom options that provide a cash bonus equivalent to the gain that could be made from a share option (being granted over a notional number of shares) have also been granted under the ESAP in situations where the grant of share options was not practicable.
The weighted average remaining contractual life for ESAP awards outstanding at 31 December 2016 was 7.7 years.
Participation in the 2010 SOP and 2000 ESOS was available to most of the Group's employees. Options have an exercise price equal to market value shortly before grant and are normally exercisable between three and 10 years from the date of the grant subject to continuing employment.
Options granted prior to 2011 were granted under the 2000 ESOS where exercise was subject to a performance condition. Performance was measured against constituents of the FTSE 100 index (excluding investment trusts). 100% of awards vested if the Company's TSR was above the median of the index companies over three years from grant. The 2010 SOP was replaced by the ESAP for grants from 2014. During 2013 phantom options were granted under the 2010 SOP to replace certain options granted under the 2000 ESOS that lapsed as a result of performance conditions not being satisfied. These replacement phantom options provide a cash bonus equivalent to the gain that could be made from a share option (being granted over a notional number of shares with a notional exercise price). Phantom options have also been granted under the 2010 SOP and the 2000 ESOS in situations where the grant of share options was not practicable.
Options outstanding at 31 December 2016 had exercise prices of 365p to 1530p (2015: 349p to 1530p) and remaining contractual lives between eight days and seven years. The weighted average remaining contractual life is 4.1 years.
These are all-employee plans set up in the UK and Ireland, to enable employees to save out of salary up to prescribed monthly limits. Contributions are used by the SIP trustees to buy Tullow shares ('Partnership Shares') at the end of each three-month accumulation period. The Company makes a matching contribution to acquire Tullow shares ('Matching Shares') on a one-forone basis. Under the UK SIP, Matching Shares are subject to time-based forfeiture over three
years on leaving employment in certain circumstances or if the related Partnership Shares are sold. The fair value of a Matching Share is its market value when it is awarded.
Under the UK SIP: (i) Partnership Shares are purchased at the lower of their market values at the start of the accumulation period and the purchase date (which is treated as a three-month share option for IFRS 2 purposes and therefore results in an accounting charge), and (ii) Matching Shares vest over the three years after being awarded (resulting in their accounting charge being spread over that period). Under the Irish SIP: (i) Partnership Shares are bought at the market value at the purchase date (which does not result in any accounting charge), and (ii) Matching Shares vest over the two years after being awarded (resulting in their accounting charge being spread over that period).
The following table illustrates the number and average weighted share price (WAEP) at grant or WAEP of, and movements in, share options under the TIP, PSP, DSBP, ESAP and 2010 SOP / 2000 ESOS.
| Outstanding as at 1 January |
Granted during the year |
Exercised during the year |
Forfeited/ expired during the year |
Outstanding at 31 December |
Exercisable at 31 December |
|
|---|---|---|---|---|---|---|
| 2016 TIP – number of shares | 3,801,426 | 7,134,968 | – | (10,127) 10,926,267 | 43,610 | |
| 2016 TIP – average weighted share price at grant | 547.3 | 147.7 | – | 782.0 | 287.1 | 782.0 |
| 2015 TIP – number of shares | 1,580,577 | 2,436,183 | – | (215,334) | 3,801,426 | 820,010 |
| 2015 TIP – average weighted share price at grant | 782.0 | 406.1 | – | 673.0 | 547.3 | 552.7 |
| 2016 PSP – number of shares | 4,208,862 | – | (283,867) | (3,014,991) | 910,004 | 910,004 |
| 2016 PSP – average weighted share price at grant |
1,125.7 | – | 962.0 | 1,214.7 | 882.0 | 882.0 |
| 2015 PSP – number of shares | 6,972,729 | – | (223,711) | (2,540,156) | 4,208,862 | 1,814,024 |
| 2015 PSP – average weighted share price at grant |
1,230.2 | – | 892.4 | 1,433.0 | 1,125.7 | 997.7 |
| 2016 DSBP – number of shares | 466,097 | – | (137,114) | (123,279) | 205,704 | 205,704 |
| 2016 DSBP – average weighted share price at grant |
1,226.7 | – | 1,338.2 | 1,121.4 | 1,215.5 | 1,215.5 |
| 2015 DSBP – number of shares | 491,916 | – | (25,819) | – | 466,097 | 315,589 |
| 2015 DSBP – average weighted share price at grant |
1,240.0 | – | 1,480.0 | – | 1,226.7 | 1,219.9 |
| 2016 ESAP – number of shares | 17,067,908 11,315,031 | (2,495,408) | (2,126,712) 23,760,819 | 3,330,615 | ||
| 2016 ESAP – average weighted share price at grant |
380.7 | 147.7 | 354.9 | 287.4 | 280.8 | 281.5 |
| 2015 ESAP – number of shares | 3,306,981 | 15,516,608 | (155,107) | (1,600,574) 17,067,908 | 651,595 | |
| 2015 ESAP – average weighted share price at grant |
779.7 | 304.2 | 730.3 | 429.0 | 380.7 | 688.7 |
| 2016 SOP/ESOS – number of shares | 14,466,011 | – | (3,362) | (4,456,279) 10,006,370 10,006,370 | ||
| 2016 SOP/ESOS – WAEP | 1,160.9 | – | 1,219.0 | 1,088.9 | 1,192.9 | 1,192.9 |
| 2015 SOP/ESOS – number of shares | 16,343,605 | – | (531,106) | (1,346,488) 14,466,011 | 9,894,040 | |
| 2015 SOP/ESOS – WAEP | 1,128.8 | – | 201.8 | 1,149.6 | 1,160.9 | 1,139.3 |
| 2016 Phantoms – number of phantom shares | 1,518,439 | – | – | (265,694) | 1,252,745 | 1,252,745 |
| 2016 Phantoms – WAEP | 1,274.5 | – | – | 1,274.4 | 1,274.4 | 1,274.4 |
| 2015 Phantoms – number of phantom shares | 2,229,052 | – | – | (710,613) | 1,518,439 | 1,518,439 |
| 2015 Phantoms – WAEP | 1,274.5 | – | – | 1,274.6 | 1,274.5 | 1,274.5 |
The options granted during the year were valued using a proprietary binomial valuation.
The following table details the weighted average fair value of awards granted and the assumptions used in the fair value expense calculations.
| 2016 TIP | 2016 ESAP | 2015 TIP | 2015 ESAP | |
|---|---|---|---|---|
| Weighted average fair value of awards granted | 147.7p | 147.7p | 406.1p | 304.2p |
| Weighted average share price at exercise for awards exercised | – | 282.1p | – | 319.0 |
| Principal inputs to options valuations model: | ||||
| Weighted average share price at grant | 147.7p | 147.7p | 406.1p | 304.2p |
| Weighted average exercise price | 0.0p | 0.0p | 0.0p | 0.0p |
| Risk-free interest rate per annum | 0.4 – 0.7% | 0.4% | 0.9 – 1.3% | 0.5 – 1.0% |
| Expected volatility per annum1 | 45 – 50% | 50% | 32 – 36% | 32 – 41% |
| Expected award life (years)2 | 3.5 | 3.0 | 3.3 | 2.2 |
| Dividend yield per annum | n/a | 0.0% | n/a | 0.0% |
| Employee turnover before vesting per annum3 | 5% / 0% | 5% | 5% / 0% | 5% |
Expected volatility was determined by calculating the historical volatility of the Company's share price over a period commensurate with the expected life of the awards.
The expected life is the average expected period from date of grant to exercise allowing for the Company's best estimate of participants' expected exercise behaviour.
Zero turnover is assumed for TIP awards made to executives and Directors, 5% per annum for TIP awards to Senior Management.
| 2016 PSP |
2015 PSP |
2016 DSBP |
2015 DSBP |
2016 SOP/ESOS1 |
2015 SOP/ESOS1 |
|
|---|---|---|---|---|---|---|
| Weighted average share price at exercise for | ||||||
| awards exercised | 254.6p | 294.5p | 213.5p | 384.6p | 255.7p | 409.0p |
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Capital commitments | 108.4 | 1,614.5 |
| Operating lease commitments | ||
| Due within one year | 143.7 | 8.4 |
| After one year but within two years | 105.9 | 8.4 |
| After two years but within five years | 319.9 | 25.2 |
| Due after five years | 464.8 | 39.3 |
| 1,034.3 | 81.3 | |
| Contingent liabilities | ||
| Performance guarantees | 85.1 | 130.9 |
| Other contingent liabilities | 156.6 | 32.0 |
| 241.7 | 162.9 |
Where Tullow acts as operator of a joint venture the capital commitments reported represent Tullow's net share of these commitments.
Where Tullow is non-operator the value of capital commitments is based on committed future work programmes.
Operating lease payments represent rentals payable by the Group for certain of its office properties and a lease for an FPSO vessel for use on TEN filed in Ghana. The TEN FPSO is expected to be recognised as a finance lease in the first half of 2017. Leases on office properties are negotiated for an average of six years and rentals are fixed for an average of six years.
Performance guarantees are in respect of abandonment obligations, committed work programmes and certain financial obligations.
Other contingent liabilities include amounts for ongoing legal disputes with third parties where we consider the likelihood of a cash outflow to be higher than remote but not probable.
The Directors of Tullow Oil plc are considered to be the only key management personnel as defined by IAS 24 – Related Party Disclosures.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Short-term employee benefits | 8.9 | 10.0 |
| Post-employment benefits | 1.0 | 1.1 |
| Amounts awarded under long-term incentive schemes | 3.7 | 4.2 |
| Share-based payments | 2.6 | 5.7 |
| 16.2 | 21.0 |
These amounts comprise fees paid to the Directors in respect of salary and benefits earned during the relevant financial year, plus bonuses awarded for the year.
These amounts comprise amounts paid into the pension schemes of the Directors.
These amounts relate to the shares granted under the annual bonus scheme that are deferred for three years under the Deferred Share Bonus Plan (DSBP) and Tullow Incentive Plan (TIP).
This is the cost to the Group of Directors' participation in share-based payment plans, as measured by the fair value of options and shares granted, accounted for in accordance with IFRS 2 Share-based Payments.
There are no other related party transactions. Further details regarding transactions with the Directors of Tullow Oil plc are disclosed in the Remuneration Report on pages 80 to 100.
On 5 January 2017, Tullow announced that Ian Springett, CFO, has taken an extended leave of absence to undergo treatment for a medical condition, with Les Wood, Vice President Finance and Commercial, appointed Interim CFO.
On 9 January 2017, Tullow announced that it had agreed a substantial farm-down of its assets in Uganda to Total. For further details please see above.
On 11 January 2017, the Group announced that Paul McDade, currently Chief Operating Officer, will be appointed Chief Executive Officer following Tullow's Annual General Meeting on 26 April 2017. This follows an internal and external process led by Tullow's Nominations Committee. At the same time, after six years on Tullow's Board and five as Chairman, Simon Thompson will step down from the Board. Aidan Heavey, Chief Executive Officer and founder of Tullow Oil, will succeed Mr. Thompson as Chairman of the Group for a transitional period of up to but not exceeding two years. Ann Grant, Senior Independent Director, will retire at the AGM after nine years' service on the Board. Jeremy Wilson, a non-executive Director of Tullow and Chairman of the Remuneration Committee, will succeed Ms Grant as Senior Independent Director.
On 17 January 2017, the Group announced that the Erut-1 well in Block 13T, Northern Kenya, had discovered a gross oil interval of 55 metres with 25 metres of net oil pay at a depth of 700 metres. The overall oil column for the field is estimated to be 100 to 125 metres.
On 7 February 2017, Tullow agreed a one year maturity extension of its Corporate Facility to April 2019, with commitments of \$500 million from April 2018 reducing to \$400 million in October 2018. The extension has been significantly over subscribed, demonstrating the continued support from Tullow's relationship banks.
The Group operates defined contribution pension schemes for staff and Executive Directors. The contributions are payable to external funds which are administered by independent trustees. Contributions during the year amounted to \$16.6 million (2015: \$20.5 million). As at 31 December 2016, there was a liability of \$nil (2015: \$nil) for contributions payable included in other payables.
AS AT 31 DECEMBER 2016 AS AT 31 DECEMBER 2016
| Notes | 2016 \$m |
2015 \$m |
|---|---|---|
| ASSETS | ||
| Non-current assets | ||
| Investments 1 |
7,398.0 | 4,885.4 |
| Intercompany derivative asset 6 |
– | 217.6 |
| 7,398.0 | 5,103.0 | |
| Current assets | ||
| Other current assets 3 |
1,431.4 | 3,475.5 |
| Intercompany derivative asset 6 |
– | 405.4 |
| Cash at bank | 6.7 | 3.4 |
| 1,438.1 | 3,884.3 | |
| Total assets | 8,836.1 | 8,987.3 |
| LIABILITIES | ||
| Current liabilities | ||
| Trade and other creditors 4 |
(343.6) | (722.5) |
| Borrowings 5 |
(508.1) | (14.2) |
| Intercompany derivative liability 6 |
(50.0) | – |
| (901.7) | (736.7) | |
| Non-current liabilities | ||
| Borrowings 5 |
(4,131.1) | (4,262.4) |
| Intercompany derivative liability 6 |
(17.2) | – |
| (4,148.3) | (4,262.4) | |
| Total liabilities | (5,050.0) | (4,999.1) |
| Net assets | 3,786.1 | 3,988.2 |
| Capital and reserves | ||
| Called-up share capital 7 |
147.5 | 147.2 |
| Share premium 7 |
619.3 | 609.8 |
| Other reserves | 850.8 | 850.8 |
| Retained earnings | 2,168.5 | 2,380.4 |
| Total equity | 3,786.1 | 3,988.2 |
During the year the Company made a loss of \$253.4 million (2015: \$1,264.8 million loss).
Approved by the Board and authorised for issue on 7 February 2017.
Aidan Heavey Les Wood
Chief Executive Officer Interim Chief Financial Officer
AS AT 31 DECEMBER 2016 AS AT 31 DECEMBER 2016
| Share capital \$m |
Share premium \$m |
Other reserves \$m |
Retained earnings \$m |
Total equity \$m |
|
|---|---|---|---|---|---|
| At 1 January 2015 | 147.0 | 606.4 | 850.8 | 3,579.8 | 5,184.0 |
| Loss for the year | – | – | – | (1,264.8) | (1,264.8) |
| Issue of employee share options | 0.2 | 3.4 | – | – | 3.6 |
| Vesting of PSP shares | – | – | – | (1.9) | (1.9) |
| Share-based payment charges | – | – | – | 67.3 | 67.3 |
| At 1 January 2016 | 147.2 | 609.8 | 850.8 | 2,380.4 | 3,988.2 |
| Loss for the year | – | – | – | (253.4) | (253.4) |
| Issue of employee share options | 0.3 | 9.5 | – | – | 9.8 |
| Vesting of PSP shares | – | – | – | (9.4) | (9.4) |
| Share-based payment charges | – | – | – | 50.9 | 50.9 |
| At 31 December 2016 | 147.5 | 619.3 | 850.8 | 2,168.5 | 3,786.1 |
Tullow Oil plc is a company incorporated in the United Kingdom under the Companies Act. The address of the registered office is Tullow Oil plc, Building 9, Chiswick Park, 566 Chiswick High Road, London W4 5XT. The Financial Statements are presented in US dollars and all values are rounded to the nearest \$0.1 million, except where otherwise stated. Tullow Oil plc is the ultimate Parent of the Tullow Oil Group.
The Company meets the definition of a qualifying entity under Financial Reporting Standard 100 (FRS 100) issued by the Financial Reporting Council. The Financial Statements have therefore been prepared in accordance with Financial Reporting Standard 101 (FRS 101) 'Reduced Disclosure Framework' as issued by the Financial Reporting Council.
As permitted by FRS 101, the Company has taken advantage of the disclosure exemptions available under that standard in relation to share-based payments, financial instruments, capital management, presentation of comparative information in respect of certain assets, presentation of an income statement, presentation of a cash flow statement, standards not yet effective, impairment of assets and related party transactions. Where relevant, equivalent disclosures have been given in the Group accounts.
The Financial Statements have been prepared on the historical cost basis, except for derivative financial instruments that have been measured at fair value.
During the year the Company made a loss of \$253.4 million (2015: \$1,264.8 million loss).
The Group closely monitors and manages its liquidity risk. Cash forecasts are regularly produced and sensitivities run for different scenarios including, but not limited to, changes in commodity prices and different production rates from the Group's producing assets. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.0 billion of debt liquidity headroom and free cash at the end of 2016. The Group's forecasts show that the Group will be able to operate within its current debt facilities and have sufficient financial headroom for the 12 months from the date of approval of the 2016 Annual Report and Accounts.
Notwithstanding our forecasts of liquidity headroom throughout the 12-month period, risk remains in relation to the volatility of the oil price environment, operational performance of the Group's assets, their impact on operating cash flows and the Group's currently contracted debt maturity profiles, such that the Group's liquidity position may deteriorate within the assessment period.
To mitigate these risks and to fulfil the Group's objective to reduce net debt, the Group continues to closely monitor cash flow projections and will take mitigating actions in advance to maintain our liquidity. Actions available to the Group include additional funding options, further rationalisation of our cost base including cuts to discretionary capital expenditure and portfolio management.
Based on the analysis above and the level of mitigating actions available, the Directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the foreseeable future. Thus they continue to
adopt the going concern basis of accounting in preparing the annual Financial Statements.
The US dollar is the reporting currency of the Company. Transactions in foreign currencies are translated at the rates of exchange ruling at the transaction date. Monetary assets and liabilities denominated in foreign currencies are translated into US dollars at the rates of exchange ruling at the balance sheet date, with a corresponding charge or credit to the income statement. However, exchange gains and losses arising on long-term foreign currency borrowings, which are a hedge against the Company's overseas investments, are dealt with in reserves.
Fixed asset investments, including investments in subsidiaries, are stated at cost and reviewed for impairment if there are indications that the carrying value may not be recoverable.
The Company uses derivative financial instruments to manage the Group's exposure to fluctuations in movements in oil and gas prices.
Derivative financial instruments are stated at fair value.
The purpose for which a derivative is used is established at inception. To qualify for hedge accounting, the derivative must be highly effective in achieving its objective and this effectiveness must be documented at inception and throughout the period of the hedge relationship. The hedge must be assessed on an ongoing basis and determined to have been highly effective throughout the financial reporting periods for which the hedge was designated.
For the purpose of hedge accounting, hedges are classified as either fair value hedges, when they hedge the exposure to changes in the fair value of a recognised asset or liability, or cash flow hedges, where they hedge exposure to variability in cash flows that is either attributable to a particular risk associated with a recognised asset or liability or forecast transaction.
In relation to fair value hedges which meet the conditions for hedge accounting, any gain or loss from remeasuring the derivative and the hedged item at fair value is recognised immediately in the income statement. Any gain or loss on the hedged item attributable to the hedged risk is adjusted against the carrying amount of the hedged item and recognised in the income statement.
For cash flow hedges, the portion of the gains and losses on the hedging instrument that is determined to be an effective hedge is taken to other comprehensive income and the ineffective portion, as well as any change in time value, is recognised in the income statement. The gains and losses taken to other comprehensive income are subsequently transferred to the income statement during the period in which the hedged transaction affects the income statement. A similar treatment applies to foreign currency loans which are hedges of the Group's net investment in the net assets of a foreign operation.
Gains or losses on derivatives that do not qualify for hedge accounting treatment (either from inception or during the life of the instrument) are taken directly to the income statement in the period.
Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities.
Costs of share issues are written off against the premium arising on the issues of share capital.
Finance costs of debt are recognised in the profit and loss account over the term of the related debt at a constant rate on the carrying amount.
Interest-bearing borrowings are recorded as the proceeds received, net of direct issue costs. Finance charges, including premiums payable on settlement or redemption and direct issue costs, are accounted for on an accruals basis in the income statement using the effective interest method and are added to the carrying amount of the instrument to the extent that they are not settled in the period in which they arise.
Current and deferred tax, including UK corporation tax and overseas corporation tax, are provided at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date. Deferred corporation tax is recognised on all temporary differences that have originated but not reversed at the balance sheet date where transactions or events that result in an obligation to pay more, or right to pay less, tax in the future have occurred at the balance sheet date. Deferred tax assets are recognised only to the extent that it is considered more likely than not that there will be suitable taxable profits from which the underlying temporary differences can be deducted. Deferred tax is measured on a non-discounted basis.
Deferred tax is provided on temporary differences arising on acquisitions that are categorised as business combinations. Deferred tax is recognised at acquisition as part of the assessment of the fair value of assets and liabilities acquired. Any deferred tax is charged or credited in the income statement as the underlying temporary difference is reversed.
The Company defines capital as the total equity of the Company. Capital is managed in order to provide returns for shareholders and benefits to stakeholders and to safeguard the Company's ability to continue as a going concern. Tullow is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, the Company may adjust the dividend payment to shareholders, return capital, issue new shares for cash, repay debt, and put in place new debt facilities.
• Financial instruments (note 6):
Some of the Company's assets and liabilities are measured at fair value for financial reporting purposes. The Directors of the Company have determined appropriate valuation techniques and inputs for fair value measurements.
In estimating the fair value of an asset or a liability, the Company uses market-observable data to the extent it is available. Where Level 1 inputs are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved.
• Investments (note 1):
The Company is required to assess the carrying values of each of its investments in subsidiaries for impairment. The net assets of certain of the Company's subsidiaries are predominantly intangible exploration and evaluation (E&E) assets. Where facts and circumstances indicate that the carrying amount of an E&E asset held by a subsidiary may exceed its recoverable amount, by reference to the specific indicators of impairment of E&E assets, an impairment test of the asset is performed by the subsidiary undertaking and the asset is impaired by any difference between its carrying value and its recoverable amount. The recognition of such an impairment by a subsidiary is used by the Company as the primary basis for determining whether or not there are indications that the investment in the related subsidiary may also be impaired, and thus whether an impairment test of the investment carrying value needs to be performed. The results of exploration activities are inherently uncertain and the assessment of impairment of E&E assets by the subsidiary, and that of the related investment by the Company, is judgemental.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Shares at cost in subsidiary undertakings | 7,397.0 | 4,884.4 |
| Unlisted investments | 1.0 | 1.0 |
| 7,398.0 | 4,885.4 |
During 2016, the Company increased its investments in subsidiaries undertakings by \$3,690.2 million (2015: \$1,245.6 million); this was partially offset by recognising an impairment of \$1,177.6 million (2015: \$1,279.8 million) against the Company's investments in subsidiaries to fund losses incurred by Group service companies and exploration companies.
The Company's subsidiary undertakings as at 31 December 2016 are listed on pages 175 and 176. The principal activity of all companies relates to oil and gas exploration, development and production.
The Company has tax losses of \$494.4 million (2015: \$359.9 million) that are available indefinitely for offset against future non-ring-fenced taxable profits in the Company. A deferred tax asset of \$nil (2015: \$nil) has been recognised in respect of these losses on the basis that the Company does not anticipate making non-ring-fenced profits in the foreseeable future.
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Other debtors | 29.1 | – |
| Due from subsidiary undertakings | 1,402.3 | 3,475.5 |
| 1,431.4 | 3,475.5 |
The amounts due from subsidiary undertakings include \$1,373.3 million (2015: \$2,951.0 million) that incurs interest at LIBOR plus 0.5% – 4.5%. The remaining amounts due from subsidiaries accrue no interest. All amounts are repayable on demand. During the year a provision of \$172.5 million (2015: \$174.8 million) was made in respect of the recoverability of amounts due from subsidiary undertakings.
Amounts falling due within one year
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| VAT and other similar taxes | 0.7 | – |
| Due to subsidiary undertakings | 342.9 | 722.5 |
| 343.6 | 722.5 |
| 2016 \$m |
2015 \$m |
|
|---|---|---|
| Current | ||
| Bank borrowings – Reserve Based Lending credit facility | 508.1 | 14.2 |
| Non-current | ||
| Bank borrowings – after one year but within two years | ||
| Reserve-Based lending credit facility | 906.2 | 800.0 |
| Revolving credit facility | 364.6 | – |
| Bank borrowings – after two years but within five years | ||
| Reserve-Based lending credit facility | 1,561.7 | 2,165.6 |
| 6.0% Senior Notes due 2020 | 647.6 | 646.4 |
| 6.25% Senior Notes due 2022 | 651.0 | 650.4 |
| 4,131.1 | 4,262.4 | |
| Carrying value of total borrowings | 4,639.2 | 4,276.6 |
| Accrued interest and unamortised fees | 40.8 | 37.6 |
| External borrowings | 4,680.0 | 4,314.2 |
Term loans are secured by fixed and floating charges over the oil and gas assets of the Group.
Where equivalent disclosures for the requirements of IFRS 7 Financial Instruments: Disclosures and IFRS 13 Fair Value Measurements have been included in the 2016 Annual Report and Accounts of Tullow Oil plc, the Company has adopted the disclosure exemptions available to the Company's accounts.
The Company follows the Group's policies for managing all its financial risks.
All derivatives are recognised at fair value on the balance sheet with valuation changes recognised immediately in the income statement, unless the derivatives have been designated as cash flow or fair value hedges. Fair value is the amount for which the asset or liability could be exchanged in an arm's length transaction at the relevant date. Where available, fair values are determined using quoted prices in active markets. To the extent that market prices are not available, fair values are estimated by reference to market-based transactions, or using standard valuation techniques for the applicable instruments and commodities involved.
On 15 April 2016, the Company terminated the intercompany derivative trade previously entered on 22 December 2015 with a wholly owned subsidiary, in exchange for a termination receipt of \$550.1 million. This terminated the Company's right to receive from the subsidiary all future receipts, and its obligations to the subsidiary to assume all future liabilities under the Group's existing and future oil derivative contracts with external counterparties.
This intercompany transaction does not impact the Group's oil derivative contracts with external counterparties, which it continues to transact and hold in line with the Group's commodity price risk management objectives.
On the same day, the Company entered into a new intercompany derivative trade with the same subsidiary, to purchase downside oil price protection up to 31 December 2018, for a deferred consideration of \$137.0 million.
The Company's derivative carrying and fair values were as follows
| Assets/liabilities | 2016 Less than 1 year \$m |
2016 1-3 years \$m |
2016 Total \$m |
2015 Less than 1 year \$m |
2015 1-3 years \$m |
2015 Total \$m |
|---|---|---|---|---|---|---|
| Intercompany oil derivatives | (50.0) | (17.2) | (67.0) | 405.4 | 217.6 | 623.0 |
| Total assets | – | – | – | 405.4 | 217.6 | 623.0 |
| Total liabilities | (50.0) | (17.2) | (67.0) | – | – | – |
The following provides an analysis of the Company's financial instruments measured at fair value, grouped into Levels 1 to 3 based on the degree to which the fair value is observable:
Level 1: fair value measurements are those derived from quoted prices (unadjusted) in active markets for identical assets or liabilities;
Level 2: fair value measurements are those derived from inputs other than quoted prices included within Level 1 which are observable for the asset or liability, either directly or indirectly; and
Level 3: fair value measurements are those derived from valuation techniques which include inputs for the asset or liability that are not based on observable market data.
All of the Company's derivatives are Level 2 (2015: Level 2). There were no transfers between fair value levels during the year.
For financial instruments which are recognised on a recurring basis, the Company determines whether transfers have occurred between levels by reassessing categorisation (based on the lowest-level input which is significant to the fair value measurement as a whole) at the end of each reporting period.
Derivative fair value movements during the year which have been recognised in the income statement were as follows.
| Loss on derivative instruments | 2016 \$m |
2015 \$m |
|---|---|---|
| Intercompany oil derivatives | (27.6) | (53.3) |
The interest rate profile of the Company's financial assets and liabilities, excluding trade and other receivables and trade and other payables, at 31 December 2016 and 2015 was as follows:
| 2016 Cash at bank \$m |
2016 Fixed rate debt \$m |
2016 Floating rate debt \$m |
2016 Total \$m |
2015 Cash at bank \$m |
2015 Fixed rate debt \$m |
2015 Floating rate debt \$m |
2015 Total \$m |
|
|---|---|---|---|---|---|---|---|---|
| US\$ | 7.7 | (1,300.0) | (3,380.0) | (4,672.3) | 2.1 | (1,300.0) | (2,857.3) | (4,155.2) |
| Euro | – | – | – | – | 0.2 | – | – | 0.2 |
| Sterling | – | – | – | – | 0.1 | – | (156.9) | (156.8) |
| Other | 0.1 | – | – | 0.1 | 1.0 | – | – | 1.0 |
| 7.8 | (1,300.0) | (3,380.0) | (4,672.2) | 3.4 | (1,300.0) | (3,014.2) | (4,310.8) |
Cash at bank consisted mainly of deposits which earn interest at rates set in advance for periods ranging from overnight to one month by reference to market rates.
The following table details the Company's remaining contractual maturity for its non-derivative financial liabilities with agreed repayment periods. The tables have been drawn up based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Company can be required to pay.
| Weighted average effective interest rate |
Less than 1 month \$m |
1-3 months \$m |
3 months to 1 year \$m |
1-5 years \$m |
5+ years \$m |
Total \$m |
|
|---|---|---|---|---|---|---|---|
| 31 December 2016 | |||||||
| Non-interest bearing | n/a | 343.6 | – | – | – | – | 343.6 |
| Fixed interest rate instruments | 7.1% | ||||||
| Principal repayments | – | – | – | 941.7 | 650.0 | 1,591.7 | |
| Interest charge | 14.5 | – | 94.1 | 395.5 | 20.3 | 524.4 | |
| Variable interest rate instruments | 5.9% | ||||||
| Principal repayments | – | 55.0 | 453.1 | 2,871.9 | – | 3,380.0 | |
| Interest charge | 14.2 | 28.2 | 118.4 | 151.9 | – | 312.7 | |
| 372.3 | 83.2 | 665.6 | 4,361.0 | 670.3 | 6,152.4 |
| Weighted average effective interest rate |
Less than 1 month \$m |
1-3 months \$m |
3 months to 1 year \$m |
1-5 years \$m |
5+ years \$m |
Total \$m |
|
|---|---|---|---|---|---|---|---|
| 31 December 2015 | |||||||
| Non-interest bearing | n/a | 722.5 | – | – | – | – | 722.5 |
| Fixed interest rate instruments | 6.5% | ||||||
| Principal repayments | – | – | – | 650.0 | 650.0 | 1,300.0 | |
| Interest charge | – | – | 79.6 | 318.5 | 60.9 | 459.0 | |
| Variable interest rate instruments | 6.0% | ||||||
| Principal repayments | – | – | 14.2 | 3,000.0 | – | 3,014.2 | |
| Interest charge | 9.9 | 19.7 | 88.5 | 206.0 | – | 324.1 | |
| 732.4 | 19.7 | 182.3 | 4,174.5 | 710.9 | 5,819.8 |
The following analysis is intended to illustrate sensitivity to changes in market variables, being Dated Brent oil prices and US dollar exchange rates. The analysis is used internally by management to monitor derivatives and assesses the financial impact of reasonably possible movements in key variables.
| Impact on profit before tax | |||
|---|---|---|---|
| Market movement | 2016 \$m |
2015 \$m |
|
| Brent oil price | 25% | – | (286.0) |
| Brent oil price | (25%) | 28.6 | 256.5 |
| US\$/foreign currency exchange rates | 20% | – | (31.4) |
| US\$/foreign currency exchange rates | (20%) | – | 31.4 |
The following assumptions have been used in calculating the sensitivity in movement of oil prices: the pricing adjustments relate only to the point forward mark-to-market (MTM) valuations and the sensitivities have been run only on the intrinsic element of the derivatives as management considers this to be the material component of oil derivative valuations.
Allotted equity share capital and share premium
| At 31 December 2016 | 914,481,960 | 147.5 | 619.3 |
|---|---|---|---|
| – Exercise of share options | 2,905,254 | 0.3 | 9.5 |
| Issued during the year | |||
| At 1 January 2016 | 911,576,706 | 147.2 | 609.8 |
| – Exercise of share options | 915,075 | 0.2 | 3.4 |
| Issued during the year | |||
| At 1 January 2015 | 910,661,631 | 147.0 | 606.4 |
| Equity share capital allotted and fully paid Number |
Share capital \$m |
Share premium \$m |
The Company does not have an authorised share capital. The par value of the Company's shares is 10 pence.
| 2016 \$m |
2015 \$m |
2014 \$m |
2013* \$m |
2012* \$m |
|
|---|---|---|---|---|---|
| Group income statement | |||||
| Sales revenue | 1,269.9 | 1,606.6 | 2,212.9 | 2,646.9 | 2,344.1 |
| Other operating income – lost production insurance proceeds | 90.1 | – | – | – | – |
| Cost of sales | (813.1) | (1,015.3) | (1,116.7) | (1,153.8) | (968.0) |
| Gross profit | 546.9 | 591.3 | 1,096.2 | 1,493.1 | 1,376.1 |
| Administrative expenses | (116.4) | (193.6) | (192.4) | (218.5) | (191.2) |
| Restructuring costs | (12.3) | (40.8) | – | – | – |
| (Loss)/profit on disposal | (3.4) | (56.5) | (482.4) | 29.5 | 702.5 |
| Goodwill impairment | (164.0) | (53.7) | (132.8) | – | – |
| Exploration costs written off | (723.0) | (748.9) | (1,657.3) | (870.6) | (670.9) |
| Impairment of property, plant and equipment | (167.6) | (406.0) | (595.9) | (52.7) | (31.3) |
| Provision for onerous service contracts | (114.9) | (185.5) | – | – | – |
| Operating (loss)/profit | (754.7) | (1,093.7) | (1,964.6) | 380.8 | 1,185.2 |
| Profit/(loss) on hedging instruments | 18.2 | (58.8) | 50.8 | (19.7) | (19.9) |
| Finance revenue | 26.4 | 4.2 | 9.6 | 43.7 | 9.6 |
| Finance costs | (198.2) | (149.0) | (143.2) | (91.6) | (59.0) |
| (Loss)/profit from continuing activities before taxation | (908.3) | (1,297.3) | (2,047.4) | 313.2 | 1,115.9 |
| Taxation | 311.0 | 260.4 | 407.5 | (97.1) | (449.7) |
| (Loss)/profit for the year from continuing activities | (597.3) | (1,036.9) | (1,639.9) | 216.1 | 666.2 |
| (Loss)/earnings per share | |||||
| Basic – ¢ | (65.8) | (113.6) | (170.9) | 18.6 | 68.8 |
| Diluted – ¢ | (65.8) | (113.6) | (170.9) | 18.5 | 68.4 |
| Dividends paid | – | – | 182.3 | 167.4 | 173.2 |
| Group balance sheet | |||||
| Non-current assets | 8,340.1 | 9,506.8 | 9,335.1 | 9,439.3 | 8,087.6 |
| Net current assets/(liabilities) | 813.1 | 259.2 | 747.4 | 637.0 | 65.4 |
| Total assets less current liabilities | 9,153.2 | 9,766.0 | 10,082.5 | 10,076.3 | 8,153.0 |
| Long-term liabilities | (6,910.7) | (6,591.3) | (6,062.2) | (4,629.9) | (2,831.4) |
| Net assets | 2,242.5 | 3,174.7 | 4,020.3 | 5,446.4 | 5,321.6 |
| Called up equity share capital | 147.5 | 147.2 | 147.0 | 146.9 | 146.6 |
| Share premium | 619.3 | 609.8 | 606.4 | 603.2 | 584.8 |
| Equity component of convertible bonds | 48.4 | – | – | – | – |
| Foreign currency translation reserve | (232.2) | (249.3) | (205.7) | (155.1) | (167.8) |
| Hedge reserve | 128.2 | 569.9 | 401.6 | 2.3 | (6.5) |
| Other reserves | 740.9 | 740.9 | 740.9 | 740.9 | 740.9 |
| Retained earnings | 778.0 | 1,336.4 | 2,305.8 | 3,984.7 | 3,931.2 |
| Equity attributable to equity holders of the Parent | 2,230.1 | 3,154.9 | 3,996.0 | 5,322.9 | 5,229.2 |
| Non-controlling interest | 12.4 | 19.8 | 24.3 | 123.5 | 92.4 |
| Total equity | 2,242.5 | 3,174.7 | 4,020.3 | 5,446.4 | 5,321.6 |
* All comparative figures have been re-presented to align disclosure of impairments of property, plant and equipment on the face of the income statement with 2014.
| 2016 Full-year results announced | 8 February 2017 |
|---|---|
| Annual General Meeting | 26 April 2017 |
| AGM Trading Update | 26 April 2017 |
| Trading Statement & Operational Update |
28 June 2017 |
| 2017 Half Year Results announced | 26 July 2017 |
| November Trading Update | 8 November 2017 |
All enquiries concerning shareholdings, including notification of change of address, loss of a share certificate or dividend payments, should be made to the Company's registrars.
For shareholders on the UK register, Computershare provides a range of services through its online portal, Investor Centre, which can be accessed free of charge at www.investorcentre.co.uk. Once registered, this service, accessible from anywhere in the world, enables shareholders to check details of their shareholdings or dividends, download forms to notify changes in personal details and access other relevant information.
Computershare Investor Services PLC The Pavilions Bridgwater Road Bristol BS99 6ZZ
Tel – UK shareholders: 0870 703 6242 Tel – Irish shareholders: + 353 1 247 5413 Tel – overseas shareholders: + 44 870 703 6242 Contact: www.investorcentre.co.uk/contactus
Tel – Ghana shareholders: + 233 303 972 254/ 302 689 313
Contact: [email protected]
A telephone share dealing service has been established for shareholders with Computershare for the sale and purchase of Tullow Oil shares. Shareholders who are interested in using this service can obtain further details by calling the appropriate telephone number below:
UK shareholders: 0870 703 0084
Irish shareholders: +353 1 447 5435
If you live outside the UK or Ireland and wish to trade you can do so through the Computershare Trading Account. To find out more or to open an account, please visit www.computershare-sharedealing.co.uk or phone Computershare on +44 870 707 1606.
If you have a small number of shares whose value makes it uneconomical to sell, you may wish to consider donating them to ShareGift which is a UK registered charity specialising in realising the value locked up in small shareholdings for charitable purposes. The resulting proceeds are donated to a range of charities, reflecting suggestions received from donors. Should you wish to donate your Tullow Oil plc shares in this way, please download and complete a transfer form from www.sharegift.org/forms, sign it and send it together with the share certificate to ShareGift, PO Box 72253, London SW1P 9LQ. For more information regarding this charity, visit www.sharegift.org.
To reduce impact on the environment, the Company encourages all shareholders to receive their shareholder communications, including annual reports and notices of meetings, electronically. Once registered for electronic communications, shareholders will be sent an email each time the Company publishes statutory documents, providing a link to the information.
Tullow actively supports Woodland Trust, the UK's leading woodland conservation charity. Computershare, together with Woodland Trust, has established eTree, an environmental programme designed to promote electronic shareholder communications. Under this programme, the Company makes a donation to eTree for every shareholder who registers for electronic communication. To register for this service, simply visit
http://www.investorcentre.co.uk/etreeuk/tullowoilplc with your shareholder number and email address to hand.
Shareholders are advised to be cautious about any unsolicited financial advice: offers to buy shares at a discount or offers of free company reports. More detailed information can be found at http://scamsmart.fca.org.uk/ and in the Shareholder Services section of the Investors area of the Tullow website: www.tullowoil.com.
Barclays 5 North Colonnade Canary Wharf London E14 4BB
20 Bank Street Canary Wharf London E14 4AD
Davy House 49 Dawson Street Dublin 2 Ireland
| Licence | Fields | Area sq km |
Tullow Interest |
Operator | Other Partners |
|---|---|---|---|---|---|
| Congo (Brazzaville) | |||||
| M'Boundi | M'Boundi | 146 | 11.00% | ENI | SNPC |
| Côte d'Ivoire | |||||
| CI-26 Special Area "E" | Espoir | 235 | 21.33% | CNR | PETROCI |
| Equatorial Guinea | |||||
| Ceiba | Ceiba | 70 | 14.25% | Hess | GEPetrol |
| Okume Complex | Okume, Oveng, Ebano, Elon, Akom North |
192 | 14.25% | Hess | GEPetrol |
| Gabon | |||||
| Arouwe1 | 4,414 | 35.00% | Perenco | ExxonMobil | |
| Avouma | Avouma, South Tchibala |
52 | 7.50% | Vaalco | Addax (Sinopec), Sasol, PetroEnergy |
| Ebouri | Ebouri | 15 | 7.50% | Vaalco | Addax (Sinopec), Sasol, PetroEnergy |
| Echira | Echira | 76 | 40.00% | Perenco | |
| Etame | Etame, North Tchibala | 49 | 7.50% | Vaalco | Addax (Sinopec), Sasol, PetroEnergy |
| Ezanga | 5,626 | 7.50% | Maurel & Prom | ||
| Gwedidi | Gwedidi | 5 | 7.50% | Maurel & Prom Gov of Gabon | |
| Igongo | Igongo | 117 | 36.00% | Perenco | Total, Gov of Gabon |
| Limande | Limande | 54 | 40.00% | Perenco | |
| Mabounda | Mabounda | 6 | 7.50% | Maurel & Prom Gov of Gabon | |
| Maroc | Maroc | 17 | 7.50% | Maurel & Prom Gov of Gabon | |
| Maroc Nord | Maroc Nord | 17 | 7.50% | Maurel & Prom Gov of Gabon | |
| Mbigou | Mbigou | 5 | 7.50% | Maurel & Prom Gov of Gabon | |
| M'Oba | M'Oba | 57 | 24.31% | Perenco | |
| Niembi | Niembi | 4 | 7.50% | Maurel & Prom Gov of Gabon | |
| Niungo | Niungo | 96 | 40.00% | Perenco | |
| Oba | Oba | 44 | 5.00% | Perenco | AIC Petrofi |
| Omko | Omko | 16 | 7.50% | Maurel & Prom Gov of Gabon | |
| Onal | Onal | 46 | 7.50% | Maurel & Prom Gov of Gabon | |
| Tchatamba Marin | Tchatamba Marin | 30 | 25.00% | Perenco | Oranje Nassau |
| Tchatamba South | Tchatamba South | 40 | 25.00% | Perenco | Oranje Nassau |
| Tchatamba West | Tchatamba West | 25 | 25.00% | Perenco | Oranje Nassau |
| Turnix | Turnix | 18 | 27.50% | Perenco | |
| Back-In Rights2 | |||||
| Dussafu Marin | 2,780 | 5.00% | Harvest Natural Res 3 |
Pan-Petroleum 3 | |
| Etame Marin | 2,972 | 7.50% | Vaalco | Addax (Sinopec), Sasol, PetroEnergy |
|
| Ghana | |||||
| Deepwater Tano | Wawa | 558 | 49.95% | Tullow | Kosmos, Anadarko, GNPC, Petro SA |
| Ten Development Area 4 | Tweneboa, Enyenra, Ntomme |
47.18% 4 | |||
| West Cape Three Points | Jubilee | 412 | 26.40% | Kosmos | Anadarko, GNPC, Petro SA |
| Jubilee Field Unit Area 5 | Jubilee | 110 | 35.48% | Tullow | Kosmos, Anadarko, GNPC, Petro SA |
Notes:
Tullow has 'Back-In Rights' on this licence as well as a working interest.
Back-In Rights: Tullow has the option, in the event of a development, to acquire varying interests in these licences where there is a Back-In Right.
Harvest Natural Res have agree to sell its equity in Dussafu Marin to BW Energy; Pan-Petroleum have also agreed to farm-out 25% of its equity leaving them with 8.33%; both deals are subject to Government approval.
GNPC has exercised its right to acquire an additional 5% in the TEN Field. Tullow's interest is 47.175%.
A unitisation agreement covering the Jubilee field was agreed by the partners of the West Cape Three Points and the Deepwater Tano licences.
| Area | Tullow | |||||
|---|---|---|---|---|---|---|
| Licence | Blocks | Fields | sq km | Interest | Operator | Other Partners |
| Netherlands | ||||||
| E10 | 401 | 30.00% | ENGIE | EBN | ||
| E11 | 401 | 30.00% | ENGIE | EBN | ||
| E14 | 403 | 30.00% | ENGIE | EBN | ||
| E15a | F16-E7 | 39 | 4.69% | Wintershall | Dana, ENGIE, EBN | |
| E15b | E18-A7 | 21 | 21.12% | Wintershall | Dana, EBN | |
| E15c | 285 | 20.00% | ENGIE | EBN, Gas Plus | ||
| E18a | E18-A7, F16-E7 | 76 | 17.60% | Wintershall | Dana, EBN | |
| F13a | F16-E7 | 4 | 4.69% | Wintershall | Dana, ENGIE, EBN | |
| J9 | 18 | 9.95% | NAM | Oranje Nassau, Wintershall, EBN |
||
| K8 | 820 | 22.50% | NAM | Oranje Nassau, Wintershall, EBN |
||
| K11 | 18.00% | |||||
| L13 | 413 | 22.50% | NAM | Oranje Nassau, Wintershall, EBN, |
||
| Joint Development Area (JDA)8 J9, K7, K8, K11, K14a, K15, L13 |
31 fields | 9.95% | NAM | Oranje Nassau, Wintershall, EBN |
||
| United Kingdom | ||||||
| CMS Area | ||||||
| P450 | 44/21a | Boulton B & F | 77 | 9.50% | ConocoPhillips | ENGIE |
| P451 | 44/22a | Murdoch | 89 | 34.00% | ConocoPhillips | ENGIE |
| 44/22b | Boulton H 9 | |||||
| P452 | 44/23a (part) | Murdoch K 9 | 48 | 6.91% | ConocoPhillips | ENGIE |
| P453 | 44/28b | Ketch | 85 | 40.00% | Faroe Petr | |
| P516 | 44/26a | Schooner 10 | 99 | 42.96% | Faroe Petr | |
| P1006 | 44/17b | Munro 11 | 48 | 20.00% | ConocoPhillips | ENGIE |
| P1058 | 44/18b | 46 | 22.50% | ConocoPhillips | ENGIE | |
| 44/23b | Kelvin 12 | |||||
| P1139 | 44/19b | Katy (formerly Harrison) 13 |
30 | 22.50% | ConocoPhillips | ENGIE |
| CMS III Unit14 | 44/17a (part) 44/17c (part) 44/21a (part) 44/22a (part) 44/22b (part) 44/22c (part) 44/23a (part) |
Boulton H, Hawksley 13 McAdam 13, Murdoch K |
14.10% | ConocoPhillips | ENGIE | |
| Munro Unit14 | 44/17b 44/17a |
Munro | 15.00% | ConocoPhillips | ENGIE | |
| Schooner Unit14 44/26a | 43/30a | Schooner | 40.00% | Faroe Petr | ||
| Thames Area | ||||||
| P007 | 49/24aF1 (Gawain) |
Gawain 15, 16 | 69 | 50.00% | Perenco | |
| P037 | 49/28a 49/28b |
Thames16, Yare16, Bure16, Deben16, Wensum16 |
90 | 66.67% | Perenco | Centrica |
| 49/28a (part) | Thurne16 | |||||
| P039 | 53/04d | Wissey16 | 29 | 76.90% | Tullow | Faroe Petr. |
| P105 | 49/29a (part) | Gawain 15, 16 | 17 | 50.00% | Perenco | |
| P786 | 53/03c | Horne16 | 8 | 50.00% | Tullow | Centrica |
| P852 | 53/04b | Horne & Wren16 | 17 | 50.00% | Tullow | Centrica |
| Gawain Unit14 | 49/24F1 (Gawain) Gawain16 49/29a (part) |
50.00% | Perenco |
| Area | Tullow | Other Partners | ||
|---|---|---|---|---|
| Africa Oil, Maersk | ||||
| Africa Oil, Maersk | ||||
| Africa Oil, Delonex | ||||
| Africa Oil, Maersk | ||||
| Jobi East, Mpyo | 372 | CNOOC | ||
| Lyec | 85 | CNOOC | ||
| 710 | CNOOC, Total | |||
| Kingfisher | 344 | Total | ||
| Kasamene - | 20 | CNOOC, Total | ||
| Kigogole - Ngara | 92 | CNOOC, Total | ||
| Nsoga | 60 | CNOOC, Total | ||
| Ngege | 57 | CNOOC, Total | ||
| Mputa - Nzizi - Waraga |
86 | CNOOC, Total | ||
| Ngiri | 50 | CNOOC | ||
| Jobi - Rii | 121 | CNOOC | ||
| Gunya | 55 | CNOOC | ||
| Fields Wahrindi |
sq km 15,811 6,172 15,390 6,200 4,719 |
Interest 50.00% 50.00% 40.00% 100.00% 50.00% |
Operator Tullow Tullow Tullow Tullow Tullow 33.33% 17 Total 33.33% 17 Total 33.33% 17 Tullow 17 33.33% 17 CNOOC 33.33% 17 Tullow 17 33.33% 17 Tullow 17 33.33% 17 Tullow 17 33.33% 17 Tullow 17 33.33% 17 Tullow 17 33.33% 17 Total 33.33% 17 Total 33.33% 17 Total |
Notes:
Exploration & production operations in the Netherlands and production in the UK are dealt with by the West Africa BDT despite falling outside this geographic region.
These fields are unitised – interests are as follows: F16-E 4.147%; E18-A 18.357%.
Interests in blocks K7, K8, K11, K14a, K15 and L13 have been unitised. These six blocks, along with J9, are known as the Joint Development Area (JDA).
Refer to CMS III Unit for field interest.
Refer to Schooner Unit for field interest.
This field is no longer producing.
For the UK offshore area, fields that extend across more than one licence area with differing partner interests become part of a unitised area. The interest held in the Unitised Field Area is split amongst the holders of the relevant licences according to their proportional ownership of the field. The unitised areas in which Tullow is involved are listed in addition to the nominal licence holdings.
Refer to Gawain Unit for field interest.
These fields are no longer producing. Abandonment works are ongoing.
Tullow has agreed a farm-down with Total whereby it will reduce it's holding to 11.76% and transfer operatorship to Total. The deal is subject to Government approval.
| Licence | Blocks | Fields | Area sq km |
Tullow Interest |
Operator | Other Partners |
|---|---|---|---|---|---|---|
| Guyana | ||||||
| Kanuku | 6,525 | 30.00% | Repsol | |||
| Orinduik | 1,776 | 60.00% | Tullow | Eco O&G | ||
| Jamaica | ||||||
| Walton Morant | 32,065 | 100.00% | Tullow | |||
| Mauritania | ||||||
| Block C-3 | 9,825 | 90.00% | Tullow | SMH | ||
| Block C-10 | 8,025 | 76.50% | Tullow | SMH, Sterling | ||
| Block C-18 | 13,225 | 90.00% | Tullow | SMH | ||
| PSC B | Chinguetti | 31 | 22.26% | Petronas | SMH, Premier, Kufpec | |
| (Chinguetti EEA) 18 | ||||||
| Namibia | ||||||
| PEL 0030 | 2012A | 5,800 | 25.00% | Eco O&G | AziNam, NAMCOR | |
| PEL 0037 | 2112A,B, 2113B | 17,295 | 65.00% | Tullow | Pancontinental, Paragon | |
| Norway 19 | ||||||
| North Sea | ||||||
| PL 636 | 36/7 | 455 | 20.00% | ENGIE | Idemitsu, Wellesley Petr | |
| PL 746S | 29/3 | 55 | 30.00% | Point Res | Concedo | |
| PL 774 | 16/7 | 114 | 40.00% | Tullow | Concedo, Petrolia | |
| PL 774B | 16/10 | 22 | 40.00% | Tullow | Concedo, Petrolia | |
| PL 776 | 16/5, 16/6, 16/8, 16/9 |
665 | 40.00% | Tullow | Concedo, Petoro, Wintershall | |
| PL 786 | 31/3, 32/1, 35/12, 36/10 |
732 | 50.00% | ENGIE | ||
| PL 826 | 29/3, 30/1, 33/12 | 15 | 30.00% | Point Res | Concedo | |
| Norwegian Sea | ||||||
| PL 651 | 6610/8, 6610/9, 6610/11, 6610/12 |
1,338 | 60.00% | AkerBP | ||
| PL 689 | 6306/3 | 457 | 20.00% | DONG | AkerBP, Bayerngas | |
| PL 689B | 6307/1, 6307/4 | 128 | 20.00% | DONG | AkerBP, Bayerngas | |
| PL 750 | 6405/4, 6405/7, 6405/10 |
1,043 | 60.00% | Tullow | Repsol | |
| PL 750B | 6404/9, 6404/12, 6405/10 |
732 | 60.00% | Tullow | Repsol | |
| PL 791 | 6203/7, 6203/8, 6203/9, 6203/10, 6203/11, 6203/12, 6204/10 |
1,302 | 50.00% | Point Res |
| Licence | Blocks | Area sq km |
Tullow Interest |
Operator | Other Partners |
|---|---|---|---|---|---|
| Pakistan | |||||
| Bannu West | 1,230 | 20.00% 20 Tullow | OGDCL, MPCL, SEL | ||
| Block 28 | 6,200 | 95.00% | OGDCL | ||
| Kalchas | 2,068 | 30.00% | OGDCL | MPCL | |
| Kohat | 1,107 | 40.00% | OGDCL | MPCL, SEL | |
| Kohlu | 2,459 | 30.00% | OGDCL | MPCL | |
| Suriname | |||||
| Block 47 | 2,369 | 100.00% | Tullow | ||
| Block 54 | 8,480 | 30.00% | Tullow | Statoil, Noble Energy | |
| Uruguay | |||||
| Block 15 | 8,030 | 35.00% | Tullow | Statoil, Inpex | |
| Zambia | 52,937 | 100.00% | Tullow | ||
| PEL 28 | Block 31 |
PSC B (Chinguetti EEA) is dealt with by the West Africa BDT.
Tullow is in the process of divesting its Norwegian business. The sale of all remaining assets should be completed by April 2017.
Tullow's interest on completion of farm-down to MPCL.
| West Africa | East Africa | New Ventures | TOTAL | ||||||
|---|---|---|---|---|---|---|---|---|---|
| Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas bcf |
Oil mmbbl |
Gas bcf |
Petroleum mmboe |
|
| Commercial reserves | |||||||||
| 1 January 2016 | 287.6 | 205.8 | – | – | – | – | 287.6 | 205.8 | 321.8 |
| Revisions | 13.8 | (0.2) | – | – | – | – | 13.8 | (0.2) | 13.8 |
| Transfer from contingent resources | (7.4) | – | – | – | – | – | (7.4) | – | (7.4) |
| Disposals | – | – | – | – | – | – | – | – | – |
| Production | (21.9) | (15.9) | – | – | – | – | (21.9) | (15.9) | (24.5) |
| 31 December 2016 | 272.1 | 189.7 | – | – | – | – | 272.1 | 189.7 | 303.7 |
| Contingent resources | |||||||||
| 1 January 2016 | 115.8 | 724.9 | 628.8 | 42.6 | 101.5 | 4.2 | 846.1 | 771.7 | 974.7 |
| Revisions | 4.8 | 5.6 | 3.7 | – | – | – | 8.5 | 5.6 | 9.5 |
| Additions | – | – | – | – | – | – | – | – | – |
| Disposals | – | – | – | – | (101.5) | – | (101.5) | – | (101.5) |
| Transfers to commercial reserves | 7.4 | – | – | – | – | – | 7.4 | – | 7.4 |
| 31 December 2016 | 128.0 | 730.5 | 632.5 | 42.6 | 0.0 | 4.2 | 760.6 | 777.3 | 890.1 |
| Total | |||||||||
| 31 December 2016 | 400.1 | 920.2 | 632.5 | 42.6 | 0.0 | 4.2 | 1,032.7 | 967.0 | 1,193.8 |
Proven and Probable Commercial Reserves are as audited by an independent engineer. Reserves estimates for each field are reviewed by the independent engineer based on significant new data or a material change with a review of each field undertaken at least every two years, with the exception of minor assets contributing less than 5% of the Group's reserves.
Proven and Probable Contingent Resources are as audited by an independent engineer. Resources estimates are reviewed by the independent engineer based on significant new data received following exploration or appraisal drilling.
The West Africa revisions to reserves relate to Jubilee, Tchatamba, Ezanga, Espoir, M'Oba, and an equity revision for certain Gabonese fields.
The West Africa transfers relate to the Etame and MBoundi fields which were transferred to Contingent Resources.
The West Africa revision to gas contingent resources relates to the relinquishment of the Pelican field in Mauritania.
New Venture disposals to contingent resources relate to the Norway country exit and Zaedyus licence relinquishment.
The Group provides for depletion and amortisation of tangible fixed assets on a net entitlements basis, which reflects the terms of the Production Sharing Contracts related to each field. Total net entitlement reserves were 283.2 mmboe at 31 December 2016 (31 December 2015: 299.1 mmboe).
Contingent Resources relate to resources in respect of which development plans are in the course of preparation or further evaluation is under way with a view to future development.
Transparency disclosure The Reports on Payments to Governments Regulations (UK Regulations) came into force on 1 December 2014 and require UK companies in the extractive sector to publicly disclose payments made to governments in the countries where they undertake extractive operations. The regulations implement Chapter 10 of EU Accounting Directive (2013/34/ EU).
The UK Regulations came into effect on 1 January 2015, but Tullow were early adopters of the EU Directive and have published our tax payments to governments in full, in our Annual Report and Accounts since 2013. The 2016 disclosure remains in line with the EU Directive and UK Regulations and we have provided additional voluntary disclosure on VAT, stamp duty, withholding tax, PAYE and other taxes.
The payments disclosed are based on where the obligation for the payment arose: payments raised at a project level have been disclosed at project level and payments raised at a corporate level have been disclosed on that basis. However, where a payment or a series of related payments do not exceed £86,000, they are disclosed at a corporate level, in accordance with the UK Regulations. The voluntary disclosure has been prepared on a corporate level.
All of the payments disclosed in accordance with the Directive have been made to National Governments, either directly or through a Ministry or Department of the National Government, with the exception of Ghana payments in respect of production entitlements and licence fees, which are paid to the Ghana National Oil Company. Our total economic contribution to all stakeholders can be found on page 51. Detailed disclosure on our 2016 tax payments can be found on page 56.
Production entitlements in barrels – includes non-cash royalties and state non-participating interest paid in barrels of oil or gas out of Tullow's working interest share of production in a licence. The figures disclosed are produced on an entitlement basis rather than a liftings basis. It does not include the Government's or NOC's working interest share of production in a licence. Production entitlements have been multiplied by the Group's 2016 average realised oil price \$61.4/bbl.
Income taxes – represent cash tax calculated on the basis of profits including income or capital gains. Income taxes are usually reflected in corporate income tax returns. The cash payment of income taxes occurs in the year in which the tax has arisen or up to one year later. Income taxes also include any cash tax rebates received from the government or revenue authority during the year. Income taxes do not include fines and penalties.
Royalties – represent cash royalties paid to governments during the year for the extraction of oil or gas. The terms of the royalties are described within our PSCs and can vary from project to project within one country. Royalties paid in kind have been recognised within the production entitlements category. The cash payment of royalties occurs in the year in which the tax has arisen.
Bonus payments – represent any bonus paid to governments during the year, usually as a result of achieving certain milestones, such as a signature bonus, POD bonus or a production bonus.
Licence fees – represent licence fees, rental fees, entry fees and other consideration for licences and/or concessions paid for access to an area during the year (with the exception of signature bonuses which are captured within bonus payments).
Infrastructure improvement payments – represent payments made in respect of infrastructure improvements for projects that are not directly related to oil and gas activities during the year. This can be a contractually obligated payment in a PSC or a discretionary payment for building/improving local infrastructure such as roads, bridges, ports, schools and hospitals.
VAT – represents net cash VAT received from/paid to governments during the year. The amount disclosed is equal to the VAT return submitted by Tullow to governments with the cash payment made in the year the charge is borne. It should be noted the operator of a joint venture typically makes VAT payments in respect of the joint venture as a whole and, as such, where Tullow has a non-operated presence in a country limited VAT will be paid.
Stamp duty –includes taxes that are placed on legal documents usually in the transfer of assets or capital. Usually these taxes are reflected in stamp duty returns made to governments and are paid shortly after capital or assets are transferred.
Withholding tax (WHT) – represent tax charged on services, interest, dividends or other distributions of profits. The amount disclosed is equal to the WHT return submitted by Tullow to governments with the cash payment made in the year the charge is borne. It should be noted the operator of a joint venture typically makes WHT payments in respect of the joint venture as a whole and, as such, where Tullow has a non-operated presence in a country limited WHT will be paid.
PAYE and national insurance – represent payroll and employer taxes paid (such as PAYE and national insurance) by Tullow as a direct employer. The amount disclosed is equal to the return submitted by Tullow to governments with the cash payment made in the year the charge is borne.
Carried interests – comprise payments made under a carrying agreement or PSC/PSA by Tullow for the cash settlement of costs owed by a government or national oil company for their equity interest in a licence.
Customs duties – represent cash payments made in respect of customs/excise/import and export duties made during the year including items such as railway levies. These payments typically arise through the import/transportation of goods into a country with the cash payment made in the year the charge is borne.
Training allowances – comprise payments made in respect of training government or national oil company staff. This can be in the form of mandatory contractual requirements or discretionary training provided by a company.
European transparency directive disclosure
| 2016 | Production entitlements |
Production entitlements |
Income taxes |
Royalties (cash only) |
Dividends | Bonus payments |
Licence fees |
Infrastructure improvement payments |
|---|---|---|---|---|---|---|---|---|
| Licence/Company level | BBL000 | \$000 | \$000 | \$000 | \$000 | \$000 | \$000 | \$000 |
| M'Boundi | 167 | – | – | – | – | – | – | – |
| Total Congo | 167 | – | – | – | – | – | – | – |
| CI-26 Espoir | – | 2,277 | – | – | – | – | – | – |
| Corporate | – | – | – | – | – | – | – | – |
| Total Côte d'Ivoire | – | 2,277 | - | – | – | – | – | – |
| Ceiba | 109 | – | – | – | – | – | – | – |
| Okume Complex | 366 | – | – | – | – | – | – | – |
| Corporate | – | – | 8,982 | – | – | – | – | – |
| Total Equatorial Guinea | 475 | - | 8,982 | – | – | – | – | – |
| Echira | – | – | – | 1,194 | – | – | – | – |
| Etame | – | – | – | 1,618 | – | – | – | – |
| Ezanga | – | – | – | 2,176 | – | – | – | – |
| Limande | – | – | – | 2,285 | – | – | – | – |
| M'Oba | – | – | – | 61 | – | – | – | – |
| Niungo | – | – | – | 2,085 | – | – | – | – |
| Tchatamba | – | – | – | 6,927 | – | – | – | – |
| Turnix | – | – | – | 1,012 | – | – | – | – |
| Corporate - Tullow Oil Gabon SA | – | – | – | 217 | – | 30,000 | – | – |
| Oba | – | – | – | 770 | – | – | – | – |
| Corporate - Tulipe Oil SA | – | – | – | – | – | – | – | – |
| Total Gabon | - | - | - | 18,345 | - | 30,000 | – | – |
| Jubilee | 478 | – | – | – | – | – | – | 348 |
| TEN | 125 | – | – | – | – | – | – | 193 |
| Company level | – | – | 27,314 | – | – | – | 75 | 2,981 |
| Total Ghana | 603 | – | 27,314 | – | – | – | 75 | 3,522 |
| Company level | – | – | – | – | – | – | 28 | 119 |
| Total Guinea | – | – | – | – | – | – | 28 | 119 |
| PSC B (Chinguetti EEA) | 39 | – | – | – | – | – | 258 | – |
| Corporate | – | – | – | – | – | – | 94 | – |
| Total Mauritania | 39 | – | – | – | – | 352 | – | |
| South Omo | – | – | – | – | – | – | 441 | 169 |
| Corporate | – | – | – | – | – | – | – | – |
| Total Ethiopia | – | – | - | – | – | – | 441 | 169 |
| Corporate | – | 9 | – | – | – | 614 | – | |
| Total Kenya | – | – | 9 | – | – | – | 614 | – |
| Voluntary disclosure | ||||||||
|---|---|---|---|---|---|---|---|---|
| VAT | Stamp duty | Withholding tax |
PAYE and national insurance |
Carried interests |
Customs duties |
Training allowances |
Total | Total |
| \$000 | \$000 | \$000 | \$000 | \$000 | \$000 | \$000 | \$000 | BBL000 |
| – | – | – | – | – | – | – | – 167 |
|
| – | – | – | – | – | – | – | – 167 |
|
| – | – | – | – | – | – | – | 2,277 | – |
| - | - | – | 19 | - | – | – | 19 – |
|
| - | - | – | 19 | - | – | – | 2,296 | – |
| – | – | – | – | – | – | – | – 109 |
|
| – | – | – | – | – | – | – | – 366 |
|
| – | – | – | – | – | – | – | 8,982 | – |
| – | – | – | – | – | – | – | 8,982 | 475 |
| – | – | – | – | – | – | – | 1,194 | – |
| – | – | – | – | – | – | – | 1,618 | – |
| – | – | – | – | – | – | – | 2,176 | – |
| – | – | – | – | – | – | – | 2,285 | – |
| – | – | – | – | – | – | – | 61 – |
|
| – | – | – | – | – | – | – | 2,085 | – |
| – | – | – | – | – | – | – | 6,927 | – |
| – | – | – | – | – | – | – | 1,012 | – |
| - | - | 52 | 402 | – | – | – | 30,671 | – |
| – | – | – | – | – | – | – | 770 | – |
| – | – | – | 3 | – | – | – | 3 – |
|
| – | – | 52 | 405 | – | – | – | 48,802 | – |
| – | – | – | – | – | – | – | 348 | 478 |
| – | – | – | – | – | – | – | 193 | 125 |
| 18,098 | – | 66,968 | 15,394 | 60,661 | 6,528 | 250 | 198,269 | – |
| 18,098 | – | 66,968 | 15,394 | 60,661 | 6,528 | 250 | 198,810 | 603 |
| – | – | – | – | – | – | – | 147 | – |
| – | – | – | – | – | – | – | 147 | – |
| – | – | – | – | – | – | – | 258 | 39 |
| – | – | 403 | 159 | – | – | 700 | 1,356 | – |
| – | – | 403 | 159 | – | – | 700 | 1,614 | 39 |
| – | – | – | – | – | – | – | 610 | – |
| (58) | – | 11 | 106 | – | – | 150 | 209 | – |
| (58) | – | 11 | 106 | – | – | 150 | 819 | – |
| 162 | – | 1,864 | 9,852 | – | 65 | 924 | 13,490 | – |
| 162 | – | 1,864 | 9,852 | – | 65 | 924 | 13,490 | – |
| Training | ||
|---|---|---|
| allowances | Total | Total |
| 2016 | Production entitlements |
Production entitlements |
Income taxes |
Royalties (cash only) |
Dividends | Bonus payments |
Licence fees |
Infrastructure improvement payments |
||
|---|---|---|---|---|---|---|---|---|---|---|
| Licence/Company level | BBL 000 | \$000 | \$000 | \$000 | \$000 | \$000 | \$000 | \$000 | ||
| Block 3111 | – | – | – | – | – | – | 150 | – | ||
| Corporate | – | – | – | – | – | – | – | – | ||
| Total Madagascar | – | – | – | – | – | – | 150 | – | ||
| Corporate | – | – | 1 | – | – | – | – | – | ||
| Total Mozambique | – | – | 1 | – | – | – | – | – | ||
| Company level | – | – | – | – | – | – | 105 | – | ||
| Total Namibia | – | – | – | – | – | – | 105 | – | ||
| Corporate | – | – | 31 | – | – | – | – | – | ||
| Total South Africa | – | – | 31 | – | – | – | – | – | ||
| Corporate | – | – | 36,059 | – | – | – | 158 | – | ||
| Total Uganda | – | – | 36,059 | – | – | – | 158 | – | ||
| Corporate | – | – | (1,129) | – | – | – | – | – | ||
| Total Ireland | – | – | (1,129) | – | – | – | – | – | ||
| Walton Morant | – | – | – | – | – | – | 133 | – | ||
| Corporate | – | – | – | – | – | – | – | – | ||
| Total Jamaica | – | – | – | – | – | – | 133 | – | ||
| Corporate | – | – | 8,215 | – | – | – | 303 | – | ||
| Total Netherlands | – | – | 8,215 | – | – | – | 303 | – | ||
| Corporate | – | – | (60,215) | – | – | – | 34 | – | ||
| Total Norway | – | – | (60,215) | – | – | – | 34 | – | ||
| Corporate | – | – | 54 | – | – | – | 14 | 14 | ||
| Total Pakistan | – | – | 54 | – | – | – | 14 | 14 | ||
| Corporate | – | – | – | – | – | – | – | – | ||
| Total Suriname | – | – | – | – | – | – | – | – | ||
| Schooner | – | – | – | – | – | – | 448 | – | ||
| Corporate | – | – | 51,126 | – | – | – | 1,024 | – | ||
| Total UK | – | – | 51,126 | – | – | – | 1,472 | – | ||
| Corporate | – | – | – | – | – | – | – | – | ||
| Total Uruguay | – | – | – | – | – | – | – | – | ||
| Total | 1,284 | 2,277 | 70,447 | 18,345 | – | 30,000 | 3,879 | 3,824 | ||
| Voluntary disclosure | ||||||||
|---|---|---|---|---|---|---|---|---|
| VAT | Stamp duty | Withholding tax |
PAYE and national insurance |
Carried interests |
Customs duties |
Training allowances |
Total | Total |
| \$000 | \$000 | \$000 | \$000 | \$000 | \$000 | \$000 | \$000 | BBL'000 |
| – | – | – | – | – | – | – | 150 | – |
| – | – | – | 2 | – | – | – | 2 | – |
| – | – | – | 2 | – | – | – | 152 | – |
| – | – | – | – | – | – | – | 1 | – |
| – | – | – | - | – | – | – | 1 | – |
| – | – | – | 3 | – | – | 34 | 142 | – |
| – | – | – | 3 | – | – | 34 | 142 | – |
| (267) | – | – | 2,073 | – | – | – | 1,837 | – |
| (267) | – | – | 2,073 | – | – | – | 1,837 | – |
| – | – | 2,590 | 3,728 | – | – | 228 | 42,763 | – |
| – | – | 2,590 | 3,728 | – | – | 228 | 42,763 | – |
| (1,483) | – | – | 4,840 | – | – | – | 2,228 | – |
| (1,483) | – | – | 4,840 | – | – | – | 2,228 | – |
| – | – | – | – | – | – | – | 133 | – |
| – | – | – | – | – | – | 104 | 104 | – |
| – | – | – | – | – | – | 104 | 237 | – |
| 433 | – | – | – | – | – | – | 8,951 | – |
| 433 | – | – | – | – | – | – | 8,951 | – |
| (2,926) | – | – | 5,633 | – | 7 | – | (57,467) | – |
| (2,926) | – | – | 5,633 | – | 7 | – | (57,467) | – |
| – | – | 121 | – | – | – | 53 | 256 | – |
| – | – | 121 | – | – | – | 53 | 256 | – |
| – | – | – | 152 | – | – | 194 | 346 | – |
| – | – | – | 152 | – | – | 194 | 346 | – |
| – | – | – | – | – | – | – | 448 | – |
| (16,216) | – | – | 47,776 | – | 15 | – | 83,725 | – |
| (16,216) | – | – | 47,776 | – | 15 | – | 84,173 | – |
| – | – | – | 280 | – | – | 100 | 380 | – |
| – | – | – | 280 | – | – | 100 | 380 | – |
| (2,257) | – | 72,009 | 90,422 | 60,661 | 6,615 | 2,737 | 358,959 | 1,284 |
| Payments in kind in \$000 | 78,919 |
Total 437,878
| 2012 | 2013 | 2014 | 2015 | 2016 | |
|---|---|---|---|---|---|
| Atmospherics | |||||
| Total air emissions (tonnes of CO2e) | 537,040 | 693,170 | 803,724 | 758,790 | 772,110 |
| Scope 1 total air emissions (tonnes of CO2e) | 686,996 | 799,551 | 752,539 | 754,338 | |
| Scope 2 total air emissions (tonnes of CO2e) | 6,174 | 4,173 | 4,631 | 4,763 | |
| Scope 3 total air emissions (tonnes of CO2e) | 1,620 | 13,010 | |||
| Total air emissions by production (tonnes of CO2e) per thousand tonnes hydrocarbon |
|||||
| produced | 98.21 | 99.78 | 123.84 | 122.07 | 142.11 |
| CH4 emissions (tonnes) | 1,931 | 2,578 | 2,191 | 2,073 | 2,741 |
| N2O emissions (tonnes) | 33.76 | 43.75 | 41.84 | 29.85 | 21.98 |
| CO2 emissions (tonnes) per thousand tonnes of HC produced |
85 | 85 | 106 | 106 | 122 |
| Flaring | |||||
| Total hydrocarbon flared (tonnes) | 30,246 | 80,695 | 117,516 | 110,638 | 149,217 |
| Total Hydrocarbon flared by production (tonnes per thousand tonnes hydrocarbon produced) |
5.53 | 11.62 | 18.11 | 17.84 | 27.93 |
| Water usage | |||||
| Metered water (m3) | 13,013 | 59,220 | 70,466 | 56,728 | |
| Seawater (m3) | 11,430,092 | 7,295,571 | 9,885,133 | 8,004,940 | 9,080,888 |
| Ground water (m3) | 143,569 | 180,337 | 129,956 | 113,847 | 46,322 |
| Fresh water (m3) | 42,342 | 35,900 | 11,695 | - | - |
| Other water (m3) | 58,291 | 31,740 | 3,643 | 10 | - |
| Total water usage (m3) - all operational sites | 11,674,294 | 7,556,562 | 10,089,647 | 8,189,263 | 9,183,938 |
| Recycled water (m3) | 21,567 | 11,250 | 5,451 | 4,722 | |
| Total water from sustainable sources (m3) | 21,567 | 11,250 | 5,451 | 4,722 | |
| Waste | |||||
| Total Waste disposed (tonnes) | 54,692 | 34,157 | 75,799 | 72,380 | 58,554 |
| Waste Recycled / Re-used / Treated (%) | 72.15 | 83.38 | 63.82 | 70.93 | 27.95 |
| Hazardous waste Recycled / Re-used / Treated (%) |
87.00 | 97.85 | 99.49 | 74.36 | |
| Non-hazardous waste Recycled / Re-used / Treated (%) |
51.75 | 3.68 | 3.44 | 15.01 | |
| Uncontrolled releases | |||||
| Oil & Chemical spills (#) | 5 | 10 | 15 | 7 | 2 |
| Oil & Chemical spills (tonnes) | 38.86 | 23.29 | 715.85 | 24.71 | 4.85 |
| Energy use | |||||
| Total operations indirect and direct energy use (GJ) |
5,757,479 | 5,345,475 | 5,104,423 | 7,272,710 | |
| Total indirect and direct energy use (GJ) | 5,685,961 | 5,798,539 | 5,375,436 | 5,158,200 | 7,318,373 |
| Total indirect and direct energy use by production (GL per thousand tonnes hydrocarbon produced) |
1,040 | 829 | 828 | 832 | 1,370 |
| Fines and sanctions | 0 | - | 80,000 | - | - |
| 2012 | 2013 | 2014 | 2015 | 2016 | |
|---|---|---|---|---|---|
| Hours worked (million) | 18.6 | 21.1 | 22.4 | 13.3 | 9.2 |
| Number of employee fatalities | – | – | – | – | – |
| Number of contractor fatalities | – | – | – | – | – |
| Number of third party fatalities involving members of the public |
2 | 1 | 1 | – | – |
| Lost Time Injuries (LTIs) | 13 | 17 | 13 | 4 | – |
| Lost Time Injuries Frequency Rate (LTIF) | 0.70 | 0.81 | 0.58 | 0.30 | – |
| OGP LTIF | 0.48 | 0.45 | 0.36 | 0.29 | n/a |
| Total Recordable Injuries (TRI) | 42 | 67 | 41 | 12 | 9 |
| Total Recordable Injuries Frequency Rate (TRIF) |
2.26 | 3.18 | 1.83 | 0.90 | 0.98 |
| OGP TRIF | 1.74 | 1.60 | 1.54 | 1.21 | n/a |
| High Potential Incidents (HiPos) | 44 | 39 | 25 | 15 | 8 |
| High Potential Incident Frequency Rate (HiPoF) |
2.37 | 1.85 | 1.11 | 1.13 | 0.87 |
| Malaria frequency rate | 0.06 | 0.01 | 0.03 | 0.30 | – |
| Kilometres driven ('000,000) | 12.2 | 12.7 | 15.5 | 6.5 | 5.4 |
| Vehicle Accident Frequency Rate (VAFR) | 1.31 | 0.71 | 0.77 | 0.47 | 0.55 |
| LOCAL CONTENT | |||||
| 2012 | 2013 | 2014 | 2015 | 2016 | |
| Local supplier spend (\$ million) | 145.4 | 217.0 | 225.4 | 308.9 | 336.6 |
| By Country | 2012 | 2013 | 2014 | 2015 | 2016 |
| Ethiopia | – | 14.4 | – | – | – |
| Ghana | 69.2 | 128.0 | 123.6 | 226.0 | 297.0 |
| Kenya | 28.7 | 48.0 | 81.5 | 75.0 | 28.0 |
| Mauritania | – | 7.0 | – | – | – |
| Uganda | 47.5 | 19.6 | 20.3 | 7.9 | 11.6 |
| Total | 145.4 | 217.0 | 225.4 | 308.9 | 336.6 |
| 2014 | 2015 | 2016 | |
|---|---|---|---|
| Corruption | 14 | 17 | 5 |
| Fraud | 10 | 22 | 19 |
| HR | 35 | 47 | 46 |
| Supply chain | 9 | 17 | 21 |
| Total speaking up cases | 68 | 103 | 91 |
| 2012 | 2013 | 2014 | 2015 | 2016 | |
|---|---|---|---|---|---|
| Number of employees | 1,415 | 1,553 | 1,595 | 1,156 | 1,023 |
| Number of contractors | 363 | 481 | 447 | 247 | 129 |
| Number of expatriates in the workforce | 347 | 446 | 448 | 268 | 173 |
| Number of people on local contract terms | 1,431 | 1,588 | 1,594 | 1,135 | 979 |
| Total workforce | 1,778 | 2,034 | 2,042 | 1,403 | 1,152 |
| Number of females in the workforce | 511 | 582 | 583 | 396 | 336 |
| Number of female managers | 73 | 85 | 90 | 76 | 66 |
| Number of managers | 379 | 433 | 442 | 338 | 297 |
| Number of female senior managers | 6 | 4 | 14 | 9 | |
| Number of senior managers | 49 | 53 | 115 | 68 | |
| Number of female board members | 2 | 2 | 2 | 2 | |
| Number of board members | 12 | 12 | 12 | 11 |
AS AT 7 FEBRUARY 2016
| Company name | Country of incorporation | % of nominal value of shares held (all ordinary shares) |
Type of ownership |
|---|---|---|---|
| Hardman Oil and Gas Pty Ltd | Australia | 100% | Indirect |
| Hardman Resources Pty Ltd | Australia | 100% | Indirect |
| Tullow Chinguetti Production Pty Ltd | Australia | 100% | Indirect |
| Tullow Petroleum (Mauritania) Pty Ltd | Australia | 100% | Indirect |
| Tullow Uganda Operations Pty Ltd | Australia | 100% | Indirect |
| Tullow Do Brasil Petroleo E Gas Ltda | Brazil | 100% | Indirect |
| Eagle Drill Limited | British Virgin Islands | 50% | Indirect |
| Tullow (EA) Holdings Limited | British Virgin Islands | 100% | Indirect |
| Tullow Oil Canada Ltd | Canada | 100% | Indirect |
| Planet Oil International Limited | England & Wales | 100% | Indirect |
| Tullow Energy Limited | England & Wales | 100% | Direct |
| Tullow Greenland Exploration Limited | England & Wales | 100% | Indirect |
| Tullow Group Services Limited | England & Wales | 100% | Direct |
| Tullow Guinea Limited | England & Wales | 100% | Indirect |
| Tullow Jamaica Limited | England & Wales | 100% | Indirect |
| Tullow Mozambique Limited | England & Wales | 100% | Indirect |
| Tullow Oil (International) Norge Limited | England & Wales | 100% | Indirect |
| Tullow Oil 100 Limited | England & Wales | 100% | Direct |
| Tullow Oil 101 Limited | England & Wales | 100% | Direct |
| Tullow Oil Finance Limited | England & Wales | 100% | Direct |
| Tullow Oil SK Limited | England & Wales | 100% | Direct |
| Tullow Oil SNS Limited | England & Wales | 100% | Direct |
| Tullow Oil SPE Limited | England & Wales | 100% | Direct |
| Tullow Oil TS Limited | England & Wales | 100% | Direct |
| Tullow Uruguay Limited | England & Wales | 100% | Indirect |
| Hardman Petroleum France S.A.S. | France | 100% | Indirect |
| Tulipe Oil SA | Gabon | 50% | Indirect |
| Tullow Oil Gabon SA | Gabon | 100% | Indirect |
| Invest In Africa | Guernsey | 100% | Indirect |
| Tullow Oil (Mauritania) Ltd | Guernsey | 100% | Indirect |
| Tullow Oil Holdings (Guernsey) Ltd | Guernsey | 100% | Indirect |
| Tullow Oil Ltd | Ireland | 100% | Direct |
| Tullow Congo Limited | Isle of Man | 100% | Indirect |
| Tullow Equatorial Guinea Ltd | Isle of Man | 100% | Indirect |
| Tullow Gabon Holdings Limited | Isle of Man | 100% | Indirect |
| Tullow Gabon Limited | Isle of Man | 100% | Indirect |
| Tullow Mauritania Ltd | Isle of Man | 100% | Indirect |
| Tullow Namibia Ltd | Isle of Man | 100% | Indirect |
| Tullow Senegal Ltd | Isle of Man | 100% | Indirect |
| Tullow Uganda Ltd | Isle of Man | 100% | Indirect |
| Tullow Côte d'Ivoire Exploration Ltd | Jersey | 100% | Indirect |
| Tullow Côte d'Ivoire Ltd | Jersey | 100% | Indirect |
| Tullow Ghana Ltd | Jersey | 100% | Indirect |
| Tullow India Operations Ltd | Jersey | 100% | Indirect |
| Tullow Madagascar Ltd | Jersey | 100% | Indirect |
| Tullow Oil International Ltd | Jersey | 100% | Indirect |
| Tullow Pakistan (Developments) Ltd | Jersey | 100% | Indirect |
| Tullow 101 Netherlands B.V. | Netherlands | 100% | Indirect |
| Tullow Angola B.V. | Netherlands | 100% | Indirect |
| Tullow DRC B.V. | Netherlands | 100% | Indirect |
| Tullow Ethiopia B.V. | Netherlands | 100% | Indirect |
| Tullow Exploration & Production B.V. | Netherlands | 100% | Indirect |
| Tullow Exploration & Production Netherlands B.V. | Netherlands | 100% | Indirect |
| Tullow Global Compliance B.V. | Netherlands | 100% | Indirect |
| Tullow Guyana B.V. | Netherlands | 100% | Indirect |
| Company name | Country of incorporation | % of nominal value of shares held (all ordinary shares) |
Type of ownership |
|---|---|---|---|
| Tullow Hardman Holdings B.V. | Netherlands | 100% | Indirect |
| Tullow Kenya B.V. | Netherlands | 100% | Indirect |
| Tullow Liberia B.V. | Netherlands | 100% | Indirect |
| Tullow Mexico B.V. | Netherlands | 100% | Indirect |
| Tullow Netherlands Holding Cooperatief B.A. | Netherlands | 100% | Indirect |
| Tullow Overseas Holdings B.V. | Netherlands | 100% | Direct |
| Tullow Sierra Leone B.V. | Netherlands | 100% | Indirect |
| Tullow Suriname B.V. | Netherlands | 100% | Indirect |
| Tullow Tanzania B.V. | Netherlands | 100% | Indirect |
| Tullow Uganda Holdings B.V. | Netherlands | 100% | Indirect |
| Tullow Zambia B.V. | Netherlands | 100% | Indirect |
| Tullow Oil (Bream) Norge AS | Norway | 100% | Indirect |
| Tullow Oil Norge AS | Norway | 100% | Indirect |
| Tullow Exploration & Production UK Limited | Scotland | 100% | Indirect |
| Energy Africa Bredasdorp (Pty) Ltd | South Africa | 100% | Indirect |
| Tullow South Africa (Pty) Ltd | South Africa | 100% | Indirect |
| T.U. S.A. | Uruguay | 100% | Indirect |
Note 1. All holdings in the second from right column are of ordinary shares, and the proportion of the nominal value of shares held.
Note 2. The financial results and the financial position of all companies listed above are included in the Tullow Oil Plc consolidated accounts.
| AGM | Annual General Meeting |
|---|---|
| AFS | Available for sale |
| APP | African Partner Pool |
| ASOC | Advanced Security Operations Centre |
| bbl | Barrel |
| bcf | Billion cubic feet |
| BDT | Business Delivery Team |
| boe | Barrels of oil equivalent |
| boepd | Barrels of oil equivalent per day |
| bopd | Barrels of oil per day |
| ¢ | Cent |
| Capex | Capital expenditure |
| CISP | Cyber Information Sharing Partnership |
| CMS | Caister Murdoch System |
| CMS III | A group development of five satellite fields linked to CMS |
| CNOOC | China National Offshore Oil Corporation |
| CSA | Control self-assessment |
| CSO | Civil Society Organisations |
| CtO | Case to Operate |
| D&O | Development and Operations |
| DD&A | Depreciation, Depletion and Amortisation |
| DEFRA | Department for Environment, Food & Rural Affairs |
| DoA | Delegation of Authority |
| DSBP | Deferred Share Bonus Plan |
| E&A | Exploration and Appraisal |
| E&P | Exploration and Production |
| EBITDA | Earnings Before Interest, Tax, Depreciation and Amortisation |
| EBITDAX | Earnings Before Interest, Tax, Depreciation, Amortisation and Exploration |
| EHS | Environment, Health and Safety |
| EITI | Extractive Industries Transparency Initiative |
| EOPS | Early Oil Pilot Scheme |
| EPS | Earnings per share |
| EuroStoxx | A European market index |
| ESIA | Environmental Social Impact Assessment |
| ESOS | Executive Share Option Scheme |
| EWT | Extended Well Test |
| FEED | Front End Engineering and Design |
|---|---|
| FID | Final Investment Decision |
| FFD | Full Field Development |
| FPSO | Floating Production Storage and Offloading vessel |
| FRC | Financial Reporting Council |
| FRS | Financial Reporting Standard |
| FTSE 250 | Equity index consisting of the 101st to 350th largest UK listed companies by market capitalisation |
| FVTPL | Fair Value Through Profit or Loss |
| G&A | General and Administrative |
| G&H | Gifts and hospitality |
| GHG | Greenhouse gas |
| GJFFD | Greater Jubilee Full Field Development |
| GNPC | Ghana National Petroleum Corporation Group Company and its subsidiary undertakings |
| HIPO | High Potential Incident |
| HMRC | HM Revenue & Customs |
| IAS | International Accounting Standard |
| IASB | International Accounting Standards Board |
| IFRS | International Financial Reporting Standards |
| IIA | Invest in Africa |
| IMF | International Monetary Fund |
| IMS | Integrated Management System |
| IOC | International oil company |
| IR | Investor Relations |
| ITLOS | International Tribunal for the Law of the Sea |
| JDA | Joint Development Agreement |
| JV | Joint Venture |
| km KNPS |
Kilometres |
| KPI | Kenya National Police Service Key Performance Indicator |
| LIBOR | London Interbank Offered Rate |
| LTI | Lost Time Injury |
| LTIF | Frequency Rate measured in LTIs per million hours worked |
| mmbo | Million barrels of oil |
| mmboe | Million barrels of oil equivalent |
| mmscfd | Million standard cubic feet per day |
| MoU | Memorandum of Understanding |
| MSP | Major Simplification Project |
| MTM | Mark-to-Market |
| MVC | Motor vehicle collision |
| MVCF | Motor vehicle collision frequency |
| NGO | Non-Governmental Organisation |
|---|---|
| OPEC | Organisation of Petroleum Exporting Countries |
| Opex | Operating expenses |
| OSE | Organisation Strategy & Effectiveness |
| p | Pence |
| PAYE | Pay As You Earn |
| PEP | Politically exposed persons |
| PoD | Plan of Development |
| PP&E | Property, plant and equipment |
| PRT | Petroleum Revenue Tax |
| PSA | Production Sharing Agreement |
| PSC | Production Sharing Contract |
| PSP | Performance Share Plan |
| S&P 500 | Standard & Poor's 500, US stock market index based on market capitalisation |
| SC | Supply Chain |
| SCT | Supplementary Corporation Tax |
| SEENT | South East Etame North Tchibala |
| SID | Senior Independent Director |
| SIP | Share Incentive Plan |
| SOGA | Skills for oil and gas in Africa |
| SOP | Share Option Plan |
| Sq km | Square kilometres |
| SRI | Socially Responsible Investment |
| SSEA | Safety, Sustainability & External Affairs |
| TEN | Tweneboa – Enyenra – Ntomme |
| TIP | Tullow Incentive Plan |
| TGSS | Tullow Group Scholarship Scheme |
| TRP | Turret Remediation Project |
| TSR | Total Shareholder Return |
| TRI | Total recordable injuries |
| UK GAAP | UK Generally Accepted Accounting Practice |
| VAT | Value Added Tax |
| VP | Vice President |
| VPSHR | Voluntary Principles on Security and Human Rights |
| WAEP | Weighted Average Exercise Price |
| WHO | World Health Organization |
| Wildcat | Exploratory well drilled in land not known to be an oil field |
Our main corporate website has key information about our business, operations, investors, media, sustainability, careers and suppliers.
Financial results, events, corporate reports, webcasts and fact books are all stored in the Investor Relations section of our website: www.tullowoil.com/investors 2015
Tullow's online supplier form provides local and international companies the facility to register their interest to become a supplier: www.tullowoil.com/suppliers
All documents on the website are available to view without any particular software requirement other than the software which is available on the Group's website.
For every shareholder who signs up for electronic communications, a donation is made to the eTree initiative run by Woodland Trust. You can register for email communication at: www.etree.com/tullowoilplc
Tullow Oil plc 9 Chiswick Park 566 Chiswick High Road London W4 5XT United Kingdom
Tel: +44 20 3249 9000
Fax: +44 20 3249 8801
To contact any of Tullow's principal subsidiary undertakings, please find address details on www.tullowoil.com/contacts or send 'in care of' to Tullow's registered address.
This report is printed on mixed source paper which is FSC® certified (the standards for well-managed forests, considering environmental, social and economic issues).
Designed and produced by Design Portfolio
Printed by Pureprint Group
Tullow Oil plc 9 Chiswick Park 566 Chiswick High Road London W4 5XT United Kingdom
Tel: +44 20 3249 9000
Fax: +44 20 3249 8801
Email: [email protected]
Website: www.tullowoil.com
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