Annual Report • Dec 31, 2015
Annual Report
Open in ViewerOpens in native device viewer
Tullow Oil is a leading independent oil and gas exploration and production company. Our focus is on finding and monetising oil in Africa and the Atlantic Margins. Our key activities include targeted exploration and appraisal, selective development projects and growing our low-cost oil production base. We maintain access to diverse sources of funding for our activities and adopt a prudent hedging strategy to mitigate the oil price risk.
Our portfolio of over 120 licences spans 22 countries and is organised into three Business Delivery Teams. We are headquartered in London and our shares are listed on the London, Irish and Ghanaian 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. Our Corporate Responsibility Report is published concurrently, which gives greater detail on our sustainability performance and objectives. 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, our CR Report and additional information about Tullow Oil on our website www.tullowoil.com
Cover: Yaw D. N. Akyea, Technical Support on the Jubilee FPSO, Ghana
"As I look back on 2015, I am satisfied with where we ended the year. It was a challenging year, but we performed well. We did not hesitate to act as the oil price began to fall. We moved early and swiftly and we are ready to benefit from the recovery – when it comes."
Chief Executive Officer
Read the Chief Executive's review on page 8
1
2
3
| Overview of our operations | 4 |
|---|---|
| Chairman's statement | 6 |
| Chief Executive's review | 8 |
| Market review | 10 |
| Our business model | 12 |
| Creating value | 14 |
| Our strategy & performance | 16 |
| Special feature – On track | 22 |
| Operations Q&A and review | 34 |
| Finance & Portfolio Management | 42 |
| Responsible Operations | 46 |
| Governance & Risk Management | 48 |
| Principal risks | 55 |
| Organisation & Culture | 64 |
| Shared Prosperity | 66 |
| Directors' report | 70 |
|---|---|
| Audit Committee report | 79 |
| Nominations Committee report | 84 |
| EHS Committee report | 86 |
| Ethics & Compliance Committee report | 88 |
| Directors' remuneration report | 90 |
| Other statutory information | 107 |
| Statement of Directors' responsibilities | 114 |
|---|---|
| Independent auditor's report for the Group Financial Statements |
115 |
| Group Financial Statements | 120 |
| Company Financial Statements | 154 |
| Five year financial summary | 163 |
| Shareholder information | 164 |
|---|---|
| Licence interests | 165 |
| Commercial reserves and resources | 170 |
| Transparency disclosure | 171 |
| Subsidiaries | 176 |
| Glossary | 178 |
The West Africa Business Delivery Team focuses on Tullow's production and development projects in West Africa and Europe. In 2015, Tullow celebrated five years of production from the Jubilee field and over 150 million barrels of oil have been produced since the field came on stream in 2010.
1
| Overview of our operations | 4 |
|---|---|
| Chairman's statement | 6 |
| Chief Executive's review | 8 |
| Market review | 10 |
| Our business model | 12 |
| Creating value | 14 |
| Our strategy & performance | 16 |
| Special feature – On track | 22 |
| Operations Q&A and review | 34 |
| Finance & Portfolio Management | 42 |
| Responsible Operations | 46 |
| Governance & Risk Management | 48 |
| Principal risks | 55 |
| Organisation & Culture | 64 |
| Shared Prosperity | 66 |
STRATEGIC REPORT OUR OPERATIONS
Tullow has a balanced portfolio of high-quality producing fields, areas for future development and exciting exploration acreage.
* West African BDT manages Mauritanian production.
22
Tullow has operations in countries across Africa, Europe, South America, the Caribbean and Asia.
Tullow's portfolio of licences is balanced between exploration, development and production activities.
The majority of Tullow's acreage is in Africa, in particular offshore West Africa and onshore East Africa.
Tullow's workforce includes full time employees and contractors who work in our corporate offices and Business Delivery Teams.
1
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.
The East Africa Business Delivery Team is focused on commercialising the significant potential of the region through its onshore exploration campaigns and progressing developments.
The New Ventures Business Delivery Team is responsible for Tullow's frontier exploration and appraisal activity largely across Africa and Latin America.
| 2015 Group financial results summary | 2015 | 2014 |
|---|---|---|
| Sales revenue (\$m) | 1,607 | 2,213 |
| Pre-tax operating cash flow (\$m) | 967 | 1,545 |
| Operating loss (\$m) | (1,094) | (1,965) |
| Net loss after tax (\$m) | (1,037) | (1,640) |
| Basic loss per share (cents) | (113.6) | (170.9) |
| Dividend per share (pence) | – | 4.0 |
CHAIRMAN'S STATEMENT
Tullow has undertaken a major restructuring in 2015, which has been difficult for all involved. I commend the loyalty and resilience of our staff during a very tough year.
Last year I reported on the underlying causes of the sharp reduction in oil prices that started in mid-2014 and has continued ever since. I also reported on the steps taken by your Company to address the new market reality. By acting quickly and decisively, we have successfully reset the business to cope with lower oil prices.
During 2015, Tullow's production remained broadly flat at 73,400 boepd. In mid-2014, the oil price peaked at \$115/bbl. During 2015, it averaged \$52/bbl and at year end stood at \$37/bbl, but the impact of lower prices was significantly mitigated by our prudent hedging strategy, which helped to underpin revenues of \$1,607 million (2014: \$2,213 million). Cash flow also remained relatively strong at \$967 million, but we suffered another significant net loss after tax of \$1,037 million, largely as a result of further write-offs and impairments. However, during one of the most difficult periods ever for the global oil and gas industry, these financial numbers do not do justice to a year of hard work and solid achievement by your Company.
There has been a relentless focus on cost control during 2015. Exploration expenditure was cut to \$256 million (\$799 million in 2014), while capital expenditure was limited to key projects, such as TEN in Ghana, which will generate strong future cash flow, even at low oil prices. Headcount has been reduced by nearly 40 per cent, and the entire business has been reorganised to become more streamlined, more efficient and more effective. Gross G&A was reduced by \$164 million in 2015 and Tullow is on track to deliver cash savings of around \$500 million over the planned three-year period from mid-2015.
The restructuring of the business has not been achieved without sacrifice. Shareholders have seen their dividend suspended and many respected and valued members of staff have been made redundant, while many of those who remain have seen their responsibilities and workload increase. On behalf of the entire Board, I would like to thank all of our staff for their loyalty, resourcefulness and resilience during a very tough year for Tullow.
The changes we have made, while painful, were absolutely necessary in this environment. We have laid strong foundations for Tullow to benefit from the recovery, whenever it occurs. We have protected the core skills and competencies necessary for our future success and built an organisation that is simpler and more cost-conscious, with clearly defined lines of authority, responsibility and accountability for the delivery of our strategy. Despite significant internal and external distractions, the focus on delivery is exemplified by the TEN Project in Ghana – a highly complex, multinational, \$5 billion project, which is currently over 85 per cent complete and remains on time and on budget to produce first oil in July-August 2016.
The sharp reduction in the oil price in mid-2014 caught Tullow at a particularly unfortunate time, when we were midway through a heavy capital expenditure programme for the TEN Project. In response, we amended the covenants in our debt agreements and strengthened liquidity by increasing the available debt capacity on our RBL and corporate facility. At the end of 2015, net debt stood at \$4.0 billion with undrawn but available credit lines and free cash amounting to \$1.9 billion. Subject to the future development of the oil price,
debt should peak around mid-2016 as the TEN Project comes on stream. It was never our intention to allow our leverage to reach these levels, and it remains our objective to reduce gearing back towards our target level of two times net debt to EBITDAX. However, we firmly believe that it is in the interest of our shareholders to run with a higher than desirable level of debt until such time as we are able to deleverage our balance sheet through internal cash generation or portfolio management activity that enhances the long-term value of the Company.
As part of the Major Simplification Project, the Board has overseen a significant improvement in our performance management process, aimed at re-invigorating teams to be highly engaged, motivated and results-orientated. The Group scorecard, which tracks key metrics and a set of shorter-term objectives, is used to award Executive Directors' performancerelated pay and a proportion of all staff bonuses. It is tracked on a monthly basis by the Board and Senior Leaders and progress has been proactively communicated to managers and teams across the Group at various times throughout the year. A score of 37.7 per cent has been achieved in 2015, which reflects the challenging year the Group has faced, but also the successful delivery of a number of objectives that were critical in these very tough market conditions. Full details of our performance are set out on pages 17 to 21.
Risk management has always been a primary focus of the Board but, with the heightened risks that come with increased debt and highly uncertain commodity markets, we are giving the matter even more attention. On pages 52 to 54, we outline the improvements that we have made to our risk management and assurance processes and on pages 55 to 63 we set out our assessment of the principal risks facing the business and the mitigation measures we have adopted.
In accordance with the requirements of the 2014 Corporate Governance Code, we have included a viability statement on page 55. The practice of reviewing the long-term viability of the Company has always been part of the Group's planning process and continues to be a topic for discussion at every Board meeting.
A 75 per cent reduction in product prices would challenge any industry, and the exploration and production sector has been under intense pressure over the past 18 months. I am therefore particularly proud that, despite the short-term pressures that we face, your Board and the management team have remained focused on our long-term strategy of creating shared prosperity for our shareholders and for the countries where we operate. In common with every other aspect of our business, we have eliminated unnecessary bureaucracy and tried to simplify processes and clarify responsibilities, but we have not compromised our commitment to the highest standards of safety, health and environmental management, social performance and ethical behaviour. Our achievements and the challenges we face in this area are discussed further on pages 46 and 47.
The UN climate change conference in Paris at the end of 2015 drew attention to the urgent need for the world to reduce greenhouse gas (GHG) emissions and Tullow fully recognises its responsibility to play a constructive role in meeting the target to limit global warning to two degrees celsius. We have already taken steps to reduce GHG emissions from our own operations and we now apply notional carbon pricing to test the viability of major capital projects for Full Field Development under a range of scenarios. As an African-focused oil company, we are also conscious of our responsibility to meet the expectations of our host governments, which regard resourceled growth as a critical driver of economic development and poverty alleviation. We will continue to play our part in trying to ensure that the resource revenues that we help to create contribute positively to economic diversification and sustainable, inclusive development in Africa.
1
In October, the Board visited Ghana, where we met senior politicians, officials from our partners and regulators, and other business leaders and stakeholders. We visited the FPSO Kwame Nkrumah and Sekondi-Takoradi, where components for the TEN Project development have been fabricated. It was a pleasure to meet so many talented members of the Tullow Ghana team during our visit and to see the high standard of work.
Graham Martin retired as Company Secretary at the end of 2015 and will step down as Executive Director at the AGM. Graham has worked with Tullow for almost 30 years, initially as an adviser and since 1997 as a member of the Board. I would like to thank him for his significant and longstanding contribution to the Group. The Board has appointed Kevin Massie, previously Corporate Counsel and Deputy Company Secretary at Tullow, to the role of Company Secretary and I wish him well as he takes up his new duties.
Despite the uncertain market outlook, there is much to look forward to in 2016. In West Africa, we have submitted the Greater Jubilee Full Field Development Plan and expect TEN to come on-stream in July-August. As we head into 2017, Tullow will grow production to around 100,000 bopd net, with an average operating cost per barrel of around \$15, giving us one of the most competitive production bases outside the Middle East.
2015 has been a year of both challenge and achievement for Tullow. It is the firm belief of your Board that with Tullow's new organisational structure, described by Aidan Heavey on pages 8 to 9, our competitive West African production and low-cost East African development projects, our exciting exploration inventory, and our talented and committed staff, Tullow is well placed to weather the storm and, importantly, to prosper when market conditions improve.
Simon R Thompson Chairman
2015 has proved to be one of the most challenging years in Tullow's history but, despite industry pressures, we have delivered exceptional operational progress.
We recognised in early 2014 that the industry was changing; the rise of the US shale industry and the cost of both development and deep water exploration challenged existing models. We recognised that changes needed to be made and started a thorough review of our internal processes and exploration strategy. When the oil price fell in late 2014 we were, as a result, able to act very quickly to start the process of adjusting the Company to a lower price environment.
This was the genesis of our Major Simplification Project (MSP), which put us in a strong position to respond rapidly to the precipitous fall in the oil price which started in the autumn of 2014. During this period, five key decisions were made: focusing our capital on high-margin West African oil projects and the generation of cash flow; a cut in exploration expenditure; the suspension of our dividend; a review of all current and future projects and where necessary the write-down of asset values; and a focus on MSP to drive through efficiencies and substantial cost savings. All five of these key decisions have been implemented during 2015 and have helped to protect the balance sheet and funding
position of the business. I can therefore state, with confidence, that Tullow's business is re-set to be resilient to lower oil prices.
We have also undertaken major changes to our organisation. Following MSP, Tullow is now managed as three Business Delivery Teams (BDTs) – West Africa (incorporating our non-operated producing assets in the UK and Dutch North Sea), East Africa and New Ventures. Each BDT is led by a highly experienced Vice-President who reports to our Chief Operating Officer, Paul McDade. The BDTs and in-country management teams have significant autonomy and, thus far, have found decision-making and business planning far easier. The corporate centre functions based in London, Dublin and Cape Town provide strategic direction and assurance and provide support to the business as requested. By making these changes, we were able to see what jobs were needed in the new, re-organised Tullow and where we had outgrown our current business needs. Accordingly, the MSP reduced the headcount of our workforce by 37 per cent. A further and significant change was the launch of Tullow's new Integrated Management System (IMS) in late 2015 which took the hundreds of standards, procedures and policies that existed within Tullow and streamlined them down to 50 integrated standards that deal with every aspect of Tullow's operations.
The thread that binds all these changes is efficiency. However, efficiency is worthless without good assets, the best people and a strong financial base and in 2015 Tullow demonstrated it is well placed not only to survive current market conditions but to thrive when the oil price improves. Financially, we benefit from an ongoing hedging programme which has reduced the impact of lower oil prices on revenue and cash flow. We have had excellent ongoing support from our banks during the routine debt redeterminations with the banks in March and September, which resulted in our available lending capacity increasing over the course of 2015. With the TEN Project in Ghana remaining on schedule and on budget for first oil in mid-2016, we will see a significant decrease in capex in the second half of the year, a decrease that can be maintained if the low oil price persists, and increased cash flows as production begins.
Tullow's strategy is based around our long-life and low-cost assets. In West Africa our non-operated oil assets generate steady cash flow in return for consistent investment. TEN and Jubilee in Ghana provide a solid production base at relatively low operating costs. Jubilee is a world-class oil field which is still in the early stages of its life and the returns it generates will justify continued investment as we target additional recoverable reserves. When TEN comes on stream we will also benefit from additional production and cash flow. In East Africa, we have a major stake in one of the world's major new onshore oil provinces. An endorsement of the quality of these assets was demonstrated by Maersk acquiring a stake in our Kenya project from Africa Oil in the third quarter of 2015. Significant exploration potential remains in Northern Kenya and future basin opening exploration drilling plans are currently being evaluated.
While we may be involved in major developments, exploration remains pivotal to our strategy. We found all the fields that we are now developing, or seeking to develop, in Ghana, Uganda and Kenya and I am clear that exploration is the key to continued organic growth. Accordingly, we are building on our exploration portfolio to ensure that, as and when we increase our exploration spend, we have a world-class prospect inventory and we will generate significant shareholder value through the drill bit. In 2015, our exploration team has been operating with a limited budget and this will continue in 2016. They have, however, successfully executed deals to strategically reduce our equities for carries to reduce our capital exposure and are making great progress in identifying and negotiating new opportunities in our core areas of Africa and the Atlantic Margins.
As I look back on 2015, I am satisfied with where we ended the year. It has been challenging, but we have benefited because we did not hesitate to act as the oil price began to fall. We moved early and swiftly. In late 2015, I travelled to our key African offices in Accra, Nairobi, Cape Town and Kampala. In each location – as well as in London and Dublin – I was heartened by the enthusiasm of our staff and their recognition that the organisational changes implemented by MSP were making a difference and their clear understanding and agreement about the direction the Company is taking.
1
Looking ahead, there is much to look forward to in 2016. The TEN Project will come on stream in the middle of the year, Jubilee will continue to play its vital role at the heart of the Group and in East Africa we are poised to make significant progress towards fulfilling the potential of this major new oil province. As for the oil price, I make no predictions except that, having made Tullow fit for lower prices in 2015, we are ready to benefit from the recovery – when it comes.
Aidan Heavey Chief Executive Officer
| Operations | 34 |
|---|---|
| Finance & Portfolio Management | 42 |
| Risk Management | 52 |
| Organisation & Culture | 64 |
Graham Martin retired as Company Secretary at the end of 2015 and will retire as an Executive Director at the 2016 AGM on 28 April 2016. Graham has been a part of Tullow almost as long as I have, as he advised us on our first sales agreement in Senegal in 1986. He continued to be a key adviser to the Company during Tullow's early years, until he officially joined the Board in 1997.
Graham has been instrumental in completing many of the transformational deals and major acquisitions that have made Tullow Africa's leading independent oil company. He has been a constant advocate of Tullow's culture and values, and he will be missed across the Company.
During his almost 30 year career with Tullow he has made an outstanding contribution to the Group and I would like to personally thank him for his loyalty and commitment. I wish him every success and happiness in his very well-earned retirement.
STRATEGIC REPORT MARKET REVIEW
Global oil prices have slipped to 12 year lows, forcing producing economies and oil companies around the world to prepare for and adjust to a sustained period of low oil prices.
In 2015, the global economy was shaped by a number of events including a dramatic decline in oil prices, slowdown in China, fears of a Greek exit from the Eurozone and anticipation of a shift in the US Central Bank monetary policy. The US economy benefited from a stronger job market, which contributed to increased incomes and investment. After seven years of near zero rates, the Federal Reserve raised its interest rates by a quarter of a per cent in December 2015 and signalled that moderate adjustments will continue as economic activity continues to expand. In Europe, markets stabilised following initial fears of a possible Greek default, with consumers being the main driver of growth while exports continued to aid the recovery despite emerging market weakness. Elsewhere, emerging markets faced several challenges including the slowdown in Chinese economic growth, the ongoing Russia-Ukraine conflict and the emergence of Islamic State extremists in Iraq and Syria.
After a particularly strong first quarter for UK and European equities, stocks in both markets had increased significantly with the EuroStoxx 600 over 20 per cent higher and FTSE 250 over 10 per cent higher by April. This was disrupted in August, when the S&P 500 index suffered its first pullback of more than 10 per cent since the Euro debt crisis in late 2011.
2015 EQUITY MARKETS
This was predominantly due to China's devaluation of the Yuan and predictions of the upcoming US Federal Reserve rate rise. By the end of the year, the focus returned to longer-term economic outlook and Central Bank policy and markets rebounded on encouraging macro data with the FTSE 250 ending the year 8.4 per cent higher.
The FTSE 350 Oil & Gas Producers sector underperformed the wider market, closing the year down 20.6 per cent, predominantly due to the oil price decline. Tullow shares fell by nearly 60 per cent over the course of 2015 to close the year at 165.70p and Tullow left the FTSE 100 in March.
Brent crude continued its decline in 2015 and slipped heavily to \$45/bbl by late-August. Oversupply concerns and demand uncertainty weighed on the oil price throughout the second half of the year and OPEC's 'non-decision' in December led to further declines. At year end, Brent crude was selling at \$37/bbl, a fall of 35 per cent since the start of 2015. At the start of 2016, prices fell once again, slipping to under \$30/bbl for a number of days in January. Prices at the end of January 2016 were \$34/bbl, the increase reflecting hopes that both OPEC and non-OPEC producers would take action to tackle oversupply. The World Bank's forecast for oil in 2016 is an average of \$37/bbl, down from a projection of \$51/bbl in October last year.
Realised oil Realised gas Market oil price
"Oversupply concerns and demand uncertainty weighed on the oil price throughout the second half of the year. At year end, Brent crude was selling at \$37/bbl and in January 2016, prices dipped under \$30/bbl."
This has been a very tough year for the global oil and gas industry with lower oil prices leading to major cost cutting throughout the sector. Companies reduced their capital expenditure for 2015 and beyond, with exploration budgets being particularly hard hit. Developments have also been impacted and a Wood MacKenzie report issued in August 2015 estimated that 46 major development projects had been deferred, with just six new projects going ahead in 2015 and 10 in 2016.
The mergers and acquisitions market was quiet in 2015 and Royal Dutch Shell's purchase of BG Group announced in April 2015 was the only major deal of note. Throughout the year, Tullow has experienced a relatively healthy farm-in market where the Group has been able to attract new partners to a number of exploration licences.
Industry costs have begun to fall due to lower commodity prices, competition between oil service companies and in line with the demands of contracting companies. The gross cost of Tullow's upstream development in Uganda, for example, was initially estimated at between \$8-12 billion, but it is now clear that a combination of technical improvements and lower service costs should lead to a gross project cost of at least 20 per cent below \$8 billion.
Whilst growth in 2015 slowed amongst a number of African countries, African economies continue to outperform much of the rest of the world. In October 2015, the International Monetary Fund (IMF) was expecting the Sub-Saharan African economy to grow 3.8 per cent in 2015, accelerating to 4.3 per cent in 2016. These growth estimates were tapered throughout 2015 as a result of a fall in oil prices, declines in other commodity prices and geopolitical tensions, with these themes remaining relevant going into 2016. Within Africa, growth rates vary significantly by country. For example, the IMF expected Côte d'Ivoire and Ethiopia to grow over 8 per cent in 2015 driven by continued external investment. In Ghana, however, power shortages and fiscal consolidation weighed on economic activity with growth projected to slow in 2015 to 3.5 per cent before bouncing back in 2016 to 5.7 per cent. The Ebola outbreak in West Africa was gradually controlled through 2015 with the World Health Organization (WHO) declaring Guinea and Liberia Ebola free in December 2015 and January 2016 respectively.
1
As in 2014, stranded assets were a major topic for discussion in the oil and gas industry throughout 2015. It has been suggested that, as governments adopt stricter climate change policies, the majority of coal, oil and gas deposits will remain undeveloped as investment in alternative energy sources grows. Climate change legislation is going to become an increasingly important factor in determining the price of all fossil fuels. As previously stated, Tullow recognises the potential risks in light of this issue and the Group will adopt a business strategy that is responsive to legal and regulatory developments designed to address climate change. However, the Group is confident there will be a continuing role for the conventional oil and gas industry for decades to come. Even if governments around the world take decisive action now, it would take years of investment to replace the installed base of assets consuming fossil fuel. Furthermore, Tullow's assets in West and East Africa are low-cost sources of fossil fuels which remain economic, even at lower oil prices, and are close to market and easily accessible.
Tullow is a leading global independent exploration and production company. Our business model shows the parts of the Group that work together to run our business and create value.
We create value over the business cycle by finding oil and selling 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 strategy, which is explained on page 16.
The skills, experience and reputation we call upon across the seven elements of our business model are what we believe sets 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; 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.
Exploration & Appraisal
Execute high-impact E&A programmes. > page 34
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.
page 42
Achieve safe and sustainable operations, minimise our adverse environmental and social impacts, and achieve the highest standards of health and safety. > page 46
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. > page 64
Create sustainable, transparent and tangible benefits from the development of oil in host countries.
page 66
| Our key strengths and activities | 2015 progress |
|---|---|
| In its recent history, Tullow has achieved significant exploration success by opening commercial oil basins in Ghana, Uganda and Kenya. While recent focus has been on monetising these discoveries, our E&A team continues to build on our industry leading acreage position as we prepare for increased exploration activity in future years, subject to market conditions. |
• Nine successful appraisal wells in South Lokichar Basin in Kenya |
| Tullow has some of the best low-cost and high-quality oil assets in the world. The Group has a track record of delivery, with the Jubilee field developed in a record 40 months, and the TEN Project on its way to first oil on time and on budget by mid-2016. In 2017, the Group will target production of circa 100,000 bopd and significant upside from current and future developments for sustainable long-term cash flow. |
• TEN Project on budget and on schedule • Met 2015 production guidance averaging 73,400 boepd |
| Our business model is underpinned by access to diverse sources of funding and we adopt a prudent hedging strategy to mitigate oil price risk. The Group negotiated suitable debt capacity to fund the capital intensive period of the TEN development. However, the Board's primary objective is to de leverage the Company organically through new production cash flow, but also through portfolio management opportunities. |
• Quality assets secured additional \$450 million debt capacity in 2015 |
| Our ambition to be a top quartile oil and gas company on health and safety performance remains steadfast and we have reduced our Lost Time Incident Frequency (LTIF) for a second year in a row as we work towards this important goal. Managing our social impacts is critical for keeping our projects on track and on budget, and meeting our commitment to creating benefits for local communities. |
• 48% reduction in Lost Time Incident Frequency (LTIF) compared to 2014 |
| Tullow upholds the highest standards of business ethics and has a zero-tolerance approach to breaches of our Code of Ethical Conduct. Our day-to-day business is governed by a set of policies and standards which form part of our Integrated Management System (IMS), covering the breadth of our business. Our policies and standards outline the Group's values, set expectations and define controls against which we can assure ourselves that all activities, and associated risks, are being effectively managed. |
• New Ethics & Compliance Board Committee |
| The challenging market in 2015 was a catalyst to the restructuring, streamlining and strengthening of our organisation. This has resulted in greater efficiency and a culture focused on better cost management and more regular and rigorous review and challenge of performance. Following the restructuring our workforce is more empowered, with the Tullow team now clearer on their individual roles and how they contribute to delivering the Group strategy. |
• Planned and executed the Major Simplification Project |
| Our brand and reputation have been built over almost 30 years of operating in Africa. We are long-term investors and seek to build strong relationships, based on mutual trust, with our host governments. We aim to leave a legacy of sustainable social and economic benefits in the countries where we operate. |
• \$1.1 billion total socio-economic contribution |
1
STRATEGIC REPORT CREATING VALUE
This diagram describes the capital investment that oil companies make throughout the life of a project, as well as the production sharing that takes place between oil companies and host governments to allow for up front investment to be recouped. It also shows the added value from jobs and businesses opportunities that are typically created through a project.
Exploration and Appraisal
Initial opportunities for local jobs and suppliers In the early stages of a project, Tullow invests in community projects and employs local sub-contractors in exploration and appraisal programmes, where possible..
Development of discovery
During this capital intensive period, an oil company will drill further wells and invest in the necessary infrastructure to extract and produce resources. For onshore projects, this includes transport infrastructure, amenities, processing facilities and pipelines. For offshore projects, this includes production platforms, floating production, storage and offtake vessels (FPSO) and sub-sea equipment.
Maintaining and extending the life of producing fields Once a field is producing, investment will focus on sustaining and extending plateau production in the most cost-effective way. This involves general maintenance, steps to protect the integrity of the field and additional infill or near-field exploration drilling.
Cost-effective production for high-margin cash flow Once producing, the oil can be marketed and sold to international buyers. Maintaining low operating costs allows the oil company to make greater margins on each barrel sold. The oil company's take is dependent on the oil price, levels of expenditure and agreed licence terms.
The main economic value to host countries is from production revenues and income taxes on the oil company's profits. Goods and services from local businesses and expertise from the local workforce are needed to run operations, maintain production and work on potential further development.
1
Tullow aims to create sustainable long-term value across the oil life cycle for our shareholders and also a wider group of beneficiaries including employees, governments, local suppliers and communities.
An oil company will often carry the host government's share of costs through to first oil. In addition to the capital invested, the oil company pays the host government a number of taxes as well as land rentals, training and ongoing licence costs. The oil company also undertakes capacity building programmes including skills, knowledge and technology transfer to maximise local business and workforce participation in the industry.
An agreement between the oil company and government determines how and when costs can be recovered and how production and revenues are shared. 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'.
Creating shared prosperity is the key pillar of Tullow's sustainability strategy. The area where we can create the most discretionary value is through foreign direct investment, local procurement, local employment and capacity building through skills, knowledge and technology transfer. The scale of the opportunity for local business contracts and jobs increases as a project moves from the exploration phase through to production.
OUR STRATEGY AND PERFORMANCE
Tullow's Board is confident that Tullow's strategy and business plans remain effective in steering our Company through challenging market conditions.
Our long-term strategy is to find oil through exploration which we then seek to monetise through production or the sale of assets. We have demonstrated this both in Ghana through the development of the Jubilee and TEN fields and in Uganda with our farm-down to CNOOC and Total in 2012. Exploration success gives us options to monetise assets and maximise value at various points in the cycle. We selectively develop the oil we find, focusing on world-class development projects that are economically viable and will return sustainable future cash flows. As and when surplus cash is generated, a decision is made to either reinvest this cash into additional operational activities, pay down debt or return cash to shareholders.
Due to the significant fall in the oil price since mid-2014, we have reduced our expenditure on exploration substantially; limited our development spend to those projects which maintain or bring onstream substantial new production; focused on cost reduction; made sure our oil production is
substantially hedged; strengthened our banking facilities; and suspended our dividend. Accordingly, although our long-term strategy for creating value for our shareholders remains unchanged, we have made significant changes to its implementation in the current environment.
As and when the sector recovers, and costs within oil services are reduced, Tullow will reconsider its exploration budget in the firm belief that the best oil to develop or sell is oil that we have found ourselves. Meanwhile, our much reduced exploration spend is currently focused on ensuring that Tullow has a balanced and exciting prospect inventory which is ready for any change in market conditions. We recognise that our strategy requires disciplined execution in the short term to deliver a successful, well-funded business for the future and we continue to stress-test both our balance sheet and business plan at very low oil prices to ensure that we can execute our strategy despite the current volatility in the oil and gas industry.
The Group's progress against its corporate scorecard is tracked every month to assess the Group's performance and delivery against its strategy.
Tullow's Key Performance Indicators (KPIs) are important in assessing the overall health and performance of the business and they make up a Group scorecard that includes a range of operational, financial and non-financial measures.
The KPIs measured in 2015 differ from those reported in 2014 and this is a result of the Major Simplification Project (MSP), which has evolved the Group's approach to ongoing performance management. A single Group scorecard was agreed with the Board for 2015 which included specific strategic targets that were deemed important for the year. 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 monthly performance management meetings, which are attended by Executive Directors and Senior Leaders. The Group's ongoing performance is regularly cascaded to staff through management briefings and internal communications.
The Group scorecard is used to determine Executive Directors' and employees' performance related pay to ensure that all areas of the business are driving towards the same goals. Executive Directors' performance is judged solely on the delivery of the targets set in the Group scorecard, whereas the majority of employees' bonuses are based on a combination of individual and Group performance.
1
Each objective measured has a percentage weighting and financial indicators have a baseline and a stretch performance target. As reflected in the table below, in 2015, Tullow's overall performance was 37.7 per cent. This reflects the challenging year the Group faced and the impact it has had on our Total Shareholder Return (TSR), which accounts for 50 per cent of the total possible score. 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.
| 2015 GROUP SCORECARD | % available in scorecard |
2015 actual performance |
|---|---|---|
| OPERATIONAL (Production, Opex, Net G&A) |
10% | 6.6% |
| TEN DEVELOPMENT (First oil date and cost) |
10% | 7.2% |
| SAFE AND SUSTAINABLE OPERATIONS (Lost Time Injury Frequency and safety and sustainability scorecard) |
10% | 7.3% |
| STRATEGIC TARGETS (Liquidity, East Africa progress, Major Simplification Project) |
20% | 16.7% |
| RELATIVE TSR | 50% | 0% |
| Total* | 100% | 37.7% |
* Due to rounding, column does not add to the total.
Production provides a key source of funding for the Group in the form of highmargin annual cash flow. Production guidance is set as part of the business planning process and meeting these levels is important for ongoing liquidity.
Maintain Group production against a base target of 71,000 boepd, and maintain the integrity and operating efficiency of the Jubilee field.
The Group's working interest production in 2015 was 73,400 boepd, exceeding the base target. This reflects strong performance from the Jubilee field and our non-operated West African portfolio.
Operating costs determine how much it costs Tullow to produce each barrel of oil it extracts. The lower the cost, the higher the margin Tullow receives when the oil is sold. Opex is impacted by industry costs, inflation, Tullow's fixed costs and production output.
Deliver Opex/boe base target of \$14.5/boe.
Opex/boe in 2015 was \$15.1/boe, after taking account of the uncontrollable effect of Gabon royalties. This did not achieve the base target of \$14.5/boe, primarily due to unforeseen maintenance on the Jubilee FPSO.
\$46 MILLION
11 12 13 14 15
saving compared to 2014 adjusted net G&A (\$155 million)
Administrative costs are the corporate costs of running the organisation. They should be directly related to our levels of operational activity, efficiency, planning and budgeting.
Reduce activities and related G&A costs that will deliver net G&A cost savings of a \$50 million run rate at the end of 2015.
Net G&A was \$194 million in 2015. There have been significant reductions in headcount, payroll and non-payroll costs during 2015. The adjusted 2015 annualised exit run-rate was \$109 million, which is a reduction of \$46 million compared to 2014 adjusted net G&A of \$155 million, after excluding the effect of the IFRS 2 Share-Based Payments charge.
OVER 85%
of project completed
Delivering the TEN Project on time and on budget will lead to significant production growth and will build on available reserves which underpin debt capacity.
Forecasts on track for delivering TEN first oil in mid-2016 and within budget. This is measured on a sliding scale and the full score of this KPI required the schedule and budget forecasts to meet stretch targets.
The base target for the forecast delivery of the TEN Project was achieved in 2015. The project is forecast to be delivered within budget and is on track for first oil in July / August 2016.
1
Tullow's safe and sustainable operations scorecard provides a complete view of Tullow's performance and drives towards a sustainable business for the long term.
Demonstrate measurable improvements to performance based on the scorecard, which covers occupational safety, process safety, social performance, social investment, environmental performance and regulatory compliance.
Performance measures in 2015 showed improvements across the majority of categories. Improvements were notably
in the safer management of motor vehicle operations, with significantly fewer Motor Vehicle Collisions (MVC) incidents (75 per cent reduction). The number of private and public security forces trained in compliance with Tullow's Voluntary Principles on Security and Human Rights requirements has also increased significantly during the year. Areas of declining performance included volume of gas flared and GHG emissions due to a compressor issue on the Jubilee FPSO.
Rolling MVCF LTIF 12 Month Avg TRIR 12 Month Avg * Incident frequency Trend
per million man hours
Lost Time Injury Frequency (LTIF) is a measure of incidents that occur either in Tullow or our contractors' operations that result in a fatality, a permanent disability or a reduction of man-hours worked. They are a direct measure of our safety procedures and the quality of training and have the potential to impact our reputation and ability to operate effectively.
Reduce LTIF by 20 per cent from the 2014 end of year performance.
Tullow reduced LTIF by 48 per cent, with an end of year LTIF of 0.30. Improvements were made through a greater focus on the organisation of land operations and control of work at these locations, in particular in our drilling, completions, and extended well testing activities.
1,548 1,778 2,034 2,042 1,403 TOTAL WORKFORCE 1,403 11 12 13 14 15
Tullow's strategy is focused on creating long-term shareholder value, supported by efficiency, cost management and a strong culture. The objective of the MSP, which was completed in 2015, was to streamline our business and processes, cut costs and re-focus the Group on key priorities and activities.
Deliver business restructuring and efficient processes focused on value.
The MSP project has successfully adjusted the operating model of the business, clarified key accountabilities, improved culture around value creation and performance management, and simplified the organisational structure – with further work ongoing to simplify internal processes and better manage our cost base. Headcount has been reduced across the business to better reflect Tullow's activities and scope of operations. The new operating model and implementation of an integrated management system has better
defined key accountabilities and responsibilities. Ongoing performance management reviews have evolved to improve discussions around value creation on a more regular basis, with the Group's ongoing delivery against its key objectives regularly communicated to staff. A shift to a more cost-conscious culture has occurred as a result of regular expenditure reviews and improved cross business challenge. Engagement with the Executive, in-country management and peers has been stepped up to help motivate, engage and focus staff on the Group's targets during this period of change and challenging market conditions.
636 mmboe East Africa net contingent resources
Tullow's basin-opening discoveries in Uganda and Kenya have discovered a new oil province with the potential of circa 300,000 bopd combined gross production. Monetising these discoveries through development and/ or portfolio management is a fundamental part of Tullow's strategy.
Deliver East Africa exploration campaign, demonstrate commercial viability of South Lokichar resource base and maintain ability to accelerate a commercially attractive project into 2016. Progress East Africa development programme though pipeline agreements and resolution of Uganda tax issues.
Nine appraisal wells were drilled in the South Lokichar Basin in Kenya in 2015 and all were largely on prognosis. Extended Well Tests displayed good connectivity at Ngamia and Amosing and provided important data for
development plans. Elsewhere, three potential basin opening exploration wells were drilled in 2015, but none made discoveries. In August 2015, the Governments of Kenya and Uganda issued a joint statement agreeing the Northern pipeline route would be used to export oil, subject to certain conditions. A technical team is working on addressing these conditions to gain unequivocal agreement from both governments. A draft field development plan for the discoveries in the South Lokichar Basin was submitted in December 2015. In Uganda, historic CGT and VAT issues were resolved.
headroom and free cash at year end 2015
Sufficient liquidity is imperative for a company's survival and it enables the Group to meet its capital commitments and to invest in projects and assets that will bring value in the future.
Take appropriate steps to ensure cost-effective and sufficient liquidity in 2015.
The March 2015 re-determination accessed \$450 million of increased debt capacity, and the strength of our producing assets helped to maintain debt capacity in the October 2015 re-determination despite lower oil
prices. Net debt at year end 2015 was \$4.0 billion and headroom and free cash was \$1.9 billion, ahead of guidance due to a combination of cost savings and deferral of certain capex to 2016. A number of exploration farm-outs were concluded during the year, reducing E&A expenditure through carried costs.
1
Tullow's strategy is focused on building long-term sustainable value growth. Our primary strategic objective is to deliver substantial returns to shareholders.
The baseline target is median TSR performance in relation to a peer group and the stretch target is upper quartile performance.
TSR is based on performance over the 24 months ended 31 December 2015.
Tullow's TSR is measured against a bespoke group of listed exploration and production companies. Tullow was ranked 19 out of 21 peers for TSR performance, resulting in no award for TSR. Over the measured 24-month period, Tullow experienced negative TSR of 77.78%, compared to a median of negative 38.2%.
Stretching financial metrics, a strong balance sheet and operational and organisation targets are included in the 2016 scorecard, as well as measures to deliver on the longer-term growth strategy of the Company.
On 23 January 2016, following 26 months of fabrication and testing, the FPSO Prof. John Evans Atta Mills left Singapore and set sail for Ghana, achieving a major milestone for the Tullow operated TEN Project.
This milestone was achieved as a result of 17 million man hours of labour at the Sembcorp Marine shipyard. Main contractor MODEC supervised the build and will own and operate the FPSO.
The FPSO conversion was one of the most successful projects of its type ever completed. It was finished on time and on budget with minimal work left to be completed on the voyage to Ghana.
The departure of the vessel on schedule keeps the project on course for its July / August 2016 first oil target.
Our operations began in Ghana 10 years ago, and the TEN Project is Tullow's second development following the record delivery of the Jubilee field in 2010. In this annual update of the project's progress, we highlight key milestones achieved and work remaining as we fast approach first oil. The project remains on time and on budget, demonstrating the operating capability of Tullow Oil and its Partners.
Operated by Tullow, the TEN Project takes its name from the three offshore fields under development – Tweneboa, Enyenra and Ntomme – which are situated in the Deepwater Tano block, around 60 kilometres offshore Western Ghana.
First oil is scheduled for July / August 2016. Following start-up, a gradual ramp up in production towards plateau is anticipated during the second half of 2016. The field will add significant low-cost production to Tullow's portfolio.
The TEN Plan of Development was approved by the Government of Ghana in May 2013. Since then, 11 wells have been drilled and the completions campaign is progressing well.
Construction vessels began installing subsea production equipment in the fields in the third quarter of 2015 and the bulk of this work is now complete. When the FPSO arrives in Ghana in the first quarter of 2016, it will be ready for installation, hook-up and commissioning.
Tullow and its Partners are confident the project will remain on schedule and they will deliver the TEN first oil safely and successfully for Ghana.
FPSO facility capacity 80,000 bopd
Gas processing Compression capacity 170 MMscf/d
Water injection 132,000 bwpd
Oil reserves being developed 240 mmbo
Gas reserves being developed 60 mmboe
Partners' working interest Tullow (operator) 47.175% Kosmos 17% Anadarko 17% GNPC 15% Petro SA 3.825%
When the TEN fields come onstream, it will be a hugely significant moment for Ghana. With TEN producing alongside the Tullow operated Jubilee field, Ghana will join the select club of nations with two major oil producing fields.
It will also be a proud moment for Tullow Ghana as we move to operating two developments and two FPSOs. This will be a new challenge for Tullow Ghana and one I am certain we will rise to. I am extremely proud that Tullow is at the forefront of unlocking
CHARLES DARKU MANAGING DIRECTOR, TULLOW GHANA LTD.
Ghana's oil resources and delivering on our promise to create shared prosperity. The development of the TEN fields has led to the creation of work for Ghanaian companies and will bring increased revenue to the Government of Ghana.
The team in Ghana has much to look forward to in 2016 and remains focused on creating value for Tullow, our shareholders and for Ghana.
Charles Darku, Managing Director, Tullow Ghana Ltd.
May The Government of Ghana approved TEN Plan of Development
October Work began on FPSO conversion in Singapore
Q2 All seismic work completed July – August The FPSO's module support stools – fabricated in Ghana – arrived in Singapore August FPSO entered dry dock
January 11 wells drilled and project 50% complete overall February First subsea christmas tree assembly completed in Takoradi July Construction of the FPSO's mooring piles in Sekondi July First subsea installation vessels arrived in Ghana September FPSO naming ceremony
in Singapore
November FPSO turret testing completed
January FPSO departed from Singapore March FPSO to arrive in Ghana
June Umbilical and riser installation to be completed July – August First oil from the TEN field
2H 2016 Final commissioning and gradual production ramp up
Plateau production reached
Stay up to date with all the latest news on how we're progressing: www.tullowoil.com
Seeing the FPSO leave Singapore was a huge milestone for us and, crucially, it sailed with minimal carry over.
I would like to recognise the efforts of our major contractors and their subcontractors in keeping the project on schedule. Fabricating the equipment for a complex deepwater development is no mean feat and requires foresight and flexibility to adapt to changing circumstances and new challenges on a weekly basis.
I would also like to commend our contractors for their commitment to
TERRY HUGHES TEN PROJECT DIRECTOR
local content and note the contribution of Ghanaian companies to the project. All of our major contractors have over delivered on their local content commitments and each work package contains equipment built in Ghana.
As we enter the home straight, we must stay focused so Tullow, our contractors and the people of Ghana can celebrate first oil later on this year.
Water depth: 1,000 – 2,000 metres
Flowlines: 70 km
Umbilicals: 60 km
Risers: 40 km
Riser Bases: 2
Christmas Trees: 24
Manifolds: 4 oil production manifolds and 1 gas export manifold
Semi-Submersible Drilling Rig
1
2
Enyenra 5
Enyenra Manifold 2
Enyenra Manifold 3
oil production flowline gas production/injection flowline water injection flowline umbilical
The subsea installation campaign began in July 2015 and is progressing well. In total, 35,000 tonnes of equipment is being installed on the seabed in the TEN fields.
The first equipment to be installed was the FPSO's nine anchor piles, which will hold the FPSO in position. These 21 metre high steel cylinders, fabricated in Ghana, were installed in the seabed by the Normand Installer in July and August 2015.
The bulk of the subsea production equipment is being installed by the TS7 consortium (Technip and Subsea7). The Seven Borealis and Simar Esperanca operated in the fields in the second half of 2015. Their work scope included the installation of three Enyenra manifolds, one Ntomme manifold and the Enyenra and Ntomme oil production riser bases. At the same time, several pipe laying vessels completed the installation of flow lines on schedule.
The project's umbilicals, which will connect the FPSO to the subsea equipment and have a total combined length of over 60 kilometres, arrived in Ghana in November 2015. The installation of the first 10 was completed by the Viking Neptun in January 2016 and the remainder will be installed by the Deep Pioneer by the end of April 2016. The flexible risers, which will carry fluids to and from the FPSO, are being installed by the Deep Energy.
Following its arrival in the field, the FPSO will be hooked up to the subsea production system and commissioned. The final milestone in the campaign, the installation of all umbilicals and risers, is planned to be completed by June 2016.
The TEN Project FPSO was officially named by Her Excellency the First Lady of the Republic of Ghana, Dr. Nana Lordina Mahama at a ceremony in Singapore on 30 September 2015.
The vessel was named FPSO Prof. John Evans Atta Mills after the late President of Ghana who presided over First Oil from the Jubilee Field.
During the ceremony, Her Excellency paid tribute to the contribution of Ghanaian artisans to the construction of the FPSO. Ghanaian companies Seaweld Engineering Ltd and Orsam Ltd fabricated the module support stools which sit on the deck to support heavy equipment. In addition, the FPSO's anchor piles, which will keep the vessel moored in place, were built in Ghana by Group Five Construction Ghana Ltd. The anchor piles were completed on time and are already installed in the seabed in the TEN fields, awaiting the arrival of the FPSO.
The First Lady also met some of the Ghanaians who have been working on the construction of the vessel in Singapore, many of whom will be part of the crew that will operate the FPSO when it begins producing.
Her Excellency commented: "It has been my great pleasure to officially name this magnificent FPSO today in honour of a true Ghanaian statesman, the late Professor Atta Mills."
"I saw the impressive facilities onboard and it gives me great pride to know that this state-ofthe-art FPSO will be producing oil for Ghana for many years to come."
DR. NANA LORDINA MAHAMA GHANA'S FIRST LADY
"During my time here in Singapore I have learnt how to piece the various aspects of a project together to ensure that it is delivered on time, according to design and on budget."
OPERATIONS READINESS & ASSURANCE ENGINEER, GNPC (ON SECONDMENT WITH TULLOW)
The offshore oil business is relatively new to Ghana so, with the exception of those working on the Jubilee field, opportunities for Ghanaians to gain experience have been rather limited. The TEN Plan of Development included commitments by Tullow Oil and its partners to create opportunities for Ghanaians to gain experience and develop skills as integral members of the project team.
Since 2013, a total of 52 Ghanaians from GNPC, the Petroleum Commission of Ghana and Tullow Ghana Ltd have spent time on secondment with the TEN Project team in London, Singapore, Houston and Ghana.
The secondees have worked in a variety of roles including Subsea Engineer, FPSO Commissioning Engineer, Geologist and Project Finance Manager. They have developed skills and experience relevant to a major offshore development project, making them well placed to contribute to future oil developments in Ghana.
In addition, 30 Ghanaian nationals worked on the FPSO conversion with MODEC in Singapore. Fifteen of these trainees completed the Level 3 General Vocational Qualification – Diploma in Process Operations. Ten of these Ghanaian engineers were members of the crew for the vessel's voyage to Ghana and many more will be part of the team that operates the FPSO.
Ghanaian secondees on the TEN FPSO in Singapore www.tullowoil.com 33
Our Chief Operating Officer, Paul McDade, and Exploration Director, Angus McCoss, discuss Tullow's progress and challenges in 2015 and the Group's plans for the year ahead.
PM: MSP has not fundamentally changed our approach to Development and Production, but it has certainly made our teams more efficient and cost conscious, which was a major objective of the project. We now have three Business Delivery Teams (BDTs), West Africa, East Africa and New Ventures, and these groups have been more empowered by the shift in the organisational design. Each of the BDTs has a clear purpose and work programme to deliver and, through a more rigorous approach to performance management, the BDTs are continually challenged by the Senior Leaders across the Group to ensure these activities are being delivered in a safe and efficient manner. We have not compromised on any of our Safety, Sustainability and External Affairs (SSEA) standards, and this remains a focus of every aspect of our operations.
MSP was not only about people, it was also about reducing and simplifying processes and we have now implemented a new, simpler Integrated Management System (IMS) which more clearly sets out all our Policies and Standards which all staff can access online. The IMS houses all the documents which define how we go about our operations and sets appropriate standards and accountabilities.
AM: As Aidan mentioned in his statement, exploration continues to be key to Tullow's organic long-term growth. MSP has impacted all teams across Tullow but it has not changed the fundamentals of finding oil. Given where Tullow is in its business cycle, with our focus on creating value from our oil discoveries and in the context of the industry downturn, we have proactively reduced our nearterm exploration drilling investments. We have been working hard to do more with less and we continue to build on our exploration portfolio and execute strategic deals to bring in good partners and share our capital exposures and risks. While it's been hard to say farewell to members of the team, we retain some of the best minds and talent in the industry, who are focused and driven to be leading explorers, using cutting-edge technology and scientific methods to discover a low-cost supply of oil.
"We retain some of the best minds and talent in the industry, who are focused and driven to be leading explorers, using cutting-edge technology and scientific methods to discover a low-cost supply of oil."
In exploration and development geosciences, our priorities are capturing material new acreage positions through the New Ventures Business Delivery Team, supported by seasoned functional experts. We are also focused on maturing 'drill-worthy' prospects and leads and discovering and appraising valuable oil.
PM: Development of the TEN field in Ghana has been a priority in 2015, and this past year was the most capital intensive period of the project, with around \$0.9 billion invested. In 2016, the capital outlay on the development of TEN will be around \$0.6 billion. I am pleased that this important project remains on track and on budget, with first oil due in July or August 2016. Keeping this deepwater project on schedule and within budget is a testament to Tullow's project delivery skills, and this ability to deliver is very important to the Company as it will see us steadily increase Group net production to around 100,000 bopd, supporting the cash flow generation of the business.
Tullow also allocated capital to Jubilee where we have maintained gross production levels averaging 102,600 bopd (36,400 bopd net to Tullow), exceeding guidance. This low-cost production means we can generate positive cash flows, even at these low oil prices. In 2016, we expect production costs to reduce further and we will continue to scrutinise every dollar of capital allocated as we manage this world-class asset in the current low oil price environment. We continued to invest capital in our portfolio of non-operated assets in West Africa, maintaining production in 2015 at 30,200 bopd. As we go into 2016, we expect the level of capital allocation on these assets to be reduced significantly.
AM: We prioritised the E&A programme in East Africa to fully underpin the estimated 600 mmbo gross recoverable resources discovered in the South Lokichar Basin in Kenya. This saw us drill nine successful appraisal wells and complete extended well tests at the Ngamia and Amosing fields which enabled us to gain useful data to support development planning. We also continued to explore further undrilled basins in our Kenyan acreage. We drilled three wildcat wells, and although we did not make any commercial discoveries, there have been encouraging signs of working petroleum systems which keep us very interested in the region's oil potential. We have also progressed our initial studies in the Caribbean-Guyanas, completing a seismic survey offshore Suriname and bathymetric and drop core studies in Jamaica. Our New Ventures team remains very encouraged by the studies being undertaken in this underexplored region and this is reflected through farm-ins by reputable industry partners and additional acreage we have picked up in Guyana.
1
PM: East Africa is a very significant project for Tullow with estimated gross resources of around 2,300 mmbo and the low development cost of the project very much suits the current low oil price environment. We remain fully committed to progressing this development and continue to work closely with the Governments of Uganda and Kenya to ensure that all parties will benefit from a combined East African development of the Lake Albert (Uganda) and South Lokichar (Kenya) discoveries. In Kenya we have now completed the planned appraisal programme of the South Lokichar Basin and this enabled us to submit a draft field development plan to the Government of Kenya in December 2015. We expect to be in a position to finalise the development plan with the Government in 2016. In Uganda, the development plans have already been submitted and we are now discussing the award of the Production Licences with the Government.
The next milestones towards achieving a Final Investment Decision (FID) include agreeing pipeline routing, completing FEED for the pipeline and upstream developments and finalising the commercial agreement.
AM: We have previously stated that we see the exploration potential of a billion barrels of oil in the South Lokichar Basin and we still stand by this. The Etom-2 appraisal well in December 2015 opened up a new area in the far north of the basin. This area has an unrisked potential of around 350 mmbo. Due to the completion of a 3D seismic survey in the area, we have a much clearer picture of how we can build on the already discovered resources. We are considering how we can incorporate this important area into our development plans and will be reviewing our 2016 exploration programme to see if we can test some of the undrilled prospects in the north of the basin.
AM: There's been a lot less exploration around the world and in turn fewer barrels discovered as companies, like Tullow, have reduced exploration and appraisal capex and focused on near-term cash flow. We drilled three wildcats and nine appraisal wells in Kenya, a single exploration well in Gabon, Pakistan and Suriname and we participated in three wildcats in Norway. Additionally, three non-operated low-equity appraisal wells supported our gas production from the Netherlands. From 20 wells, 10 were commercially successful, with the Pakistan well result pending flow testing in 2016. From our experience in 2015, the exploration industry remains buoyant in terms of farm-outs and farm-ins and it is clear that our existing exploration acreage is highly valued within the industry. Tullow has successfully reduced its equity levels in a number of licences, in order to reduce its exposure to costs and gain carries for exploration
activities. We're focused on refreshing and high grading our portfolio and concentrating on seismic interpretation in order to identify and prepare the best drill-ready prospects for when the cycle turns and capital becomes available for our team of explorers.
"It will be good to see our teams continue to capably adapt to this changing oil price environment, whilst not compromising our high operating standards and ensuring that we continue to reduce costs and maximise revenue."
PM: In our operated assets in Ghana, we are starting to see our underlying operating costs (opex) reduce, due to the impact of both market deflation and increased efficiency post the implementation of MSP. The market deflation is industry wide as service providers adjust to the low oil price environment we are currently in and this will lead to continued downward pressure on opex in our operated and non-operated assets. We are taking the opportunity to renegotiate many of our contracts, where appropriate, to take advantage of this market deflation. In addition, as we start up production from the TEN fields, we will benefit from the significant synergies from the shared resources that will service the increased production volume. In addition to the reduction in operating costs, we are seeing very significant
deflation in development costs. Independent studies indicate that our East African development could benefit from an overall capital cost reduction of over 20 per cent, further reducing the development cost of this attractive development.
AM: Despite a highly focused budget in 2016, we continue to be excited about our Kenyan acreage and a series of prospects being prepared for drilling in the South Lokichar Basin. We are also encouraged by the opportunities in the market for new acreage, and the team is busy looking into all these opportunities in Africa and South America. We hope to be in some new licences by the end of 2016 and we will be preparing for drilling operations in 2017, where we plan to drill some key 'trigger wells' looking for basin opening success.
PM: Delivery of first oil at TEN in July or August will be a very special event for Ghana, Tullow and our Partners. We are all focused on safely completing the final stages of this project on time and on budget, and achieving this will be a testament to our teams' capability, our contractors' delivery and the
Partnership's ongoing commitment to Ghana. In addition to TEN, it will be good to see our teams continue to capably adapt to this changing oil price environment, whilst not compromising our high operating standards and ensuring that we continue to reduce costs and maximise revenue.
| TEN special feature | 22 |
|---|---|
| Operations review | 37 |
| Responsible Operations | 46 |
Tullow's operations are managed by three Business Delivery Teams for West Africa, East Africa and New Ventures. The Group has delivered strong operational performance in 2015 across its portfolio of exploration, development and production assets.
* West Africa BDT manages Mauritanian production
The Jubilee field exceeded its gross production target during 2015, averaging 102,600 bopd (net: 36,400 bopd). A stable rate of gas offtake has been achieved following final commissioning of the onshore gas processing plant in March 2015, averaging around 90 mmscfd in the fourth quarter of the year. This strong gas export performance significantly reduced the requirement for gas reinjection at the field. Tullow is forecasting Jubilee 2016 average production to be around 101,000 bopd gross (net: 36,000 bopd). This reflects the impact of a planned two week FPSO
maintenance shutdown scheduled for March 2016 and a period of reduced water injection capacity during the first half of the year which is currently being addressed.
During the year, Jubilee Phase 1A drilling and completions continued with two oil producers coming on stream in September and December and a water injector which has yet to be completed. With the Phase 1A investment programme nearing completion, Tullow and partners submitted the Greater Jubilee Full Field Development (GJFFD) Plan in December 2015 and discussions are ongoing with the Government regarding its progress. This project, to extend field production and increase commercial reserves, has been redesigned given the current environment to reduce the overall capital requirement and allow flexibility in the timing of the capital investment. During 2016 and beyond, a continued focus on cost reduction opportunities and the careful balancing of future capital investment initiatives, including infill drilling as part of the GJFFD, will be key as Tullow seeks to ensure maximum return on investment from this world-class oil field.
The TEN Project continues to make excellent progress, is over 85 per cent complete, and remains within budget and on schedule for first oil between July and August 2016. To date, all the key milestones of the project have been met, including the sailaway of the TEN FPSO from Singapore to Ghana on 23 January 2016. The vessel sailed with almost zero 'carry over', which means that only 2,000 man hours out of a total 17 million man hours of work remain to be completed during the vessel's journey to Ghana, a very significant industry achievement. Arrival in Ghana is expected to be in early March and the vessel will move directly to the installation phase where it will be fixed to the seabed using pre-installed anchor chains and piles. This is followed by the hook-up of subsea facilities to the FPSO via flowline risers and control umbilicals, much of which has also been pre-installed. The 11 pre-drilled wells are now being completed with the sixth completion under way. The integrated facilities will undergo final commissioning and testing during the second quarter and following start-up, a gradual ramp up in production towards plateau is anticipated during the second half of 2016. Tullow estimates that TEN average production in 2016 will be around 23,000 bopd gross (net: 11,000 bopd).
Tullow operative on the Jubilee FPSO, offshore Ghana TEN FPSO in Singapore, prior to sailaway
The overall gross capex cost of the development remains at around \$5 billion, without FPSO lease costs. Total gross capex to first oil is expected to be around \$4 billion after which the remaining capex is largely associated with the drilling and completion of an additional 13 wells. The export of associated gas from the TEN field is scheduled to start up one year after first oil. Tullow is guiding 2016 net capex for the development to be around \$600 million with approximately 75 per cent being spent in the first half of the year in preparation for first oil.
In April 2015, the Special Chamber of the International Tribunal of the Law of the Sea (ITLOS) in Hamburg rejected Côte d'Ivoire's request that Ghana be ordered to suspend all oil exploration and exploitation in the disputed zone including the TEN Project. ITLOS ordered a number of provisional measures which both Ghana and Côte d'Ivoire are required to comply with, including continued cooperation and 'no new drilling' until ITLOS gives its decision on the maritime boundary dispute, which is expected in late 2017. It is therefore assumed that development drilling will not recommence until the ITLOS proceedings have completed.
Working interest oil production from Tullow's non-operated West African portfolio was in line with guidance in 2015, averaging 30,200 bopd net. The region still generates important operating cash flow for the Group with a low average operating cost of \$15.0/bbl. Production from the region is expected to be around 29,500 bopd net in 2016. Capital investment on development activities in 2016 will be reduced to around \$100 million net to Tullow versus spend in 2015 of around \$200 million. The strategy across the portfolio is to target investment decisions on activities that limit the decline rates of these mature fields.
In Côte d'Ivoire, the first five wells of the Espoir Phase 3 infill campaign have successfully been completed. Around 14,000 bopd gross have been added to the Espoir field's production since the start of the drilling programme. Up to a further six wells are due to be drilled in 2016 which will continue to support strong production from the field.
In Congo (Brazzaville), additional infill wells were drilled across the M'Boundi field during 2015. The rig was released in July and the partners are reviewing field performance before a rig returns to drill a further three wells in the second half of 2016.
In Equatorial Guinea, activity during 2015 focused on improving operating efficiencies and asset integrity at the Hess operated Ceiba and Okume fields. A subsea workover on an existing Ceiba well will be completed in the second quarter 2016. The Joint Venture is currently reviewing the new 4D seismic shot over the Okume Complex to prepare an infill inventory to restart drilling on Elon and Oveng in 2017.
In Gabon, the drilling programmes on the Perenco operated fields finished in late 2015. Field performance reviews are taking place with the hopes of restarting drilling late 2016. The Etame infill drilling programme yielded good results at the new Etame and SEENT wellhead platforms. Focusing on driving down operating costs remains a key objective ahead of a potential resumption in drilling operations in late 2016 or early 2017. During the year, Tullow regained its 7.5 per cent stake in the Onal Complex producing fields and the Ezanga block (formerly the Omoueyi exploration block). In addition, Tullow has been granted licence extensions in the Onal Complex fields until 2034 and has gained access to two small oil discoveries made within the Ezanga block in 2014. In return for access to these discoveries, it was agreed that the effective date of the new licence would be 1 August 2015.
In 2015, Tullow's activities in Kenya largely focused on completing the appraisal of the South Lokichar Basin discoveries, gaining important reservoir data for the field development plans. Nine appraisal wells were drilled and five Extended Well Tests (EWTs) were successfully completed at the Ngamia and Amosing fields.
Successful appraisal wells drilled included Ngamia-7, 8 and 9, Amosing-3, 4 and 5, Twiga-3, Ekales-2 and Etom-2. In December, Etom-2, the most recent well drilled in the South Lokichar Basin, discovered 102 metres of net oil pay in high quality reservoir sands in an untested fault block identified on new 3D seismic. The results of these appraisal wells have significantly advanced the subsurface definition of the main South Lokichar discoveries.
The EWTs conducted at the Amosing and Ngamia fields have demonstrated production rates and reservoir continuity over distances suitable for field development. In the Amosing EWT, five separate zones were completed in the Amosing-1 and 2 wells. The five zones produced at a cumulative average constrained rate of 4,300 bopd oil under natural flow conditions and good pressure communication was observed between the wells. For the Ngamia EWTs, five separate zones were completed in the Ngamia-3, 6 and 8 wells. The five zones produced at a cumulative average constrained rate of 2,400 bopd and all except the lowest zone produced under natural flow conditions. During the EWTs, approximately 68,000 barrels of oil were produced into storage.
Completion of the appraisal drilling and testing campaign in the South Lokichar Basin underpins an estimated gross contingent recoverable resource base of 600 mmbo. The new 3D seismic, which was used to locate the Etom-2 well which encountered the best oil reservoir quality to date, indicates significant remaining exploration prospectivity in the greater Etom area. This supports an upside potential of 1 billion barrels of oil in the South Lokichar Basin. Plans for further exploration drilling to test this upside will be evaluated during the first half of 2016.
1
Outside of the South Lokichar Basin, frontier exploration activity continued in 2015. Three potential basin opening exploration wells were drilled across Tullow's extensive Kenyan acreage in the North Kerio (Epir-1), North Turkana (Engomo-1) and North Lokichar (Emesek-1) Basins. While none of the wells were discoveries, they have provided valuable data to assess the wider prospectivity of the basins. There is significant remaining exploration potential in the basins outside of South Lokichar and future basin opening exploration drilling plans are currently being evaluated.
The Cheptuket-1 exploration well in Block 12A spudded on 28 December. The well will test a basin bounding structural closure in the undrilled Kerio Valley Basin, in a similar structural setting to the successful Ngamia and Amosing discoveries in the South Lokichar Basin. Cheptuket-1 will likely complete drilling in late February after which the PR Marriott Rig-46 will demobilise, marking the end of the current drilling campaign.
In November, Tullow agreed to farm down 25 per cent of its 65 per cent operated working interest in Block 12A to Delonex for a carry. This farm-down was completed on 28 January 2016.
PR Marriott Rig-46 at the Etom-2 well site, Kenya
In Uganda, all appraisal activities and pre-FEED studies have been completed. Significant progress has been made on several fiscal matters and in June 2015, the Government of Uganda announced that it had amended the VAT Act to exempt oil exploration and development from VAT. Later in June, Tullow announced that it had agreed to pay the Uganda Revenue Authority \$250 million in full and final settlement of its CGT liability for the farm-downs to Total and CNOOC completed in 2012. This sum comprises \$142 million that Tullow paid in 2012 and \$108 million to be paid in three equal instalments. The first of these was paid upon settlement and the remainder will be paid in 2016 and 2017. These decisions are important steps towards the sanction of the Lake Albert development. In July 2015, Tullow prequalified for the upcoming Uganda exploration bid round and evaluation is currently under way ahead of the 26 February bid deadline.
Good progress continues to be made on development planning in Kenya. A draft Field Development Plan was submitted to the Government of Kenya in December and will inform discussions as we progress towards potential FID of both the Kenya and Uganda upstream development projects and preparation for FEED is under way in both countries. Scoping studies and terms of reference for the detailed upstream environmental and social impact assessments were submitted to the regulatory authorities in both countries.
In August 2015, a bilateral agreement was reached between the Presidents of Uganda and Kenya adopting the Northern Kenya route for the regional crude oil pipeline, subject to certain conditions. These conditions, which include ensuring that this is the lowest cost route, are being worked on by both Governments in conjunction with the Kenyan and Ugandan upstream parties.
Over 2015, Tullow has undertaken a strategic review of its New Ventures portfolio to determine how it can best use this period of reduced industry exploration activity to prepare for future growth. The focus has been on enhancing Tullow's licence and prospect inventory in preparation for increasing drilling activity in future years. The Group has also been actively managing its current equity positions and exposure to drilling costs across the portfolio through various transactions for carried interests. A number of farm-downs are under way across the portfolio and this work will continue in the coming year. In 2016, our main focus will be to continue to selectively replenish and high grade the exploration portfolio for future growth.
In Mauritania, 2D seismic was acquired in the Block C-3 licence during the first quarter of 2015. Tullow is hopeful of acquiring a new 3D survey across the shelf prospectivity in Blocks C-3 and C-10 during the next 12 to 24 months, to determine the exploration potential of both licences and areas for future exploration activity. In June 2015, the Group agreed to farm down a 13.5 per cent interest in Block C-10 to Sterling Energy.
In Guinea, discussions have been ongoing with the Government and our Partners regarding the resumption of petroleum operations. SCS Corporation, a subsidiary of Hyperdynamics Corporation, has unilaterally declared these discussions to be at an impasse and has commenced legal Drilling at Amosing discovery, Kenya action against the other members of the joint venture.
In Gabon, further 3D seismic data was acquired during Q1 2015 in the Arouwe block, the results of which are currently under review. In Namibia, interpretation of the 3D survey across the PEL30 and PEL37 licences has yielded significant prospectivity in shallow water in close proximity to the Wingat well in the adjacent licence which encountered oil in the Cretaceous.
Tullow has been active in the South America and Caribbean region in 2015, an area the Group considers to have great potential. In Suriname, a 4,000 sq km 3D seismic programme of the Tullow-operated offshore Block 54 completed in September 2015. This was followed by a 20 per cent farm out of Block 54 in October 2015 to Noble for a carry, leaving Tullow with a 30 per cent interest and retained operatorship. Tullow and its partners are reviewing the very encouraging results of the seismic programme ahead of selecting future drilling prospects. In the neighbouring Block 47, a two-year licence extension has been granted and a drop core survey is planned to be completed in 2016. The Spari-1 well in offshore Block 31 was completed in August 2015 and was subsequently plugged and abandoned. Despite the presence of targeted Campanian turbidite sands in the well, no significant hydrocarbon shows were encountered.
In Guyana, Tullow and its Partners continue to evaluate and map prospectivity in the offshore Kanuku licence and an 18 month extension has been requested to allow a new 3D survey to be acquired. In early 2016, Tullow was awarded a 60 per cent operated interest in the Orinduik licence, a 1,801 square kilometre block offshore Guyana. Both of Tullow's Guyana licences sit close to Exxon Mobil's 'Liza' oil discovery which was announced in 2015.
In Jamaica, a 2D seismic survey is under way over the 32,056 sq km Walton Morant licence and will be completed in the first quarter of 2016 to delineate potential plays in shallow water. In Uruguay, good progress has been made in mapping the large 3D dataset and a number of prospects have been identified.
BGP Challenger at quayside prior to 2D seismic survey in Jamaica
1
South American Exploration team members, Dublin
Exploration activity continued offshore Norway in 2015 with the non-operated Bjaaland, Zumba and Salander wells. All three wells were unsuccessful and were plugged and abandoned. Tullow actively managed its equity position and exposure to drilling costs in Norway and the Group reduced its equity in the Zumba well from 60 per cent to 40 per cent (paying 32.5 per cent) and farmed out its remaining 20 per cent interest in the unsuccessful Hagar well in PL650, ahead of drilling for a cash payment.
In Norway, the Group made applications in the 23rd licensing round and was recently awarded eight licences in the 2015 APA licence round. In 2016, four wells are planned to be drilled to test the Cara prospect adjacent to the Gjoa field, the Rovarkula prospect adjacent to the Ivar Hansen field, the Rome well adjacent to the Johan Sverdrup field and a recently spudded horizontal well in the Wisting Discovery.
The Kup-1 well in the Kalchas block in Pakistan, in which Tullow has a 30 per cent non-operated stake, reached total depth in December 2015. Over 400 metres of weak gas shows were encountered in fractured sandstone reservoirs and a drill stem test programme has commenced to establish hydrocarbon presence and productivity. In January 2016, Tullow agreed to sell a 20 per cent interest in the Bannu West licence in Pakistan to Mari Petroleum. The deal is subject to Government approval.
Tullow continues to focus on driving down costs and capital expenditure to maintain liquidity and deliver our operational commitments.
The challenging business environment that the oil and gas sector is experiencing and the requirement to fund the capital intensive TEN Project, have meant that maintaining strong liquidity has been a key priority for Tullow in 2015. The combination of our excellent hedging programme, the suspension of our dividend, expanding the capacity of our debt facilities, cutting exploration capital expenditure and going through a significant cost cutting exercise has enabled Tullow to maintain liquidity.
Maximising our cash flow has been key and we have benefited significantly from our hedging programme, which has contributed some \$365 million to the revenue of the business in 2015. The hedging programme will continue to provide future cash flow benefits to the business and the mark-to-market value of the hedges looking forward at the end of 2015 was \$623 million.
A focus on cost savings and improving efficiency has also positively benefited our cash flows. We initiated the Major Simplification Project at the end of 2014 and forecast that over the next three years from mid-2015, we will generate around \$500 million in cash cost savings. In addition to cost savings incurred through headcount reductions and associated costs, our contract and procurement teams are working hard with suppliers to deliver savings on current and future contracts, which will reduce expenditure in the years to come and improve the profitability of our business.
At the end of 2014, we made a decisive shift in our capital allocation to prioritise key development projects that generate current and future high margin production for the business. I am pleased to say that our West Africa portfolio of oil producing fields met their production targets for the year and were largely responsible for the \$1 billion of pre-tax operating cash flow that the Group generated in 2015. The largest single element of our 2015 \$1.7 billon capital expenditure was the \$900 million investment in the TEN Project. This development has been expertly executed and remains on schedule and on budget for first oil in July/August 2016. The completion of the TEN Project will end the current capital intensive period and this is reflected in our lower 2016 capital expenditure forecast of up to \$1.1 billion, with work ongoing to potentially reduce this to \$0.9 billion.
Having ensured we maximise our current and future cash flows, the final element of our strategy of maintaining a strong liquidity position has been ensuring our lending banks continue to support the business. I am once again pleased to report that we completed the two routine re-determinations in 2015 and, due to the long-term, high-quality oil assets in the portfolio, we were able to increase the debt capacity of the RBL and Corporate Facility in March by \$450 million. As a result we have exited 2015 with headroom facility capacity and free cash of around \$1.9 billion, providing sufficient headroom to take the TEN Project to first oil in mid-2016. Whilst net debt at the year end was \$4.0 billion and our net debt to EBITDAX ratio was 4 times, it is not our intention to continue at this high gearing level. The longterm aspiration of the Group is to run the business at around 2 times net debt to EBITDAX and that target remains. We intend to achieve this organically over time through our high-margin West Africa oil production and continued disciplined capital allocation. We can decrease our capex if market conditions fail to improve and our portfolio will generate free cash flow even at very low oil prices. We intend to accelerate de-leveraging through strategic portfolio management, which has always been a key part of Tullow's strategy and will remain so in the coming years.
| 2015 | 2014 | Change | |
|---|---|---|---|
| Working interest production volume (boepd) | 73,400 | 75,200 | -2% |
| Sales volume (boepd) | 67,600 | 67,400 | 0% |
| Realised oil price (\$/bbl) | 67.0 | 97.5 | -31% |
| Realised gas price (p/therm) | 41.8 | 51.7 | -19% |
| Sales revenue (\$m) | 1,607 | 2,213 | -27% |
| Cash operating costs (\$per boe) | 15.1 | 18.6 | -19% |
| Exploration write-off (\$m) | 749 | 1,657 | -55% |
| Impairment of property, plant and equipment (\$m) | 406 | 596 | -32% |
| Operating loss (\$m) | (1,094) | (1,965) | 44% |
| Loss before tax (\$m) | (1,297) | (2,047) | 37% |
| Loss after tax (\$m) | (1,037) | (1,640) | 37% |
| Basic loss per share (cents) | (113.6) | (170.9) | 34% |
| Cash generated from operations (before working capital) (\$m) | 967 | 1,545 | -37% |
| Operating cash flow (before working capital) per boe (\$/bbl) | 35.9 | 56.1 | -36% |
| Dividend per share (pence) | – | 4.0 | – |
| Capital investment (\$m) | 1,720 | 2,020 | -15% |
| Net debt (\$m) | 4,019 | 3,103 | 30% |
| Gearing (net debt/net assets plus net debt) (%) | 56 | 44 | 12 |
Working interest production averaged 73,400 boepd, a decrease of 2% for the year (2014: 75,200 boepd). Growth in low cost West Africa oil production was offset by the end of field life declines in UK gas production, the partial farm-down of the Schooner and Ketch gas fields in October 2014 and the disposal of the Netherlands Q&L blocks in April 2015. Sales volumes for West Africa oil and European gas averaged 60,000 bopd and 7,600 boepd respectively.
On average, oil prices in 2015 were lower than in 2014 due to the oil price falling significantly since the third quarter 2014. Realised oil price after hedging for 2015 was US\$67.0/bbl (2014: US\$97.5/bbl), a decrease of 31% versus a 47% decrease in Brent oil prices over the period. European gas prices in 2015 were lower than 2014. The realised European gas price after hedging for 2015 was 41.8 pence/ therm (2014: 51.7 pence/therm), a decrease of 19%.
Underlying cash operating costs, which exclude depletion and amortisation and movements in underlift / overlift, amounted to \$406 million; \$15.1/boe (2014: \$512 million; \$18.6/boe). The decrease of 19% in underlying cash operating costs per barrel is principally due to increased West African production combined with ongoing cost savings and the impact of the farm-down and disposal in the UK and Netherlands which have higher than average cash operating costs per barrel.
DD&A charges before impairment on production and development assets amounted to \$551 million; \$20.5/boe (2014: \$572 million; \$20.8/boe). The Group recognised an impairment charge of \$406 million (2014: \$596 million) in respect of lower forecast oil and gas prices and an increase in anticipated future decommissioning costs, offset both by impairment write backs in Gabon due to increased reserves and by lower forecast decommissioning costs in the UK. The impairment charge net of tax amounted to \$357 million. The Group recognised an impairment in relation to goodwill of \$54 million (2014: \$133 million).
1
Administrative expenses of \$194 million (2014: \$192 million) include an amount of \$48 million (2014: \$38 million) associated with IFRS 2 – Share-based Payment accruals. The MSP was undertaken during 2015, is on track to deliver cash savings of around \$500 million over a three-year period and has resulted in a workforce reduction of 37% to date.
During 2015, the Group recognised a provision for restructuring costs of \$45 million. After recharges to JV partners the net restructuring cost included in the income statement is \$41 million. This has been presented separately from administrative expenses in the income statement.
| 2015 | 2014 | |
|---|---|---|
| Total costs written off | \$m | \$m |
| Exploration costs written off | (749) | (1,657) |
| Associated deferred tax credit | 277 | 398 |
| Net exploration costs written off | (472) | (1,259) |
During 2015, the Group spent \$256 million, including Norway exploration costs on a post-tax basis, on exploration and appraisal activities and has written off \$130 million in relation to this expenditure. This included write-offs in Suriname (\$28 million), Norway (\$11 million), Kenya (\$28 million) and new venture costs (\$19 million). In addition, the Group has written off \$343 million in relation to prior years' expenditure as a result of a review of future work programmes based on capital relocation to focus on the Group's key development projects and the impact of the current low oil price environment. This included write-offs in the Netherlands (\$186 million), Guinea (\$54 million), Greenland (\$39 million), Ethiopia (\$35 million), Gabon (\$9 million) and Madagascar (\$11 million).
At the end of 2015, Tullow has provided \$186 million for onerous service contracts due to the reduction in planned future activity.
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 2015, the Group's derivative instruments had a net positive fair value of \$623 million (2014: positive \$471 million), net of deferred premium (\$101 million). While all of the Group's commodity derivative instruments currently qualify for hedge accounting, a pre-tax charge of \$59 million (2014: credit of \$51 million) in relation to the change in time value of the Group's commodity derivative instruments has been recognised in the income statement for 2015.
| Hedge position | 2016 | 2017 | 2018 |
|---|---|---|---|
| Oil hedges | |||
| Volume – bopd | 36,511 | 23,000 | 9,500 |
| Average floor | |||
| price protected | |||
| (\$/bbl) | 75.14 | 72.94 | 62.09 |
The net interest charge for the year was \$145 million (2014: \$134 million). The increase in finance costs is associated with an increase in net debt but partially offset by an increase in capitalised interest on the TEN development. The 2015 net interest charge includes interest incurred on the Group's debt facilities 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 \$260 million (2014: \$408 million, credit) relates to a tax charge in respect of the Group's North Sea, Gabon, Equatorial Guinea and Ghanaian production activities offset by the tax credits arising from Norwegian exploration and deferred tax credits associated with exploration writeoffs and impairments. After adjusting for disposals, restructuring costs, exploration write-offs and impairments, the related deferred tax benefit in relation to the exploration write-offs and impairments and profits/losses on disposal, the Group's underlying effective tax rate was 29% (2014: 24%). The increase in underlying effective tax rate is primarily a result of lower PSC income and the tax credit recognised on the derivative financial instruments in 2014.
The loss from continuing activities for the year amounted to \$1,037 million (2014: \$1,640 million loss). Basic loss per share was 113.6 cents (2014: 170.9 cents loss).
In view of the fall in the oil price, the Board suspended the dividend 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 investing these funds into the business.
Operating cash flow before working capital movements decreased by 37% to \$1.0 billion (2014: \$1.5 billion) as a result of reduced sales volumes and lower realised commodity prices partially offset by lower cash operating costs. In 2015, this cash flow together with increased debt facilities helped fund the Group's \$1.7 billion of capital expenditure in exploration and development activities and \$232 million servicing the Group's debt facilities.
| Reconciliation of net debt | \$m |
|---|---|
| Year-end 2014 net debt | (3,103) |
| Revenue | 1,607 |
| Operating costs | (406) |
| Operating expenses | (234) |
| Cash flow from operations | 967 |
| Movement in working capital | 349 |
| Tax paid | 35 |
| Capital expenditure | (2,112) |
| Disposals | 56 |
| Other investing activities | 4 |
| Financing activities | (232) |
| Foreign exchange gain on cash and debt | 17 |
| Year-end 2015 net debt | (4,019) |
2015 capital expenditure amounted to \$1.7 billion (2014: \$2.0 billion) (net of Norwegian tax) with \$1.5 billion invested in development activities and \$0.2 billion in exploration and appraisal activities. More than 80% of the total was invested in Kenya, Ghana and Uganda and over 90%, more than \$1.6 billion, was invested in Africa. Based on current estimates and work programmes, 2016 capital expenditure is currently forecast to be up to \$1.1 billion (net of Norwegian tax), with \$100 million allocated to exploration and appraisal activities and work ongoing to potentially reduce 2016 capital expenditure to around \$0.9 billion.
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 in the Netherlands to AU Energy. The consideration was €64 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% interests in, and the operatorship of, Exploration Licences E10, E11 (including Tullow's Vincent discovery), E14, E15c and E18b.
In the first half of 2015, Tullow increased its commitments under the Revolving Corporate Facility from \$0.75 billion to \$1.0 billion and commitments under the Reserve Based Lending Facility increased from \$3.5 billion to \$3.7 billion. Furthermore, amendments to the financial covenants on the Reserve Based Lending Facility and Revolving Corporate Facility were agreed to address the risk of any potential covenant breach during a period of oil price volatility and investment in production and development assets in West Africa. At 31 December 2015, Tullow had net debt of \$4.0 billion (2014: \$3.1 billion). Unutilised debt capacity and free cash at 31 December 2015 amounted to approximately \$1.9 billion. Total net assets at 30 December 2015 amounted to \$3.2 billion (2014: \$4.0 billion) with the decrease in total net assets principally due to the loss during 2015 from continuing activities.
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. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.9 billion of debt liquidity headroom and free cash at the end of 2015. The Group's forecasts, 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 2015 Annual Report and Accounts.
1
Notwithstanding our forecasts of liquidity headroom throughout the 12-month period, there remains a risk, given the volatility of the oil price environment and its impact on operating cash flows and facility availability, that the Group's liquidity position may deteriorate and/or the Group may become technically non-compliant with one of its financial covenants at the end of 2016.
To mitigate this risk, we will continue to maintain our long-term banking relations and will monitor our cash flow projections and, if necessary, take mitigating actions well in advance to maintain our liquidity and compliance with covenants. Actions available to the Group include further rationalisation of our cost base, cuts to discretionary capital expenditure, portfolio management and other funding options.
Based on this analysis, the Directors have adopted the going concern basis of accounting in preparing the annual Financial Statements.
The principal financial risks to performance identified for 2016 are:
In January 2016 Tullow completed the farm-down of 25% of its interest in block 12A to Delonex and Tullow also agreed to sell a 20% interest in the Bannu West licence in Pakistan to Mari Gas. Tullow was awarded a 60% operated interest in the Orinduik licence in January 2016, a 1,801 square kilometre block offshore Guyana. On 23 January 2016, the TEN FPSO set sail from Singapore to Ghana with arrival expected in early March 2016.
Subsequent to the balance sheet date there has been a deterioration in the spot price of Brent crude. Sensitivity analysis on the impact of a reduction in Brent crude prices on the carrying value of PP&E is provided in note 10.
RESPONSIBLE OPERATIONS
As a responsible operator, Tullow manages non-technical, and above-ground, risks with the same rigour and focus with which it manages the technical challenges of exploring for and producing oil and gas.
We drive continuous improvement in process and occupational safety, environmental and social performance, health management, security, and the protection of human rights, through clear policies, standards and guidelines. These are reinforced by structured assurance activities and ongoing performance management.
Our non-technical risk performance is measured through a KPI made up of our Lost Time Incident Frequency Rate and 14 measures covering occupational and process safety, asset protection, health, environment, social performance and regulatory compliance.
This KPI accounts for 10 per cent of Tullow's Group scorecard for determining Executive Directors' and employees' performance related pay. See pages 17-21 for more information. In 2015, we achieved an overall performance of 7.3 per cent out of a possible 10 per cent for 2015.
For a second year in a row Tullow has reduced its Lost Time Incident Frequency (LTIF). In 2015, we achieved a LTIF of 0.30, which represents a 48 per cent improvement on our 2014 performance.
During 2015, two contracted drilling rigs – one operating in Ghana and the other in Kenya – achieved two years without a Lost Time Incident (LTI). This is a good achievement given that both rigs are in challenging operating environments. This performance reflects the combined efforts of Tullow, our rig contractors, and all service providers.
Notwithstanding these improvements, we regret to report the tragic death of two sub-contractors at the year end and start of 2016. The first involved a sub-contractor temporarily working on the Jubilee FPSO who had contracted malaria. The second involved a TEN FPSO sub-contractor working for the main contractor responsible for the construction and commissioning of the TEN FPSO in the shipyard in Singapore. In-depth investigations into both fatalities have been carried out and specific actions have been identified and implemented to further improve the accurate diagnosis and effective management of malaria symptoms and our oversight of control of work.
In 2015, Tullow carried out improvements to the management of asset integrity on the Jubilee FPSO to ensure we were operating the facility in line with our commitment to the standard of the UK safety case regulatory regime. We reviewed the physical facility, the processes and procedures used to run the FPSO, the organisational structure and the professional competencies of our staff, as well as our approach to maintenance planning.
We had a particular focus on the identification and operation of safety critical elements on the FPSO. We found that in early 2015, we were taking too long to formally assure compliance with operating specifications for a number of these safety critical elements, creating a backlog. To address this, we improved our planning and accelerated work to manage the backlog.
During routine inspection activities a worker was exposed to carbon monoxide levels that resulted in hospitalisation. This was a high potential and IGP Tier 1 Process Safety Incident. The investigations identified many lessons including improved focus on planned sequencing of jobs, risk assessment and toolbox talks, the use of non-standard isolations and gas test requirements.
The Board EHS Committee commissioned an audit of asset integrity during 2015 and found that many of the areas requiring improvement had been identified within the Business Unit and that plans were already being developed to rectify those weaknesses. There were, however, areas requiring additional focus, including how we manage change on the facility and document management for safety critical elements. Action plans are now in place, which are monitored monthly by Senior Management.
Tullow acknowledges the global threat posed by climate change and recognises the need to reduce greenhouse gas (GHG) emissions. Our activities and products contribute to climate change and we accept our responsibility to comply with emerging climate change legislation and regulation, and to reduce our GHG emissions as far as is reasonably practical through appropriate voluntary initiatives.
Demand for energy is forecast to grow, and we expect fossil fuels to continue to play a role in the global energy mix over
the coming decades. We also expect new policies, laws and regulations aimed at reducing emissions of GHGs, and we will adopt a business strategy that responds to these developments. As an Africa-focused company, we will continue to support our host Governments and communities as they seek to use oil revenues to fight poverty and to promote sustainable, inclusive economic development.
Tullow will aim to minimise GHG emissions both in project design and in our operations, and adopt a business strategy that is responsive to legal and regulatory developments
designed to address climate change. We will also maintain transparency in our performance reporting and align our activities with the actions that our host Governments take to manage climate change.
"We made significant progress in 2015 in our performance in Responsible Operations with a reduction in our Lost Time Incident Frequency Rate and improvements across a range of sustainability metrics."
Tullow's Group total scope 1 emissions, which in 2015 included gas and diesel from
our offices as well as emissions from our operations, were 752,539 tonnes CO2 e (2014: 799,5511 tonnes CO2 e) and 122.07 tonnes of CO2 e per 1,000 tonnes of hydrocarbon produced (2014: 123.84 tonnes CO2 e). Total scope 2 emissions were 4,631 tonnes of CO2 e (2014: 4,173 tonnes of CO2 e) and 0.75 tonnes of CO2 e per 1,000 tonnes of hydrocarbon produced (2014: 0.64). Full details of our Basis of Reporting can be found online.
Securing the water we need for development in East Africa will be a challenge for Tullow, especially in the Turkana region of Kenya. The design figure for the maximum amount of water needed for full field development is 24,000 m3 /day. As part of pre-development planning for our projects in Turkana, we are considering a number of options, both underground and surface, for water sourcing and management, with more detailed planning due to take place in 2016. We are committed to working with national, county and local government and all stakeholders in coming up with the best sourcing option for the development.
Tullow is committed to respecting internationally recognised human rights, as set out in the Universal Declaration of Human Rights and the ILO Declaration across our operations.
At the end of 2015, Tullow Kenya conducted an externally-led review of our performance in Kenya against the requirements of the Voluntary Principles on Security and Human Rights (VPSHR), which Tullow works to meet across our global operations. The audit reviewed Tullow's
arrangements with private security providers, who do not carry firearms, as well as the Kenya National Police Service (KNPS).
1
The audit found there had been good progress in efforts to train both private security providers and KNPS staff on the requirements of the VPSHR and concluded
that the training was delivering results. Several opportunities for improvement were noted in the review, including the reporting of security related community grievances. We have also been working towards a formal Memorandum of Understanding covering how Tullow and the Kenyan Government will jointly implement the VPSHR for some years, but this has not yet been achieved. Getting this in place remains a priority as the project approaches the development phase.
Tullow conducted tests of its three tier Crisis Management System during 2015. The system was also tested in real time in Ghana this year when our Accra offices were flooded during some extreme weather. Despite challenges across the city, Tullow was able to resume full operations within 24 hours. A number of lessons were learned from this emergency and our approach to business continuity planning will be a focus area for 2016.
LOST OR REDUCED MAN HOURS RESULTING FROM COMMUNITY RELATED OPERATION STOPPAGES
• % lost/reduced man hours compared to total man hours – Group
• % lost/reduced man hours compared to total man hours – Kenya
In 2015, Tullow overhauled its risk, assurance and performance management processes to better support the delivery of our strategic objectives.
In response to the 2014 amendments to the Corporate Governance Code (the 'Code') relating to risk management, long-term viability and remuneration, your Board believes that we have taken appropriate steps to remain fully compliant with the Code. Our revised approach to risk management is discussed in this section of the report. The long-term viability statement can be found on page 55. We believe that our remuneration policy (set out on page 92), which was approved by shareholders at the AGM in 2014, remains fully compliant. A full review of our compliance with the Code and the Board's activities and performance against its objectives during the year can be found in the Directors' Report on pages 70 to 78.
During 2015, the Board oversaw a major overhaul of Tullow's risk, assurance and performance management processes as part of the Major Simplification Project (MSP). The key objectives were to streamline and simplify decision-making, to clarify roles and responsibilities, and to create clearer accountabilities for enterprise risk management and the delivery of our strategic objectives. An important part of the
MSP was the development of a new Integrated Management System (IMS). The IMS now holds all of Tullow's consolidated mandatory policies and standards in a single, integrated online management system. It represents a systematic way of putting our strategy and values into practice, and it provides a clear and consistent framework that sets out expectations and defines the controls and assurance necessary to ensure that our activities and associated risks are effectively managed. The IMS was formally launched in November 2015 and will continue to evolve and develop during the course of 2016 and beyond.
As part of the overhaul of risk management and assurance processes, the Board approved a new policy and standard that defines an integrated 'top-down' and 'bottom-up' approach to identifying, assessing and managing enterprisewide risks. The governance and reporting of risks is now fully embedded as part of the quarterly business reviews, forms a key element of the Group's performance management, and informs decision-making about internal audit and other assurance priorities. The Board of Directors has carried out a robust assessment of the principal risks facing the Company, including those that would threaten
| BOARD COMMITTEES | ||||
|---|---|---|---|---|
| Audit Committee Responsible for ensuring our Financial Statements give a true and fair view of the business. |
Nominations Committee Ensures the balance of skills and expertise of the Board remains appropriate to meet the needs of the Company. |
EHS Committee Responsible for monitoring and advising on the Group's EHS policies and performance. |
Ethics & Compliance Committee Responsible for promoting good ethical behaviour and ensuring compliance with relevant legislation. |
Remuneration Committee Responsible for determining and agreeing the Executive Directors' remuneration policy. |
| > page 79 | > page 84 | > page 86 | > page 88 | > page 90 |
our business model, future performance, solvency and liquidity. Details of the process and our principal risks are on pages 52 to 63.
The MSP, the new IMS, and the revised risk and assurance framework are fully aligned with our core values of focusing on results, entrepreneurial spirit, teamwork, integrity and respect. However, they will only become fully effective when they are thoroughly embedded within our operations and become simply part of the way we do business. The implementation of the MSP and IMS has therefore involved a high level of staff engagement and discussion. Early indications that the new approach is gaining acceptance and approval within the business are encouraging.
During 2015, as part of our ongoing monitoring efforts to improve our compliance processes, and to reflect best practice and lessons learnt from internal investigations, we also updated a number of our IMS standards relating to ethics and compliance. We replaced the existing executive Compliance Committee with a formal Board Committee, chaired by Ann Grant, the Senior Independent Director. The formation of this Committee underlines our commitment to uphold the highest standards of integrity and recognises that ethical behaviour, like safety, must be an area of constant focus. In November, the launch of our revised and improved Code of Ethical Conduct was accompanied by a Companywide communication campaign and training programme, which will continue throughout 2016. So far, approximately 40 per cent of employees and contractors attended fraud risk assessment workshops during the year, to raise awareness of the risk and encourage early detection.
Tullow's reputation as a fair, ethical and responsible company is dependent upon our employees' and contractors' behaviour and the values they exhibit in their day-to-day work. Any member of staff, contractor or supplier can raise concerns about inappropriate behaviour via internal channels or our independent, confidential reporting line,
Safecall. Concerns raised during exit interviews and via Safecall are also investigated and any recommendations arising, for updates and improvements to our internal processes and procedures, are applied across the Group. Notwithstanding these efforts, 19 members of our workforce and sub-contractors left the Group and had their contracts terminated as a result of investigations carried out during the year. Whilst it is clearly regrettable that such actions should be necessary, they underscore Tullow's commitment to comply with our Code of Ethical Conduct.
1
During 2015 we continued to engage with Governments, international development agencies, international think tanks, academia and civil society to identify and discuss policy issues relevant to the sustainability of Tullow's business model. These initiatives have built upon established themes of transparency, natural resource revenue governance and capacity-building, as well as new initiatives seeking to better understand the relationship between resources-led economic growth and climate change in our countries of operation. Tullow has sought to gain a better understanding of the issues in order to develop a strategic response that meets the requirements of our shareholders and our broader responsibilities to other stakeholders.
We have continued to focus on the development of technical and vocational training for the oil and gas industry in East Africa by supporting the scoping stages of the Skills for Oil and Gas in Africa (SOGA) project, initiated by the UK's Department for International Development in Kenya and Uganda. In Kenya, we also helped to establish the Turkana Focus Forum, which brings together industry, NGOs, development partners and other bodies with the aim of coordinating the many initiatives that are under way to manage the impact and to maximise the social and economic benefits arising from resources-led development in the country.
Chairman 9 February 2016
Simon Thompson (age 56, 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.
Nominations Committee (Chair), Remuneration Committee and EHS Committee.
Simon is Chairman of 3i Group plc and a non-executive Director of Rio Tinto plc.
Aidan Heavey (age 62, 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.
Ian Springett (age 58, 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, CFO for the United States and also served as a Business Unit Leader in Alaska.
Ethics and Compliance Committee.
Graham Martin (age 61, British) is a solicitor (admitted in England and Wales) and joined Tullow as Legal and Commercial Director in 1997. Graham served as Tullow's General Counsel from 2004 to 2013 and as Company Secretary from 2008 to 2015. Graham has over 30 years' experience in international corporate and energy transactions.
Graham retired as Company Secretary in December 2015. He will retire as an Executive Director and leave the Company following the Annual General Meeting on 28 April 2016.
Paul McDade (age 53, British) was appointed to the Board of Directors in 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. 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.
Committee membership EHS Committee.
Angus McCoss (age 54, British) was appointed to the Board of Directors in 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 67, 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.
Ethics and Compliance Committee (Chair), Audit Committee and Nominations Committee.
Ann is a Board member of the Overseas Development Institute and a council member of the London School of Hygiene and Tropical Medicine as well as the Rift Valley Institute. She also chairs the Serious Music Trust.
Tutu Agyare (age 53, 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.
Audit Committee, Nominations Committee and Remuneration Committee.
Tutu is a director of the Nubuke Foundation, a Ghanaian-based cultural and educational foundation. Tutu is also a Senior Advisor to Power Africa, an initiative launched by the Obama administration to increase access to electricity in Africa.
Steve Lucas (age 61, 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.
Audit Committee (Chair), Nominations Committee, Remuneration Committee and Ethics and Compliance Committee.
Steve is a non-executive Director of Acacia Mining plc (UK) and is the Senior Independent Director (non-executive) of HTN Towers plc.
Anne Drinkwater (age 60, 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.
EHS Committee (Chair), Audit Committee, Remuneration Committee and Nominations Committee.
Anne is a non-executive Director of Aker Solutions ASA (Norway) and is an oil and gas advisor to the Government of the Falkland Islands.
Jeremy Wilson (age 51, 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.
Remuneration Committee (Chair), Nominations Committee and Audit Committee.
Jeremy is a non-executive Director of John Wood Group PLC (UK).
Mike Daly (age 62, 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.
Audit Committee, Nominations Committee and EHS Committee.
Mike is a visiting Professor at the University of Oxford and a Senior Director at Macro Advisory Partners. Mike is also a nonexecutive Director of CGG, an integrated geoscience company based in France, which is listed on the Euronext and New York Stock Exchanges.
Kevin Massie was appointed Company Secretary on 1 January 2016, following Graham Martin's resignation as Company Secretary. Kevin was previously Corporate Counsel and Deputy Company Secretary at Tullow.
| Audit Committee | 79 |
|---|---|
| Nominations Committee | 84 |
| EHS Committee | 86 |
| Ethics & Compliance Committee | 88 |
| Remuneration Committee | 90 |
Strong and effective risk management is an integral part of running our business. Over the past year, Tullow has adopted a more rigorous and consistent approach to managing risks across the Group and rolled out an enhanced integrated enterprise-wide risk management process.
Managing risk is an integral part of our everyday business and we believe that risk management should be embedded in our processes and procedures that we use to run our business. Effectively managing risk across the Group is a competitive necessity and fundamental to creating and maintaining shareholder value. An effective and joined up risk management framework enhances Tullow's ability to achieve its strategic objectives, and helps to 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 a sound risk management and internal control system. As part of that system, the Board determines principal risks and sets respective risk tolerance/appetite levels. 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's and manager's job
• Internal risks associated with inadequate strategy and external risks associated with external competitive, political and social business environment
• Board
• Aidan Heavey, Chief Executive Officer, Paul McDade, Chief Operating Officer, and Ian Springett, Chief Financial Officer
• Financial risks arising from adverse market conditions and reporting risks from unreliable or inaccurate information and reporting procedures
• Board, Audit and EHS Committees
• Ian Springett, Chief Financial Officer
to manage the day-to-day risks the Group may face. They are responsible for identifying the risks, assessing their impact and determining their consequence for the business. Appropriate actions are then taken to manage the risk to an acceptable level defined by the Board.
Historically, Tullow has always managed its risks and this has not changed. However, in the past year the Board has implemented a number of actions to re-assess and further improve Tullow's risk management framework. These actions were part of the Group's overall organisational design review that took place during the Major Simplification Project (MSP) and, as a result, the following enhancements have been made:
• Defined its risk appetite to clearly communicate the level of risk the Board is willing to take in pursuit of its strategy;
1
In order to ensure complete and systematic identification of risks and to ensure commonality of risk definitions across the Group, the Group maintains a 'Risk Universe', which holds an extensive collection of potential risks that could impact the Group's performance. These risks are separated into four broad categories: Strategic, Financial, Operational and Compliance. 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.
• Organisation & Human Resources, Health & Safety, Information systems, Technical and Exploration
• Operational risks that ultimately impact our business delivery, performance, stakeholders and reputation
• Board, Audit, EHS and Remuneration Committees
• Aidan Heavey, Chief Executive Officer, Paul McDade, Chief Operating Officer, and Angus McCoss, Exploration Director
• Legal, Ethics & Compliance
• Legal & Compliance risks arising from unethical behaviour or violation of applicable laws and regulations.
• Ethics & Compliance Committee
• Aidan Heavey, Chief Executive Officer, Ian Springett, Chief Financial Officer
The Group's 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 their business level, which is formally reviewed on a quarterly basis at their business performance review. The risk register identifies all key inherent risks facing the Group, taken from the Tullow Risk Universe. These inherent risks are then assessed at both an inherent and residual level, to determine the strength of existing controls and mitigating actions and the required treatment action for each risk. 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 and after consideration of the Group's defined risk appetite.
Risks are assessed on two scales: a) according to their likelihood and b) by their potential impact on the Group, not just financially, but also in terms of safety, reputation and regulatory impact. The risk registers are consolidated upwards to the Group who then prepare a Group risk register, identifying the 'principal' risks facing the Company. The risk register, its method of preparation and the operation of key controls are periodically reported to the Executive and the Audit Committee.
The risk management process is 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.
The Board is responsible for setting the Group's risk appetite, acceptable risk tolerance levels and putting in place a mechanism to monitor compliance with these agreed tolerances. A number of enterprise-wide risk workshops attended by the Executive Directors, BDT VPs and Group Functional VPs were undertaken in 2015, to agree the principal risks and discuss and set the right risk tolerances for each risk.
In considering the Group's risk appetite, the Board has reviewed the risk process, 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 going to be kept under regular, at least annual, review to reflect the current external and market conditions.
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, as described on pages 55 to 63, 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, but severe scenarios, and combinations thereof, and 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.
1
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 reductions in operating and capital expenditure, portfolio management and other funding options. 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 the Board's assessment, there remains a risk, given the volatility of the oil price environment and the crystallisation of a combination of the Group's principal risks, that the Group's liquidity position may deteriorate and the Group may become technically non-compliant with one of its financial covenants during the assessment period. To mitigate this risk, the Group will continue to monitor our cash flow projections and, if necessary, take appropriate action with the support of our long-term banking relationships.
Tullow's principal risks are listed in the following tables. Internally, the Group monitors and mitigates a more substantive list of risks, but those listed are the risks currently considered to be the most important because of their likelihood, the magnitude of their potential impact, frequency on the Executive's agenda, or a combination of these reasons.
| Risk and Executive responsibility STRATEGIC |
Link to business model | Potential impact |
|---|---|---|
| 1 Strategy not fully achievable in sustained low oil prices Aidan Heavey, Chief Executive Officer |
Sustainable long-term value growth |
• Tullow may be unable to deliver value growth during a period of sustained low oil price • Inability to deleverage the business |
| 2 Inability to progress major portfolio management options Ian Springett, Chief Financial Officer |
Finance & Portfolio Management |
• Inability to execute strategic farm downs or divest non-core assets • Potential over concentration of risk in some areas • Increased exposure to capex and decommissioning costs • Write down on acquired assets, over-investment in mature assets for low returns, using capital that could be better invested elsewhere • Reputational harm |
| 3 Impact on TEN expected value due to border dispute between Ghana and Côte d'Ivoire Paul McDade, Chief Operating Officer |
Development & Production | • Loss of some of TEN reserves/ facilities and contractual rights if ITLOS decision moves maritime border and part of the field is in Côte d'Ivoire waters |
| 4 Impact on TEN expected value due to delayed delivery Paul McDade, Chief Operating Officer |
Development & Production | • Delay in production start up and revenue build up which impacts financial performance and reputation |
| Mitigation and assurance | 2015 outcomes and ongoing actions | |
|---|---|---|
| • Tullow may be unable to deliver value growth during a period of sustained |
• Robust planning of strategy and business plan which is reviewed and approved by the Board |
• Improved Group capital allocation process and reporting |
| • Inability to deleverage the business | • Business plan includes options/alternatives for lower oil prices that underpin the agreed strategy |
• Continued review of cost structure post MSP |
| • Strict capital allocation process in line with agreed business plan • Rigorous monthly performance management and reporting to track delivery |
• Test and retain options for increased EBITDA delivery • Focus on deleveraging options |
|
| • Regular investor meetings with Executive to gain feedback and challenge |
||
| • Inability to execute strategic farm downs or divest non-core assets • Potential over concentration of |
• Maintain a highly competent transaction capability • Conduct regular portfolio assessments with the Board as part of the annual strategy review • Adhere to relevant commercial and investment appraisal standards, |
• Initiated bi-annual portfolio reviews with Business Delivery Teams • Portfolio review is part of the Board's agendas |
| • Increased exposure to capex and • Write down on acquired assets, over-investment in mature assets for low returns, using capital that could be better invested elsewhere |
and review of all major acquisition or divestment proposals • Follow approval process with the Executive Directors and the Board for any major decisions and new country entry to ensure a suitable amount of screening, challenge and justification • Conduct post-transactions reviews, whether completed or aborted |
• Improve quality of portfolio analysis • Execute current strategic portfolio plan • Progress and operate current operations efficiently in order to gain maximum value |
| • Regularly monitor the ITLOS case, analysing claims with expert counsel assistance |
• Case progressed in line with schedule defined by ITLOS |
|
| facilities and contractual rights if ITLOS decision moves maritime border and part of the field is in |
• Work closely with the Government of Ghana to fully understand the potential impacts of movement in border and encouraging continued dialogue between both countries • Providing technical support and materials as requested • Identifying other uses for rigs to avoid periods of inactivity |
• Scenario analysis • Alternative projects for planned rig usage |
| • Delay in production start up and revenue build up which impacts financial performance and reputation |
• Effective project management driven by execution plan and competent professional project team • Assurance plans and stage gated project delivery system in place, including delivery of independent operations readiness and assurance audits • Regular project meetings with Tullow leadership and major contractors |
• Project over 85% complete in February 2016, on track and on budget • Continued tracking of project plan progress with necessary interventions • Series of workshops with TEN team and major contractors • Continually identifying and mitigating new risks if they occur • Bi-monthly project steering group meetings • Business transition plan |
| Risk and Executive responsibility | Link to business model | Potential impact |
|---|---|---|
| 5 Failure to adequately manage stakeholder relationships Aidan Heavey, Chief Executive Officer |
Responsible Operations Shared Prosperity |
• Restrictions to operations, leading to significant variances in financial forecasts • Contractual or regulatory change could impact the viability of projects • Portfolio of assets affected by licence withdrawals or expropriation • Reputational damage and loss of social licence to operate • Fines, penalties or criminal prosecution |
| FINANCIAL | ||
| 6 Insufficient liquidity and funding capability Ian Springett, Chief Financial Officer |
Finance & Portfolio Management |
• Excessive leverage could lead to the Group being unable to meet its financial obligations • Constrains ability to raise further debt |
| 7 Failure to manage oil price risk |
Commodity price volatility could reduce cash flow and asset value by reduced: |
|
| Ian Springett, Chief Financial Officer |
Finance & Portfolio Management |
• Revenues • EBITDA • Debt capacity • Funding to support investment programme |
| OPERATIONAL | ||
| 8 Loss of production revenue from Jubilee Paul McDade, Chief Operating Officer |
Development & Production | • Loss of some or all of Jubilee production revenue for an extended period of time due to the failure of critical equipment |
| Mitigation and assurance | 2015 outcomes and ongoing actions | |
|---|---|---|
| • Restrictions to operations, leading to significant variances |
• Non-Technical Risk Standard sets minimum requirements for stakeholder management |
• Fully embedded Non-Technical Risk Standard |
| • Contractual or regulatory change could impact the viability of projects |
• A quarterly political risk driver analysis is completed in partnership with the Business Units |
• Develop 'landscape level solution' plans that map and articulate |
| • Portfolio of assets affected by licence | • Country Strategy Papers, alongside stakeholder engagement plans, provide context and a framework |
integrated solutions for complex risks • Develop an approach and plan to |
| withdrawals or expropriation • Reputational damage and loss |
• Skilled, experienced and competent staff are embedded in Business Units and the Corporate Centre provides strategic advice and assurance |
obtain agreements with communities • Develop a system to manage Group Regulatory and non-Supply Chain |
| • Fines, penalties or criminal | • Safety, Sustainability and External Affairs (SSEA) scorecard monitors certain leading and lagging indicators of effectiveness such as work stoppage man hours/total man hours, % closure of grievances |
(SC) agreement compliance aligned to the Non-SC Agreement Management Standard |
| • Excessive leverage could lead to the Group being unable to meet |
• Prudent approach to diversified debt and equity, with a balance maintained through business planning and |
• \$450 million additional bank commitments secured in 2015 |
| • Constrains ability to raise further debt | performance management processes • Finance standard in place to ensure debt funding is optimised |
• Strength of assets retained debt capacity despite fall in oil prices |
| for all assets and projects • The Board reviews and approves the financial strategy, the funding |
• 2015 year end facility headroom and free cash of \$1.9 billion; net |
|
| position and policy targets • Short-term and long-term cash forecasts are reported to Senior Management and to the Board on a regular basis |
debt of \$4 billion • Mark-to-market value of hedging instruments \$623 million at end 2015 |
|
| • Regular monitoring of maturities of facilities, and relationships with lending banks and debt capital investors continually developed |
• 2016 financing initiatives in progress; discussions under way with |
|
| • Significant hedging policy adopted to protect against oil price volatility | commercial banks to consider possible refinancing/amendments to the RBL and RCF facilities |
|
| • Capital allocation process implemented to meet funding targets |
||
| • Board approved hedge programme to protect against low oil prices • Programme is monitored monthly and communicated to the Board |
• Mark-to-market value of hedges at the end of 2015 was \$623 million |
|
| • Hedging programme must be executed in accordance with the policy, with approvals sought ahead of execution |
• Approximately 52 per cent (64 per cent post-tax) of 2016 entitlement oil production hedged at an average floor price of \$75/bbl |
|
| • Funding to support investment | • Value of hedges support EBITDA and contribute to debt capacity under the RBL |
|
| • Loss of some or all of Jubilee production revenue for an extended |
• Ongoing Production Loss Reporting and Root Cause Analysis to identify actions and prevent issues reoccurring |
• 2015 gross production averaged 102,600 bopd |
| period of time due to the failure of | • Integrity, operations and competency systems in place, supported by critical spares and strategy and competency certification for all |
• Ongoing analysis of FSPO systems to strive for top quartile reliability |
| core crew • External and internal assurance programme |
• Jubilee Asset Integrity Audit completed in 2015 |
|
| • Appropriate standards and plans in place | • Implementation of Asset Integrity Improvement Plan |
|
| • Weekly review of maintenance, fortnightly Asset Integrity Improvement Steering Committee, monthly Asset Integrity Management meetings and analysis by both Business Unit and Group Operations |
• Improvements to Competency Assessments |
|
| • Purchase of critical spare equipment as per agreed spares strategy |
| Risk and Executive responsibility | Link to business model | Potential impact |
|---|---|---|
| 9 Major operational incident Paul McDade, Chief Operating Officer |
Development & Production | Major failure in Tullow operated asset results in: • multiple fatalities or serious injuries • environmental damage or pollution • asset damage or remediation • mitigation costs and compensation • reputational damage |
| 10 Inability to replenish exploration portfolio Angus McCoss, Exploration Director |
Exploration & Appraisal | Failure to replenish exploration acreage or fund new ventures results in: • poor or no queue of drill-ready prospects • failure to deliver key element of growth strategy |
| 11 Major cyber or information security incident Angus McCoss, Exploration Director |
Governance & Risk Management |
A compromise could lead to: • disruption to or halt of critical business systems • loss or theft of confidential information, competitive advantage and intellectual property • financial and/or reputational harm |
| Mitigation and assurance | 2015 outcomes and ongoing actions |
|---|---|
| During exploration and appraisal: | • Jubilee Asset Integrity Audit |
| • Early well design and planning screening for new exploration opportunities |
completed in 2015 • Group-wide Well Delivery Process |
| • Well risk profiles reviewed by Senior Management • Well design, process and equipment in accordance with Well Design and Operations Standard, Well Control Standard and associated procedures During development and production: • Minimum asset integrity, maintenance and planning requirements mandated through Production Operations Standard and associated procedures • Use of computer-based maintenance systems and leading corrosion management application system • Independently verified Safety Case and Cases to Operate procedure |
Audit completed • Ongoing compilation of Asset Integrity Action Plans • Competency reviews and regular monitoring of key data and procedures to identify gaps or losses • Identify and action improvements to Competency Assessments • Ongoing audit of implementation and effectiveness of mitigation controls and actions |
| Overall: • Vigorous assurance processes both internally and externally • Operations risk insurance coverage • Jubilee Asset Integrity Project Improvement Steering Committee meets fortnightly • In case of incident, contingency/containment plans e.g. emergency response procedures, with contracts in place for third-party support |
|
| • New opportunities are considered against existing portfolio to maintain diversity of prospects • Funding is limited and exploration portfolio reviewed annually • BDTs, in particular New Ventures, tasked with actively seeking and pursuing opportunities • Exploration and Appraisal Values Controls Standard in place • Exploration and Development Geosciences Executive team work with BDTs and Commercial team on portfolio planning • Corporate Centre assurance programme and central store of all exploration data • Twice-yearly review of exploration prospect inventory and tracking of net prospective risked resources |
• New licence granted in Guyana • Farm-down of licences in Suriname, Norway, Mauritania • Review of New Ventures strategy • Geoscientists focused on seismic interpretation to decipher best prospects • Ongoing farm-downs to reduce Tullow equity earlier in licence cycle to gain carries and reduce costs |
| • Advanced Security Operations Centre (ASOC) provides global monitoring, analysis, alerting and incident response • Bespoke advanced security equipment is used at key operations sites which are continually updated with relevant intelligence • Active member of Cyber Information Sharing Partnership (CISP) and maintain key government relationships which provide alerts or response to hidden threats • Third-party specialists analyse potential areas of weakness and provide network assurance activities • Group-wide awareness training, aligned with Information Security Standard, conducted across Tullow's business and operations |
• Ongoing Group-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 |
1
| Risk and Executive responsibility | Link to business model | Potential impact |
|---|---|---|
| 12 Failure to retain or develop key staff Aidan Heavey, Chief Executive Officer |
Organisation & Culture | • Key skills and experience are not available internally, impacting delivery of the business plan • Staff turnover increases resulting in recruitment costs and possible buy-in of short-term contractors • Disengaged workforce not aligned with culture of efficiency, performance management and cost consciousness • Localisation and organisational plans may not be delivered, affecting relationships with national governments • Competitors recruit Tullow staff |
| COMPLIANCE | ||
| 13 Major breach of business or ethical conduct standards Aidan Heavey, Chief Executive Officer Ian Springett, Chief Financial Officer |
Governance & Risk Management |
• Unethical behaviour breaches anti-corruption laws • Investigations result in reputational damage • Cost impact through investigation costs and fines • Senior Officers liable under UK Bribery Act |
| Mitigation and assurance | 2015 outcomes and ongoing actions | |||
|---|---|---|---|---|
| career progression Operations Committee meetings management meetings • Annual Employee Engagement Survey • Annual review of reward package |
• Nominations Committee focus on diversity plan • Monthly reporting to Executives of HR analytics and Executives, with key deliverables set each year |
• Bi-annual performance and development cycle, with functions and BDTs responsible for their employees' development and • Succession planning, localisation and diversity objectives are set and being actively progressed and key targets monitored • Organisation structure designed for HR Business Partner to report key staff data including resignations through the line to BDT and functional discipline and to the HR function • Organisation Strategy & Effectiveness (OSE) VP attends weekly • Key people data reported to monthly and quarterly performance • A staff engagement plan is agreed with HR, Communications |
• Revised organisation design with clear accountabilities • Embedded performance management framework • Increased focus on staff engagement to embed culture • Implementation of employee engagement plan • Re-structured HR Delivery & Reward team to ensure higher level of capability and experience • Review of total reward for all employees planned in 2016 and one-off Exceptional Share Award made in 2015 • Diversity plan defined with actions in place for 2016 |
|
| certification process carried out with all staff with online G&H register available to all staff procedures in place, adhered to and maintained |
• Implementation of the Tullow Code of Ethical Conduct, with annual • Gifts and Hospitality (G&H) Standard adhered to and maintained, • Other relevant Ethics & Compliance standards, policies and • Leadership leading by example and advocating good behaviour • Dedicated Ethics & Compliance Advisors in key Business Units |
• Updated Code of Ethical Conduct • Established Ethics & Compliance Board sub-committee • Ongoing development of a monitoring and assurance plan to be used by Business Units • Planned development of an e-learning solution to continue to promote the |
||
| contractors and other counter-parties | • Appropriate anti-bribery and corruption provisions in agreements with service providers, contractors and other counter-parties |
• Appropriate due diligence carried out in relation to service providers, | Code of Ethical Conduct • Fraud Risk Awareness provided to 591 staff • Achieved 100 per cent completion of the self-certification of compliance |
with the Code of Ethical Conduct
1
Despite the challenges of the downturn for Tullow and the industry, we ended 2015 with a new organisational structure that makes us more efficient, providing clearer lines of responsibility and accountability inside the business.
Tullow and the industry faced a year of significant challenge during 2015. Initiated ahead of the fall in oil price in 2014, work on our Major Simplification Project (MSP) dominated much of the year, leading to a restructuring aimed at driving efficiency and simplicity across the business, with clearer lines of accountability. The ultimate aim of the programme was to enhance shareholder value; make Tullow a more engaging and rewarding workplace for our staff; and over a three-year period, we expect to secure \$500 million in cost savings.
While there is more work to be done to embed the changes, it has already resulted in greater efficiency and a culture focused on better cost management and more regular and rigorous review and challenge of performance.
We have implemented a new three-pillar organisational operating model, comprised of three Business Delivery Teams (BDTs), a corporate centre and a team which delivers services requested by the BDTs across the whole organisation. Now, we have clearer lines of
Total workforce in 2015 was 1,403 (2014: 2,042) with 1,156 permanent staff (2014: 1,595) and 247 contractors (2014: 447). While Tullow's workforce has been reduced, we have also focused on engaging, reinvigorating and motivating our staff to help them focus on delivering our business objectives.
Our 2014 annual employee survey, 'engageTullow', highlighted communication and organisational efficiency as areas for improvement. During the MSP, engagement with staff was a high priority. We held a series of focus groups with a cross-section of staff on why the MSP was needed and how it could have positive outcomes for the Company. In addition, we set up an internal confidential e-mail address
"Establishing a new organisation with clearer lines of responsibility and accountability was a key achievement in 2015. While there is more work to do, we are already a more efficient and performance focused business."
to encourage ideas and suggestions for organisational effectiveness from staff, and this platform became a critical and well-used feedback tool.
In light of the amount of change in the organisation and how frequently employees have been asked
to give feedback this year, we decided to postpone the annual employee survey until 2016.
Tullow's integrated reward strategy is designed to attract, retain and motivate the best talent in our industry. We aim to offer a transparent, competitive reward package of base salary, incentives and benefits, which reflects market practice and is fully compliant with the regulations in each of the countries where we operate. Our incentive plans are linked to the Company's financial and operational performance, as well as to individual achievement measured through Tullow's annual employee performance management process.
All permanent employees have the opportunity to earn an annual bonus and a share award based on how well they perform against their set objectives for the year. Our employee share award plans are intended to provide employees with a longer-term stake in the success of our business.
accountability for delivery in the Business Delivery Teams; the corporate centre is better positioned to provide the advice and direction, governance, and assurance expected by our stakeholders; and employees are clearer about their roles and what is expected of them.
This work and everything we do is underpinned by our values, which set the framework for our organisational culture. The behaviour we expect of our employees is set out in our Code of Ethical Conduct. We also work to create a consistent culture that embraces, understands and integrates the diverse set of international cultures and subcultures that make up our workforce.
The new operating model has also helped to create a more streamlined organisation that is appropriate for the level of work in our exploration, development and production portfolio. In addition to managed headcount reduction, there was a natural turnover of 6 per cent across the Group. In recognition of this year's challenging environment and employees' commitment to the Company, a one-off Exceptional Share Award was granted to permanent employees.
Our approach to attracting, developing and retaining people starts by identifying our requirements through business plans and resource planning activities. Although the reduction in headcount and the pressures in the industry have been challenging, we worked to ensure that talent management and any recruitment was aligned with current business needs and anticipated future requirements. We also continued to develop a succession pipeline for Executive leaders, senior managers and other critical roles.
We have now identified a pool of possible successors for 100 per cent of senior roles. During 2016, a robust assessment and development programme will be introduced to help develop future leaders. We have also looked at other critical roles and will ensure we have robust succession plans in place.
An inclusive workforce that enables employees to reach their full potential is crucial to our business success, and we strive to create an environment where all employees are treated fairly, equally and with respect. We have 57 nationalities in our workforce. Women made up 28 per cent (396/1,403) of our total workforce in 2015 and 22 per cent (76/338) of our managers and 17 per cent (2/12) of our Board of Directors.
Each of our key African Business Units is headed by African nationals, and 83 per cent of our Ghanaian Leadership Team is now represented by African nationals. Kenyan and Ugandan nationals make up 67 per cent of those respective Business Unit's leadership teams.
In 2014, we reported on our plans to develop and meet clear diversity targets, but in light of the focus on the reorganisation and the reduction in headcount during the year, we deferred this work. Our 2016 Diversity Plan, which is on the Board's agenda, will focus on setting nationality and gender targets with proactive monitoring and reporting against these goals.
1
Tullow employees in the Accra office, Ghana
The plan is aimed at being proportionate and with a nationality mix representative of our asset geographies, as well as seeking gender diversity particularly in senior leadership teams. Our local offices will primarily employ local nationals, and expatriate employees will have personal objectives committing them to training and development of local staff to support the Group's localisation strategies, succession targets and our commitment to shared prosperity.
Our recruitment practices will change and broaden to proactively seek out, attract and encourage stronger nationality and gender diversity in our workforce to deliver our Diversity Plan.
There was a decrease in the amount of staff training that took place during 2015 as a direct result of the reorganisation. Some notable initiatives introduced were the in-house Passport to Manage course for new and inexperienced managers and team leaders, and the launch of Fundamentals of the Oil and Gas Industry – an interactive training and e-learning tool available on Tullow's intranet.
Tullow continued its support of the Chartered Engineering Council-accredited Well Engineering Development Programme, achieving an 88 per cent retention rate of those who participated since the programme started in 2012.
During 2016, we plan to implement a 70:20:10 Development Framework that supports learning through experience, mentoring and formal training.
As Africa's leading independent oil company, 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 bid successfully for contracts.
Our payments to governments, including payments in kind, amounted to \$391 million in 2015 (2014: \$518 million).
Total payments to all major stakeholder groups including employees, suppliers and communities, as well as governments, brought our total socio-economic contribution to \$1.1 billion (2014: \$1.4 billion). This included \$309 million spent with local suppliers, \$359 million in payroll globally and \$8 million in discretionary spend on social projects.
Our total payment made to the Ghanaian Government in 2015 was \$237 million (2014: \$314 million). The reduction in income taxes paid was partly offset by an increase in our carried interest of approximately \$30 million and withholding tax of \$20 million. Other tax payments such as Value Added Tax and PAYE & national insurance were broadly consistent with 2014.
Lower oil prices and continued investment in the TEN Project will continue to have an impact on our likely payment of taxes to the Government of Ghana in 2016.
Local content expenditures by contrast have increased by 37 per cent across the Group and have almost doubled in Ghana. This is largely due to the ongoing concerted effort of the government, Tullow and our Joint Venture partners to identify contracts where local businesses can tender for the supply of goods and services locally. In 2015, in Ghana we spent \$226 million (2014: \$124 million) with local businesses. This expenditure also does not include the significant sums that our international suppliers spend with local businesses, which is as a direct result of our contracting strategy, which requires our international suppliers to maximise opportunities for local businesses within their contracts with Tullow.
Full disclosure under the UK Regulations of taxes and other payments to governments of our host countries can be found on page 171.
Operationally, our contracting and procurement processes are critical to delivering Local Content and we structure our contracts to optimise the amount of goods and services that can be sourced locally. We ensure that local companies are given the opportunity to prequalify for contracts and that our international suppliers submit Local Content Development Plans as part of contract tenders. These plans are part of our selection and award process and are continually reviewed throughout the life of the contract to ensure commitments are met.
We aim to align our local hiring policies with our host governments' priorities, and we work to ensure that local staff make up the majority of our skilled workforce. Our localisation programmes focus on training and skills transfer through mentoring and job shadowing. Most contracts during the exploration and appraisal phase tend to be short term, making the recruitment and training of local staff problematic. This becomes easier during the development and production phases, when there is a clearer business case for the investment in required training programmes.
In Ghana, Tullow meets the requirements of the Local Content and Local Participation Bill (2013) and we have a target of employing local nationals in more than 90 per cent of positions for the Jubilee Field Phase I Development.
∙Local nationals as a % of in country staff
This year, in our Ghana Business Unit, the proportion of our expatriate staff marginally increased, reflecting the need to secure expertise for the TEN and the Jubilee Field Full Development Projects that was not available in Ghana. Once all operational phases of these projects are under way, the proportion of expatriates will decrease.
Although we have made progress in employing more local staff across all functions in Ghana, they remain underrepresented in technical and engineering roles. Overall, permanent staff who are Ghanaian nationals make up 67 per cent of our Ghana-based workforce and 83 per cent of our permanent Ghana-based staff. However, the number of nationals as a proportion of our technical staff lags behind our target.
In Kenya, as the Government prepares for the development of its oil and gas resources, its draft national content legislation is expected to come before parliament in 2016. This will build on the Petroleum Act that already requires Tullow to prioritise the employment and development of Kenyan nationals. Currently, Tullow Kenya has 194 permanent employees and contractors working in our Nairobi offices and in the field, 61 per cent of whom are Kenyan nationals. Permanent staff who are nationals working in Tullow Kenya, represent 78 per cent of our employee base. We are committed to increasing the proportion of local staff and developing sector-specific skills and we continue to coordinate this effort with our partners and the Government. Improving this performance will be an area of focus in 2016.
Our Kenyan operations have created a number of local supply chain opportunities for businesses in Turkana. For example, Kapese Transporters specialise in providing light and heavy vehicles to transport personnel and materials to drill locations. Over the last five years, Kapese have increased the number of vehicles in their fleet and have been able to strategically diversify their business to include the supply of spare parts.
Invest in Africa (IIA) was founded in 2012 by Tullow Oil with the vision of partnering with companies across sectors to create thriving African economies.
LOCAL CONTENT (\$ MILLION)
In Ghana, IIA is working to empower local enterprise and increase links to international companies with West Africa's first online business platform – the African Partner Pool (APP). The APP allows Ghanaian small to medium sized enterprises to better promote their services and helps investors choose the best local businesses to partner with.
1
For example, prior to joining the APP, one of the major challenges faced by Adentiti, a Ghanaian IT supply company, was identifying and responding to tenders from larger companies in a quick and easy way. According to Business Development Manager Kafui Bokor: "The decision to join the APP was the solution that completely simplified Adentiti's search for tenders."
Adentiti now has access to opportunities from some of the biggest buyers in Ghana such as General Electric, Newmont Mining, Ecobank and others. After winning a tender posted on the APP, Adentiti has established a profitable business relationship with UT Bank. Adentiti is just one of over 1,000 companies registered on the APP and Kafui concluded: "Adentiti has received so many benefits from being a member. I urge my fellow local SMEs to register to enjoy the many benefits it offers."
We support investment in education and training programmes to develop the future pipeline of expertise required by the oil and gas industry in the medium and long term. We try to ensure that our technical and vocational skills training programmes provide both relevant and transferable skills that will enhance long-term socioeconomic stability and boost growth in our host countries and communities.
Tullow's flagship social investment project remains the Tullow Group Scholarship Scheme. It is administered by the British Council and aims to build capacity in our host countries. \$24 million has been invested over five years and students are sponsored to take academic and vocational courses at leading institutions. Over 400 students have benefited to date and 227 students have completed their courses. Participants have a 93 per cent employment rate following their studies.
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
Tullow has a large onshore acreage position in Uganda and Kenya and considers this region to have great potential. To date, the Group has discovered a total of 2.3 billion barrels of oil in the Lake Albert Basin in Uganda and the South Lokichar Basin in Kenya. Tullow is focused on its continued exploration in Kenya and progressing the regional development.
2
| Directors' report | 70 |
|---|---|
| Audit Committee report | 79 |
| Nominations Committee report | 84 |
| EHS Committee report | 86 |
| Ethics & Compliance Committee report | 88 |
| Directors' remuneration report | 90 |
| Other statutory information | 107 |
Tullow Oil plc is required, under the UK Listing Rules, to comply with the UK Corporate Governance Code (the 'Code') published by the Financial Reporting Council (the 'FRC') in September 2014, for the year ended 31 December 2015. A copy of the Code is available at www.frc.org.uk. In 2014, the FRC published the Code which applies to financial reporting periods commencing on or after 1 October 2014 and which replaced the previous UK Corporate Governance Code published in September 2012. The Code contains a number of new provisions, including requiring companies to: make greater disclosures of their strategic approach to risk and risk management; make a statement about the long-term viability and prospects of the company; ensure that remuneration policies are designed to deliver long-term benefits to the company and include measures for claw-back on variable pay; and, in cases where a significant proportion of shareholders oppose any particular measure, explain the actions the company intends to take to understand the reasons for this opposition.
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 2015.
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 2015, the Board met eight 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 Regional Vice Presidents and other heads of functions presented a strategic overview of their respective area to the Board for endorsement. In particular, the Board reviewed and endorsed non-technical risk strategies for its major areas of operations.
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 2015, the Board travelled to Accra.
The Chairman and 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 2015, the Board considered all relevant matters within its remit, with a particular focus on the following issues:
The attendance of Directors at the eight scheduled meetings of the Board held during 2015 was as follows:
| Director | No. of meetings attended (out of a total possible) |
|---|---|
| Tutu Agyare | 8/8 |
| Mike Daly | 8/8 |
| Anne Drinkwater | 8/8 |
| Ann Grant | 8/8 |
| Aidan Heavey | 8/8 |
| Steve Lucas | 8/8 |
| Graham Martin | 8/8 |
| Angus McCoss | 8/8 |
| Paul McDade | 8/8 |
| Ian Springett | 7/8 |
| Simon Thompson | 8/8 |
| Jeremy Wilson | 8/8 |
In addition to the Board members, a number of Senior Managers attend relevant sections of Board meetings by invitation.
The Chairman, Simon Thompson, is primarily responsible for the effective working of the Board, whilst the Chief Executive Officer, Aidan Heavey, 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, Simon Thompson met the independence criteria set out in the Code and continues to do so.
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 and 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 development projects (e.g. TEN). 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, which may, subject to satisfactory performance and re-election by shareholders, be extended by mutual agreement.
The Senior Independent Director, Ann Grant, is available to meet shareholders if they have concerns that cannot be resolved through discussion with the Chairman, Chief Executive Officer or 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 79, the EHS Committee on page 86, the Ethics & Compliance Committee on page 88, the Nominations Committee on page 84, and the Remuneration Committee on page 90.
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 2015.
The Board currently comprises the Chairman, Chief Executive Officer, four other Executive Directors and six independent non-executive Directors. Their biographical details are set out on pages 50 and 51.
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 did not change during the course of 2015.
| ∙Strategy & Stakeholder Management | 24% |
|---|---|
| ∙Financial management | 28% |
| ∙SSEA | 12% |
| ∙D&O | 14% |
| ∙E&A | 7% |
| ∙Governance/Risk Management | 15% |
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.
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 2015 the Board undertook an internal evaluation of its own performance and effectiveness and also that of its Committees and individual Directors. The evaluation was facilitated by Lintstock Ltd and each of the Directors was required to submit responses to a series of questionnaires designed to the specific circumstances of the Company and, in particular, to pick up on themes identified in the 2014 exercise, including the composition and expertise of the Board, strategic oversight, risk management and internal control, succession planning, human resource management and a review of past decisions. In addition, the Chairman conducted a process of interviews between himself and each of the individual Directors.
The results of the survey determined that the performance and composition of the Board and its Committees were adequate and found a strong alignment within the Board on the key strategic priorities in the year to come. The Board determined that its allocation of time and priorities and particularly its focus on strategy had improved in 2015. Discussions at Board meetings continued to display a positive balance of support and healthy challenge of management exercised by the non-executive Directors. The review noted a recent improvement in the presentation of information with a focus on the need for clearly articulating any decisions sought. The time management by the Board and each of its Committees was improved following a review and restructuring of its annual rolling agenda and meetings schedule. Finally, the review noted that the Board would need to continue to review: the size and composition of the Board and its Committees; the diversity and succession planning for Executive Directors and Senior Management; the utilisation of the non-executive Directors' expertise; and the Board's focus on strategic priorities and the market environment. The Board objectives for 2016 (set out on the next page) reflect the action plan and priorities agreed by all the Directors as part of the 2015 Board evaluation.
The internal Board evaluation carried out in 2015 followed the independent and interview-driven Board evaluation conducted by Lintstock in 2013 and the subsequent internal evaluation facilitated by Lintstock in 2014. This completes a three-year cycle of Board evaluation and it is envisaged that, in accordance with the requirements of the Code, the Board will commission a new external facilitation of the Board evaluation in 2016. Lintstock have no other connection to the Company.
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 2015 objectives and also details the priorities and rolling agenda items the Board will focus on in 2016.
All Directors seek re-election every year and accordingly all Directors will stand for re-election in 2016 (with the exception of Graham Martin who the Company has already announced will retire at the end of the AGM in April 2016). The Board has set out in the Notice of AGM its reasons for supporting the re-election of each of the Directors at the forthcoming AGM.
| 2015 Board objectives | |
|---|---|
| Strategy and execution |
• Regularly review strategy in light of market, political and socio-economic developments. • Deliver the TEN Project on time and on budget. • Progress development plans for Kenya/ Uganda. • Reduce expenditure and ensure high-grading of exploration opportunities. • Reduce costs, maximise cash flow from operations and manage business within prudent funding constraints. |
| Risk management |
Continue to strengthen processes for identification, management and assurance of financial, technical and non-technical risks, with a particular focus on: • Safety, health and environment; • Reserves and resources management; • Capital project management; • Community relations and social performance; • Government relations; • Liquidity management; and • Improving performance management. |
| Governance and values |
• Maintain and enhance Tullow's culture and values throughout the re-shaping of the business. • Update the Code of Business Conduct to reflect trends and best practices and reinforce compliance with it. |
| Organisational capacity |
• Redesign, streamline and simplify organisational structure to deliver revised strategy. • Continue to strengthen Human Resource function. • Continue to strengthen Commercial function. • Progress Senior Executive development plans and strengthen succession planning for key positions. • Further increase diversity of talent pipeline. |
| Stakeholder engagement |
• Ensure that shareholders, staff and other major stakeholders understand and are aligned with the revised strategy. • Further enhance engagement with governments and Civil Society Organisations (CSOs) in our principal countries of operation. |
| 2015 Performance | 2016 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 and travelled to Ghana in October to be briefed by the project team. The Ghana trip also allowed Directors to visit key facilities, including the FPSO. • In Uganda, CGT and historic VAT issues were resolved. The Government of Kenya and Uganda issued a joint statement agreeing the Northern pipeline route in August. A draft field development plan for discoveries in the South Lokichar Basin in Kenya was submitted to the Government of Kenya in December. • The exploration budget was reduced to \$200 million. • The Major Simplification Project resulted in significant headcount and cost reductions across the Group. Headroom and liquidity were actively monitored throughout the year, amid a rapidly declining oil price. Tullow's prudent hedging policy helped to maximise cash flow and the business was managed within funding constraints. |
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. |
| • A revised enterprise risk management process was implemented, which maps Tullow's key risks, potential impacts, mitigation strategies and assurance processes. • A new Integrated 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 strategic people plan and is subject to regular Board review. |
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. |
| • The Major Simplification Project involved extensive staff engagement aimed at establishing a more cost-conscious, entrepreneurial culture with clearer lines of responsibility and accountability for the delivery of the agreed strategy. • A revised Code of Ethical Conduct was approved by the Board and is currently being rolled-out across the Group. |
• 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 is embedded and that Tullow's policies, standards and procedures are consistently followed and result in efficient, safe and responsible operations. |
| • The Major Simplification Project was completed during the year resulting in a significantly smaller and more streamlined organisation. Efforts are ongoing to enhance performance management and accountability in the business. • A new Group Head of Reward has joined the HR team along with key hires in a strengthened commercial function. • Succession planning, diversity and talent management were regularly discussed at Board level with an acknowledgement that improvement is required in these areas. Processes to expedite the identification and development of a more diverse talent pool are under preparation. A new diversity KPI will be introduced in 2016. |
• 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. |
| • Both Executive and non-executive Directors engaged with shareholders, staff, CSOs and other major stakeholders throughout the year. • Internal communications were enhanced as part of the Major Simplification Project. |
• 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 CSOs in our principal countries of operation. |
Exploration and production companies have faced yet another challenging year. Oil prices falling to unexpected lows has impacted both companies and investors, and the sector, as a whole, continues to experience some negative shareholder sentiment.
Tullow recognises that it is important to maintain open and transparent communication with shareholders and potential investors, especially in these difficult times. We do this through meetings, presentations, investor conferences and ad hoc events with institutional investors and sell-side analysts. Over the year, the Investor Relations (IR) team and Senior Management met some 380 institutions and the Group participated in approximately 40 roadshows and investor conferences around the world. Executive Directors and Senior Management met institutional investors in the UK, Europe, Ghana, Asia Pacific, South Africa and North America.
Tullow also participated in a roadshow for Socially Responsible Investors (SRI) following the release of our 2014 CR Report in April 2015. These meetings provided an opportunity to discuss topics including health and safety, the environment, corporate governance, bribery and corruption, country and political risk and other operational matters. The meetings were hosted by our Vice President of SSEA and Head of IR.
Tullow's fourth Ghana Investor Forum took place in May 2015 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. The Group recognises the importance of continued shareholder engagement with our 9,000 Ghanaian shareholders, and Tullow plans to give a 'Facts Behind the Figures' presentation to investors and brokers at the Ghana Stock Exchange in the second half of 2016.
Outside these formal events, 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.
The Board is kept in touch with market developments following major operational announcements through regular summaries from the Investor Relations team. They also receive a monthly Board Report which includes shareholder analysis, shareholder feedback and Tullow's performance against our peers.
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. Updates and details of the
∙ Other 17%
| ∙ UK | 55% |
|---|---|
| ∙ Europe | 19% |
| ∙ North America | 20% |
| ∙ Rest of the world | 6% |
| ∙Mutual Fund Manager | 29% |
|---|---|
| ∙Pension Fund Manager | 18% |
| ∙Asset Manager | 12% |
| ∙Insurance Fund Manager | 11% |
| ∙Private Banking | 7% |
| ∙Other | 23% |
status of exploration and development programmes are also available on the website. 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. As part of this work Tullow launched a new corporate website in the first half of 2015. Among the improvements, the new site provides a consistent experience for all desktop, tablet and mobile devices. Since its launch in April, the new corporate website has had just under 200,000 unique visitors and around one million page views.
We are also responding to the growing use of social media by shareholders and the media. The Group has circa 16,700 followers on its corporate Twitter account, circa 12,000 on Facebook, circa 65,800 on its LinkedIn account and the films provided on YouTube have received circa 124,000 views.
Another important way we keep shareholders informed is through regular formal reporting and Tullow's Annual and Corporate Responsibility Reports are available on the corporate website.
Tullow has two corporate bonds and 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
February Full Year Results
March Full Year Results roadshows
April
Annual General Meeting Annual General Meeting Trading Update
Trading Statement and Operational Update Half Year Results
September Half Year Results roadshows
November 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.
2015 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 auditors to the Audit Committee. Their work is outlined in the Audit Committee report on page 79.
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. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.9 billion of debt liquidity headroom and free cash at the end of 2015. The Group's forecasts, 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 2015 Annual Report and Accounts.
Notwithstanding our forecasts of liquidity headroom throughout the 12-month period, there remains a risk, given the volatility of the oil price environment and its impact on operating cash flows and facility availability, that the Group's liquidity position may deteriorate and/or the Group may become technically non-compliant with one of its financial covenants at the end of 2016.
To mitigate this risk, we will continue to maintain our long-term banking relations and will monitor our cash flow projections and, if necessary, take mitigating actions well in advance to maintain our liquidity and compliance with covenants. Actions available to the Group include further rationalisation of our cost base, cuts to discretionary capital expenditure, portfolio management and other funding options.
Based on the analysis above, 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 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 pages 82 and 83.
The Board has delegated responsibility for agreeing the remuneration policy for the Chairman, Chief Executive Officer, Executive Directors and senior executives to the Remuneration Committee. Its role and activities are set out in the Directors' Remuneration Report on page 98.
At the AGM held on 30 April 2015, 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 business presentation was held in Dublin on 1 May 2015 following the AGM.
A poll was used to vote for all resolutions at the 2015 AGM, and the final results (which included all votes cast for, 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
Chairman
9 February 2016
| Risk Management | 52 |
|---|---|
| Long-term viability statement | 55 |
Strong corporate governance and risk management 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 also oversaw the risk management and internal control system and we were pleased that during 2015 the risk management process has been considerably enhanced and internal controls have been further improved following the finalisation of SAP roll-out and formalisation of the fraud risk management framework, both of which strengthen control over accounting and reporting practices.
A key agenda item for the Audit Committee in 2015 was implementation of the changes to the UK Corporate Governance Code and the revised Financial Reporting Council (FRC) guidelines, which were published in the second half of 2014. Following the Board review of our risk management processes across the Group, the new risk management policy and standards have been approved which introduce a consistent enterprise-wide process of managing risk at Tullow. The Audit Committee plays an active role in that process by making sure it meets business needs and remains fit for purpose.
Chairman of the Audit Committee
9 February 2016
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 50 and 51. Together the members of the Committee bring a broad 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 – Finance and Commercial and representatives of the external auditors are invited to attend each meeting of the Committee and participated in all of the meetings during 2015. The Chairman of the Board also attends meetings of the Committee by invitation and was present at all of the meetings in 2015. The external auditors and the Group Internal Audit Manager have unrestricted access to the Committee Chairman.
In 2015, 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 UK Corporate Governance Code, the FRC's 2012 Guidance on Audit Committees, the FRC's 2014 Guidance on Risk Management and Internal Control, 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 8 December 2015.
The Committee's detailed responsibilities are described in its terms of reference and include:
During the year the Board established the Ethics & Compliance Committee, which took responsibility for monitoring systems and controls to prevent bribery and corruption, which was previously a responsibility of the Audit Committee. 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.
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 auditors. 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:
The following describes the work completed to discharge the Audit Committee's main responsibilities:
Monitoring the integrity of the Financial Statements and formal announcements relating to the Group's financial performance. Reviewing the significant financial reporting issues and accounting policies and disclosures in the financial reports.
The Committee met with the external auditors as part of the full-year and half-year accounts approval process. During this exercise the Committee considered the key audit risks identified as being significant to the 2015 accounts and the most appropriate treatment and disclosure of any new or judgemental matters identified during the audit and halfyearly review as well as any recommendations or observations made by the external auditors. The primary areas of judgement considered by the Committee in relation to the 2015 accounts and how these were addressed are detailed on the next page:
| Meetings attended (out of a total |
|
|---|---|
| Committee member | possible) |
| Steve Lucas | 4/4 |
| Tutu Agyare | 4/4 |
| Anne Drinkwater | 4/4 |
| Ann Grant | 4/4 |
| Jeremy Wilson | 4/4 |
| Mike Daly | 4/4 |
| Significant financial judgements for 2015 | How the Committee addressed these judgements |
|---|---|
| Intangible assets – The amounts for intangible exploration and evaluation assets represent active exploration projects. These amounts are written-off to the income statement as exploration costs unless commercial reserves are established or the determination process is not completed. The key areas in which management has applied judgement 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 well at each balance sheet date. In addition, Deloitte LLP have identified this as a significant area of focus for their audit and undertake discussions with operational and finance staff to challenge evidence provided by management to support the value of intangible assets and provide detailed reporting to the Committee on the results of their work. This is a recurring area of judgement. |
| Taxation – The Group is subject to various claims which arise in the ordinary course of its business, including tax claims from tax authorities in a number of the jurisdictions in which the Group operates. The Group assesses all such claims in the context of the tax laws of the countries in which it operates and, where applicable, makes provision for any settlements which it considers are probable. |
The Committee was satisfied with the treatment of these issues and judgements applied through reporting from Senior Management, supported by advice from external professional advisers and independent legal counsel. 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 their conclusions from the audit of these matters. This is a recurring area of judgement. |
| Decommissioning – 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 an independent specialist. 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 their audit. This is a recurring area of judgement. |
| Value in use of property, plant and equipment (PPE) – Management performs impairment tests on the Group's PPE assets when there are indicators of impairments. The calculation of the recoverable amount requires estimation of future cash flows within complex impairment models. Key assumptions and estimates relate to commodity prices based on forward curves for two years and the long-term corporate economic assumptions thereafter, 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 and Deloitte LLP review these calculations and audit the underlying economic models to satisfy themselves of the integrity of the process. This is a recurring area of judgement. |
| Carrying value of goodwill – Following the acquisition of Spring Energy in 2013, Tullow recognised goodwill in line with the requirements of IFRS 3 Business Combinations. Management performs impairment tests on the carrying value of goodwill semi-annually. The calculation of the recoverable amount is based on the likely future economic benefits of the exploration assets in the portfolio and is based on chance of exploration success and estimated value of the potential discoveries. |
Results of the impairment tests were discussed and challenged by the Committee and Deloitte LLP review these calculations and audit the underlying economic models to satisfy themselves of the integrity of the process. |
| Provision for onerous contracts – Due to the reduction in planned future work programmes the Group has identified a number of onerous service contracts. In order to calculate the provision management have estimated the expected future usage. If the Group is able to sub-contract the rigs or find a use for them the provision will decrease. |
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. |
| 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 are reviewed to potentially enhance the financial capability and flexibility of the Group. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.9 billion of debt liquidity headroom at the end of 2015. 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 2015 Annual Report and Accounts. |
The Committee reviewed and challenged the assumptions and judgements in the underlying going concern forecast cashflows 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 their conclusions on management assessment of going concern. |
Making recommendations to the Board on the appointment or re-appointment of the Group's external auditors and overseeing the Board's relationship with the external auditor and, where appropriate, the selection of a new external auditor, and assessing the effectiveness of the external audit process is a key responsibility of the Audit Committee.
The Group's external auditors are Deloitte LLP and the Audit Committee assessed the qualification, expertise and resources, and independence of the external auditors as well as the effectiveness of the audit process. This review covered all aspects of the audit service provided by Deloitte LLP, including obtaining a report on the audit firm's own internal quality control procedures and consideration of the audit firm's annual transparency reports in line with the UK Corporate Governance Code. The Audit Committee also approved the external audit terms of engagement and remuneration. During 2015 the Committee held private meetings with the external auditors and the Audit Committee Chairman also maintained regular contact with the audit partner throughout the year. These meetings provide an opportunity for open dialogue with the external auditors 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 them by management, maintaining the independence of the audit and how they have exercised professional challenge;
In order to ensure the effectiveness of the external audit process, Deloitte LLP conduct an audit risk identification process at the start of the audit cycle. This plan is presented to the Audit Committee for their review and approval and, for the 2015 audit, the key audit risks identified included carrying value of exploration and evaluation assets, carrying value of plant, property and equipment, provision for tax claims, provision for onerous rig contracts, oil and gas reserves, decommissioning provisions, risk of management override, liquidity risk and going concern, Depreciation Depletion and Amortisation (DD&A), as well as revenue recognition. These and other identified risks are reviewed through the year and reported at Audit Committee meetings where the Committee challenges the work completed by the auditor and tests management's assumptions and estimates in relation to these risks. The Committee also seeks an assessment from management of the effectiveness of the audit process. In addition, a separate questionnaire addressed to all attendees of the Audit Committee and senior finance managers is used to assess external audit effectiveness. As a result of these reviews, the Audit Committee considered the external audit process to be operating effectively;
Responsibility for reviewing the effectiveness of the Group's risk management and internal control systems was 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 their findings to the Audit Committee who 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. The Committee oversaw the enhancement of the enterprise risk management process and fraud risk management framework.
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.
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 2015 to allow staff to confidentially raise any concerns about business practices. This procedure complements established internal reporting processes. The whistleblowing 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.
There are five Executive and seven non-executive Directors on the Tullow Board. They come from varied professional backgrounds and provide the Board with a diverse range of experience, knowledge and approach. Their biographies are set out on pages 50 and 51 of this report.
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 work to ensure that we recruit, develop and retain a diverse group of senior managers who will be able to take on the most senior positions in the Company in the future.
Chairman of the Nominations Committee
9 February 2016
The Committee reviews the composition and balance of the Board and the senior executive team on a regular basis. 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 Committee was comprised of four non-executive Directors for the majority of 2015. In December 2015, on the Committee's recommendation, the Board approved the appointment of the remaining non-executive Directors, Anne Drinkwater, Mike Daly and Jeremy Wilson, to the Committee. Simon Thompson was Chairman of the Committee throughout the year. The membership and attendance of members at Committee meetings held in 2015 are shown in the table on the next page.
In addition to the two formal meetings, the Committee's remit allowed for informal discussions, interviews, telephone conversations and a number of informal meetings during the year.
The principal activities of the Committee during 2015 and after the year-end were:
• Board diversity – The Board currently consists of five Executive and seven non-executive Directors. Two of the seven non-executive Directors are women but all of the Executive Directors are men, which translates to a relatively low level of gender diversity. The Board supports the aspirations set out in the 2011 Davies Report 'Women on Boards' that women should make up at least 25 per cent of board positions, but to achieve
2
this within the timeframe contemplated would restrict future Board appointments to women only, which may not be in the best interest of the Company.
| Committee member | attended (out of a total possible) |
|---|---|
| Simon Thompson (Chair) | 2/2 |
| Tutu Agyare | 2/2 |
| Steve Lucas | 2/2 |
| Ann Grant | 2/2 |
| Mike Daly | 0/0* |
| Anne Drinkwater | 0/0* |
| Jeremy Wilson | 0/0* |
* Appointed to Committee in December 2015
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.
Process safety is an enduring focus for the Committee. We had the opportunity to review first-hand the progress being made on the Jubilee multi-year Asset Integrity Management Plan during a site visit to the FPSO Kwame Nkrumah in October 2015. We also reviewed the structure and competence of the integrated operations team that underpins process safety – this same team will also support TEN operations, leading to the efficient transfer of best practice.
The EHS Committee has observed how Tullow's simplification of its business and risk management process within the Integrated Management System has facilitated greater emphasis on improving the core elements of good EHS performance such as work planning.
During 2015 Tullow made significant progress in implementing the UN Voluntary Principles on Security and Human Rights (VPSHR) in its operations. This is particularly important in onshore operations, such as in Uganda and Kenya, and sets a solid foundation for the development phase.
Chair of the EHS Committee
9 February 2016
The Committee has an objective of enhancing the Board's engagement with EHS by instigating appropriate in-depth reviews of strategically important EHS issues for the Group. The agenda of the Committee is forward looking, seeking to provide appropriate advice in anticipation of emerging risks the business might face in its operations. The Committee reviews a wide range of EHS leading and lagging indicators to gain insight into how EHS policies, standards and practices are being realised in the field. Some examples are high-potential incidents, especially where incidents occur repeatedly in one location or activity, and audit and investigation outcomes.
The Committee's responsibilities are:
The Committee's terms of reference are reviewed annually and can be accessed 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 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, provide guidance on EHS issues, or discuss how EHS can be embedded across their parts of the business. 2015 visiting attendees included Senior Management and management team members from the SSEA function and line leadership.
| Meetings (out of a total |
|
|---|---|
| Committee member | possible) |
| Anne Drinkwater (Chair) | 4/4 |
| Paul McDade | 4/4 |
| Simon Thompson | 4/4 |
| Mike Daly | 4/4 |
Tullow's good reputation for business integrity is one of our most valuable assets. A shift in sentiment could seriously impact our ability to operate, and loss of reputation is one of our key risks.
In 2015 we have strengthened our ability to promote and monitor ethics and compliance throughout the Group. As part of the Major Simplification Project and the consequent reshaping of the business, we replaced the existing Ethics & Compliance Committee with a formal Committee of the Board. The Committee will support the Board and the business in protecting and promoting Tullow's core values, encouraging strong ethical behaviour throughout the Company, and ensuring that we fully comply with all relevant legislation.
During its first year the Committee approved Tullow's revised Code of Ethical Conduct, and comprehensively reviewed and challenged our investigation processes, and our culture of compliance, with positive results.
We will not be complacent and look forward to building on this progress in 2016.
Chair of the Ethics & Compliance Committee
9 February 2016
The Committee exists to support the Board in promoting within Tullow, and with people who work with Tullow, the importance of ethics and compliance. This is to ensure the continued success and business integrity of the business and protect value as part of our risk management processes. 'Ethics' means the Tullow values and the culture that exists in the business to do things that are morally good and ethically sound. 'Compliance' means ensuring that we meet all the requirements of legislation within the business and specifically the UK Bribery Act. The Committee supports and reinforces our commitment to being an ethical company and to providing extra assurance to our stakeholders that our policies and approach are adequate and effective.
The Committee's responsibilities are to:
The Committee's terms of reference will be reviewed annually and can be accessed on the corporate website.
The Committee currently comprises two non-executive Directors, Ann Grant and Steve Lucas, and one Executive Director – Ian Springett, who now has executive responsibility for Ethics & Compliance across the Group. Ann Grant is Chair of the Committee and chaired all meetings throughout the year.
In addition to the core Committee members, the Chairman and functional heads from across the Group attended the meetings to contribute to specific agenda items and discussions. Regular visiting attendees in 2015 included management team members from Ethics & Compliance, Legal, Organisation Strategy & Effectiveness and Internal Audit.
The Committee was briefed on and oversaw Ethics & Compliance initiatives across the Group during the year which included:
| Meetings (out | |
|---|---|
| of a total | |
| Committee member | possible) |
| Ann Grant (Chair) | 3/3 |
| Steve Lucas | 3/3 |
| Ian Springett | 3/3 |
Additional attendees who provide support and input to the Committee process include: the Chairman; Group Ethics & Compliance Manager; General Counsel; VP Organisation Strategy & Effectiveness; and Group Internal Audit Manager.
The Remuneration Committee is focused on ensuring Executive Directors are rewarded for long-term performance rather than short-term returns.
On behalf of the Board, I am presenting the Remuneration Committee's ('Committee') report for 2015 on Directors' remuneration. The report is again split into three main sections:
The Committee has continued to operate the approved shareholder policy during 2015 and will continue to do so during 2016. As such, the major work of the Committee this year involved the monitoring of the 2015 performance targets (KPIs) for the TIP and the setting of new performance targets for 2016.
At the start of 2015, Executive Director base salaries were frozen for the second consecutive year to reflect the streamlining and refocusing of the business and the ongoing challenging nature of the oil and gas industry.
The performance targets set for 2015 in respect of the TIP awards to be granted in 2016 were challenging in the context of the time and proved even more so as the year progressed.
It is disappointing to report a nil contribution for the TSR measure, which made up 50 per cent of the scorecard. However, the Group scored well on its financial, production, organisational and strategic targets for 2015, and the Committee is particularly pleased with the progress of the TEN Project with first oil due, as planned, during 2016. The net result of these various factors produced an overall KPI performance of 37.7 per cent, resulting in a cash bonus of 94 per cent of salary and a further 94 per cent of salary awarded in shares deferred for five years. Full details of performance against the KPIs is shown on pages 100 and 101.
The 2013 PSP Awards were based on relative TSR performance over the three years ended 31 December 2015 and did not vest in 2016 as a result of Tullow's below-threshold TSR against the competitor groups over the performance period.
In determining base salary levels and TIP performance targets for 2016, the Committee wanted to recognise the ongoing challenging environment of the oil and gas sector, our business strategy and the ongoing need to streamline and refocus the business. We also wanted to recognise and reward the talent and continued commitment of the Executive team, albeit in light of market conditions.
Our conclusion from these discussions has led to a freeze in base salary and fixed pay for the third year running and a set of KPI targets which include TSR performance (50 per cent), strong production of Jubilee, and the final delivery of the TEN Project.
Stretching financial metrics, a strong balance sheet and operational and organisation targets are also included in the 2016 scorecard as well as measures to deliver on the longer-term growth strategy of the Company. Details of the actual targets are currently commercially sensitive and will therefore be fully disclosed in the 2016 Annual Report. Finally, in line with the pay freeze, the Committee has again, for the second consecutive year, agreed with the Executive Directors to reduce the maximum award available under the TIP in 2016 from 600 per cent to 500 per cent of salary.
During 2016, the Committee intends to conduct a major review of all aspects of remuneration, in particular the design and operation of the TIP, prior to the submission of our policy to shareholders at the 2017 AGM.
The Committee encourages dialogue with the Company's shareholders and will consult major shareholders ahead of any significant future changes to policy for 2017 onwards.
On behalf of the Committee, I would like to thank shareholders for their significant vote approving the 2014 Annual Statement and Annual Report on Remuneration at the last AGM and for their continued support.
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
| 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 new reporting requirements in respect of Directors' remuneration and the Listing Rules. The legislation requires the external auditors to state whether, in their 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.
Although Tullow is not technically required to disclose the Remuneration Policy Report this year, this part of the remuneration report, which has been included again in line with best practice, sets out the remuneration policy for the Company which commenced 1 January 2014 and became formally effective following approval from shareholders through a binding vote at the 2014 AGM. This section also explains how the remuneration policy will be operated during 2016.
The principles of the 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 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 general opportunity to impact directly upon Company performance.
The table on pages 94 and 95 sets out a summary of each element of the Directors' remuneration packages, their link to the Company's strategy, the policy for how these are operated, the maximum opportunity and the performance framework. Although not part of the Remuneration Policy Report, the column to the right of the table also sets out how the Committee intends to apply the policy for 2016.
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.
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.
| Summary Directors' remuneration policy | |||
|---|---|---|---|
| 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; • Skills and experience of the individual; • Retention risk; • Base salary of other employees; and • Base salary of individuals undertaking similar roles in companies of comparable size and complexity. |
Any increases to current Executive Director salaries, presented in the application of policy in 2016 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 contribution to personal pension plan. Medical insurance, permanent health insurance and life assurance. May participate in the UK 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. Additional benefits may be provided, as appropriate. SIP: Up to HM Revenue & Customs (HMRC) limits, currently £150 per month. |
| Tullow Incentive Plan (TIP) |
To provide a simple, competitive, performance linked incentive plan that: • Will attract, retain and motivate individuals with the required personal attributes, skills and experience; • Provides a real incentive to achieve our strategic objectives; and • Aligns the interests of management and shareholders. |
Annual award of cash (up to 100% of salary) and deferred shares (up to 500% of salary). Awards under the TIP (which are non pensionable) will be made in line with the Committee's assessment of the performance targets. Deferred shares normally vest after five years from grant, normally subject to continued service. |
The maximum annual level of award is 600% of salary for Executive Directors. Dividend equivalents will accrue on Deferred TIP Shares over the vesting period, to the extent awards vest. |
| 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% of post-tax share awards until a minimum shareholding equivalent to 400% of salary is achieved (increasing to 600% of salary from the date the first TIP Awards vest). |
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 set by the Remuneration Committee and 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. |
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 2016 (Not part of the Policy Report) |
|---|---|
| Not applicable. | Current Executive Director base salaries: 2016 Aidan Heavey £886,074 Graham Martin £501,106 Angus McCoss £501,106 Paul McDade £501,106 Ian Springett £532,073 No changes for 2016. |
| Not applicable. | No change. |
| A balanced scorecard of financial and operational objectives, linked to the achievement of Tullow's long-term strategy. Specific targets 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); EHS; financial; production; operations; projects; exploration; or specific strategic objectives. Performance will typically be measured over one year, apart from TSR and EPS, if adopted, which will normally be measured over three years (although see 'Operation of share plans' in respect of transitional arrangements). Non-TSR targets will normally be based on a sliding scale from 20% at threshold performance to 100% at maximum. The Committee reserves the right to exercise discretion in the event of unforeseen positive or negative developments during the course of the year. The Committee retains discretion to apply malus and clawback to the cash and deferred shares 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 risk management. |
The Committee has again reduced the maximum TIP award for 2016 from 600% to 500% of salary. The balanced score card in 2016 will consist of stretching targets as follows: • 50% based on relative TSR against a basket of oil and gas exploration companies with a threshold of median performance and a maximum of upper quintile; • 15% based on strategic financing targets; • 15% based on operational and safety targets; • 15% based on business development and growth targets; and • 5% based on organisation targets. Details of actual performance will be given retrospectively in the 2016 Annual Report. Details of the 2016 strategic objectives are on page 100 of the Annual Report on Remuneration. |
| Not applicable. | No change. |
| Not applicable. | Current non-executive Director fees: 2016 Chairman £310,500 Non-executive base fee £69,500 Senior Independent Director £15,000 Audit Committee Chair £20,000 Remuneration Committee Chair £20,000 EHS Committee Chair £15,000 Ethics & Compliance Committee Chair £5,000 No changes for 2016. |
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:
Each Executive Director entered into a new service agreement with Tullow Group Services Limited effective 1 January 2014. 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. Currently, the only Executive Director who holds a reportable external directorship is Angus McCoss. Angus 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, where possible, 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.
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, will result in only the cash part of the TIP being paid (and pro-rated for the proportion of the year worked). There would be no entitlement to Deferred TIP Shares that would have been granted following the date of cessation. |
No entitlement to any TIP cash award following the date notice is served. |
| TIP (Deferred Shares) |
Unvested Deferred TIP Shares normally vest at the normal time (except on death or retirement – see below) unless the Committee determines they should vest at cessation. |
Unvested Deferred TIP Shares lapse. |
| On death, Deferred Shares normally vest unless the Committee determines that they should vest at the normal vesting date. |
||
| On retirement (as evidenced to the satisfaction of the Committee), Deferred 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. |
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 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 (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 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) subject to performance conditions and time pro-rating (unless the Committee decides that the application of time pro-rating is inappropriate).
| Non-executive Director |
Year appointed Director |
Number of complete years on the Board |
Date current engagement commenced |
Expiry of current term |
|---|---|---|---|---|
| Simon Thompson |
2011 | 4 | 01.01.15 | 31.12.17 |
| Tutu Agyare | 2010 | 5 | 25.08.13 | 24.08.16 |
| Mike Daly | 2014 | 1 | 01.06.14 | 31.05.17 |
| Anne Drinkwater |
2012 | 3 | 10.02.15 | 09.02.18 |
| Ann Grant | 2008 | 7 | 15.05.14 | 30.04.17 |
| Steve Lucas | 2012 | 3 | 14.03.15 | 13.03.18 |
| Jeremy Wilson |
2013 | 2 | 21.10.13 | 20.10.16 |
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 2015 (including payment and awards in respect of incentive arrangements) and how shareholders voted at the 2015 AGM. This part of the report also includes a summary of how the policy will be operated for 2016, although, for ease of reference, this is 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 2015 are shown below.
| Committee member | Meetings attended |
|---|---|
| Jeremy Wilson (Chair) | 4 / 4 |
| Tutu Agyare | 3 / 4 |
| Anne Drinkwater | 4 / 4 |
| Steve Lucas | 4 / 4 |
| Simon Thompson | 4 / 4 |
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 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 2015 payable by Group companies and comparative figures for 2014 are shown in the table below:
| Fixed Pay | Tullow Incentive Plan | Legacy Incentives |
||||||
|---|---|---|---|---|---|---|---|---|
| Salary /fees1 £ |
Pensions £ |
Taxable Benefits2 £ |
TIP Cash £ |
Deferred TIP Shares3 £ |
PSP Awards4 £ |
Total £ |
||
| Executive Directors |
||||||||
| Aidan Heavey | 2015 | 886,080 | 221,520 | 57,849 | 835,130 | 835,130 | – | 2,835,709 |
| 2014 | 886,080 | 221,520 | 47,926 | 611,395 | 611,395 | – | 2,378,316 | |
| Graham Martin | 2015 | 501,110 | 125,278 | 9,744 | 472,296 | 472,296 | – | 1,580,724 |
| 2014 | 501,110 | 125,278 | 7,001 | 345,766 | 345,766 | – | 1,324,921 | |
| Angus McCoss | 2015 | 501,110 | 125,278 | 6,655 | 472,296 | 472,296 | – | 1,577,635 |
| 2014 | 501,110 | 125,278 | 5,204 | 345,766 | 345,766 | – | 1,323,124 | |
| Paul McDade | 2015 | 501,110 | 125,278 | 5,394 | 472,296 | 472,296 | – | 1,576,374 |
| 2014 | 501,110 | 125,278 | 3,937 | 345,766 | 345,766 | – | 1,321,857 | |
| Ian Springett | 2015 | 532,080 | 133,020 | 8,371 | 501,485 | 501,485 | – | 1,676,441 |
| 2014 | 532,080 | 133,020 | 6,331 | 367,135 | 367,135 | – | 1,405,701 | |
| Subtotal | 2015 | 2,921,490 | 730,374 | 88,013 | 2,753,503 | 2,753,503 | – | 9,246,883 |
| 2014 | 2,921,490 | 730,374 | 70,399 | 2,015,828 | 2,015,828 | – | 7,753,919 | |
| Non-executive Directors | ||||||||
| Tutu Agyare | 2015 | 69,500 | – | – | – | – | – | 69,500 |
| 2014 | 69,500 | – | – | – | – | – | 69,500 | |
| Mike Daly | 2015 | 69,500 | – | – | – | – | – | 69,500 |
| 2014 | 40,542 | – | – | – | – | – | 40,542 | |
| Anne Drinkwater |
2015 | 84,500 | – | – | – | – | – | 84,500 |
| 2014 | 84,500 | – | – | – | – | – | 84,500 | |
| Ann Grant | 2015 | 89,500 | – | – | – | – | – | 89,500 |
| 2014 | 79,500 | – | – | – | – | – | 79,500 | |
| Steve Lucas | 2015 | 89,500 | – | – | – | – | – | 89,500 |
| 2014 | 89,500 | – | – | – | – | – | 89,500 | |
| Simon | ||||||||
| Thompson | 2015 | 310,500 | – | – | – | – | – | 310,500 |
| 2014 | 310,500 | – | – | – | – | – | 310,500 | |
| Jeremy Wilson | 2015 | 89,500 | – | – | – | – | – | 89,500 |
| 2014 | 82,833 | – | – | – | – | – | 82,833 | |
| Subtotal | 2015 | 802,500 | – | – | – | – | – | 802,500 |
| 2014 | 756,875 | – | – | – | – | – | 756,875 | |
| Total | 2015 | 3,723,990 | 730,374 | 88,013 | 2,753,503 | 2,753,503 | – | 10,049,383 |
| 2014 | 3,678,365 | 730,374 | 70,399 | 2,015,828 | 2,015,828 | – | 8,510,794 |
Notes
Base salaries of the Executive Directors have been rounded up to the nearest £10 for payment purposes, in line with established policy.
Taxable benefits comprise private medical insurance and, in the case of Aidan Heavey, car benefits.
These figures represent that part of the TIP award required to be deferred into shares.
Relates to the 2013 PSP award which lapses in 2016 as a result of the relative TSR performance conditions not being met.
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.
No Executive Director left in 2015 and therefore no compensation for loss of office was paid. The principles governing compensation for loss of office payments are set out on page 97.
Determination of 2016 TIP Award based on performance to 31 December 2015 (audited).
Following the end of the 2015 financial year, the scorecard KPI performance was 37.7 per cent of the maximum and the Committee awarded Executive Directors a total TIP award equating to 188.5 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 2021). Details of the performance targets which operated and performance against those targets are as follows:
| Performance metric | Performance target | % of Award (% of salary maximum) |
Actual |
|---|---|---|---|
| Operational (Production, Opex and Net G&A) |
20% payable at threshold, increasing to 40% payable at target, increasing to 100% payable at stretch |
10% (50%) |
6.6%1 (33.0%) |
| TEN Development (First oil date and cost) |
20% payable at threshold, increasing to 40% payable at target, increasing to 100% payable at stretch |
10% (50%) |
7.2%2 (36.0%) |
| Safe and sustainable operations |
Lost time injury (LTIF) frequency and safe and sustainable operations scorecard |
10% (50%) |
7.3%3 (36.5%) |
| Strategic Targets | Three specific strategic targets (see overleaf) | 20% (100%) |
16.7%4 (84.0%) |
| Relative TSR | 25% payable at median, increasing to 100% payable at upper quintile against a bespoke group of listed exploration and production companies measured over two years to 31 December 2015 |
50% (250%) |
0%5 (0%) |
| Total | 100% (500%) |
37.7%6 (188.5%) |
Production was above the stretch target of 70,987 boepd. The 'run rate' to deliver net G&A cost savings was on target.
TEN Development was above target but below stretch target.
LTIF target was achieved; Safe and sustainable operations scorecard below stretch target.
Details of the assessment against the strategic targets are presented on page 105.
The TSR comparator group for the 2016 TIP award was as follows: Afren, Anadarko, Apache, BG Group, Cairn Energy, Canadian Natural Resources, Cobalt Energy, Conoco Phillips, Hess, Kosmos Energy, Lundin Petroleum, Marathon Oil, Noble Energy, Oil Search, Ophir Energy, Premier Oil, Santos, SOCO International, Talisman Energy and Woodside Petroleum. As per the transitional arrangements set out in the Remuneration Policy Report, the performance period for the 2016 TIP award was based on the 24 months ended 31 December 2015. Tullow's TSR of -77.78% was below the median of -38.2%.
Due to rounding, column does not add to total.
Note: See KPIs on pages 17 to 21 for more details.
As mentioned in the summary Directors' remuneration policy table on page 95, the 2016 strategic objectives are in line with strategic priorities and consist of:
| 2015 Strategic TIP targets | Remuneration Committee assessment of performance |
|---|---|
| Liquidity: Take appropriate steps to ensure cost effective and sufficient liquidity in 2015. |
The March 2015 re-determination accessed \$450 million of increased debt capacity, and the strength of our producing assets helped to maintain debt capacity despite lower oil prices. An enhanced sculpted covenant profile has also been negotiated to ensure sufficient headroom. Net debt at year end 2015 was \$4.0 billion and headroom and free cash was \$1.9 billion, ahead of guidance due to a combination of cost savings and deferral of certain capex to 2016. A number of exploration farm-outs were concluded during the year, reducing E&A expenditure through carried costs. |
| East Africa: Deliver East Africa exploration campaign, demonstrate commercial viability of South Lokichar resource base and maintain ability to accelerate a commercially attractive project into 2016. |
Nine appraisal wells were drilled in the South Lokichar Basin in Kenya in 2015 and all were largely on prognosis, underpinning an estimated gross contingent resource base of 600 mmbo. Extended Well Tests displayed good connectivity at Ngamia and Amosing and provided important data for development plans. Elsewhere, three potential basin opening exploration wells were drilled in 2015, but none made discoveries. In August 2015, the Governments of Kenya and Uganda issued a joint statement agreeing the Northern pipeline route would be used to export oil, subject to certain conditions. A technical team is working on addressing these conditions to gain unequivocal agreement from both governments. A draft field development plan for the discoveries in the South Lokichar Basin was submitted in December 2015. In Uganda, historic CGT and VAT issues were resolved. |
| Major Simplification Project: Deliver business restructuring and efficient processes focused on enhancing value. |
The MSP project has successfully adjusted the operating model of the business, clarified key accountabilities, improved culture around value creation and performance management, and simplified the organisational structure – with further work ongoing to simplify internal processes and better manage our cost base ongoing. Headcount has been reduced across the business to better reflect Tullow's activities and scope of operations. The new operating model and implementation of an integrated management system has better defined key accountabilities and responsibilities. Ongoing performance management reviews have evolved to improve discussions around value creation on a more regular basis, with the Group's ongoing delivery against its key objectives regularly communicated to staff. A shift to a more cost-conscious culture has occurred as a result of regular expenditure reviews and improved cross business challenge. Engagement with the Executive, in-country management and peers has been stepped up to help motivate, engage and focus staff on the Group's targets during this period of change and challenging market conditions. |
The PSP awards granted on 22 February 2013 were based on performance to 31 December 2015. As disclosed in previous annual reports, the performance condition was as follows:
| Metric | Performance Condition | Threshold Target |
Stretch Target |
Actual | % Vesting |
|---|---|---|---|---|---|
| Oil Sector TSR 70% of Awards |
15% of this part of an award vests at Index TSR1, increasing pro-rata to 100% of this part of an award vesting for outperformance of Index TSR by 20% p.a. |
0% TSR | 20% TSR | -46.6% TSR | 0% |
| FTSE 100 TSR 30% of Awards |
15% of this part of an award vests at Index TSR2, increasing pro-rata to 100% of this part of an award vesting for outperformance of Index TSR by 20% p.a. |
0% TSR | 20% TSR | -46.6% TSR | 0% |
| Total vesting | 0% |
For the Oil Sector element, Index TSR is based on the weighted mean TSR (i.e. each comparator's TSR is weighted by the comparator's market capitalisation at the start of the performance period, subject to a minimum weighting of 2% and a maximum weighting of 10% for any individual company). The constituents of the group were as follows: Afren, Anadarko, Apache, BG Group, Cairn Energy, Canadian Natural Resources, Cononco Phillips, EOG Resources, Hess, Lundin Petroleum, Marathon Oil, Noble Energy, Oil Search, Ophir Energy, Pioneer Natural Resources, Premier Oil, Santos, SOCO International, Talisman Energy and Woodside Petroleum.
For the FTSE 100 element, Index TSR is the median TSR of the individual constituents of the index.
The award details for the Executive Directors are therefore as follows:
| Executive | Type of award | Number of shares at grant |
Number of shares to vest |
Number of shares to lapse |
Total | Estimated value (£'000) |
|---|---|---|---|---|---|---|
| Aidan Heavey | Nil-cost option | 300,000 | 0 | 300,000 | 0 | 0 |
| Ian Springett | Nil-cost option | 175,000 | 0 | 175,000 | 0 | 0 |
| Other Executive Directors | Nil-cost option | 525,000 | 0 | 525,000 | 0 | 0 |
The second TIP awards were granted to Executive Directors on 18 February 2015, based on the performance period ended 31 December 2014, as follows:
| Executive | Number of TIP shares awarded |
Face value of awards at grant date |
Normal vesting dates (end of exercise window) |
Pre-grant performance period |
|---|---|---|---|---|
| Aidan Heavey | 152,772 | £611,395 | 18.02.2019 – 50% | |
| Ian Springett | 91,737 | £367,135 | 18.02.2020 – 50% | 01.01.2014 to 31.12.2014 |
| Other Executive Directors* | 86,398 | £345,766 | [17.02.2025] | (TSR 01.01.2013 to 31.12.2014) |
* Individual award
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 01.01.15 |
Partnership shares acquired in year |
Matching shares awarded in year |
Total shares held 31.12.15 |
SIP shares that became unrestricted in the year |
Total unrestricted shares held at 31.12.15 |
|---|---|---|---|---|---|---|
| Graham Martin | 8,212 | 645 | 645 | 9,502 | 278 | 7,056 |
| Angus McCoss | 3,242 | 645 | 645 | 4,532 | 278 | 2,086 |
| Paul McDade | 8,212 | 645 | 645 | 9,502 | 278 | 7,056 |
| Ian Springett | 1,720 | 645 | 645 | 3,010 | 276 | 562 |
* Unrestricted shares (which are included in the total shares held at 31 December 2015) are those which no longer attract a tax liability if they are withdrawn from the Plan.
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 a seven-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 seven 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 2015). The annual bonus payout, 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 | ||
| Total remuneration | £4,516,580 | £3,558,698 | £4,688,541 | £2,623,116 | £2,750,273 | £2,378,316 | £ 2,835,709 | |
| Annual bonus (%) | 86% | 58% | 80% | 70% | – | – | – | |
| PSP vesting (%) | 100% | 100% | 100% | 23% | 0% | 0% | 0% | |
| TIP (%) | – | – | – | – | 30% | 23% | 38% |
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 2014 and 31 December 2015, compared to that of the average for all employees of the Group.
| % Change from 2014 to 2015 | |||||||
|---|---|---|---|---|---|---|---|
| Salary Benefits |
|||||||
| Chief Executive | 0% | 21% | 37% | ||||
| Average Employees | 5.2% 0% |
The following table shows the Group's actual spend on pay for all employees relative to dividends, tax and retained profits.
| 2014 | 2015 | % change | |
|---|---|---|---|
| Staff costs (£'m) | 279 | 218 | -21% |
| Dividends (£'m) | 111 | – | -100% |
| Tax (£'m)* | -247 | -158 | 36% |
| Retained profits (£'m)* | 1,484 | 860 | -42% |
* Voluntary disclosure.
The dividend figures relate to amounts payable in respect of the relevant financial year.
At last year's AGM on 30 April 2015 the remuneration-related resolutions received the following votes from shareholders:
| 2014 Annual Statement & Annual Report on Remuneration | ||
|---|---|---|
| Total number of votes | % of votes cast | |
| For | 630,764,351 | 96% |
| Against | 22,532,315 | 3.5% |
| Total votes cast (for and against) | 653,296,666 | 99% |
| Votes withheld | 7,175,014 | 1% |
| Total issued share capital instructed | 660,471,680 | 71.7% |
Details of nil cost options granted to Executive Directors under the TIP:
| Award grant | Share price on | Granted during | Earliest date shares can be |
Latest date shares can be |
|||
|---|---|---|---|---|---|---|---|
| Director | date | grant date | As at 01.01.15 | year | As at 31.12.15 | 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 | |
| 102,992 | 255,764 | ||||||
| Graham Martin | 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 | |
| 58,246 | 144,644 | ||||||
| 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 | |
| 58,246 | 144,644 | ||||||
| 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 | |
| 58,246 | 144,644 | ||||||
| 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 | |
| 61,845 | 153,582 |
Details of nil exercise cost option shares granted to Executive Directors for nil consideration under the PSP:
| Earliest date | Latest date | |||||||
|---|---|---|---|---|---|---|---|---|
| Director | Award grant date |
Share price at grant (pence) |
As at 01.01.15 | Exercised during year |
Lapsed during year |
As at 31.12.15 | shares can be acquired |
shares can be acquired |
| Aidan | ||||||||
| Heavey | 22.02.13 | 1,241 | 300,000 | – | 300,000 | – | 22.02.16 | 21.02.23 |
| 300,000 | – | 300,000 | – | |||||
| Graham | ||||||||
| Martin | 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 | |
| 22.02.13 | 1,241 | 175,000 | – | 175,000 | – | 22.02.16 | 21.02.23 | |
| 367,604 | 175,000 | 192,604 | ||||||
| Angus | ||||||||
| McCoss | 22.02.13 | 1,241 | 175,000 | – | 175,000 | – | 22.02.16 | 21.02.23 |
| 175,000 | 175,000 | – | ||||||
| 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 | |
| 22.02.13 | 1,241 | 175,000 | – | 175,000 | – | 22.02.16 | 22.02.23 | |
| 367,604 | 175,000 | 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 | |
| 22.02.13 | 1,241 | 175,000 | – | 175,000 | – | 22.02.16 | 21.02.23 | |
| 363,147 | 175,000 | 188,147 |
All of the PSP awards listed on the previous page 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.
The PSP awards granted in February 2013 reached the end of their performance period on 31 December 2015. As a result of the performance conditions not being met the awards have now lapsed.
Details of nil exercise cost options granted to Executive Directors for nil consideration under the DSBP:
| Earliest date | Latest date | |||||
|---|---|---|---|---|---|---|
| Director | Award grant date |
As at 01.01.15 | Exercised during year |
As at 31.12.15 | shares can be acquired |
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 | ||||
| Graham Martin | 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 | ||||
| Angus McCoss | 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 | |
| 51,635 | 25,819 | 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 |
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.
The aggregate gain made by Directors on the exercise of nil cost options under the DSBP during the year was £99,332 (gross) (£42,712 for 2014). On 11 February 2015, being the date Angus McCoss exercised his options in the table above, the middle market quoted price of a Tullow share was £3.85.
During 2015, the highest mid-market price of the Company's shares was 429.8p and the lowest was 152.1p. The year-end price was 165.7p.
The interests of the Directors (all of which were beneficial), who held office at 31 December 2015, are set out in the table below:
| Ordinary shares held |
TIP Awards |
PSP Awards |
DSBP Awards |
SIP | Total | % of salary held under Shareholding Guidelines* |
||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 31.12.14 | 31.12.15 | Unvested | Vested | Unvested | Vested | Unvested | Vested | Restricted | Unrestricted | 31.12.15 | (400% of salary) | |
| Aidan Heavey |
6,401,511 | 6,401,511 | 255,764 | – | 300,000 | – | 45,649 | 65,649 | – | – | 7,068,573 | 1322% |
| Graham Martin |
2,030,392 | 2,030,392 | 144,644 | – | 175,000 | 192,604 | 25,816 | 97,463 | 2,446 | 7,056 | 2,675,421 | 885% |
| Angus McCoss |
247,425 | 261,078 | 144,644 | – | 175,000 | – | 25,816 | – | 2,446 | 2,086 | 611,070 | 202% |
| Paul McDade |
260,801 | 305,801 | 144,644 | – | 175,000 | 192,604 | 25,816 | 96,128 | 2,446 | 7,056 | 949,495 | 314% |
| Ian Springett |
12,000 | 12,000 | 153,582 | – | 175,000 | 188,147 | 27,411 | 56,349 | 2,448 | 562 | 615,499 | 192% |
| Non-executive Directors |
||||||||||||
| Simon Thompson |
20,604 | 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 | 15,000 | – | – | – | – | – | – | – | – | 15,000 | – |
* Calculated using share price of 165.7p 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 400% of their salary. Further details of the Shareholding Guidelines are set out on page 94.
On 8 January 2016 each of Graham Martin, Angus McCoss and Paul McDade were awarded 618 SIP shares and Ian Springett was awarded 616 SIP shares, all of which are restricted. Accounting for certain restricted SIP shares becoming unrestricted SIP shares in the period between 1 January 2016 and the date of this report, Graham Martin accordingly holds 3,006 restricted SIP shares and 7,114 unrestricted SIP shares, Angus McCoss holds 3,006 restricted SIP shares and 2,144 unrestricted SIP shares, Paul McDade holds 3,006 restricted SIP shares and 7,114 unrestricted SIP shares and Ian Springett holds 3,006 restricted SIP shares and 620 unrestricted SIP shares.
There have been no other changes in the interests of any Director between 1 January 2016 and the date of this report other than as a consequence of PSP awards made in 2013 lapsing as mentioned in the notes to the table 'Directors' remuneration' on page 99.
The loss on ordinary activities after taxation of the Group for the year ended 31 December 2015 was \$1,036.9 million (2014: Loss \$1,639.9 million).
No dividends have been recommended by the Board in 2015 (2014: Stg 4p).
In January 2016 Tullow completed the farm-down of 25 per cent of its interest in block 12A to Delonex and Tullow also agreed to sell a 20 per cent interest in the Bannu West licence in Pakistan to Mari Gas. Tullow was awarded a 60 per cent operated interest in the Orinduik licence in January 2016, a 1,801 square kilometre block offshore Guyana. On 23 January 2016, the TEN FPSO set sail from Singapore to Ghana with arrival expected in early March 2016.
Subsequent to the balance sheet date there has been a deterioration in the spot price of Brent crude. Sensitivity analysis on the impact of a reduction in Brent crude prices on the carrying value of PP&E is provided in note 12.
As at 1 February 2016, the Company had an allotted and fully paid up share capital of 911,655,547 each with a nominal value of £0.10.
As at 9 February 2016, 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. | 109,187,335 | 11.98 |
| Genesis Asset Managers, LLP | 72,871,524 | 8.01 |
| Oppenheimer Funds, Inc. | 45,191,459 | 4.96 |
| BlackRock, Inc. | not provided | below 5 |
| Commonwealth Bank of | ||
| Australia (on behalf of certain | ||
| controlled undertakings) | 28,054,427 | 3.08 |
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%.
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:
• US\$3.4 billion (or up to US\$3.9 billion in the event that the Company exercises its option to increase the commitments by up to an additional US\$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 pursuant to which 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 terms of each of the above agreements, a 'change of control' occurs if any person, or group of persons acting in concert (as defined in the City Code on Takeovers and Mergers), gains control of the Company.
Under the terms of each of the above indentures a change of control occurs, in general terms, when (i) a disposal is made of all or substantially all the properties or assets of the Company and all its restricted subsidiaries (other than through a merger or consolidation) in one or a series of related transactions; (ii) a plan is adopted relating to the liquidation or dissolution of the Company; or (iii) a person becomes the beneficial owner, directly or indirectly, of shares of the Company which grant that person more than 50 per cent of the voting rights of the Company.
The biographical details of the Directors of the Company at the date of this Report are given on pages 50 and 51.
Details of Directors' service agreements and letters of appointment can be found on pages 96 and 97. 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 102 and pages 104 to 106 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's 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 46 and 47 of this Report. In addition, Tullow publishes a separate Corporate Responsibility Report which is available on the Group website: www.tullowoil.com.
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 auditors are 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 auditors are aware of that information.
A resolution to re-appoint Deloitte LLP as the Company's auditors will be proposed at the AGM. More information can be found in the Audit Committee report on page 79.
The Notice of Annual General Meeting accompanies this Annual Report and sets out the resolutions to be proposed at the forthcoming AGM. The meeting will be held on 28 April 2016, 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
9 February 2016
Registered office: 9 Chiswick Park 566 Chiswick High Road London W4 5XT
Company registered in England and Wales No. 3919249
The New Ventures Business Delivery Team is responsible for Tullow's frontier exploration and appraisal activity. This involves investigating potential new countries to enter, negotiating deals to acquire, farm-in or farm-out of licences and high-grading the Group's explorations portfolio to prepare drill-ready prospects for future years.
3
| Statement of Directors' responsibilities | 114 |
|---|---|
| Independent auditor's report for the Group Financial | |
| Statements | 115 |
| Group Financial Statements | 120 |
| Company Financial Statements | 154 |
| Five year financial summary | 163 |
| Supplementary information | |
| Shareholder information | 164 |
| Licence interests | 165 |
| Commercial reserves and resources | 170 |
|---|---|
| Transparency disclosure | 171 |
| Subsidiaries | 176 |
| Glossary | 178 |
South American exploration team reviewing subsurface geology, Dublin office, Ireland
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 have elected to prepare the Group Financial Statements in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union and the Parent Company Financial Statements in accordance with Financial Reporting Standard 101 Reduced Disclosure Framework. Under company law the Directors must not approve the Financial Statements 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 proper 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 Ian Springett Chief Executive Officer Chief Financial Officer
9 February 2016 9 February 2016
114 Tullow Oil plc 2015 Annual Report and Accounts
| Opinion on Financial Statements of Tullow Oil plc |
In our opinion: • the Financial Statements give a true and fair view of the state of the Group's and of the Parent Company's affairs as at 31 December 2015 and of the Group's loss for the year then ended; • the Group Financial Statements have been properly prepared in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union; • the Parent Company Financial Statements have been properly prepared in accordance with United Kingdom Generally Accepted Accounting Practice, including FRS 101 "Reduced Disclosure Framework"; and • the Financial Statements have been prepared in accordance with the requirements of the Companies Act 2006 and, as regards the Group Financial Statements, Article 4 of the IAS Regulation. The Financial Statements comprise the Group Income Statement, the Group Statement of Comprehensive Income and Expense, the Group and Company Balance Sheets, the Group Statement of Changes in Equity, the Group Cash Flow Statement, the Group Accounting Policies with related notes 1 to 31 and the Company Accounting Policies with related notes 1 to 10. 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". |
|---|---|
| Going concern and the Directors' assessment of the principal risks that would threaten the solvency or liquidity of the Group |
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 (af) to the Financial Statements and the Directors' statement on the longer-term viability of the Group on page 55. We have nothing material to add or draw attention to in relation to: • the Directors' confirmation on page 114 that they have carried out a robust assessment of the principal risks facing the Group, including those that would threaten its business model, future performance, solvency or liquidity; • the disclosures on page 52 that describe those risks and explain how they are being managed or mitigated; • the Directors' statement in note (af) to the Financial Statements about whether they considered it appropriate to adopt the going concern basis of accounting in preparing them and their identification of any material uncertainties to the Group's ability to continue to do so over a period of at least 12 months from the date of approval of the Financial Statements; • the Directors' explanation on page 78 as to how they have assessed the prospects of the Group, over what period they have done so and why they consider that period to be appropriate, and their statement as to whether they have a reasonable expectation that the Group will be able to continue in operation and meet its liabilities as they fall due over the period of their assessment, including any related disclosures drawing attention to any necessary qualifications or assumptions. We agreed 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. |
| Independence | We are required to comply with the Financial Reporting Council's Ethical Standards for Auditors and 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. |
| Our assessment of risks of material misstatement |
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. |
The Audit Committee has requested that while not required under International Standards on Auditing (UK and Ireland), we include in our report any significant key observations in respect of these assessed risks of material misstatement.
| Risk description | The carrying value of E&E assets at 31 December 2015 is \$3,400.0 million, and the Group has written off E&E expenditure totalling \$748.9 million in the year. See note 11 for further details. |
|||||
|---|---|---|---|---|---|---|
| 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 128. 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. |
||||||
| 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 126). In 2015, the Group has continued to review their exploration strategy and geographical areas of exploration focus in the context of a lower oil price environment. Our work has considered both of these factors. |
|||||
| The audit procedures we performed included obtaining an understanding of the Group's ongoing E&E activity by interviewing operational and finance staff at 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 been impaired we have challenged management on the events that led to the impairment, including reference to future budgeted expenditure. |
||||||
| Where an asset has demonstrated indicators of impairment but has been retained on the balance sheet, we have gathered evidence in respect of the status of appraisal activity, allocation of budget and any conclusion on commerciality. |
||||||
| 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 consent is obtained, for example in 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. |
||||||
| Carrying value of PP&E assets | ||||||
| Risk description | The Group holds PP&E assets of \$5,204.4 million at 31 December 2015 and has recorded impairments of PP&E of \$406.0 million in 2015. See note 12 for further information. |
|||||
| As described in the "critical accounting judgements" section of the Annual Report on page 128, the assessment of the carrying value of PP&E assets requires management to exercise judgement in identifying indictors 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 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 |
We examined management's assessment of impairment indicators, which concluded that the fall in commodity prices represented an indicator of impairment for all oil and gas assets held within PP&E. |
|||||
| the risk | 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 judgements of 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; |
||||||
| • 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 of Deloitte industry valuation specialists. |
| Key observations | From the work performed, we are satisfied that the assets have been treated in accordance with the requirements of IAS 36: Impairment of Assets. |
|---|---|
| When considered in aggregate, we consider the assumptions adopted to be within a reasonable range. Management has disclosed the impact of sensitivities of both the discount rate and commodity prices in the PP&E note on page 138. |
|
| Provision for tax claims | |
| Risk description | The nature, rate and type of taxation which is applicable to hydrocarbon exploration and production activities varies widely by jurisdiction. In addition, the Group is subject to various claims from local tax authorities in the normal course of its business. |
| Significant judgement is required to estimate the appropriate level of provision for the tax claims against the Group as the validity and ultimate outcome of such claims can be uncertain. As such, the Group has included tax provisions in their disclosure of key sources of uncertainty on page 129. |
|
| How the scope of our audit responded to the risk |
We have challenged the assumptions made by management regarding each significant claim with Tullow's tax team, such as their assessment of the likely outcome of the claim, and their estimate of any future settlement value. We have also evaluated the provisions and potential exposures together with tax specialists within the audit team from the relevant jurisdictions. |
| Our audit work included review of correspondence with the relevant tax authorities and we used our knowledge of the specific tax regimes to challenge the Group's assumptions and judgements regarding the level of provisions made. |
|
| Key observations | We are satisfied that the judgements made by management are reasonable, based on the audit evidence gathered. |
| The settlement of the Ugandan Capital Gains Tax dispute in the year has significantly reduced the overall tax exposure. There remain a number of claims where the Group believes there is a low probability of adverse outcomes due to the locations and industry in which the Group operates. |
|
| Going concern | |
| Risk description | The Group is dependent upon its ability to generate sufficient cash flows 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 has placed increased pressure on these cash flows and the ability of the Group to comply in the future with covenant ratios. |
| How the scope of our audit responded to |
Management's going concern forecasts include a number of assumptions on future cash flows, associated risks, and covenant compliance. Our audit work has focused on evaluating and challenging the reasonableness of these assumptions and their impact on the forecast period. |
| the risk | 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 the benchmarking of market data; |
|
| • Verifying the consistency of key inputs relating to future costs and production to other financial and operational information obtained during our audit; |
|
| • Reviewing key loan agreements, and past and forecast loan covenant calculations, and obtaining and reviewing correspondence with the lead arrangers of the RBL and RCF facilities with regards to the risk of non-compliance with financial covenant ratios; and |
|
| • Performing sensitivity analysis on management's "base case", including applying potential downside scenarios such as lower oil prices and business interruption. |
|
| Key observations | Management has concluded that the going concern basis remains appropriate after performing a detailed forecast of the liquidity and covenant compliance for a period of 12 months from the date of approval of the 2015 Annual Report and Accounts. In reaching their conclusion, they have considered the impact of possible downside scenarios and their ability to take mitigating actions if required, in advance of any such scenario threatening the maintenance of liquidity or covenant compliance. We are satisfied that management's going concern assessment is appropriate as stated above. |
| The description of risks above should be read in conjunction with the significant issues considered by the Audit Committee discussed on page 81. |
|
| 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. |
| Our application of materiality |
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. |
|||||
|---|---|---|---|---|---|---|
| We determined materiality for the Group to be \$60 million (2014: \$80 million), which is below 6% of pre-tax loss, and below 2% of equity. The decrease in materiality in 2015 reflects the decrease in the Group's net assets following the impairments recorded in the year. |
||||||
| We agreed with the Audit Committee that we would report to them all audit differences in excess of \$1.6 million (2014: \$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. |
||||||
| An overview of the scope of our audit |
Our Group audit scope for the current and prior year included a full audit of all seven (2014: eight) 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 seven reporting units account for 100% of the Group's total revenue, profit before tax and net assets. The materialities used for these components ranged from \$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 following reporting locations in the year: Gabon, Ghana, Kenya, and Uganda to direct and review the audit work performed by the component auditors. |
||||||
| At the Parent Company level we also tested the consolidation process and carried out analytical procedures to confirm our conclusion that there were no significant risks of material misstatement of the aggregated financial information of the remaining components not subject to audit or audit of specified account balances. |
||||||
| Opinion on other | In our opinion: | |||||
| matters prescribed by the Companies |
• the part of the Directors' Remuneration Report to be audited has been properly prepared in accordance with the Companies Act 2006; and |
|||||
| Act 2006 | • the information given in the Strategic Report and the Directors' Report for the financial year for which the Financial Statements are prepared is consistent with the Financial Statements. |
|||||
| Matters on which we are required to |
Adequacy of explanations received and accounting records Under the Companies Act 2006 we are required to report to you if, in our opinion: |
|||||
| report by exception | • 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. |
||||||
| We have nothing to report in respect of these matters. | ||||||
| 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: |
||||||
| • 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. We confirm that we have not identified any such inconsistencies or misleading statements.
| Respective responsibilities of Directors and auditor |
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. |
|||||
| Scope of the audit of the Financial Statements |
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
9 February 2016
| Notes | 2015 \$m |
2014 \$m |
|
|---|---|---|---|
| Continuing activities | |||
| Sales revenue | 2 | 1,606.6 | 2,212.9 |
| Cost of sales | 4 | (1,015.3) | (1,116.7) |
| Gross profit | 591.3 | 1,096.2 | |
| Administrative expenses | 4 | (193.6) | (192.4) |
| Restructuring costs | 4 | (40.8) | – |
| Loss on disposal | 9 | (56.5) | (482.4) |
| Goodwill impairment | 10 | (53.7) | (132.8) |
| Exploration costs written off | 11 | (748.9) | (1,657.3) |
| Impairment of property, plant and equipment, net | 12 | (406.0) | (595.9) |
| Provision for onerous service contracts | 23 | (185.5) | – |
| Operating loss | 4 | (1,093.7) | (1,964.6) |
| (Loss)/gain on hedging instruments | 21 | (58.8) | 50.8 |
| Finance revenue | 2 | 4.2 | 9.6 |
| Finance costs | 5 | (149.0) | (143.2) |
| Loss from continuing activities before tax | (1,297.3) | (2,047.4) | |
| Income tax credit | 6 | 260.4 | 407.5 |
| Loss for the year from continuing activities | (1,036.9) | (1,639.9) | |
| Attributable to: | |||
| Owners of the Company | (1,034.8) | (1,555.7) | |
| Non-controlling interest | 26 | (2.1) | (84.2) |
| (1,036.9) | (1,639.9) | ||
| Loss per ordinary share from continuing activities | 8 | ¢ | ¢ |
| Basic | (113.6) | (170.9) | |
| Diluted | (113.6) | (170.9) |
YEAR ENDED 31 DECEMBER 2015
| Notes | 2015 \$m |
2014 \$m |
|
|---|---|---|---|
| Loss for the year | (1,036.9) | (1,639.9) | |
| Items that may be reclassified to the income statement in subsequent periods | |||
| Cash flow hedges | |||
| Gains arising in the year | 21 | 513.0 | 485.7 |
| Reclassification adjustments for items included in profit on realisation | 21 | (302.4) | 4.6 |
| Exchange differences on translation of foreign operations | (43.6) | (50.6) | |
| Other comprehensive income | 167.0 | 439.7 | |
| Tax relating to components of other comprehensive income | 21 | (42.3) | (91.0) |
| Net other comprehensive income for the year | 124.7 | 348.7 | |
| Total comprehensive expense for the year | (912.2) | (1,291.2) | |
| Attributable to: | |||
| Owners of the Company | (910.1) | (1,207.0) | |
| Non-controlling interest | (2.1) | (84.2) | |
| (912.2) | (1,291.2) |
| ASSETS Non-current assets Goodwill 10 164.0 217.7 3,400.0 Intangible exploration and evaluation assets 11 3,660.8 Property, plant and equipment 12 5,204.4 4,887.0 Investments 13 1.0 1.0 223.4 Other non-current assets 14 119.7 Derivative financial instruments 21 218.7 193.9 Deferred tax assets 24 295.3 255.0 9,506.8 9,335.1 Current assets Inventories 15 107.2 139.5 Trade receivables 16 80.8 87.8 Other current assets 14 763.2 902.3 Current tax assets 6 127.6 221.6 Derivative financial instruments 21 406.5 280.8 Cash and cash equivalents 17 355.7 319.0 Assets classified as held for sale 18 – 135.6 1,841.0 2,086.6 11,347.8 11,421.7 Total assets LIABILITIES Current liabilities Trade and other payables 19 (1,110.6) (1,074.9) Provisions 23 (187.0) – Borrowings 20 (73.8) (131.5) Current tax liabilities (208.3) (115.9) Derivative financial instruments 21 (2.1) (3.3) Liabilities directly associated with assets classified as held for sale 18 – (13.6) (1,581.8) (1,339.2) Non-current liabilities (99.3) Trade and other payables 19 (85.1) Borrowings 20 (4,262.4) (3,209.1) Provisions 23 (1,065.1) (1,260.4) (1,164.5) Deferred tax liabilities 24 (1,507.6) (6,591.3) (6,062.2) (8,173.1) (7,401.4) Total liabilities 3,174.7 4,020.3 Net assets EQUITY Called-up share capital 25 147.2 147.0 Share premium 25 609.8 606.4 Foreign currency translation reserve (249.3) (205.7) Hedge reserve 21 569.9 401.6 Other reserves 740.9 740.9 Retained earnings 1,336.4 2,305.8 3,154.9 3,996.0 Equity attributable to equity holders of the Company Non-controlling interest 26 19.8 24.3 3,174.7 4,020.3 Total equity |
Notes | 2015 \$m |
2014 \$m |
|---|---|---|---|
Approved by the Board and authorised for issue on 9 February 2016.
Chief Executive Officer Chief Financial Officer
Aidan Heavey Ian Springett
| Notes | Share capital \$m |
Share premium \$m |
Foreign 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 2014 | 146.9 | 603.2 | (155.1) | 2.3 | 740.9 | 3,984.7 | 5,322.9 | 123.5 | 5,446.4 | |
| Loss for the year | – | – | – | – | – | (1,555.7) | (1,555.7) | (84.2) | (1,639.9) | |
| Hedges, net of tax | 21 | – | – | – | 399.3 | – | – | 399.3 | – | 399.3 |
| Currency translation adjustments |
– | – | (50.6) | – | – | – | (50.6) | – | (50.6) | |
| Issue of employee share options |
25 | 0.1 | 3.2 | – | – | – | – | 3.3 | – | 3.3 |
| Vesting of PSP shares | – | – | – | – | – | (0.4) | (0.4) | – | (0.4) | |
| Share-based payment charges |
27 | – | – | – | – | – | 59.5 | 59.5 | – | 59.5 |
| Dividends paid | 7 | – | – | – | – | – | (182.3) | (182.3) | – | (182.3) |
| Distribution to non controlling interests |
26 | – | – | – | – | – | – | – | (15.0) | (15.0) |
| 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 |
| Dividends paid | 7 | – | – | – | – | – | – | – | – | – |
| Distribution to non controlling interests |
26 | – | – | – | – | – | – | – | (2.4) | (2.4) |
At 31 December 2015 147.2 609.8 (249.3) 569.9 740.9 1,336.4 3,154.9 19.8 3,174.7
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.
| Notes | 2015 \$m |
2014 \$m |
|
|---|---|---|---|
| Cash flows from operating activities | |||
| Loss before taxation | (1,297.3) | (2,047.4) | |
| Adjustments for: | |||
| Depletion, depreciation and amortisation | 4 | 580.1 | 621.8 |
| Loss on disposal | 9 | 56.5 | 482.4 |
| Goodwill impairment | 10 | 53.7 | 132.8 |
| Exploration costs written off | 11 | 748.9 | 1,657.3 |
| Impairment of property, plant and equipment | 12 | 406.0 | 595.9 |
| Provision for onerous service contracts | 23 | 185.5 | – |
| Provision for inventory | 15 | 22.2 | – |
| Decommissioning expenditure | 23 | (40.8) | (20.4) |
| Share-based payment charge | 27 | 48.7 | 39.5 |
| Loss/(gain) on hedging instruments | 21 | 58.8 | (50.8) |
| Finance revenue | 2 | (4.2) | (9.6) |
| Finance costs | 5 | 149.0 | 143.2 |
| Operating cash flow before working capital movements | 967.1 | 1,544.7 | |
| (Increase)/decrease in trade and other receivables | (26.5) | 29.9 | |
| Decrease in inventories | 9.0 | 61.0 | |
| Increase/(decrease) in trade payables | 366.5 | (119.6) | |
| Cash generated from operating activities | 1,316.1 | 1,516.0 | |
| Income taxes received/(paid) | 34.9 | (34.2) | |
| Net cash from operating activities | 1,351.0 | 1,481.8 | |
| Cash flows from investing activities | |||
| Proceeds from disposals | 9 | 55.8 | 21.3 |
| Purchase of intangible exploration and evaluation assets | (647.6) | (1,255.1) | |
| Purchase of property, plant and equipment | (1,464.8) | (1,098.3) | |
| Interest received | 4.2 | 4.6 | |
| Net cash used in investing activities | (2,052.4) | (2,327.5) | |
| Cash flows from financing activities | |||
| Net proceeds from issue of share capital | 3.5 | 3.3 | |
| Debt arrangement fees | (25.7) | (22.2) | |
| Repayment of bank loans | (191.8) | (1,202.1) | |
| Drawdown of bank loans | 1,168.8 | 1,749.8 | |
| Issue of senior loan notes | 20 | – | 650.0 |
| Repayment of obligations under finance leases | (3.3) | (1.1) | |
| Finance costs paid | (203.6) | (172.9) | |
| Dividends paid | 7 | – | (182.3) |
| Distribution to non-controlling interests | 26 | (2.4) | (15.0) |
| Net cash generated by financing activities | 745.5 | 807.5 | |
| Net increase/(decrease) in cash and cash equivalents | 44.1 | (38.2) | |
| Cash and cash equivalents at beginning of year | 17 | 319.0 | 352.9 |
| Cash transferred from held for sale | – | 16.2 | |
| Foreign exchange loss | (7.4) | (11.9) | |
| Cash and cash equivalents at end of year | 17 | 355.7 | 319.0 |
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 given on page 111.
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 were in issue but not yet effective (and in some cases had not yet been adopted by the EU):
| IFRS 5 | Non-current Assets Held for Sale and Discontinued Operations – Changes in methods of disposal |
|---|---|
| IFRS 9 | Financial Instruments |
| IFRS 10 and IAS 28 | Sale or Contribution of Assets between an Investor and its Associate or Joint Venture |
| IFRS 11 | Accounting for Acquisitions of Interests in Joint Operations |
| IFRS 14 | Regulatory Deferral Accounts |
| IFRS 15 | Revenue from Contracts with Customers |
| IFRS 16 | Leases |
| IAS 1 | Disclosure Initiative |
| IAS 16 and IAS 38 | Clarification of Acceptable Methods of Depreciation and Amortisation |
| IAS 19 | Employee Benefits – Discount rate: regional market issue |
| IAS 27 | Equity Method in Separate Financial Statements |
| IAS 34 | Interim Financial Reporting – Disclosure of information 'elsewhere in the interim financial report' |
The adoption of IFRS 9 Financial Instruments which the Group plans to 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 plans to adopt for the year commencing 1 January 2019 will impact both the measurement and disclosures of leases.
The Directors do not expect that the adoption of the other Standards listed above will have a material impact on the Financial Statements of the Group in future periods.
Other than the changes to the Standards noted above, 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 non-current assets 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 (see note 21 for further details).
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 acquisition of subsidiaries is accounted for using the acquisition method. The consideration of the acquisition is measured at the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed and equity instruments issued by the Group in exchange for control of the acquiree. Acquisition costs incurred are expensed and included in administration expenses. The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 are recognised at their fair value at the acquisition date, except for non-current assets (or disposal groups) that are classified as held for sale in accordance with IFRS 5 Non-current Assets held for Sale and Discontinued
Operations, which are recognised and measured at fair value less costs to sell. Goodwill arising on acquisition is recognised as an asset and initially measured at cost, being the excess of the cost of the business combination over the Group's interest in the net fair value of the identifiable assets, liabilities and contingent liabilities recognised. If, after reassessment, the Group's interest in the net fair value of the acquiree's identifiable assets, liabilities and contingent liabilities exceeds the cost of the business combination, the excess is recognised immediately in the income statement.
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 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.
Sales revenue represents the sales value, net of VAT, of the Group's share of liftings in the year together with tariff income. Revenue is recognised when goods are delivered and title has passed.
Revenues received under take-or-pay sales contracts in respect of undelivered volumes are accounted for as deferred income.
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 re-determinations, 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 product, are stated at the lower of cost and net realisable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, 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 dollar-denominated 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 'Value in Use' 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. Prelicence 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. Where there is evidence of economic interdependency between fields, such as common infrastructure, the fields are grouped as a single cash-generating unit for impairment purposes.
Any impairment identified is charged to the income statement as additional depletion and amortisation. 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.
In order to account for uncertain tax positions management has formed an accounting policy, in accordance with IAS 8, whereby the ultimate outcome of legal proceedings is viewed as a single unit of account. The results of separate hearings in relation to the same matter, such as local tribunals and international arbitration, are not viewed separately and only the final outcome is assessed by management to determine the best estimate of any potential outcome. If management viewed the results of individual hearings separately an income statement charge could arise due to the differing recognition criteria of assets and liabilities.
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.
Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. 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.
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.
The Group assesses critical accounting judgements annually. The following are the critical judgements, apart from those involving estimations (which are dealt with in policy (af)), 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.
• 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 judgement.
The key areas in which management has applied judgement 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 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 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 and performs valuations of acquired property, plant and equipment in conjunction with IFRS 3 Business Combinations. 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 and the long-term corporate economic assumptions thereafter, 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 (note 21);
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. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.9 billion of debt liquidity headroom and free cash at the end of 2015. 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 2015 Annual Report and Accounts.
Notwithstanding our forecasts of liquidity headroom throughout the 12 month period, there remains a risk, given the volatility of the oil price environment and its impact on operating cash flows and facility availability, that the Group's liquidity position may deteriorate and/or the Group may become technically non-compliant with one of its financial covenants at the end of 2016.
To mitigate this risk, we will continue to maintain our long-term banking relations and will monitor our cash flow projections and, if necessary, take mitigating actions well in advance to maintain our liquidity and compliance with covenants. Actions available to the Group include further rationalisation of our cost base, cuts to discretionary capital expenditure, portfolio management and other funding options.
Based on the analysis above, 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 external 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.
• Recoverability of deferred tax assets (note 24);
Deferred tax assets are recognised for unused tax losses to the extent that it is probable that future taxable profits will be available against which the losses can be utilised. Estimation and judgement is required to determine the value of the deferred tax asset, based upon the timing and level of future taxable profits.
• Other tax provisions;
The Group is subject to various claims which arise in the ordinary course of its business, including tax claims from tax authorities in a number of the jurisdictions in which the Group operates. In order to assess whether tax claims should be provided for in the Financial Statements management has assessed all such claims in the context of the tax laws of the countries in which it operates. Management has applied judgement in assessing the likely outcome of the tax claims and has estimated the financial impact based on external tax and legal advice and prior experience of such claims.
The Directors believe that the Group has recorded adequate provisions as of 31 December 2015 and 2014 for all such matters.
• 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. If the Group is able to sub-contract the contracts or find a use for them the provision will decrease.
During 2015 the Group reorganised its operational structure so that the management and resources of the business are better aligned with the delivery of the business objectives. As a result the information reported to the Group's Chief Executive Officer for the purposes of resource allocation and assessment of segment performance has changed to focus on three new 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, profit and certain asset and liability information regarding the Group's reportable business segments for the years ended 31 December 2015 and 31 December 2014. The table for the year ended 31 December 2014 has been restated to reflect the new reportable segments of the business.
| 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 |
| Depletion, depreciation 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) |
All sales are to external customers. Included in revenue arising from West Africa are revenues of approximately \$314.9 million and \$164.2 million relating to the Group's largest customers (2014: \$545.9 million, \$323.2 million, \$217.8 million and \$210.5 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.
| Restated | Notes | West Africa \$m |
East Africa \$m |
New Ventures \$m |
Unallocated \$m |
Total \$m |
|---|---|---|---|---|---|---|
| 2014 | ||||||
| Sales revenue by origin | 2,205.2 | – | 7.7 | – | 2,212.9 | |
| Segment result | 371.8 | 0.8 | (1,656.1) | (6.3) | (1,289.8) | |
| Loss on disposal | (482.4) | |||||
| Unallocated corporate expenses | (192.4) | |||||
| Operating loss | (1,964.6) | |||||
| Gain on hedging instruments | 50.8 | |||||
| Finance revenue Finance costs |
9.6 (143.2) |
|||||
| Loss before tax Income tax credit |
(2,047.4) 407.5 |
|||||
| Loss after tax | (1,639.9) | |||||
| Total assets | 7,454.2 | 2,354.7 | 1,397.3 | 215.5 | 11,421.7 | |
| Total liabilities | (3,285.9) | (267.6) | (588.5) | (3,259.4) | (7,401.4) | |
| Other segment information Capital expenditure: |
||||||
| Property, plant and equipment | 12 | 1,463.1 | 1.6 | 11.0 | 59.6 | 1,535.3 |
| Intangible exploration and evaluation assets | 11 | 181.9 | 555.8 | 667.8 | – | 1,405.5 |
| Depletion, depreciation and amortisation | 12 | (577.1) | (0.9) | (1.2) | (42.6) | (621.8) |
| Impairment of property, plant and equipment | 12 | (592.4) | – | (3.5) | – | (595.9) |
| Exploration costs written off | 11 | (134.6) | 0.8 | (1,523.5) | – | (1,657.3) |
| Goodwill impairment | 10 | – | – | (132.8) | – | (132.8) |
| Sales revenue and non-current assets by origin | Sales revenue 2015 \$m |
Restated Sales revenue 2014 \$m |
Non-current assets 2015 \$m |
Restated Non-current assets 2014 \$m |
|---|---|---|---|---|
| Congo | 39.7 | 52.4 | 12.2 | 82.9 |
| Côte d'Ivoire | 91.8 | 58.5 | 159.1 | 143.3 |
| Equatorial Guinea | 176.1 | 262.8 | 218.6 | 354.7 |
| Gabon | 284.3 | 275.4 | 234.5 | 313.1 |
| Ghana | 869.1 | 1,272.1 | 4,891.0 | 4,102.9 |
| Mauritania | 18.9 | 35.9 | – | 1.4 |
| Netherlands | 57.5 | 93.1 | 115.5 | 572.6 |
| UK | 69.2 | 155.0 | 6.0 | 93.9 |
| Other | – | – | 0.5 | 10.6 |
| Total West Africa | 1,606.6 | 2,205.2 | 5,637.4 | 5,675.4 |
| Kenya | – | – | 880.6 | 659.4 |
| Uganda | – | – | 1,593.5 | 1,444.2 |
| Total East Africa | – | – | 2,474.1 | 2,103.6 |
| Norway | – | 7.7 | 474.8 | 573.9 |
| Other | – | – | 297.7 | 412.2 |
| Total New Ventures | – | 7.7 | 772.5 | 986.1 |
| Unallocated | – | – | 108.8 | 121.1 |
| Total revenue / non-current assets | 1,606.6 | 2,212.9 | 8,992.8 | 8,886.2 |
Non-current assets excludes derivative financial instruments and deferred tax assets.
| Notes | 2015 \$m |
2014 \$m |
|---|---|---|
| Sales revenue (excluding tariff income) | ||
| Oil and gas revenue from the sale of goods | 1,225.6 | 2,225.1 |
| Gain/(loss) on realisation of cash flow hedges 21 |
365.2 | (14.5) |
| 1,590.8 | 2,210.6 | |
| Provision for accrued income | – | (18.5) |
| Tariff income | 15.8 | 20.8 |
| Total sales revenue Finance revenue |
1,606.6 4.2 |
2,212.9 9.6 |
| Total revenue | 1,610.8 | 2,222.5 |
During 2014 accrued income of \$18.5 million in Gabon was written off.
The average monthly number of employees and contractors (including Executive Directors) employed by the Group worldwide was:
| 2015 Number |
2014 Number |
|
|---|---|---|
| Administration | 785 | 956 |
| Technical | 928 | 1,115 |
| Total | 1,713 | 2,071 |
| Staff costs in respect of those employees were as follows: | ||
| 2015 \$m |
2014 \$m |
|
| Salaries | 325.5 | 415.2 |
| Social security costs | 13.0 | 24.1 |
| Pension costs | 20.9 | 19.6 |
| 359.4 | 458.9 |
The decrease in staff costs is due to decreased employee numbers as a result of the 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 \$124.7 million (2014: \$100.8 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 | 2015 \$m |
2014 \$m |
|
|---|---|---|---|
| Operating loss is stated after charging: | |||
| Operating costs | 406.3 | 511.5 | |
| Depletion and amortisation of oil and gas assets | 12 | 551.2 | 572.2 |
| Underlift, overlift and oil stock movements | (1.5) | 27.1 | |
| Share-based payment charge included in cost of sales | 27 | 0.8 | 1.6 |
| Other cost of sales | 58.5 | 4.3 | |
| Total cost of sales | 1,015.3 | 1,116.7 | |
| Share-based payment charge included in administrative expenses | 27 | 47.9 | 37.9 |
| Depreciation of other fixed assets | 12 | 28.9 | 49.6 |
| Relocation costs associated with simplification project | 5.9 | – | |
| Other administrative costs | 110.9 | 104.9 | |
| Total administrative expenses | 193.6 | 192.4 | |
| Total restructuring costs | 23 | 40.8 | – |
| Fees payable to the Company's auditor for: | |||
| The audit of the Company's annual accounts | 0.4 | 0.4 | |
| The audit of the Company's subsidiaries pursuant to legislation | 2.1 | 2.4 | |
| Total audit services | 2.5 | 2.8 | |
| Non-audit services: | |||
| Audit related assurance services – half-year review | 0.4 | 0.5 | |
| Tax compliance services | 0.1 | 0.2 | |
| Corporate finance services | 0.1 | 0.2 | |
| Other services | 0.2 | 0.1 | |
| Total non-audit services | 0.8 | 1.0 | |
| Total | 3.3 | 3.8 |
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 ad-hoc assurance services in relation to the Group's JV agreements.
Details of the Company's policy on the use of auditors 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 79 to 83. No services were provided pursuant to contingent fee arrangements.
| Notes | 2015 \$m |
2014 \$m |
|---|---|---|
| Interest on bank overdrafts and borrowings | 246.3 | 202.3 |
| Interest on obligations under finance leases | 2.0 | 1.1 |
| Total borrowing costs | 248.3 | 203.4 |
| Less amounts included in the cost of qualifying assets 11,12 |
(160.1) | (120.6) |
| 88.2 | 82.8 | |
| Finance and arrangement fees | 16.8 | 14.4 |
| Other interest expense | 2.7 | 1.0 |
| Foreign exchange losses | 13.0 | 22.6 |
| Unwinding of discount on decommissioning provisions 23 |
28.3 | 22.4 |
| Total finance costs | 149.0 | 143.2 |
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 6.15% (2014: 6.63%) to cumulative expenditure on such assets.
Analysis of credit in period The tax credit comprises:
| Notes | 2015 \$m |
2014 \$m |
|---|---|---|
| Current tax | ||
| UK corporation tax | (3.5) | (61.5) |
| Foreign tax | 94.9 | (70.0) |
| Total corporate tax | 91.4 | (131.5) |
| UK petroleum revenue tax | (0.3) | 4.8 |
| Total current tax | 91.1 | (126.7) |
| Deferred tax | ||
| UK corporation tax | 6.9 | (199.7) |
| Foreign tax | (354.0) | (81.4) |
| Total deferred corporate tax | (347.1) | (281.1) |
| Deferred UK petroleum revenue tax | (4.4) | 0.3 |
| 24 Total deferred tax |
(351.5) | (280.8) |
| Total tax credit | (260.4) | (407.5) |
Factors affecting tax credit for the period
The change in tax credit in 2015 is driven by deferred tax credits associated with exploration write-offs of \$276.5 million (2014: \$397.9 million) and impairments of \$49.1 million (2014: \$174.9 million).
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% (2014: 21%) to the loss before tax is as follows:
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| Group loss on ordinary activities before tax | (1,297.3) | (2,047.4) |
| Tax on Group loss on ordinary activities at the standard UK corporation tax rate of 20% (2014: 21%) |
(259.5) | (430.0) |
| Effects of: | ||
| Expenses not deductible for tax purposes | 212.4 | 287.0 |
| Goodwill impairment | 10.7 | 27.9 |
| PSC income not subject to corporation tax | (28.5) | (5.9) |
| Net losses not recognised | 15.8 | 104.7 |
| Petroleum revenue tax (PRT) | (4.4) | 5.4 |
| UK corporation tax deductions for current PRT | 2.2 | (3.3) |
| Utilisation of tax losses not previously recognised | – | (56.1) |
| Adjustment relating to prior years | (14.9) | (7.1) |
| Adjustments to deferred tax relating to change in tax rates | (1.0) | – |
| Income taxed at a different rate | (297.3) | (313.0) |
| Uganda capital gains tax | 108.2 | – |
| Tax incentives for investment | (4.1) | (17.1) |
| Group total tax credit for the year | (260.4) | (407.5) |
The Finance (No.2) Act 2015 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 18% from 1 April 2020. These changes were substantively enacted on 26 October 2015 and hence the effect of the change on the deferred tax balances has been included, depending upon when deferred tax will 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 \$1,802.0 million (2014: \$1,642.1 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. The Group has recognised \$55.7 million in deferred tax assets in relation to taxable losses (2014: \$72.0 million); this is offset net of a deferred tax liability in respect of capitalised interest.
No deferred tax liability is recognised on temporary differences of \$8.5 million (2014: \$21.2 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 2015 \$42.3 million (2014: \$91.0 million) of tax has been recognised through other comprehensive income of which \$43.2 million (2014: \$89.5 million) is current and \$0.9 million (2014: \$1.5 million) is deferred tax relating to charges on cash flow hedges arising in the year.
As at 31 December 2015, current tax assets were \$127.6 million (2014: \$221.6 million) of which \$55.0 million (2014: \$155.9 million) relates to Norway, where 78% of exploration expenditure is refunded as a tax refund in the following year and \$47.7 million (2014: \$47.7 million) relates to a tax overpayment in Ghana.
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| Declared and paid during year | ||
| Final dividend for 2014: nil pence (2013: 8 pence) per ordinary share | – | 123.3 |
| Interim dividend for 2015: nil pence (2014: 4 pence) per ordinary share | – | 59.0 |
| Dividends paid | – | 182.3 |
| Proposed for approval by shareholders at the AGM | ||
| Final dividend for 2015: nil pence (2014: nil pence) per ordinary share | – | – |
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 were converted into ordinary shares. The losses made in 2015 and 2014 are antidilutive.
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| Loss | ||
| Net loss attributable to equity shareholders | (1,034.8) | (1,555.7) |
| Effect of dilutive potential ordinary shares | – | – |
| Diluted net loss attributable to equity shareholders | (1,034.8) | (1,555.7) |
| 2015 Number |
2014 Number |
|
| Number of shares | ||
| Basic weighted average number of shares | 911,252,238 | 910,144,565 |
| Dilutive potential ordinary shares | 25,070,398 | 13,296,447 |
| Diluted weighted average number of shares | 936,322,636 | 923,441,012 |
| Income statement 2015 \$m |
Cash flow 2015 \$m |
Income statement 2014 \$m |
Cash flow 2014 \$m |
|
|---|---|---|---|---|
| Uganda farm-down consideration adjustments | – | – | (36.6) | (36.6) |
| Write-off of Uganda contingent consideration | – | – | (370.1) | – |
| Disposal of L&Q blocks (Netherlands) | (46.3) | 53.5 | – | – |
| Farm-down of E blocks (Netherlands) | – | 0.1 | – | – |
| Disposal of Brage (Norway) to Wintershall | – | – | 21.1 | 8.4 |
| Various licence disposals (Norway) | (7.4) | – | – | – |
| Farm-down of Schooner & Ketch (UK) to Faroe Petroleum (U.K.) Limited | 2.2 | 2.2 | (90.4) | 38.1 |
| Other | (5.0) | – | (6.4) | 11.4 |
| (56.5) | 55.8 | (482.4) | 21.3 |
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.
In 2014, the Group completed the disposal of Brage (Norway) and the farm-down of Schooner and Ketch (UK) for net cash consideration of \$8.4 million and \$38.1 million respectively. In 2014, it was determined that it was no longer probable that the contingent consideration, recorded on the farm-down of Ugandan assets in 2012, would be recoverable and as such the balance of \$370.1 million was written off. In 2014, the Group made a payment of \$36.6 million in respect of certain indemnities granted on the farm-down of Tullow's interest in Uganda.
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| At 1 January | 217.7 | 350.5 |
| Impairment | (53.7) | (132.8) |
| At 31 December | 164.0 | 217.7 |
| Related deferred tax at 31 December | (89.0) | (99.1) |
| Goodwill net of associated deferred tax | 75.0 | 118.6 |
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 \$264.5 million (2014: \$419.8 million) and the recoverable amount of the CGUs was \$210.8 million (2014: \$287.0 million), resulting in an impairment of \$53.7 million (2014: \$132.8 million). The cumulative impairment is \$186.5 million (2014: \$132.8 million).
Proven and probable reserves are estimated using standard recognised evaluation techniques. The estimate is reviewed at least twice annually and is regularly reviewed by independent consultants. 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.
A Value in Use (VIU) calculation was performed for discoveries. The VIU was calculated using risked resources, a long-term oil price assumption of \$90/bbl, estimated future costs and a discount rate of 10%.
As discussed above the principal assumptions are oil price and discount rate. A \$10/bbl reduction in oil prices would increase the impairment charge by \$115.1 million and a 1% increase in the discount rate would increase the impairment by \$59.3 million.
| Notes | 2015 \$m |
2014 \$m |
|
|---|---|---|---|
| At 1 January | 3,660.8 | 4,148.3 | |
| Additions | 1 | 626.3 | 1,405.5 |
| Disposals | 9 | (5.2) | (26.8) |
| Amounts written-off | (748.9) | (1,657.3) | |
| Amounts written-off previously classified as held for sale | – | (5.1) | |
| Write-off associated with Norway contingent consideration provision | 23 | – | (88.8) |
| Net transfer to assets held for sale | 18 | – | (13.8) |
| Transfer to property, plant and equipment | 12 | (63.6) | – |
| Currency translation adjustments | (69.4) | (101.2) | |
Included within 2015 additions is \$49.7 million (note 5) of capitalised interest (2014: \$47.8 million). The Group only capitalises interest in respect of intangible exploration and evaluation assets where it is considered that development is highly likely and advanced appraisal and development is ongoing.
The below table provides a summary of the exploration costs written-off on a pre-and post-tax basis by country.
| Rationale for 2015 write-off |
2015 Current year expenditure written-off \$m |
2015 Prior year expenditure written-off \$m |
2015 Post-tax write off \$'m |
2015 Pre-tax write off \$'m |
2014 Current year expenditure \$m |
2014 Prior year expenditure \$m |
2014 Post-tax write off \$'m |
2014 Pre-tax write off \$'m |
|
|---|---|---|---|---|---|---|---|---|---|
| Côte d'Ivoire | b | 2.9 | – | 2.9 | 2.9 | 2.7 | 55.3 | 58.0 | 58.0 |
| Ethiopia | c | 4.8 | 34.9 | 39.7 | 39.7 | 65.1 | – | 65.1 | 65.1 |
| French Guiana | c | 0.3 | – | 0.3 | 0.3 | (1.3) | 344.4 | 343.1 | 363.4 |
| Gabon | a, b, c | 3.5 | 8.5 | 12.0 | 21.3 | 26.9 | 6.4 | 33.3 | 54.0 |
| Ghana | b | 0.4 | – | 0.4 | 0.4 | 0.5 | 19.9 | 20.4 | 20.4 |
| Guinea | c | 6.0 | 54.3 | 60.3 | 60.3 | – | – | – | – |
| Greenland | c | 0.2 | 38.5 | 38.7 | 38.7 | – | – | – | – |
| Kenya | a | 28.3 | – | 28.3 | 28.3 | 0.6 | – | 0.6 | 0.6 |
| Netherlands | c | – | 185.7 | 185.7 | 371.3 | – | – | – | – |
| Norway | a, b | 11.3 | 8.9 | 20.2 | 92.2 | 28.1 | 52.3 | 80.4 | 366.6 |
| Madagascar | c | 1.5 | 10.7 | 12.2 | 12.2 | – | – | – | – |
| Mauritania | b | 7.3 | – | 7.3 | 7.3 | 199.6 | 368.6 | 568.2 | 621.4 |
| Mozambique | b | 4.6 | – | 4.6 | 4.6 | (6.2) | – | (6.2) | (6.2) |
| Suriname | a | 27.8 | 1.0 | 28.8 | 28.8 | – | – | – | – |
| Uganda | n/a | – | – | – | – | (1.5) | – | (1.5) | (1.5) |
| Other | a, b, c | 11.9 | – | 11.9 | 15.2 | 48.7 | 7.0 | 55.7 | 62.2 |
| New ventures | 19.1 | – | 19.1 | 25.4 | 42.3 | – | 42.3 | 53.3 | |
| Total write-off | 129.9 | 342.5 | 472.4 | 748.9 | 405.5 | 853.9 | 1,259.4 | 1,657.3 |
a. Current year unsuccessful drilling results.
b. Licence relinquishments.
c. Review of forward work programme in light of capital re-allocation to development projects and current low oil and gas price environment.
| 2015 | 2015 | 2014 | 2014 | ||||
|---|---|---|---|---|---|---|---|
| Oil and gas | Other fixed | 2015 | Oil and gas | Other fixed | 2014 | ||
| Notes | assets \$m |
assets \$m |
Total \$m |
assets \$m |
assets \$m |
Total \$m |
|
| Cost | |||||||
| At 1 January | 9,240.3 | 283.7 | 9,524.0 | 8,692.4 | 221.4 | 8,913.8 | |
| Additions | 1 | 1,235.1 | 23.1 | 1,258.2 | 1,454.7 | 80.6 | 1,535.3 |
| Disposals | (6.2) | (3.6) | (9.8) | (601.3) | 0.1 | (601.2) | |
| Transfer to assets held for sale | 18 | – | – | – | (177.2) | – | (177.2) |
| Transfer from intangible assets | 11 | 63.6 | – | 63.6 | – | – | – |
| Currency translation adjustments | (92.9) | (13.7) | (106.6) | (128.3) | (18.4) | (146.7) | |
| At 31 December | 10,439.9 | 289.5 | 10,729.4 | 9,240.3 | 283.7 | 9,524.0 | |
| Depreciation, depletion and amortisation |
|||||||
| At 1 January | (4,489.1) | (147.9) | (4,637.0) | (3,942.3) | (108.6) | (4,050.9) | |
| Charge for the year | 4 | (551.2) | (28.9) | (580.1) | (572.2) | (49.6) | (621.8) |
| Impairment loss | (467.2) | – | (467.2) | (595.9) | – | (595.9) | |
| Reversal of impairment loss | 61.2 | – | 61.2 | ||||
| Disposal | 6.4 | 3.6 | 10.0 | 448.0 | (0.1) | 447.9 | |
| Transfer to assets held for sale | 18 | – | – | – | 73.3 | – | 73.3 |
| Currency translation adjustments | 79.9 | 8.2 | 88.1 | 100.0 | 10.4 | 110.4 | |
| At 31 December | (5,360.0) | (165.0) | (5,525.0) | (4,489.1) | (147.9) | (4,637.0) | |
| Net book value at 31 December | 5,079.9 | 124.5 | 5,204.4 | 4,751.2 | 135.8 | 4,887.0 |
The 2015 additions include capitalised interest of \$110.4 million (note 5) in respect of the TEN development project (2014: \$72.8 million). The carrying amount of the Group's oil and gas assets includes an amount of \$27.4 million (2014: \$33.0 million) in respect of assets held under finance leases. Other fixed assets include leasehold improvements, motor vehicles and office equipment. 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.
| Trigger for 2015 |
2015 Impairment |
Discount rate | Short-term price | Mid-term price |
Long-term price |
|
|---|---|---|---|---|---|---|
| impairment | \$'m | assumption | assumptiond | assumption | assumption | |
| CMS GCUe | a | 87.5 | 10% | 2yr forward curve | n/a | 42.5p/th |
| Thames GCUe | b | (44.2) | 10% | 2yr forward curve | n/a | 42.5p/th |
| Netherlands CGUe | a | 28.7 | 10% | 2yr forward curve | n/a | 0.53€/th |
| Limande CGUf (Gabon) |
a | (0.2) | 13% | 2yr forward curve | \$70/bbl | \$90/bbl |
| Niungo CGUf (Gabon) |
a | 21.1 | 15% | 2yr forward curve | \$70/bbl | \$90/bbl |
| Oba CGUf (Gabon) |
a | 13.7 | 13% | 2yr forward curve | \$70/bbl | \$90/bbl |
| Tchatamba (Gabon) | c | (16.8) | 13% | 2yr forward curve | \$70/bbl | \$90/bbl |
| M'boundi (Congo) | a | 65.9 | 12% | 2yr forward curve | \$70/bbl | \$90/bbl |
| Equatorial Guinea CGUg | a | 16.3 | 10% | 2yr forward curve | \$70/bbl | \$90/bbl |
| TEN (Ghana) | a | 228.5 | 10% | 2yr forward curve | \$70/bbl | \$90/bbl |
| Chinguetti (Mauritania) | a | 5.5 | 10% | 2yr forward curve | \$70/bbl | \$90/bbl |
| Impairment before tax | 406.0 | |||||
| Associated deferred tax credit | (49.1) | |||||
| Impairment after tax | 356.9 |
a. Reduction in estimated oil and gas forward curve and long-term price (refer to accounting policy on significant estimates).
b. Reduction in decommissioning estimate.
c. Increase in 2P reserves.
d. UK NBP gas forward curve and Bloomberg Brent forward curve as at 31 December 2015. All pricing assumptions have been adjusted for individual field and contract differentials.
e. The fields in the UK and the Netherlands are grouped into two CGUs as all fields within those countries share critical gas infrastructure.
f. The Limande and Niungo CGUs in Gabon comprise a number of fields which share export infrastructure.
g. The Ceiba and Okume fields in Equatorial Guinea form a single CGU as they share export infrastructure.
All impairment assessments are prepared on a Value In Use basis using discounted future cash flows based on 2p reserves profiles. A 1% increase in the discount rates used would trigger a further impairment of \$161.9 million and a \$10/bbl reduction to the oil whole price deck would trigger a further impairment of \$784.3 million.
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| Unlisted investments | 1.0 | 1.0 |
The fair value of these investments is not materially different from their carrying value. A list of the subsidiaries is included on page 176.
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| Non-current | ||
| Amounts due from joint venture partners | 161.8 | 57.0 |
| Uganda VAT recoverable | 50.3 | 50.6 |
| Other non-current assets | 11.3 | 12.1 |
| 223.4 | 119.7 | |
| Current | ||
| Amounts due from joint venture partners | 584.4 | 633.2 |
| Underlifts | 2.4 | – |
| Prepayments | 77.9 | 82.6 |
| VAT & WHT recoverable | 9.2 | 49.8 |
| Other current assets | 89.3 | 136.7 |
| 763.2 | 902.3 |
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.
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| Warehouse stocks and materials | 66.0 | 86.0 |
| Oil stocks | 41.2 | 53.5 |
| 107.2 | 139.5 |
Inventories include a provision of \$65.2 million (2014: \$33.6 million) for warehouse stock and materials where it is considered that the net realisable value is lower than the original cost; this represents the total costs of inventory expensed. The increase in the provision during 2015 is associated with the completion of certain exploration campaigns and development projects, resulting in an income statement charge of \$22.2 million (2014: \$29.1 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 (2014: \$nil million).
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| Cash at bank | 355.7 | 319.0 |
Cash and cash equivalents includes an amount of \$169.5 million (2014: \$200.6 million) which the Group holds as operator in joint venture bank accounts.
In September 2014, Tullow signed an agreement to sell its operated and non-operated interests in the L12/L15 area in the Netherlands along with non-operated interests in blocks Q4 and Q5 to AU Energy, a subsidiary of Mercuria Energy Group Ltd. This transaction completed in 2015, refer to note 9.
The major classes of assets and liabilities comprising the operations classified as held for sale are as follows:
| Netherlands 2015 \$m |
Netherlands 2014 \$m |
|
|---|---|---|
| Intangible exploration and evaluation assets | – | 40.4 |
| Property, plant and equipment | – | 95.2 |
| Total assets classified as held for sale | – | 135.6 |
| Provisions | – | (13.6) |
| Total liabilities associated with assets classified as held for sale | – | (13.6) |
| Net assets of disposal group | – | 122.0 |
Current liabilities
| Notes | 2015 \$m |
2014 \$m |
|
|---|---|---|---|
| Trade payables | 24.0 | 126.5 | |
| Other payables | 61.2 | 104.6 | |
| Overlifts | 3.7 | 15.6 | |
| Accruals | 993.3 | 734.8 | |
| VAT and other similar taxes | 26.9 | 92.1 | |
| Current portion of finance lease | 22 | 1.5 | 1.3 |
1,110.6 1,074.9
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 decrease in trade payables and the decrease in other payables predominantly represent timing differences.
| Notes | 2015 \$m |
2014 \$m |
|---|---|---|
| Other non-current liabilities | 72.8 | 57.0 |
| Non-current portion of finance lease 22 |
26.5 | 28.1 |
| 99.3 | 85.1 |
Trade and other payables are non-interest bearing except for finance leases (note 22).
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| Current | ||
| Short-term borrowings – Revolving Norwegian Exploration Finance facility | 59.6 | 131.5 |
| Bank loans – Reserves Based Lending credit facility | 14.2 | – |
| 73.8 | 131.5 | |
| Non-current | ||
| Term loans repayable – Reserves Based Lending credit facility | ||
| – After one year but within two years | 800.0 | – |
| – After two years but within five years | 2,165.6 | 1,914.0 |
| – After five years | – | – |
| 6.0% Senior notes due 2020 | 646.4 | 645.5 |
| 6.25% Senior notes due 2022 | 650.4 | 649.6 |
| 4,262.4 | 3,209.1 | |
| Carrying value of total borrowings | 4,336.2 | 3,340.6 |
| Unamortised fees | 38.8 | 81.3 |
| External borrowings | 4,375.0 | 3,421.9 |
External borrowings represent the principal amount due at maturity. Short-term borrowings, bank loans and most guarantees are secured by fixed and floating charges over the oil and gas assets of the Group.
In March 2015, the Company arranged an additional \$200 million of commitments, increasing the Reserves Based Lending credit facility to \$3.7 billion. 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 31 October 2019, or such time as is determined by reference to the remaining reserves of the assets, whichever is earlier.
In March 2015, the Company arranged an additional \$250 million of commitments, increasing the Revolving credit facility to \$1,000 million. The facility incurs interest on outstanding debt at US dollar LIBOR plus an applicable margin.
In February 2015, the Company reduced commitments under the Revolving Norwegian Exploration Finance facility by NOK 750 million to NOK 2,250 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 2016, and its final maturity date is either the date the 2016 tax reimbursement claims are received or 31 December 2017, whichever is the earlier. The facility incurs interest on outstanding debt at NIBOR plus an applicable margin.
At the end of December 2015, the headroom under the three facilities amounted to \$1,686 million; \$686 million under the \$3.7 billion Reserves Based Lending credit facility and \$1,000 million under the Revolving credit facility. At the end of December 2014, the headroom under the three facilities amounted to \$2,263 million; \$1,513 million under the Reserves Based Lending credit facility and \$750 million under the Revolving credit facility.
The Group defines capital as the total equity 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 2015.The Group monitors capital on the basis of the net debt ratio, that is, the ratio of net debt to equity. Net debt is calculated as external borrowings, as shown above, less cash and cash equivalents.
| Notes | 2015 \$m |
2014 \$m |
|---|---|---|
| External borrowings | 4,375.0 | 3,421.9 |
| Less cash and cash equivalents 17 |
(355.7) | (319.0) |
| Net debt | 4,019.3 | 3,102.9 |
| Equity | 3,174.7 | 4,020.3 |
| Net debt ratio | 127% | 77% |
The movement from 2014 is attributable to higher external borrowings during 2015, principally as a result of the Group's \$2,112.4 million capital expenditure and loss incurred during 2015, partially offset by operating cash flows.
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 is 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, 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 2015, was \$884.0 million (2014: \$1,101.3 million). The Group has no material financial assets that are past due. No financial assets are impaired at the balance sheet date.
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 | 2015 Less than 1 year \$m |
2015 1-3 years \$m |
2015 Total \$m |
2014 Less than 1 year \$m |
2014 1-3 years \$m |
2014 Total \$m |
|---|---|---|---|---|---|---|
| Cash flow hedges | ||||||
| Oil derivatives | 458.9 | 265.2 | 724.1 | 329.4 | 242.6 | 572.0 |
| Gas derivatives | 1.1 | – | 1.1 | 2.5 | 0.3 | 2.8 |
| Interest rate derivatives | (2.1) | 1.1 | (1.0) | (3.3) | 3.7 | 0.4 |
| 457.9 | 266.3 | 724.2 | 328.6 | 246.6 | 575.2 | |
| Deferred premium | ||||||
| Oil derivatives | (53.5) | (47.6) | (101.1) | (51.0) | (52.7) | (103.7) |
| Gas derivatives | – | – | – | (0.1) | – | (0.1) |
| (53.5) | (47.6) | (101.1) | (51.1) | (52.7) | (103.8) | |
| Total assets | 406.5 | 218.7 | 625.2 | 280.8 | 193.9 | 474.7 |
| Total liabilities | (2.1) | – | (2.1) | (3.3) | – | (3.3) |
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 (2014: 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 | Related | |||||
|---|---|---|---|---|---|---|
| amounts | Net amounts | amounts not | ||||
| offset in | presented in | offset in the | ||||
| Gross | Group | Group | Group | |||
| amounts | balance | balance | balance | |||
| recognised | sheet | sheet | sheet | Net amount | ||
| 31 December 2015 | \$m | \$m | \$m | \$m | \$m | |
| Derivative assets | 726.3 | (101.1) | 625.2 | (593.9) | 31.3 | |
| Derivative liabilities | (2.1) | – | (2.1) | – | (2.1) | |
| Deferred premiums | (101.1) | 101.1 | – | – | – | |
| Borrowings | (4,336.2) | – | (4,336.2) | 593.9 | (3,742.3) |
| 31 December 2014 | Gross amounts recognised \$m |
Gross amounts offset in Group balance sheet \$m |
Net amounts presented in Group balance sheet \$m |
Related amounts not offset in the Group balance sheet \$m |
Net amount \$m |
|---|---|---|---|---|---|
| Derivative assets | 578.5 | (103.8) | 474.7 | (473.0) | 1.7 |
| Derivative liabilities | (3.3) | – | (3.3) | – | (3.3) |
| Deferred premiums | (103.8) | 103.8 | – | – | – |
| Borrowings | (3,340.6) | – | (3,340.6) | 473.0 | (2,867.6) |
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 2015 and 31 December 2014, 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.
Net gains from commodity derivative settlements during the period, included in the income statement, were \$365.2 million (2014: \$14.5 million loss) (note 2).
Derivative fair value movements during the year which have been recognised in the income statement were as follows:
| (Loss)/profit on hedging instruments: | 2015 \$m |
2014 \$m |
|---|---|---|
| Cash flow hedges | ||
| Gas derivatives | ||
| Time value | (0.2) | 0.9 |
| (0.2) | 0.9 | |
| Oil derivatives | ||
| Time value | (58.6) | 49.9 |
| (58.6) | 49.9 | |
| Total net (loss)/profit for the year in the income statement | (58.8) | 50.8 |
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.
| Deferred amounts in the hedge reserve | 2015 \$m |
2014 \$m |
|---|---|---|
| At 1 January | 401.6 | 2.3 |
| Revaluation gains arising in the year | 513.0 | 485.7 |
| Reclassification adjustments for items included in income statement on realisation | (302.4) | 4.6 |
| Movement in current and deferred tax | (42.3) | (91.0) |
| 168.3 | 399.3 | |
| At 31 December | 569.9 | 401.6 |
| The following table summarises the hedge reserve by type of derivative, net of tax effects: | ||
| Hedge reserve by derivative type | 2015 \$m |
2014 \$m |
| Cash flow hedges | ||
| Gas derivatives | 0.4 | 1.0 |
| Oil derivatives | 570.6 | 400.2 |
| Interest rate derivatives | (1.1) | 0.4 |
| 569.9 | 401.6 |
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, 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 2015 is a liability of \$1.0 million (2014: \$0.4 million asset). 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 2015 and 2014 was as follows:
| 2015 Cash at bank \$m |
2015 Fixed rate debt \$m |
2015 Floating rate debt \$m |
2015 Total \$m |
2014 Cash at bank \$m |
2014 Fixed rate debt \$m |
2014 Floating rate debt \$m |
2014 Total \$m |
|
|---|---|---|---|---|---|---|---|---|
| US\$ | 258.2 | (1,600.0) | (2,557.3) | (3,899.1) | 216.6 | (1,600.0) | (1,522.4) | (2,905.8) |
| Euro | 28.4 | – | – | 28.4 | 16.8 | – | – | 16.8 |
| Sterling | 19.1 | – | (156.9) | (137.8) | 20.6 | – | (164.6) | (144.0) |
| Other | 50.0 | – | (60.8) | (10.8) | 65.0 | – | (134.9) | (69.9) |
| 355.7 | (1,600.0) | (2,775.0) | (4,019.3) | 319.0 | (1,600.0) | (1,821.9) | (3,102.9) |
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 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 assessment. Where considered appropriate security in the form of trade finance instruments such as letters of credit, guarantees and credit insurance are employed to mitigate the risks.
The Group generally enters into derivative agreements with banks who are lenders under the Reserves 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 2015 was \$2,176.9 million (2014: \$2,126.1 million).
Wherever possible, the Group conducts and manages its business in Sterling (UK) and US dollars (all other countries), the operating currencies of the industry in the areas in which it operates. The Group's borrowing facilities are also mainly denominated in Sterling and US dollars, which further assists in foreign currency risk management. 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 2015 year-end (2014: 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 2015, the only material monetary assets or liabilities of the Group that were not denominated in the functional currency of the respective subsidiaries involved were \$49.7 million in non-US dollar denominated cash and cash equivalents (2014: \$54.3 million) and £106.0 million cash drawings under the Group's borrowing facilities (2014: £106.0 million). The carrying amounts of the Group's foreign currency denominated monetary assets and monetary liabilities at the reporting date are net liabilities of \$107.2 million (2014: net liabilities of \$110.4 million).
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. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.9 billion of debt liquidity headroom at the end of 2015. 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 2015 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 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 |
| 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 2014 | |||||||
| Non-interest bearing | n/a | 234.2 | 40.0 | 64.6 | 57.0 | – | 395.8 |
| Finance lease liabilities | 6.5% | – | – | 1.3 | 28.1 | – | 29.4 |
| Fixed interest rate instruments | 6.5% | ||||||
| Principal repayments | – | – | – | – | 1,300.0 | 1,300.0 | |
| Interest charge | – | – | 79.6 | 318.5 | 160.9 | 559.0 | |
| Variable interest rate instruments | 6.7% | ||||||
| Principal repayments | – | – | 134.9 | 1,987.0 | – | 2,121.9 | |
| Interest charge | 6.6 | 13.2 | 63.1 | 372.3 | – | 455.2 | |
| 240.8 | 53.2 | 343.5 | 2,762.9 | 1,460.9 | 4,861.3 |
The Group has interest rate swaps that fix \$300.0 million (2014: \$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.
The following analysis is intended to illustrate sensitivity to changes in market variables, being interest rates, Dated Brent oil prices, UK D-1 Heren and M-1 Heren natural gas 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.
| Equity | Foreign currency denominated liabilities and equity |
||||
|---|---|---|---|---|---|
| Market movement | 2015 \$m |
2014 \$m |
2015 \$m |
2014 \$m |
|
| Interest rate | 25 basis points | 2.0 | 3.0 | – | – |
| Interest rate | (25) basis points | (2.1) | (3.0) | – | – |
| Brent oil price | 50% | (441.1) | (512.3) | – | – |
| Brent oil price | (50%) | 564.1 | 833.5 | – | – |
| UK D-1 Heren and M-1 Heren natural gas price | 50% | (0.6) | (2.6) | – | – |
| UK D-1 Heren and M-1 Heren natural gas price | (50%) | 0.6 | 7.8 | – | – |
| US\$/foreign currency exchange rates | 20% | – | – | (31.4) | (32.9) |
| US\$/foreign currency exchange rates | (20%) | – | – | 31.4 | 32.9 |
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 consider this to be the material component of oil and gas hedge valuations.
| Notes | 2015 \$m |
2014 \$m |
|---|---|---|
| Amounts payable under finance leases: | ||
| – Within one year | 3.3 | 3.2 |
| – Within two to five years | 14.5 | 14.1 |
| – After five years | 21.3 | 24.9 |
| 39.1 | 42.2 | |
| Less future finance charges | (11.1) | (12.8) |
| Present value of lease obligations | 28.0 | 29.4 |
| 19 Amount due for settlement within 12 months |
1.5 | 1.3 |
| 19 Amount due for settlement after 12 months |
26.5 | 28.1 |
The Group's only finance lease is the Espoir FPSO (2014: Espoir FPSO). The fair value of the Group's lease obligations approximates the carrying amount. The average remaining lease term as at 31 December 2015 was 11 years (2014: 12 years). For the year ended 31 December 2015, the effective borrowing rate was 6.5% (2014: 6.5%).
| Current provisions | 2015 \$m |
2014 \$m |
|---|---|---|
| Provision for onerous service contracts | 185.5 | – |
| Provision for restructuring costs | 1.5 | – |
| 187.0 | – |
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 resulting in an income statement charge of \$185.5 million (2014:\$nil million).
During 2015, the Group has incurred \$44.9 million in respect of restructuring costs. After recharges to joint venture partners, the income statement charge for restructuring costs is \$40.8 million. As at 31 December 2015, \$1.5 million is yet to be incurred and has been recorded as a provision.
| Non-current provisions | Notes | Decommissioning 2015 \$m |
Other provisions 2015 \$m |
Total 2015 \$m |
Decommissioning 2014 \$m |
Other provisions 2014 \$m |
Total 2014 \$m |
|---|---|---|---|---|---|---|---|
| At 1 January | 1,192.9 | 67.5 | 1,260.4 | 841.5 | 147.7 | 989.2 | |
| New provisions and changes in estimates |
(147.4) | (9.9) | (157.3) | 454.9 | (82.1) | 372.8 | |
| Transfer to liabilities held for sale | 18 | – | – | – | (14.8) | – | (14.8) |
| Disposals | 0.8 | 0.3 | 1.1 | (54.6) | – | (54.6) | |
| Decommissioning payments | (40.8) | – | (40.8) | (20.4) | – | (20.4) | |
| Unwinding of discount | 5 | 28.3 | 0.1 | 28.4 | 22.4 | 16.9 | 39.3 |
| Currency translation adjustment | (25.0) | (1.7) | (26.7) | (36.1) | (15.0) | (51.1) | |
| At 31 December | 1,008.8 | 56.3 | 1,065.1 | 1,192.9 | 67.5 | 1,260.4 |
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 |
2015 \$m |
2014 \$m |
|
|---|---|---|---|---|---|
| Congo | 2% | 3% | 2027 | 15.2 | 13.4 |
| Côte d'Ivoire | 2% | 3% | 2026 | 53.3 | 52.7 |
| Equatorial Guinea | 2% | 3% 2028-2029 | 126.2 | 175.8 | |
| Gabon | 2% | 3% 2021-2034 | 61.0 | 107.1 | |
| Ghana | 2% | 3% 2034-3036 | 257.7 | 278.3 | |
| Mauritania | 2% | 3% | 2017 | 121.4 | 113.3 |
| Netherlands | 2% | 3% 2020-2036 | 90.5 | 100.7 | |
| UK | 2% | 3% 2014-2018 | 283.5 | 351.6 | |
| 1,008.8 | 1,192.9 |
Other provisions include a liability acquired through the acquisition of Spring which is contingent in terms of timing and amount on the development of the PL407 licence in Norway. Other provisions also include the contingent consideration in respect of the Spring acquisition and the recognition of intangible exploration and evaluation assets therefore the unwinding of other provisions is adjusted to exploration and evaluation assets and not finance costs.
| Accelerated tax depreciation \$m |
Decommissioning \$m |
Revaluation of financial assets \$m |
Other temporary differences \$m |
Deferred PRT \$m |
Total \$m |
|
|---|---|---|---|---|---|---|
| At 1 January 2014 | (1,801.4) | 137.4 | 0.5 | 69.2 | 7.4 | (1,586.9) |
| Credit/(charge) to income statement | 255.2 | 3.9 | (0.5) | 22.5 | (0.3) | 280.8 |
| Credit to other comprehensive income | – | – | (1.6) | – | – | (1.6) |
| Exchange differences | 65.8 | (9.5) | – | (0.8) | (0.4) | 55.1 |
| At 1 January 2015 | (1,480.4) | 131.8 | (1.6) | 90.9 | 6.7 | (1,252.6) |
| Credit to income statement | 218.2 | 37.7 | 0.2 | 91.0 | 4.4 | 351.5 |
| Credit to other comprehensive income | – | – | 0.9 | – | – | 0.9 |
| Exchange differences | 37.8 | (6.7) | – | 0.4 | (0.5) | 31.0 |
| At 31 December 2015 | (1,224.4) | 162.8 | (0.5) | 182.3 | 10.6 | (869.2) |
| 2015 \$m |
2014 \$m |
|||||
| Deferred tax liabilities | (1,164.5) | (1,507.6) | ||||
| Deferred tax assets | 295.3 | 255.0 | ||||
| (869.2) | (1,252.6) |
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 |
|||
|---|---|---|---|
| Number | \$m | \$m | |
| Ordinary shares of 10 pence each | |||
| At 1 January 2014 | 909,971,941 | 146.9 | 603.2 |
| Issued during the year | |||
| – Exercise of share options | 689,690 | 0.1 | 3.2 |
| 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 31 December 2015 | 911,576,706 | 147.2 | 609.8 |
The Company does not have an authorised share capital.
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| At 1 January | 24.3 | 123.5 |
| Share of loss for the year | (2.1) | (84.2) |
| Distribution to non-controlling interests | (2.4) | (15.0) |
| At 31 December | 19.8 | 24.3 |
The non-controlling interest relates to Tulipe Oil SA (Tulipe), where the Group has a 50% controlling shareholding whose place of business is Gabon. The loss associated with non-controlling interests is principally as a result of impairments recorded against property, plant and equipment.
Reconciliation of share-based payment charge
| 2015 | 2014 | |
|---|---|---|
| Notes | \$m | \$m |
| Tullow Incentive Plan | 12.3 | 5.2 |
| 2005 Performance Share Plan | 7.9 | 19.0 |
| 2005 Deferred Share Bonus Plan | 1.0 | 2.3 |
| Employee Share Award Plan | 30.8 | 10.4 |
| 2010 Share Option Plan and 2000 Executive Share Option Scheme | 14.8 | 21.6 |
| UK & Irish Share Incentive | 0.5 | 1.0 |
| Total share-based payment charge | 67.3 | 59.5 |
| Capitalised to intangible and tangible assets | 18.6 | 20.0 |
| Expensed to operating costs 4 |
0.8 | 1.6 |
| Expensed as administrative cost 4 |
47.9 | 37.9 |
| Total share-based payment charge | 67.3 | 59.5 |
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 ten 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 Directors' Remuneration Report on pages 90 to 106.
The weighted average remaining contractual life for TIP awards outstanding at 31 December 2015 was 6.9 years.
Under the PSP, Senior Management could be granted nil exercise price options, normally exercisable between three and ten 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 Directors' Remuneration Report on pages 90 to 106. 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 2015 was 4.8 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 ten 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 2015 was 5.6 years.
Most Group employees are eligible to be granted nil exercise price options under the ESAP. These are normally exercisable from three to ten 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 2015 was 8.8 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 ten 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 2015 had exercise prices of 349p to 1530p (2014: 157p to 1530p) and remaining contractual lives between nine days and eight years. The weighted average remaining contractual life is 4.3 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-for-one 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 |
|
|---|---|---|---|---|---|---|
| 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 |
| 2014 TIP– number of shares | – | 1,611,122 | – | (30,545) | 1,580,577 | – |
| 2014 TIP – average weighted share price at grant | – | 782.0 | – | 782.0 | 782.0 | – |
| 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 |
1230.2 | – | 892.4 | 1433.0 | 1125.7 | 997.7 |
| 2014 PSP – number of shares | 9,392,763 | 3,500 | (37,319) | (2,386,215) | 6,972,729 | 1,528,876 |
| 2014 PSP – average weighted share price | ||||||
| at grant | 1256.8 | 753.0 | 926.7 | 1338.9 | 1230.2 | 896.8 |
| 2015 DSBP – number of shares | 491,916 | – | (25,819) | – | 466,097 | 315,589 |
| 2015 DSBP – average weighted share price at grant |
1240.0 | – | 1480.0 | – | 1226.7 | 1219.9 |
| 2014 DSBP – number of shares | 503,224 | – | (11,308) | – | 491,916 | 190,882 |
| 2014 DSBP – average weighted share price | ||||||
| at grant | 1242.7 | – | 1362.0 | – | 1240.0 | 1049.9 |
| 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 |
| 2014 ESAP– number of shares | – | 3,494,417 | – | (187,436) | 3,306,981 | 9,621 |
| 2014 ESAP – average weighted share price at grant |
– | 779.9 | – | 782.0 | 779.7 | 782.0 |
| 2015 SOP/ESOS – number of shares | 16,343,605 | – | (531,106) (1,346,488) 14,466,011 | 9,894,040 | ||
| 2015 SOP/ESOS – WAEP | 1128.8 | – | 201.8 | 1149.6 | 1160.9 | 1139.3 |
| 2014 SOP/ESOS – number of shares | 18,129,299 | – | (652,371) | (1,133,323) 16,343,605 | 7,184,988 | |
| 2014 SOP/ESOS – WAEP | 1109.2 | – | 269.4 | 1310.3 | 1128.8 | 913.5 |
| 2015 Phantoms – number of phantom shares | 2,229,052 | – | – | (710,613) 1,518,439 | 1,518,439 | |
| 2015 Phantoms – WAEP | 1274.5 | – | – | 1274.6 | 1274.5 | 1274.5 |
| 2014 Phantoms – number of phantom shares | 2,417,507 | – | – | (188,455) | 2,229,052 | 2,229,052 |
| 2014 Phantoms – WAEP | 1274.5 | – | – | 1275.3 | 1274.5 | 1274.5 |
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.
| 2015 TIP | 2015 ESAP | 2014 TIP | 2014 ESAP | |
|---|---|---|---|---|
| Weighted average fair value | ||||
| of awards granted | 406.1p | 304.2p | 782.0p | 744.7p |
| Weighted average share price at exercise for awards exercised | – | 319.0 | – | – |
| Principal inputs to options valuations model: | ||||
| Weighted average share price at grant | 406.1p | 304.2p | 782.0p | 779.9p |
| Weighted average exercise price | 0.0p | 0.0p | 0.0p | 0.0p |
| Risk-free interest rate per annum | 0.9 – 1.3% 0.5 – 1.0% 1.1 – 1.5% 1.1 – 1.4% | |||
| Expected volatility per annum1 | 32 – 36% | 32 – 41% | 33 – 34% | 32 – 34% |
| Expected award life (years)2 | 3.3 | 2.2 | 3.1 | 3.0 |
| Dividend yield per annum | n/a | 0.0% | n/a 1.5 – 1.7% | |
| 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.
| 2015 | 2014 | 2015 | 2014 | 2015 | 2014 | |
|---|---|---|---|---|---|---|
| PSP | PSP | DSBP | DSBP | SOP/ESOS1 | SOP/ESOS1 | |
| Weighted average share price at exercise for awards exercised |
294.5p | 728.7p | 384.6p | 792.5p | 409.0p | 752.8p |
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| 1,614.5 | 2,457.8 | |
| Capital commitments | ||
| Operating lease commitments | ||
| Due within one year | 8.4 | 21.6 |
| After one year but within two years | 8.4 | 22.7 |
| After two years but within five years | 25.2 | 40.2 |
| Due after five years | 39.3 | 10.4 |
| 81.3 | 94.9 | |
| Contingent liabilities | ||
| Performance guarantees | 130.9 | 288.7 |
| Ugandan CGT | – | 265.3 |
| Other contingent liabilities | 32.0 | 1.9 |
| 162.9 | 555.9 |
Where Tullow acts as operator of a joint venture the capital commitments reported represent Tullow's net share. Where Tullow is non-operator the value of capital commitments is based on committed future work programmes. Capital commitments excludes future payments of \$2,074.1 million (gross) in relation to the TEN FPSO which will be accounted for as a finance lease.
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 the Chinguetti field in Mauritania. 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.
The Directors of Tullow Oil plc are considered to be the only key management personnel as defined by IAS 24 – Related Party Disclosures.
| 2015 \$m |
2014 \$m |
|
|---|---|---|
| Short-term employee benefits | 10.0 | 9.5 |
| Post-employment benefits | 1.1 | 1.2 |
| Amounts awarded under long-term incentive schemes | 4.2 | 3.3 |
| Share-based payments | 5.7 | 10.4 |
| 21.0 | 24.4 |
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 Directors' Remuneration Report on pages 90 to 106.
In January 2016 Tullow completed the farm-down of 25% of its interest in block 12A to Delonex and Tullow also agreed to sell a 20% interest in the Bannu West licence in Pakistan to Mari Gas. Tullow was awarded a 60% operated interest in the Orinduik licence in January 2016, a 1,801 square kilometre block offshore Guyana. On 23 January 2016, the TEN FPSO set sail from Singapore to Ghana with arrival expected in early March 2016.
Subsequent to the balance sheet date there has been a deterioration in the spot price of Brent crude. Sensitivity analysis on the impact of a reduction in Brent crude prices on the carrying value of PP&E is provided in note 12.
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 \$20.5 million (2014: \$19.6 million). As at 31 December 2015, there was a liability of \$nil million (2014: \$ nil million) for contributions payable included in other payables.
| Notes | 2015 \$m |
2014 \$m |
2013 \$m |
|
|---|---|---|---|---|
| ASSETS | ||||
| Non-current assets | ||||
| Investments | 1 | 4,885.4 | 4,919.6 | 3,851.4 |
| Intercompany derivative asset | 7 | 217.6 | – | – |
| 5,103.0 | 4,919.6 | 3,851.4 | ||
| Current assets | ||||
| Other current assets | 4 | 3,475.5 | 3,706.0 | 3,602.6 |
| Intercompany derivative asset | 7 | 405.4 | – | – |
| Cash at bank | 3.4 | 3.6 | 0.9 | |
| 3,884.3 | 3,709.6 | 3,603.5 | ||
| Total assets | 8,987.3 | 8,629.2 | 7,454.9 | |
| LIABILITIES | ||||
| Current liabilities | ||||
| Trade and other creditors | 5 | (722.5) | (236.1) | (181.9) |
| Borrowings | 6 | (14.2) | – | – |
| (736.7) | (236.1) | (181.9) | ||
| Non-current liabilities | ||||
| Borrowings | 6 | (4,262.4) | (3,209.1) | (1,995.0) |
| Loans to subsidiaries | 8 | – | – | (1.3) |
| (4,262.4) | (3,209.1) | (1,996.3) | ||
| Total liabilities | (4,999.1) | (3,445.2) | (2,178.2) | |
| Net assets | 3,988.2 | 5,184.0 | 5,276.7 | |
| Capital and reserves | ||||
| Called-up share capital | 9 | 147.2 | 147.0 | 146.9 |
| Share premium | 9 | 609.8 | 606.4 | 603.2 |
| Other reserves | 850.8 | 850.8 | 850.8 | |
| Retained earnings | 2,380.4 | 3,579.8 | 3,675.8 | |
| Total equity | 3,988.2 | 5,184.0 | 5,276.7 |
Approved by the Board and authorised for issue on 9 February 2016.
Aidan Heavey Ian Springett
Chief Executive Officer Chief Financial Officer
| Share capital \$m |
Share premium \$m |
Other reserves \$m |
Retained earnings \$m |
Total equity \$m |
|
|---|---|---|---|---|---|
| At 1 January 2014 | 146.9 | 603.2 | 850.8 | 3,675.8 | 5,276.7 |
| Profit for the year | – | – | – | 27.3 | 27.3 |
| Issue of employee share options | 0.1 | 3.2 | – | – | 3.3 |
| Vesting of PSP shares | – | – | – | (0.4) | (0.4) |
| Share-based payment charges | – | – | – | 59.4 | 59.4 |
| Dividends paid | – | – | – | (182.3) | (182.3) |
| 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) |
| At 31 December 2015 | 147.2 | 609.8 | 850.8 | 2,380.4 | 3,988.2 |
|---|---|---|---|---|---|
| Share-based payment charges | – | – | – | 67.3 | 67.3 |
| Vesting of PSP shares | – | – | – | (1.9) | (1.9) |
Tullow Oil plc is a company incorporated in the United Kingdom under the Companies Act. The address of the registered office is given on page 111. 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 FRS 100 (Financial Reporting Standard 100) issued by the Financial Reporting Council. Accordingly, in the year ended 31 December 2015 the Company has undergone transition from reporting under UK Generally Accepted Accounting Practice (UK GAAP) to FRS 101 as issued by the Financial Reporting Council. The Financial Statements have therefore been prepared in accordance with FRS 101 (Financial Reporting Standard 101) 'Reduced Disclosure Framework' as issued by the Financial Reporting Council. On transition to FRS 101 the Company has applied paragraphs 6-33 of IFRS 1 as adopted by the EU, this transition is not considered to have had a material effect on the Financial Statements.
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 \$1,264.8 million (2014: \$27.3 million profit).
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. In the currently low commodity price environment, the Group has taken appropriate action to reduce its cost base and had \$1.9 billion of debt liquidity headroom and free cash at the end of 2015. 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 2015 Annual Report and Accounts.
Notwithstanding our forecasts of liquidity headroom throughout the 12 month period, there remains a risk, given the volatility of the oil price environment and its impact on operating cash flows and facility availability, that the Group's liquidity position may deteriorate and/or the Group may become technically non-compliant with one of its financial covenants at the end of 2016.
To mitigate this risk, we will continue to maintain our long-term banking relations and will monitor our cash flow projections and, if necessary, take mitigating actions well in advance to maintain our liquidity and compliance with covenants. Actions available to the Group include further rationalisation of our cost base, cuts to discretionary capital expenditure, portfolio management and other funding options.
Based on the analysis above, 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 re-measuring 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.
In order to account for uncertain tax positions management has formed an accounting policy, in accordance with IAS 8, whereby the ultimate outcome of legal proceedings is viewed as a single unit of account. The results of separate hearings in relation to the same matter, such as local tribunals and international arbitration, are not viewed separately and only the final
outcome is assessed by management to determine the best estimate of any potential outcome. If management viewed the results of individual hearings separately an income statement charge could arise due to the differing recognition criteria of assets and liabilities.
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.
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.
| 2015 \$m |
2014 \$m |
2013 \$m |
|
|---|---|---|---|
| Shares at cost in subsidiary undertakings | 4,884.4 | 4,918.6 | 3,850.4 |
| Unlisted investments | 1.0 | 1.0 | 1.0 |
| 4,885.4 | 4,919.6 | 3,851.4 |
During 2015, an impairment of \$1,279.8 million (2014: \$661 million) was recorded against the Company's investments in subsidiaries to fund losses incurred by Group service companies. This was partially offset by an increase of investment in the Company's directly held subsidiaries.
The Company's subsidiary undertakings as at 31 December 2015 are listed on page 176. The principal activity of all companies relates to oil and gas exploration, development and production.
| – | 123.3 | 110.6 |
|---|---|---|
| – | 59.0 | 56.8 |
| – | 182.3 | 167.4 |
| – | – | 120.0 |
The final dividend is subject to approval by shareholders at the Annual General Meeting.
The Company has tax losses of \$359.9 million (2014: \$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 million (2014: \$nil million) 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.
Amounts falling due within one year
| 2015 \$m |
2014 \$m |
2013 \$m |
|
|---|---|---|---|
| Other debtors | – | 16.4 | 0.2 |
| Due from subsidiary undertakings | 3,475.5 | 3,689.6 | 3,602.4 |
| 3,475.5 | 3,706.0 | 3,602.6 |
The amounts due from subsidiary undertakings include \$2,951.0 million (2014: \$2,800.8 million) that incurs interest at LIBOR plus 0.875% – 5.95%. The remaining amounts due from subsidiaries accrue no interest. All amounts are repayable on demand. During the year a provision of \$174.8 million (2014: \$128.9 million) was made in respect of the recoverability of amounts due from subsidiary undertakings.
Amounts falling due within one year
| 2015 \$m |
2014 \$m |
2013 \$m |
|
|---|---|---|---|
| Other creditors | – | 7.3 | 5.4 |
| Accruals | – | – | 0.8 |
| VAT and other similar taxes | – | 15.4 | – |
| Due to subsidiary undertakings | 722.5 | 213.4 | 175.7 |
| 722.5 | 236.1 | 181.9 |
| 2015 \$m |
2014 \$m |
2013 \$m |
|
|---|---|---|---|
| Current | |||
| Short-term borrowings | 14.2 | – | – |
| Non-current | |||
| Term loans repayable | |||
| – After one year but within two years | 800.0 | – | – |
| – After two years but within five years | 2,165.6 | 1,914.0 | 445.0 |
| – After five years | – | – | 906.0 |
| Senior notes due 2020 | 646.4 | 645.5 | 644.0 |
| Senior notes due 2022 | 650.4 | 649.6 | – |
| 4,262.4 | 3,209.1 | 1,995.0 | |
| Carrying value of total borrowings | 4,276.6 | 3,209.1 | 1,995.0 |
| Accrued interest and unamortised fees | 37.6 | 77.9 | 107.0 |
| External borrowings | 4,314.2 | 3,287.0 | 2,102.0 |
Term loans are secured by fixed and floating charges over the oil and gas assets of the Group Financial Statements.
Where equivalent disclosures for the requirements of IFRS 7 Financial Instruments: Disclosures and IFRS 13 Fair Value Measurements have been included in the 2015 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 22 December 2015, the Company entered into an intercompany derivative trade with a wholly owned subsidiary, Tullow Oil SPE limited ('SPE'), paying consideration of \$676.3 million in exchange for the right to receive all future receipts, and assumes all future obligations under SPE's existing and future oil derivative contracts with external counterparties. The consideration paid is considered to be at fair value on the date of the transaction.
As at 31 December 2015, none of the Company's derivatives have been designated into hedging relationships at entity level. As such, derivative fair value movements in the year have been recognised immediately in the income statement.
The Company's derivative carrying and fair values were as follows
| Assets/liabilities | 2015 Less than 1 year \$m |
2015 1-3 years \$m |
2015 Total \$m |
2014 Less than 1 year \$m |
2014 1-3 years \$m |
2014 Total \$m |
|---|---|---|---|---|---|---|
| Intercompany oil derivatives | 405.4 | 217.6 | 623.0 | – | – | – |
| Total assets | 405.4 | 217.6 | 623.0 | – | – | – |
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 (2014: n/a). 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.
Netting agreements are in place to enable the Company and its counterparty to set-off liabilities against available assets in the event that either party is unable to fulfil its contractual obligations.
| 31 December 2015 | Gross amounts recognised \$m |
Gross amounts offset in Group balance sheet \$m |
Net amounts presented in balance sheet \$m |
Related amounts not offset in the balance sheet \$m |
Net amount \$m |
|---|---|---|---|---|---|
| Intercompany derivative assets | 623.0 | – | 623.0 | (623.0) | – |
| Trade and other creditors | (722.5) | – | (722.5) | 623.0 | (99.5) |
| 31 December 2014 | Gross amounts recognised \$m |
Gross amounts offset in Group balance sheet \$m |
Net amounts presented in balance sheet \$m |
Related amounts not offset in the balance sheet \$m |
Net amount \$m |
|---|---|---|---|---|---|
| Intercompany derivative assets | – | – | – | – | – |
| Trade and other creditors | (236.1) | – | (236.1) | – | (236.1) |
Derivative fair value movements during the year which have been recognised in the income statement were as follows
| Loss on derivative instruments | 2015 \$m |
2014 \$m |
|---|---|---|
| Intercompany oil derivatives | (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 2015 and 2014 was as follows:
| 2015 Cash at bank \$m |
2015 Fixed rate debt \$m |
2015 Floating rate debt \$m |
2015 Total \$m |
2014 Cash at bank \$m |
2014 Fixed rate debt \$m |
2014 Floating rate debt \$m |
2014 Total \$m |
|
|---|---|---|---|---|---|---|---|---|
| US\$ | 2.1 | (1,300.0) | (2,857.3) | (4,155.2) | 2.2 | (1,300.0) | (1,822.4) | (3,120.2) |
| Euro | 0.2 | – | – | 0.2 | – | – | – | – |
| Sterling | 0.1 | – | (156.9) | (156.8) | (0.3) | – | (164.6) | (164.9) |
| Other | 1.0 | – | – | 1.0 | 1.7 | – | – | 1.7 |
| 3.4 | (1,300.0) | (3,014.2) | (4,310.8) | 3.6 | (1,300.0) | (1,987.0) | (3,283.4) |
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 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 |
| 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 2014 | |||||||
| Non-interest bearing | n/a | 236.1 | – | – | – | – | 236.1 |
| Fixed interest rate instruments | 6.5% | ||||||
| Principal repayments | – | – | – | – | 1,300.0 | 1,300.0 | |
| Interest charge | – | – | 79.6 | 318.5 | 160.9 | 559.0 | |
| Variable interest rate instruments | 6.7% | ||||||
| Principal repayments | – | – | – | 1,987.0 | – | 1,987.0 | |
| Interest charge | 6.2 | 12.4 | 59.5 | 372.3 | – | 450.4 | |
| 242.3 | 12.4 | 139.1 | 2,677.8 | 1,460.9 | 4,532.5 |
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.
| Equity | Foreign currency denominated liabilities and equity |
||||
|---|---|---|---|---|---|
| Market movement | 2015 \$m |
2014 \$m |
2015 \$m |
2014 \$m |
|
| Brent oil price | 50% | – | – | (441.1) | – |
| Brent oil price | (50%) | – | – | 564.1 | – |
| US\$/foreign currency exchange rates | 20% | – | – | (31.4) | (32.9) |
| US\$/foreign currency exchange rates | (20%) | – | – | 31.4 | 32.9 |
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, the sensitivities have been run only on the intrinsic element of the derivatives as management consider this to be the material component of oil derivative valuations.
Amounts falling due after more than one year
| 2015 | 2014 | 2013 | |
|---|---|---|---|
| \$m | \$m | \$m | |
| Loans from subsidiary companies | – | – | 1.3 |
The amounts due from subsidiaries do not accrue interest. All loans from subsidiary companies are not due to be repaid within five years.
Allotted equity share capital and share premium
| At 31 December 2015 | 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 |
| – Exercise of share options | 689,690 | 0.1 | 3.2 |
| Issued during the year | |||
| At 1 January 2014 | 909,971,941 | 146.9 | 603.2 |
| 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.
In January 2016 Tullow completed the farm-down of 25% of its interest in block 12A to Delonex and Tullow also agreed to sell a 20% interest in the Bannu West licence in Pakistan to Mari Gas. Tullow was awarded a 60% operated interest in the Orinduik licence in January 2016, a 1,801 square kilometre block offshore Guyana. On 23 January 2016, the TEN FPSO set sail from Singapore to Ghana with arrival expected in early March 2016.
Subsequent to the balance sheet date there has been a deterioration in the spot price of Brent crude. Sensitivity analysis on the impact of a reduction in Brent crude prices on the carrying value of PP&E is provided in note 12 of the Group accounts.
| 2015 | 2014 | 2013* | 2012* | *Restated 2011 |
|
|---|---|---|---|---|---|
| Group income statement | \$m | \$m | \$m | \$m | \$m |
| Sales revenue | 1,606.6 | 2,212.9 | 2,646.9 | 2,344.1 | 2,304.2 |
| Cost of sales | (1,015.3) | (1,116.7) | (1,153.8) | (968.0) | (897.2) |
| Gross profit | 591.3 | 1,096.2 | 1,493.1 | 1,376.1 | 1,407.0 |
| Administrative expenses | (193.6) (40.8) |
(192.4) | (218.5) | (191.2) | (122.8) |
| Restructuring costs | (56.5) | – | – | – | – |
| (Loss)/profit on disposal | (482.4) | 29.5 | 702.5 | 2.0 | |
| Goodwill impairment | (53.7) (748.9) |
(132.8) | – | – | – |
| Exploration costs written off | (1,657.3) | (870.6) | (670.9) | (120.6) | |
| Impairment of property, plant and equipment | (406.0) | (595.9) | (52.7) | (31.3) | (33.6) |
| Provision for onerous service contracts | (185.5) | – | – | – | – |
| Operating (loss)/profit | (1,093.7) | (1,964.6) | 380.8 | 1,185.2 | 1,132.0 |
| (Loss)/profit on hedging instruments | (58.8) | 50.8 | (19.7) | (19.9) | 27.2 |
| Finance revenue | 4.2 | 9.6 | 43.7 | 9.6 | 36.6 |
| Finance costs | (149.0) | (143.2) | (91.6) | (59.0) | (122.9) |
| (Loss)/profit from continuing activities before taxation | (1,297.3) | (2,047.4) | 313.2 | 1,115.9 | 1,072.9 |
| Taxation | 260.4 | 407.5 | (97.1) | (449.7) | (383.9) |
| (Loss)/profit for the year from continuing activities | (1,036.9) | (1,639.9) | 216.1 | 666.2 | 689.0 |
| (Loss)/earnings per share | |||||
| Basic – ¢ | (113.6) | (170.9) | 18.6 | 68.8 | 72.5 |
| Diluted – ¢ | (113.6) | (170.9) | 18.5 | 68.4 | 72.0 |
| Dividends paid | – | 182.3 | 167.4 | 173.2 | 114.2 |
| Group balance sheet | |||||
| Non-current assets | 9,506.8 | 9,335.1 | 9,439.3 | 8,087.6 | 9,463.5 |
| Net current assets/(liabilities) | 259.2 | 747.4 | 637.0 | 65.4 | (361.2) |
| Total assets less current liabilities | 9,766.0 | 10,082.5 | 10,076.3 | 8,153.0 | 9,102.3 |
| Long-term liabilities | (6,591.3) | (6,062.2) | (4,629.9) | (2,831.4) | (4,336.3) |
| Net assets | 3,174.7 | 4,020.3 | 5,446.4 | 5,321.6 | 4,766.0 |
| Called up equity share capital | 147.2 | 147.0 | 146.9 | 146.6 | 146.2 |
| Share premium | 609.8 | 606.4 | 603.2 | 584.8 | 551.8 |
| Foreign currency translation reserve | (249.3) | (205.7) | (155.1) | (167.8) | (175.5) |
| Hedge reserve | 569.9 | 401.6 | 2.3 | (6.5) | (14.3) |
| Other reserves | 740.9 | 740.9 | 740.9 | 740.9 | 740.9 |
| Retained earnings | 1,336.4 | 2,305.8 | 3,984.7 | 3,931.2 | 3,441.3 |
| Equity attributable to equity holders of the parent | 3,154.9 | 3,996.0 | 5,322.9 | 5,229.2 | 4,690.4 |
| Non-controlling interest | 19.8 | 24.3 | 123.5 | 92.4 | 75.6 |
| Total equity | 3,174.7 | 4,020.3 | 5,446.4 | 5,321.6 | 4,766.0 |
* 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.
** The 2011 figures have been restated to reflect the adjustment to business combination fair values.
| 10 February 2016 |
|---|
| 28 April 2016 |
| 28 April 2016 |
| 1 July 2016 |
| 27 July 2016 |
| 9 November 2016 |
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
The Central Securities Depository (Ghana) Limited 4th Floor, Cedi House, P.M.B CT 465 Cantonments, Accra, Ghana
Tel – Ghana shareholders: + 233 302 689 313 / 689 314 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:
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 www.etree.com/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 www.fca.org.uk/scams 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
| Area | Tullow | ||||
|---|---|---|---|---|---|
| Licence | Fields | sq km | 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, 2 | 4,414 | 35.00% | Perenco | ExxonMobil | |
| Avouma | Avouma, South Tchibala |
52 | 7.50% | Vaalco | Addax (Sinopec), Sasol, Sojitz, PetroEnergy |
| Ebouri | Ebouri | 15 | 7.50% | Vaalco | Addax (Sinopec), Sasol, Sojitz, PetroEnergy |
| Echira | Echira | 76 | 40.00% | Perenco | |
| Etame | Etame, North Tchibala |
49 | 7.50% | Vaalco | Addax (Sinopec), Sasol, Sojitz, PetroEnergy |
| Ezanga | 5,626 | 7.50% | Maurel & Prom Gov of Gabon | ||
| 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 | |
| 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 | |
| Maroc | Maroc | 17 | 7.50% | Maurel & Prom Gov of Gabon | |
| Maroc Nord | Maroc Nord | 17 | 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 Rights3 | |||||
| Dussafu Marin | 2,780 | 5.00% | Harvest Natural Res |
Pan-Petroleum | |
| Etame Marin | 2,972 | 7.50% | Vaalco | Addax (Sinopec), Sasol, Sojitz, PetroEnergy |
|
| Ghana | |||||
| Deepwater Tano | Wawa | 558 | 49.95% | Tullow | Kosmos, Anadarko, GNPC, PetroSA |
| Ten Development Area4 | Tweneboa, Enyenra, Ntomme |
47.18%4 | |||
| West Cape Three Points | Jubilee | 412 | 26.40% | Kosmos | Anadarko, GNPC, PetroSA |
| Jubilee Field Unit Area5 | Jubilee | 110 | 35.48% | Tullow | Kosmos, Anadarko, GNPC, PetroSA |
Notes:
Tullow has 'Back-In Rights' on this licence as well as a working interest.
Exploration activities on this licence are dealt with by the New Ventures BDT.
Back-In Rights: Tullow has the option, in the event of a development, to acquire varying interests in licences where there is a Back-In Right.
GNPC has exercised its right to acquire an additional 5% in the Tweneboa, Enyenra and Ntomme (TEN) discoveries. Tullow's interest in these discoveries is now 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.
CURRENT EXPLORATION, DEVELOPMENT AND PRODUCTION INTERESTS
| 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 | 343 | 20.00% | ENGIE | EBN, Gas Plus | ||
| E18a | E18-A7, F16-E7 | 212 | 17.60% | Wintershall | Dana, EBN | |
| E18b | 192 | 30.00% | ENGIE | EBN | ||
| F13a | F16-E7 | 4 | 4.69% | Wintershall | Dana, ENGIE, EBN | |
| J9 | 18 | 9.95% | NAM | Oranje Nassau, | ||
| Wintershall, EBN | ||||||
| K8 | 820 | 22.5% | NAM | Oranje Nassau, | ||
| Wintershall, EBN | ||||||
| K11 | 18.00% | |||||
| L13 | 413 | 22.50% | NAM | Oranje Nassau, EBN, | ||
| Wintershall | ||||||
| Joint Development Area (JDA)8 | 31 fields | 9.95% | NAM | Oranje Nassau, | ||
| J9, K7, K8, K11, K14a, K15, L13 | 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 H9 | |||||
| P452 | 44/23a (part) | Murdoch K9 | 48 | 6.91% | ConocoPhillips ENGIE | |
| P453 | 44/28b | Ketch | 85 | 40.00% | Faroe Petr | |
| P516 | 44/26a | Schooner10 | 99 | 42.96% | Faroe Petr | |
| P1006 | 44/17b | Munro11 | 48 | 20.00% | ConocoPhillips ENGIE | |
| P1058 | 44/18b | 46 | 22.50% | ConocoPhillips ENGIE | ||
| 44/23b | Kelvin13 | |||||
| P1139 | 44/19b | Katy (formerly Harrison) |
30 | 22.50% | ConocoPhillips ENGIE | |
| CMS III Unit12 | 44/17a (part) 44/17c (part) 44/21a (part) 44/22a (part) 44/22b (part) 44/22c (part) 44/23a (part) |
Boulton H, Hawksley13 McAdam, Murdoch K |
14.10% | ConocoPhillips ENGIE | ||
| Munro Unit12 | 44/17b 44/17a |
Munro | 15.00% | ConocoPhillips ENGIE | ||
| Schooner Unit12 44/26a | 43/30a | Schooner | 40.00% | Faroe Petr | ||
| Thames Area | ||||||
| P007 | 49/24aF1 (Gawain) |
Gawain 14, 15 | 69 | 50.00% | Perenco | |
| P037 | 49/28a 49/28b |
Thames15, Yare15, Bure15, Deben15, Wensum15 |
90 | 66.67% | Perenco | Centrica |
| 49/28a(part) | Thurne15 | 86.96% | Tullow | Centrica | ||
| P039 | 53/04d | Wissey15 | 29 | 62.50% | Tullow | First Oil, Faroe Petr |
| P105 | 49/29a (part) | Gawain14, 15 | 17 | 50.00% | Perenco | |
| P786 | 53/03c | Horne15 | 8 | 50.00% | Tullow | Centrica |
| P852 | 53/04b | Horne & Wren15 | 17 | 50.00% | Tullow | Centrica |
| Gawain Unit12 | 49/24F1 (Gawain) |
Gawain15 | 50.00% | Perenco | ||
| 49/29a (part) |
| Area | Tullow | ||||
|---|---|---|---|---|---|
| Licence | Fields | sq km | Interest | Operator | Other Partners |
| Kenya | |||||
| Block 10BA | 15,811 | 50.00% | Tullow | Africa Oil, Maersk | |
| Block 10BB | 6,172 | 50.00% | Tullow | Africa Oil, Maersk | |
| Block 12A | 15,390 | 40.00% | Tullow | Africa Oil, Delonex | |
| Block 12B | 6,200 | 50.00% | Tullow | Swala Energy | |
| Block 13T | 4,719 | 50.00% | Tullow | Africa Oil, Maersk | |
| Uganda | |||||
| Exploration Area 1 | Jobi, Rii, Jobi East, Gunya, Ngiri, Mpyo |
598 | 33.33% | Total | CNOOC |
| Exploration Area 1A | Lyec | 85 | 33.33% | Total | CNOOC |
| Exploration Area 2 | Kasamene, Kigogole, Mputa, Nsogo, Ngege, Ngara, Nzizi, Waraga, Wahrindi |
1,025 | 33.33% | Tullow | CNOOC, Total |
| Production Licence 1/12 | Kingfisher | 344 | 33.33% | CNOOC | 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 block J9, are known as the Joint Development Area (JDA).
Refer to CMS III Unit for field interest.
Refer to Schooner Unit for field interest.
Refer to Munro Unit for field interest.
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.
This field is no longer producing.
Refer to Gawain Unit for field interest.
These fields are no longer producing. Abandonment works are ongoing.
CURRENT EXPLORATION, DEVELOPMENT AND PRODUCTION INTERESTS
| Licence | Blocks | Fields | Area sq km |
Tullow Interest |
Operator | Other Partners |
|---|---|---|---|---|---|---|
| Ethiopia | ||||||
| South Omo | 22,288 | 50.00% | Tullow | Africa Oil, Delonex16, Maersk | ||
| French Guiana | ||||||
| Guyane Maritime | 24,100 | 27.50% | Shell | Total, Northpet Investments | ||
| Greenland | ||||||
| Block 9 (Tooq) | 11,802 | 40.00% | Maersk | Nunaoil | ||
| Guinea | ||||||
| Offshore Guinea (Deepwater)17 |
18,746 | 40.00% | Tullow | SCS, Dana | ||
| Guyana | ||||||
| Kanuku | 6,525 | 30.00% | Repsol 18 | RWE18 | ||
| Orinduik | 1,776 | 60.00% | Tullow | Eco O&G | ||
| Jamaica | ||||||
| Walton Morant | 32,065 | 100.00% | Tullow | |||
| Madagascar | ||||||
| Mandabe | 7,189 | 65.00% | Tullow | OMV | ||
| (Block 3109) | ||||||
| Berenty | 7,492 | 65.00% | Tullow | OMV | ||
| (Block 3111) | ||||||
| Mauritania | ||||||
| Block C-3 | 9,825 | 49.50%19 Tullow | Sterling Energy19, SMH | |||
| Block C-10 | 8,025 | 76.50% | Tullow | SMH, Sterling Energy | ||
| Block C-18 | 13,225 | 90.00% | Tullow | SMH | ||
| PSC B | Chinguetti | 31 | 22.26% | Petronas | SMH, Premier, Kufpec | |
| (Chinguetti EEA)20 | ||||||
| Namibia | ||||||
| PEL 0030 | 5,800 | 25.00% | Eco O&G | AziNam, NAMCOR | ||
| (Block 2012A) | ||||||
| PEL 0037 (Blocks | 17,295 | 65.00% | Tullow | Pancontinental, Paragon | ||
| 2112A,B, 2113B) | ||||||
| Norway | ||||||
| North Sea | ||||||
| PL 405 | 8/10 | 101 | 15.00% | Centrica | Faroe Petr, Suncor | |
| PL 406 | 18/10 | 115 | 20.00% | Premier | Kufpec | |
| PL 407 | 17/12 | 81 | 20.00% | Premier | Kufpec | |
| PL 507 | 25/2, 25/3, 30/11, | 1,003 | 20.00%22 Statoil 21 | North Energy, MOL | ||
| 30/12, 31/10 (parts) |
||||||
| PL 550 | 31/1, 31/2 | 469 | 80.00% | Tullow | Det norske, VNG | |
| PL 626 | 25/10 | 202 | 30.00% | Det norske | Fortis Petr, MOL | |
| PL 636 | 36/7 | 455 | 20.00% | ENGIE | Idemitsu, Wellesley Petr | |
| PL 746S | 29/3 | 55 | 30.00% | Pure E&P | Concedo | |
| PL 774 | 16/7 | 114 | 40.00% | Tullow | Concedo, Petrolia | |
| PL 774B | 16/10 | 22 | 40.00% | Tullow | Concedo, Petrolia | |
| PL 775 | 16/7, 16/8 | 347 | 40.00% | Tullow | Concedo, Petoro, Spike | |
| PL 776 | 16/5, 16/6, 16/8, | 665 | 40.00% | Tullow | Concedo, Petoro, Wintershall | |
| 16/9 | ||||||
| PL 784 | 25/3, 25/6 | 273 | 40.00% | Tullow | Concedo, North Energy, | |
| Pure E&P | ||||||
| PL 786 | 31/3, 32/1, 35/12, | 732 | 50.00% | ENGIE | ||
| 36/10 | ||||||
| PL 811 | 7/9, 7/12, 8/7, 8/10 |
359 | 20.00% | Origo | Faroe Petr | |
| PL 826 | 29/3, 30/1, 33/12 | 15 | 30.00% | Pure E&P | Concedo | |
| PL 827S | 35/10 | 52 | 40.00% | Tullow | Statoil, Shell | |
| Licence | Blocks | Area sq km |
Tullow Interest |
Operator | Other Partners |
|---|---|---|---|---|---|
| Norway | |||||
| Norwegian Sea PL 583 |
6306/6, 6306/7 | 1,021 | 55.00% | Tullow | Svenska |
| 6306/8, 6306/9 | |||||
| PL 650 | 6507/3 | 140 | 25.00% | E. ON | Statoil |
| PL 651 | 6610/8, 6610/9, 6610/11, 6610/12 |
1,338 | 35.00% | E. ON | Dana |
| PL 689 | 6306/3 | 457 | 20.00% | DONG | Bayerngas, Svenska |
| PL 689B | 6307/1, 6307/4 | 128 | 20.00% | DONG | Det norske, Bayerngas |
| PL 701 | 6406/9, 6406/11, 6406/12 |
419 | 30.00% | Noreco | ENGIE |
| 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% | Pure E&P | |
| PL 838 | 6507/5, 6507/6 | 125 | 30.00% | PGNiG | E. ON |
| PL 843 | 6608/12, 6609/7, 6609/8, 6609/9, 6609/10, 6609/11, 6609/12 |
1,123 | 20.00% | Det norske | Pure E&P, Statoil |
| Barents Sea | |||||
| PL 537 | 7324/7, 7324/8 | 594 | 20.00% | OMV | Petoro, Idemitsu, Statoil |
| PL 610 | 7222/2, 7222/3 (parts) |
403 | 37.50% | ENGIE | Pure E&P |
| PL 659 | 7121/3, 7122/1, 7122/2, 7221/12, 7222/10, 7222/11, 7222/12 |
1,462 | 15.00% | Det norske | Lundin, Petoro, Pure E&P, Atlantic Petr |
| PL 695 | 7018/3, 7018/6 7019/1 |
590 | 40.00% | Lundin | Petoro |
| PL 709 | 7224/6, 7225/4 |
476 | 40.00% | Det norske | ENGIE |
| PL 710 | 7218/12, 7219/10, 7219/11 |
956 | 20.00% | Total | Maersk, ENGIE |
| Pakistan | |||||
| Bannu West | 1,230 | 20.00%23 Tullow | OGDCL, MPCL, SEL | ||
| Block 28 | 6,200 | 95.00% | Tullow | 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 31 | 5,560 | 30.00% | Inpex | ||
| Block 47 | 2,369 | 100.00% | Tullow | ||
| Block 54 | 8,480 | 30.00% | Tullow | Statoil, Noble Energy | |
| Uruguay | |||||
| Block 15 | 8,030 | 35.00%24 Tullow | Statoil, Inpex |
Notes
Delonex has acquired Marathon's interest, subject to Government approval.
Area listed is following a 25% relinquishment, subject to Government approval.
Repsol is in the process of acquiring RWE'S interest, subject to Government approval.
Sterling is in the process of withdrawing from this licence; Tullow will revert to 90% on completion.
PSC B (Chinguetti EEA) is dealt with by the West Africa BDT.
Statoil is taking over operatorship of this licence from Tullow, subject to Government approval.
Tullow's interest on completion of deal with Statoil.
Tullow's interest on completion of farm-down to MPCL.
Tullow's interest on completion of deal with Statoil, subject to Government approval.
| 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 | |||||||||||
| 31 December 2014 | 307.6 | 226.4 | – | – | – | – | 307.6 | 226.4 | 345.3 | ||
| Revisions | 3.0 | 6.8 | – | – | – | – | 3.0 | 6.8 | 4.1 | ||
| Transfer from contingent resources |
0.9 | – | – | – | – | – | 0.9 | – | 0.9 | ||
| Disposals | – | (10.0) | – | – | – | – | – | (10.0) | (1.7) | ||
| Production | (23.9) | (17.4) | – | – | – | – | (23.9) | (17.4) | (26.8) | ||
| 31 December 2015 | 287.6 | 205.8 | – | – | – | – | 287.6 | 205.8 | 321.8 | ||
| Contingent resources | |||||||||||
| 31 December 2014 | 106.8 | 993.7 | 531.6 | 12.4 | 101.5 | 4.2 | 739.9 | 1,010.3 | 908.3 | ||
| Revisions | 9.9 | (233.6) | 79.1 | 30.2 | – | – | 89.0 | (203.4) | 55.1 | ||
| Additions | – | – | 18.1 | – | – | – | 18.1 | – | 18.1 | ||
| Disposals | – | (35.2) | – | – | – | – | – | (35.2) | (5.9) | ||
| Transfers to commercial reserves |
(0.9) | – | – | – | – | – | (0.9) | – | (0.9) | ||
| 31 December 2015 | 115.8 | 724.9 | 628.8 | 42.6 | 101.5 | 4.2 | 846.1 | 771.7 | 974.7 | ||
| Total | |||||||||||
| 31 December 2015 | 403.4 | 930.7 | 628.8 | 42.6 | 101.5 | 4.2 | 1,133.7 | 977.5 | 1,296.5 |
Proven and Probable Commercial Reserves are based on a Group reserves report produced 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.
Proven and Probable Contingent Resources are based on a Group reserves report produced 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, Equatorial Guinea and Gabon.
The West Africa disposals relate to the L&Q block in the Netherlands and farm-down of the Vincent discovery.
The West Africa revision to gas contingent resources relates to the relinquishment of the Pelican field in Mauritania.
East Africa additions to oil contingent resources relate to Etom in Kenya.
East Africa revision to contingent resources relate to Kenya and Uganda.
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 299.1 mmboe at 31 December 2015 (31 December 2014: 321.0 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.
3
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 its Annual Report and Accounts since 2013. The 2015 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 a 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 66. Detailed disclosure on our 2015 tax payments can be found on pages 172 to 175.
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 2015 average realised oil price \$67.0/bbl.
Income taxes – This represents 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 – This represents 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 – This represents 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 – This represents 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 – This represents 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 – This 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 – This includes taxes that are placed on legal documents usually in the transfers 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) – This represents 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 & national insurance – This represents 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 – This comprises 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 – This represents 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 – This comprises 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.
| UK Regulations | ||||||||
|---|---|---|---|---|---|---|---|---|
| Production entitlements |
Production entitlements |
Income taxes | Royalties (cash only) |
Dividends | Bonus payments |
Licence fees |
Infrastructure improvement payments |
|
| Licence / Company level | bbls (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) |
| M'Boundi | 226 | – | – | – | – | – | – | – |
| Total Congo | 226 | – | – | – | – | – | – | – |
| CI-26 Espoir | – | 274 | – | – | – | – | – | – |
| Corporate | – | – | – | – | – | – | – | – |
| Total Côte d'Ivoire | – | 274 | – | – | – | – | – | – |
| Ceiba | 149 | – | – | – | – | – | – | – |
| Okume Complex | 346 | – | – | – | – | – | – | – |
| Corporate | – | – | 37,381 | – | – | – | – | – |
| Total Equatorial Guinea | 495 | – | 37,381 | – | – | – | – | – |
| Echira | – | – | – | 1,304 | – | – | – | – |
| Etame | – | – | – | 3,124 | – | – | – | – |
| Ezanga | – | – | – | 706 | – | 20,000 | – | – |
| Limande | – | – | – | 3,236 | – | – | – | – |
| M'Oba | – | – | – | 157 | – | – | – | – |
| Niungo | – | – | – | 3,013 | – | – | – | – |
| Tchatamba | – | – | – | 9,413 | – | – | – | – |
| Turnix | – | – | – | 1,088 | – | – | – | – |
| Corporate – Tullow Oil Gabon SA | – | – | 15,775 | 94 | – | – | – | – |
| Oba | – | – | – | 1,106 | – | – | – | – |
| Corporate – Tulipe Oil SA | – | – | 2,122 | – | – | – | – | – |
| Total Gabon | – | – | 17,897 | 23,241 | – | 20,000 | – | – |
| Jubilee | 664 | – | – | – | – | – | – | 915 |
| TEN | – | – | – | – | – | – | – | 237 |
| Company level | – | – | – | – | – | – | 60 | 3,190 |
| Total Ghana | 664 | – | – | – | – | – | 60 | 4,342 |
| Company level | – | – | – | – | – | – | 75 | 60 |
| Total Guinea | – | – | – | – | – | – | 75 | 60 |
| PSC B (Chinguetti EEA) | 47 | – | – | – | – | – | 258 | – |
| Corporate | – | – | – | – | – | – | 70 | – |
| Total Mauritania | 47 | – | – | – | – | – | 328 | – |
| South Omo | – | – | – | – | – | – | 441 | 197 |
| Corporate | – | – | – | – | – | – | – | – |
| Total Ethiopia | – | – | – | – | – | – | 441 | 197 |
| Corporate | – | – | 9 | – | – | – | 486 | – |
| Total Kenya | – | – | 9 | – | – | – | 486 | – |
| Block 3111 | – | – | – | – | – | – | 300 | – |
| Corporate | – | – | – | – | – | – | 300 | – |
| Total Madagascar | – | – | – | – | – | – | 600 | – |
| Corporate | – | – | 1 | – | – | – | – | – |
| Total Mozambique | – | – | 1 | – | – | – | – | – |
| Company level | – | – | – | – | – | – | 127 | – |
| Total Namibia | – | – | – | – | – | – | 127 | – |
| Voluntary disclosure | |||||||
|---|---|---|---|---|---|---|---|
| PAYE & | |||||||
| Training | Customs | Carried | national | Withholding | |||
| TOTAL US\$ (000) |
allowances US\$(000) |
duties US\$ (000) |
interests US\$ (000) |
insurance US\$ (000) |
tax US\$ (000) |
Stamp duty US\$ (000) |
VAT US\$(000) |
| – | – | – | – | – | – | – | – |
| – | – | – | – | – | – | – | – |
| 274 | – | – | – | – | – | – | – |
| 59 | – | – | – | 59 | – | – | – |
| 333 | – | – | – | 59 | – | – | – |
| – | – | – | – | – | – | – | – |
| – | – | – | – | – | – | – | – |
| 37,381 | – | – | – | – | – | – | – |
| 37,381 | – | – | – | – | – | – | – |
| 1,304 | – | – | – | – | – | – | – |
| 3,124 | – | – | – | – | – | – | – |
| 20,706 | – | – | – | – | – | – | – |
| 3,236 | – | – | – | – | – | – | – |
| 157 | – | – | – | – | – | – | – |
| 3,013 | – | – | – | – | – | – | – |
| 9,413 | – | – | – | – | – | – | – |
| 1,088 | – | – | – | – | – | – | – |
| 16,870 | – | – | – | 588 | 69 | – | 344 |
| 1,106 | – | – | – | – | – | – | – |
| 2,124 | – | – | – | 2 | – | – | – |
| 62,141 | – | – | – | 590 | 69 | – | 344 |
| 915 | – | – | – | – | – | – | – |
| 237 | – | – | – | – | – | – | – |
| 191,456 | 250 | 10,215 | 94,114 | 16,597 | 63,321 | – | 3,709 |
| 192,608 | 250 | 10,215 | 94,114 | 16,597 | 63,321 | – | 3,709 |
| 160 | – | – | – | 25 | – | – | – |
| 160 | – | – | – | 25 | – | – | – |
| 258 | – | – | – | – | – | – | – |
| 2,101 | 700 | – | – | 61 | 1,270 | – | – |
| 2,359 | 700 | – | – | 61 | 1,270 | – | – |
| 638 | – | – | – | – | – | – | – |
| (1,421) | 150 | – | – | 160 | 49 | – | (1,780) |
| (783) | 150 | – | – | 160 | 49 | – | (1,780) |
| 33,240 | 958 | 993 | – | 21,634 | 9,003 | – | 157 |
| 33,240 | 958 | 993 | – | 21,634 | 9,003 | – | 157 |
| 300 | – | – | – | – | – | – | – |
| 303 | – | – | – | 3 | – | – | – |
| 603 | – | – | – | 3 | – | – | – |
| 1 | – | – | – | – | – | – | – |
| 1 | – | – | – | – | – | – | – |
| 370 | 55 | – | – | 188 | – | – | – |
| 370 | 55 | – | – | 188 | – | – | – |
| Training | ||
|---|---|---|
| allowances | TOTAL | TOTAL |
| UK Regulations | ||||||||
|---|---|---|---|---|---|---|---|---|
| Production entitlements |
Production entitlements |
Income taxes | Royalties (cash only) |
Dividends | Bonus payments |
Licence fees |
Infrastructure improvement payments |
|
| Licence / Company level | bbls (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) |
| Corporate | – | – | 505 | – | – | – | – | – |
| Total South Africa | – | – | 505 | – | – | – | – | – |
| Corporate | – | – | 36,059 | – | – | – | 11 | – |
| Total Uganda | – | – | 36,059 | – | – | – | 11 | – |
| Corporate | – | – | (2,919) | – | – | – | – | – |
| Total Ireland | – | – | (2,919) | – | – | – | – | – |
| Walton Morant | – | – | – | – | – | – | 128 | – |
| Corporate | – | – | – | – | – | – | – | – |
| Total Jamaica | – | – | – | – | – | – | 128 | – |
| Corporate | – | – | (5,755) | – | – | – | 259 | – |
| Total Netherlands | – | – | (5,755) | – | – | – | 259 | – |
| PL 405B | – | – | – | – | – | – | 263 | – |
| PL 406 | – | – | – | – | – | – | 391 | – |
| PL 438 | – | – | – | – | – | – | 1,002 | – |
| PL 519 | – | – | – | – | – | – | 186 | – |
| PL 550 | – | – | – | – | – | – | 1,370 | – |
| Corporate | – | – | (144,867) | – | – | – | 71 | – |
| Total Norway | – | – | (144,867) | – | – | – | 3,283 | – |
| Corporate | – | – | – | – | – | – | 10 | 14 |
| Total Pakistan | – | – | – | – | – | – | 10 | 14 |
| Block 47 | – | – | – | – | – | – | – | 258 |
| Block 54 | – | – | – | – | – | – | – | 258 |
| Corporate | – | – | – | – | – | – | – | – |
| Total Suriname | – | – | – | – | – | – | – | 516 |
| Murdoch | – | – | – | – | – | – | 260 | – |
| Ketch | – | – | – | – | – | – | 299 | – |
| Schooner | – | – | – | – | – | – | 434 | – |
| Corporate | – | – | 7,080 | – | – | – | 634 | 238 |
| Total UK | – | – | 7,080 | – | – | – | 1,627 | 238 |
| Corporate | – | – | – | – | – | – | – | – |
| Total Uruguay | – | – | – | – | – | – | – | – |
| TOTAL | 1,432 | 274 | (54,609) | 23,241 | – | 20,000 | 7,435 | 5,367 |
| Voluntary disclosure | |||||||
|---|---|---|---|---|---|---|---|
| PAYE & | |||||||
| Training | Customs | Carried | national | Withholding | |||
| TOTAL | allowances | duties | interests | insurance | tax | Stamp duty | VAT |
| US\$ (000) | US\$(000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$ (000) | US\$(000) |
| 6,405 | – | – | – | 5,428 | – | – | 472 |
| 6,405 | – | – | – | 5,428 | – | – | 472 |
| 49,660 | 276 | – | – | 6,121 | 6,286 | – | 907 |
| 49,660 | 276 | – | – | 6,121 | 6,286 | – | 907 |
| 3,398 | – | – | – | 8,910 | – | – | (2,593) |
| 3,398 | – | – | – | 8,910 | – | – | (2,593) |
| 128 | – | – | – | – | – | – | – |
| 102 | 102 | – | – | – | – | – | – |
| 230 | 102 | – | – | – | – | – | – |
| (4,606) | – | – | – | 490 | – | – | 400 |
| (4,606) | – | – | – | 490 | – | – | 400 |
| 263 | – | – | – | – | – | – | – |
| 391 | – | – | – | – | – | – | – |
| 1,002 | – | – | – | – | – | – | – |
| 186 | – | – | – | – | – | – | – |
| 1,370 | – | – | – | – | – | – | – |
| (137,861) | – | 135 | – | 10,597 | – | – | (3,797) |
| (134,649) | – | 135 | – | 10,597 | – | – | (3,797) |
| 301 | 7 | – | – | – | 270 | – | – |
| 301 | 7 | – | – | – | 270 | – | – |
| 258 | – | – | – | – | – | – | – |
| 258 | – | – | – | – | – | – | – |
| 242 | – | – | – | 242 | – | – | – |
| 758 | – | – | – | 242 | – | – | – |
| 260 | – | – | – | – | – | – | – |
| 299 | – | – | – | – | – | – | – |
| 434 | – | – | – | – | – | – | – |
| 44,378 | – | – | – | 63,015 | – | – | (26,589) |
| 45,371 | – | – | – | 63,015 | – | – | (26,589) |
| 220 | 100 | – | – | 153 | – | – | (33) |
| 220 | 100 | – | – | 153 | – | – | (33) |
| 295,501 | 2,598 | 11,343 | 94,114 | 134,273 | 80,268 | – | (28,803) |
| TOTAL US\$ (000) | 391,429 |
|---|---|
| US\$ (000) | 95,928 |
| Payments in kind in | |
| % of nominal value | |||
|---|---|---|---|
| Company name | Country of Incorporation | of shares held (all ordinary shares) |
Type of Ownership |
| Hardman Mauritania Finance Pty Ltd | Australia | 100% | Indirect |
| Hardman Oil and Gas Pty Ltd | Australia | 100% | Indirect |
| Hardman Petroleum (Uganda) Pty Ltd | Australia | 100% | Indirect |
| Hardman Petroleum (West Africa) Pty Ltd | Australia | 100% | Indirect |
| Hardman Petroleum Tanzania 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 |
| Energy Africa UK Limited | England & Wales | 100% | Indirect |
| Planet Oil International Limited | England & Wales | 100% | Indirect |
| Planet Oil Limited | England & Wales | 100% | Indirect |
| Tullow CMS (North Sea) Limited | England & Wales | 100% | Direct |
| Tullow Energy Limited | England & Wales | 100% | Direct |
| Tullow Exploration & Production UK Limited | Scotland | 100% | Indirect |
| Tullow Greenland Exploration Limited | England & Wales | 100% | Indirect |
| Tullow Group Services Limited | England & Wales | 100% | Direct |
| Tullow Guinea Limited | England & Wales | 100% | Indirect |
| Tullow Mozambique Limited | England & Wales | 100% | Indirect |
| Tullow Jamaica 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 |
| Hardman Petroleum Holdings Ltd | Guernsey | 100% | Indirect |
| Tullow Oil (Mauritania) Ltd | Guernsey | 100% | Indirect |
| Tullow Oil Holdings (Guernsey) Ltd | Guernsey | 100% | Indirect |
| Invest In Africa | Guernsey | 100% | Indirect |
| Tullow Oil Ltd | Ireland | 100% | Direct |
| Tullow Oil Overseas Finance Limited | 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 Kudu Ltd | Isle of Man | 100% | Indirect |
| Tullow Mauritania Ltd | Isle of Man | 100% | Indirect |
| Tullow Senegal Ltd | Isle of Man | 100% | Indirect |
| Tullow Uganda Ltd | Isle of Man | 100% | Indirect |
| Tullow Cote D'Ivoire Exploration Ltd | Jersey | 100% | Indirect |
| Tullow Cote D'Ivoire Ltd | Jersey | 100% | Indirect |
| Tullow Ghana Ltd | Jersey | 100% | Indirect |
| % of nominal value of shares held (all |
|||
|---|---|---|---|
| Company name | Country of Incorporation | ordinary shares) | Type of Ownership |
| 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 6 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 |
| 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 Norge AS | Norway | 100% | Indirect |
| Tullow Oil (Bream) Norge AS | Norway | 100% | Indirect |
| Energy Africa Bredasdorp (Pty) Ltd | South Africa | 100% | Indirect |
| Tullow South Africa (Pty) Ltd | South Africa | 100% | Indirect |
| Tullow St. Lucia Holdings Ltd | St. Lucia | 100% | Indirect |
| Tullow Trinidad Ltd | Trinidad and Tobago | 100% | Indirect |
| Tullow Oil Canada Ltd | Canada | 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 |
| 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 | |
| EHS | Environment, Health and Safety |
| EITI | Extractive Industries Transparency Initiative |
| EPS | Earnings per share |
| EuroStoxx | A European market index |
| 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&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 |
| km | Kilometres |
| KNPS | Kenya National Police Service |
| KPI | 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 |
| 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 |
| 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 |
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:
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
Kevin Massie 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 Black Sun Plc Printed by Pureprint Group
Tel: +44 (0)20 3249 9000 Fax: +44 (0)20 3249 8801
Email: [email protected] Website: www.tullowoil.com
Building tools?
Free accounts include 100 API calls/year for testing.
Have a question? We'll get back to you promptly.