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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Enquest Plc | LSE:ENQ | London | Ordinary Share | GB00B635TG28 | ORD 5P |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| -0.30 | -1.92% | 15.30 | 15.24 | 15.40 | 15.68 | 14.90 | 14.90 | 869,823 | 15:19:33 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| Offices-holdng Companies,nec | 1.92B | -41.23M | -0.0224 | -6.92 | 285.74M |
From Apr 2019 to Apr 2024
TIDMENQ
RNS Number : 2117I
EnQuest PLC
20 March 2018
Results for the year ended 31 December 2017 and 2018 outlook
20 March 2018
Unless otherwise stated, all figures are on a Business performance basis and are in US Dollars.
2017 performance
-- Kraken first oil delivered in Q2; full cycle gross project capital expenditure further reduced
-- Acquisition of interests in Magnus and the Sullom Voe Oil Terminal completed in December -- Group production averaged 37,405 Boepd in 2017, down 5.9% on 2016
-- Revenue of $635.2 million (2016: $849.6 million) and EBITDA of $303.6 million (2016: $477.1 million); lower realised prices, reflecting the favourable impact of commodity hedges in 2016
-- Cash generated from operations of $327.0 million (2016: $408.3 million) -- Cash capital expenditure of $367.6 million (2016: $609.2 million)
-- Cash* and available bank facilities amounted to $244.4 million at 31 December 2017, with net debt of
$1,991.4 million. Excluding Payment in Kind interest, net debt was $1,900.9 million
-- Reported post-tax non-cash impairments of $107.2 million -- Net 2P reserves of 210 MMboe at the end of 2017
* Excluding $26.5 million of cash from the ring fenced working capital facility associated with SVT.
2018 outlook
-- Guidance range of c.50,000 to 58,000 Boepd; Kraken gross production has averaged around 38,000 Bopd in the first two months of the year
-- Unit opex expected to be c.$24/Boe, including costs associated with planned workovers
-- Cash capital expenditure expected to be c.$250 million; includes drilling programmes at Kraken (DC4), PM8/Seligi and Heather
-- Kraken full cycle gross project capital expenditure further reduced to c.$2.3 billion, more than 25% lower than originally sanctioned
-- The Group has hedged c.7.5 MMbbls of oil at an average price of c.$62/bbl
EnQuest Chief Executive, Amjad Bseisu, said:
"2017 was a transformational year for EnQuest. The Group delivered the complex Kraken project on schedule and expects full cycle gross capital expenditure to be significantly below budget, while the acquisition of the Magnus oil field and Sullom Voe Oil Terminal is aligned with the Group's asset life extension capabilities and provides further opportunities for synergies and growth.
"Production performance in January and February was strong and the Group expects a material increase in production in 2018. This growth, combined with a focus on cost control and a substantially reduced cash capital expenditure programme, should see the Group generate increased cash flow, enabling it to manage its liquidity and reduce debt.
"Beyond 2018, the Group has significant potential within the existing portfolio, in particular at Magnus and PM8/Seligi, but also with potential future developments at Kraken, positioning EnQuest to deliver long-term sustainable growth."
Production and financial information
Hot Features
Premium
2017 2016 Change
%
Production (Boepd) 37,405 39,751 (5.9)
---------------------------------- ---------- ---------- -------
Revenue and other operating
income ($m)(***) 635.2 849.6 (25.2)
---------------------------------- ---------- ---------- -------
Realised oil price ($/bbl)(***) 52.2 63.8 (18.2)
---------------------------------- ---------- ---------- -------
Gross profit ($m) 65.7 196.1 (66.5)
---------------------------------- ---------- ---------- -------
Profit before tax & net
finance costs ($m) 47.3 237.1 (80.1)
---------------------------------- ---------- ---------- -------
EBITDA ($m)** 303.6 477.1 (36.4)
---------------------------------- ---------- ---------- -------
Cash generated from operations
($m) 327.0 408.3 (19.9)
---------------------------------- ---------- ---------- -------
Reported basic earnings
per share (cents) (5.4) 22.7 -
---------------------------------- ---------- ---------- -------
Cash capex ($m)**** 367.6 609.2 (39.7)
---------------------------------- ---------- ---------- -------
End 2017 End 2016
---------------------------------- ---------- ---------- -------
Net (debt)/cash ($m)(*****) (1,991.4) (1,796.5) 10.8
---------------------------------- ---------- ---------- -------
**EBITDA is calculated on a business performance basis, and is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion, depreciation, foreign exchange movements and the realised gains/loss on foreign currency derivatives related to capital expenditure. *** Including losses of $20.6 million (2016: revenue of $255.8 million) associated with EnQuest's oil price hedges. ****Cash capex is stated net of proceeds received from the disposal of tangible and intangible fixed assets of $nil (2016: $1.5 million). ***** Net (debt)/cash represents cash and cash equivalents less borrowings, stated excluding accrued interest and the net-off of unamortised fees.
Production details
Production Net daily Net daily
on a working average average
interest basis 1 Jan' 1 Jan'
2017 to 2016 to
31 Dec' 31 Dec'
2017 2016
----------------- ---------- ----------
(Boepd) (Boepd)
Northern North
Sea 15,627(1) 18,885
Central North
Sea 8,131 11,718(2)
Kraken 4,709(3) -
---------- ----------
Total UKCS 28,467 30,603
---------- ----------
Total Malaysia 8,938 9,148
----------
Total EnQuest 37,405 39,751
---------- ----------
(1) Includes net production from Magnus since acquisition on 1 December 2017, averaged over the 12 months to the end of December 2017.
(2) Includes net production from Scolty/Crathes since first oil on 21 November 2016, averaged over the 12 months to the end of December 2016.
(3) Net production since first oil on 23 June, averaged over the 12 months to the end of December 2017.
2017 performance summary
The Group's focus during the year was to deliver the Kraken development, complete the acquisition of assets from BP and position the Group for profitable growth as it transitions from a period of heavy investment to one in which the Group can begin to reduce its debt. First oil from the Kraken project, one of the largest developments in the North Sea in the last ten years, was delivered on schedule, with full cycle gross capital expenditure expected to be significantly below budget. EnQuest completed the acquisition of initial interests in Magnus, the Sullom Voe Oil Terminal and associated infrastructure in December.
Production for the year was lower than originally expected at 37,405 Boepd, impacted by Electrical Submersible Pump performance at Alma/Galia and lower contributions from the Scolty/Crathes and Kraken developments.
The Group's focus on cost control and management of commercial agreements resulted in lower operating expenditures of $349.3 million, with unit opex of $25.6/boe. However, lower realised prices, reflecting the forward prices available at the time at which the commodity hedge programme was implemented, combined with lower production reduced EnQuest's revenue, EBITDA and cash generated by operations.
As expected, cash capital expenditure of $367.6 million was materially lower than 2016. The majority of the expenditure was at Kraken, with the remaining spend largely reflecting the settlement of deferred invoices in respect of the Alma/Galia and Scolty/Crathes developments and the Eagle discovery. Excellent drilling performance at Kraken has delivered the first three drill centres ('DC's) significantly ahead of schedule, which, along with lower market rates for the remaining subsea campaign, resulted in a reduction of approximately $100 million in the expected full life gross project capital expenditure estimate.
Liquidity and net debt
EnQuest's lending banks continued their support of the Group and agreed to relax the Company's covenants and to amend the amortisation schedule of its Term Loan and Revolving Credit Facility. EnQuest also agreed an $80 million oil prepayment transaction and execution of a $37.25 million refinancing agreement in relation to its Tanjong Baram project. EnQuest finished the year with net debt of $1,991.4 million, with cash and available bank facilities of
$244.4 million, excluding $26.5 million of cash from the ring fenced working capital facility associated with SVT.
Reserves
Net 2P reserves at the end of 2017 were 210 MMboe, (2016: 215 MMboe) representing a reserve life of 17 years. The slight reduction in reserves was driven by some changes in long-term assumptions combined with lower production performance in the North Sea, largely offset by the benefit of the acquisition of an initial 25% equity interest in Magnus and better production performance in Malaysia.
2018 performance and additional outlook details
Production performance in the first two months of 2018 was strong across the portfolio, with Kraken gross average production around 38,000 Bopd in this period. Extreme cold weather in early March resulted in brief shutdowns at a number of the Group's North Sea fields. While Kraken was shut down, the Group has undertaken much of the workscope previously scheduled for the planned shutdown in April and, as a result, this planned shutdown is no longer required. The Group continues to have planned maintenance shutdowns at a number of the Group's fields, including Kraken, in the third quarter. The drilling programmes at Magnus and PM8/Seligi, along with the workover programme at Alma/Galia are expected to deliver production improvements later in the year, with the DC4 programme at Kraken expected to come into production in 2019. The Group expects material net production growth in 2018 to within the guidance range of c.50,000 to 58,000 Boepd.
The Group continues to expect unit operating expenditures of approximately $24/Boe, including the impact of planned workovers at Alma/Galia, while the depletion and depreciation charge is anticipated to be around $22/Boe, reflecting the impact of a full year's contribution from Kraken.
2017 general and administration costs reflect the Group's ongoing efforts to reduce costs across the organisation. 2018 costs are expected to be in the 'single digit' millions.
Cash capital expenditure is still expected to be around $250 million, largely reflecting the drilling programmes at Kraken, Heather and PM8/Seligi. The renegotiation of the drilling rig contract with Transocean, reducing both the contract duration and day rate, has resulted in net cash capital expenditure savings of c.$60 million in 2019. Kraken full cycle gross project capital expenditure is now expected to be c.$2.3 billion, more than 25% lower than originally sanctioned.
EnQuest continues to take prudent measures to improve its liquidity position. In January, EnQuest received $30 million in cash in exchange for agreeing to undertake the management of the physical decommissioning at Thistle and Deveron and being liable to make payments to BP by reference to 3.7% of the gross decommissioning costs of these assets. The Group has an outstanding option, exercisable over a 12 month period, to receive a further $20 million in cash in exchange for making additional payments by reference to 2.4% of the gross decommissioning costs of these fields. In February, the Group completed the $37.25 million refinancing agreement in relation to its Tanjong Baram project, providing approximately $25 million in additional liquidity.
Summary financial review of 2017
(all figures quoted are in US Dollars and relate to Business performance unless otherwise stated)
Total revenue for 2017 was $635.2 million, 25.2% lower than 2016 ($849.6 million). This reduction was largely as a result of lower realised prices, which reflected the forward prices available at the time at which the commodity hedge programme was implemented. The commodity hedge programme resulted in realised losses of $20.6 million in 2017 compared to realised gains of $255.8 million in 2016. As a result, the Group's blended average realised oil price was $52.2/bbl in 2017, compared to $63.8/bbl during 2016. Excluding this hedging impact, the average realised oil price was $53.9/bbl in 2017, 21.8% higher than 2016 ($44.3/bbl), reflecting higher market prices. Revenue is predominantly derived from crude oil sales which totalled $637.0 million for 2017, 10.2% higher than 2016 ($577.8 million). This increase in crude oil revenue reflected a higher market oil price, partially offset by lower production.
Total cost of sales for 2017 was $569.5 million, 12.9% lower than 2016 ($653.5 million). This included depletion expense of $223.1 million (2016: $240.6 million).
Operating expenditures of $349.3 million were 2.3% lower than 2016 ($357.4 million), reflecting the Group's focus on cost control and management of commercial agreements and includes net lease charter payment credits of
$19.5 million arising from the non-availability of the Kraken FPSO and the absence of the 2016 loss on operating expense foreign exchange derivatives, partially offset by a full year of operations at Scolty/Crathes, which came onstream in November 2016. The Group's average unit operating cost for 2017 was $25.6/Boe, 4.0% higher than 2016 ($24.6/Boe) primarily as a result of the 5.9% reduction in production.
Realised losses on foreign currency derivatives related to capital expenditure were $4.8 million, down 89.9% compared to 2016 (losses of $47.3 million) reflecting weaker Sterling:US Dollar exchange rates during the year.
At 31 December 2017, the Group had moved to a net underlift position compared to the prior year end net overlift position, resulting in a $20.4 million credit to cost of sales (2016: charge of $2.8 million).
Other net expenses of $17.6 million (2016: income of $51.9 million) primarily comprise net foreign exchange losses, as a result of revaluing Sterling-denominated amounts on the balance sheet following the strengthening of Sterling against the US Dollar. The prior year included foreign exchange gains of $51.9 million.
EBITDA for 2017 was $303.6 million, 36.4% lower than 2016 ($477.1 million) largely as a result of lower realised prices and lower production.
The tax credit for 2017 of $66.0 million (2016: $5.2 million tax credit), excluding exceptional items, is due predominantly to the Ring Fence Expenditure Supplement on UK activities.
Exceptional items resulting in a net post-tax loss of $27.3 million have been disclosed separately for 2017 (2016: profit of $63.7 million). These largely reflect tangible oil and gas non-cash impairments of $107.2 million, primarily arising from some changes in assumptions combined with lower production performance in the North Sea, partially offset by the recognition of accounting for the excess of fair value over consideration of $48.7 million associated with the acquisition of initial interests in assets from BP.
Net debt at 31 December 2017 was $1,991.4 million, an increase of 10.8% compared to 2016 ($1,796.5 million) primarily as a result of the capital expenditure programme for 2017 of $367.6 million (2016: $609.2 million), principally at Kraken. Excluding Payment in Kind interest ('PIK'), net debt was $1,900.9 million (2016: $1,768.8 million).
UK corporate tax losses at the end of the year increased to $3,121.3 million (2016: $2,893.7 million).
Ends
For further information please contact:
EnQuest PLC Tel: +44 (0)20 7925 4900
Amjad Bseisu (Chief Executive)
Jonathan Swinney (Chief Financial Officer)
Ian Wood (Communications & Investor Relations)
Tulchan Communications Tel: +44 (0)20 7353 4200
Martin Robinson
Martin Pengelley
Presentation to Analysts and Investors
A presentation to analysts and investors will be held at 09:30 today - London time. The presentation and Q&A will also be accessible via an audio webcast, available on the investor relations section of the EnQuest website at www.enquest.com. A conference call facility will also be available at 09:30 on the following numbers:
Conference call details:
UK: +44 (0)330 336 9105
USA: +1 323 794 2093
Confirmation Code: EnQuest
Notes to editors
This announcement has been determined to contain inside information.
ENQUEST
EnQuest is one of the largest UK independent producers in the UK North Sea. EnQuest PLC trades on both the London Stock Exchange and the NASDAQ OMX Stockholm. Its operated assets include Thistle/Deveron, Heather/ Broom, the Dons area, Magnus, the Greater Kittiwake Area, Scolty/Crathes Alma/Galia and Kraken; EnQuest also has an interest in the non-operated Alba producing oil field. At the end of December 2017, EnQuest had interests in 25 UK production licences and was the operator of 23 of these licences.
EnQuest believes that the UKCS represents a significant hydrocarbon basin, which continues to benefit from an extensive installed infrastructure base and skilled labour. EnQuest believes that its assets offer material organic growth opportunities, driven by exploitation of current infrastructure on the UKCS and the development of low risk near field opportunities.
EnQuest is replicating its model in the UKCS by targeting previously underdeveloped assets in a small number of other maturing regions; complementing its operations and utilising its deep skills in the UK North Sea. In which context, EnQuest has interests in Malaysia where its operated assets include the PM8/Seligi Production Sharing Contract and the Tanjong Baram Risk Services Contract.
Forward-looking statements: This announcement may contain certain forward-looking statements with respect to EnQuest's expectation and plans, strategy, management's objectives, future performance, production, reserves, costs, revenues and other trend information. These statements and forecasts involve risk and uncertainty because they relate to events and depend upon circumstances that may occur in the future. There are a number of factors which could cause actual results or developments to differ materially from those expressed or implied by these forward-looking statements and forecasts. The statements have been made with reference to forecast price changes, economic conditions and the current regulatory environment. Nothing in this announcement should be construed as a profit forecast. Past share performance cannot be relied on as a guide to future performance.
Chairman's statement
EnQuest performance overview
EnQuest delivered a number of commendable operational achievements in 2017, combined with another year of strong safety performance. In June, first oil was achieved at the Kraken project, a critical turning point for the Company in delivering improved operating cash flow and marking the start of a material reduction in the Group's capital investment requirements. While the subsequent ramp-up in production took longer than anticipated following initial commissioning and operational efficiency issues, by the end of the year, this large and complex development had produced over 40,000 Bopd (gross). In the first two months of 2018, average gross production was around 38,000 Bopd, and has reached 50,000 Bopd with improving operational efficiency as we continue to optimise performance.
Group production of 37,405 Boepd in 2017 was disappointing, primarily caused by performance issues at Alma/Galia and lower than planned production from both Kraken and Scolty/Crathes.
Despite the challenges presented by the prevailing macro-economic environment, the Group undertook further steps to set the platform to improve the balance sheet. The Group delivered operating and capital expenditures in line with targets, demonstrating the team's focus on cost control and managing commercial agreements. EnQuest also completed a crude oil prepayment transaction and executed a refinancing agreement for its Tanjong Baram project in Malaysia, which combined improve the Group's liquidity by more than $100 million.
The Group continued to pursue its vision and advance its long-term growth plan, agreeing and completing the acquisition of interests in the Magnus oil field and the Sullom Voe Oil Terminal ('SVT') from BP. This innovatively structured transaction required no immediate cash payment from EnQuest and limits the Group's exposure to negative cash flows from Magnus, capitalising on EnQuest's strengths in realising value from maturing oil fields with large volumes in place.
This transaction adds to the material growth potential of EnQuest's asset base. By the end of 2017, EnQuest had a net 2P reserve base of 210 MMboe, which represents average growth of approximately 13% per annum since EnQuest's formation eight years ago and a reserve life of around 17 years.
Industry context
Oil & Gas UK's Economic Report 2017 showed that since 2014 the cost of lifting oil from the North Sea has almost halved, an improvement in unit operating costs highlighted as being greater than the improvements achieved by any other basin. EnQuest's cost conscious approach has been central to its business model since its inception and the Group remains focused on driving innovative and collaborative ways of operating to deliver cost savings across its business. While that quantum of reduction in operating costs cannot be repeated, a focus on improving costs and driving efficiencies is a fundamental requirement in ensuring EnQuest is able to deliver profitable growth over the long term.
The opportunity for long-term growth in the North Sea is clear: The UK Oil & Gas Authority recently announced they expect 11.7 billion barrels of oil and gas to be produced from the UK Continental Shelf ('UKCS') over the period 2016 to 2050, an increase of 2.8 billion barrels of oil and gas from that previously forecast; and the UK Department for Business, Energy & Industrial Strategy forecasts oil and gas will still be supplying around two-thirds of domestic energy demand by 2035, confirming their place as vital sources of energy supply.
EnQuest is supportive of the UK Government's proposals to introduce a mechanism to transfer tax history on the sale and purchase of North Sea oil assets. We welcome the removal of a potential tax barrier to the conclusion of deals. EnQuest has demonstrated the dramatic and positive impact on production, production efficiency and field life which can be achieved when assets move into the right hands. If implemented in the right way, these measures will be another positive step by the Government in supporting the strategy for Maximising Economic Recovery for the UK.
The UKCS remains a compelling basin in which to invest. It has exciting hydrocarbon opportunities, established infrastructure, access to a world-class supply chain and a highly skilled workforce, all supported by a globally competitive fiscal regime. A similar investment proposition continues to prevail in Malaysia, where the Group has a strong partnership with PETRONAS. These opportunities provide EnQuest with long-term potential for growth.
The EnQuest Board
With the Board's focus on succession planning, and after rigorous search processes, I was delighted to welcome three new Non-Executive Directors to the Company since the start of 2017: Carl Hughes joined the Board on 1 January 2017, having previously been an energy and resources audit partner of Deloitte; John Winterman, who has extensive leadership experience in global exploration, business development and asset management, was appointed on
7 September 2017; and Laurie Fitch, who has worked in a variety of investment and corporate finance roles, joined us on 8 January 2018. All three bring considerable and varied expertise to the Company and I look forward to working with them.
In July 2017, Dr Philip Nolan stepped down from his role as Non-Executive Director, having joined the Board in 2012.
I thank Philip for his valuable contribution to the Company, especially in its development over the past five years.
I would also like to thank Neil McCulloch, who stepped down as Chief Operating Officer and Executive Director in December 2017, for his unstinting contribution to EnQuest during a challenging period for both the Company and industry.
EnQuest's people
In 2017, the Group remained focused on positioning the business for the prevailing oil price environment, whilst at the same time ensuring it continued to achieve its operational targets. Management of matters pertaining to the Kraken and Magnus projects required significant amounts of the Board and management's time and attention, while compliance with debt covenants and review of liquidity options also remained a priority. The Group's achievements against these objectives have only been possible due to EnQuest's people. The Board and I would like to express our gratitude to everyone at EnQuest for having continued to work with such energy and dedication to address the challenges presented in recent years, ensuring that EnQuest can move forward, to create further value from opportunities in maturing oil fields.
The Board and I would also like to take this opportunity to thank all those who worked on the acquisition of assets from BP, and extend a particularly warm welcome to our new colleagues and contractor workforce who joined EnQuest as a result.
Strategy and governance
The Directors provide strategic guidance to executive management and take key decisions on the implementation of the Group's strategy. During 2017, the Board reviewed and refined the presentation of the Company's purpose, vision, strategy and business model. In addition, a number of 'tenets' were developed to guide the Company's pursuit of its strategy in accordance with the Group's appetite for risk and within its Risk Management Framework.
Ensuring that the Board works effectively remains a key focus of the Company. 2017 saw the Risk Committee, established in 2016, fully embedded into the governance structure of the Company. The primary purpose of the Risk Committee is to provide a forum for in-depth examination of non-financial risk areas. EnQuest's governance framework also contains several non-Board Committees, which provide advice and support to the Chief Executive, including an Executive Committee, Operations Committee and Investment Committee.
The Board believes that the manner in which it conducts its business is important and it is committed to delivering the highest standards of corporate governance for the benefit of all of its stakeholders. The Board has approved the Company's overall approach to corporate responsibility, which is focused on five main areas. These are Health and Safety, People, Environment, Business Conduct and Community.
The Board receives regular information on the performance of the Company in these areas, and specifically monitors health and safety and environmental reporting at each Board meeting. The Company's Health, Safety, Environment & Assurance ('HSE&A') Policy is reviewed by the Board annually and all incidents, forward-looking indicators and significant HSE&A programmes are discussed by the Board. Specific developments and updates in all areas are brought to the Board's attention when appropriate.
The Group has a Code of Conduct that it requires all personnel to be familiar with as it sets out the behaviour which the organisation expects of its Directors, managers and employees, and of our suppliers, contractors, agents and partners. This year, it has been updated with guidance on preventing the facilitation of tax avoidance.
EnQuest's company values underpin a working environment where people are safe, creative and passionate, with a relentless focus on results. Inductions for all employees transferring from BP were run in September to ensure that all those impacted understood the EnQuest business, how we work and how they can contribute to EnQuest's success. Alongside this, time was invested to understand the culture of our business through an online survey and subsequent focus groups. Following a review of the results from these activities, the Executive Committee is working on identifying the next steps to develop the culture and ensure that EnQuest is an attractive place to work.
Dividend
The Company has not declared or paid any dividends since incorporation and does not plan to pay dividends in the near future. Any future payment of dividends is expected to depend on the earnings and financial condition of the Company meeting the conditions for dividend payments which the Company has agreed with its lenders and such other factors as the Board of Directors of the Company considers appropriate.
2018: A new chapter
In 2018, EnQuest is entering a new phase. Kraken is progressing well, the Magnus integration and drilling programmes are well underway, plans are being developed to enhance performance at our other producing assets, and the period of heavy capital investment is largely behind us. These material advances should result in EnQuest generating positive net cash flow after investment and tax, allowing us to continue to manage our capital structure and liquidity position. Despite the current improvement in the near term oil price environment, we recognise we must maintain our focus on financial discipline, cost efficiencies and managing Group liquidity. Consequently, it is important that we prioritise our resources to those key projects which maximise cash flow to facilitate debt reduction, continuing the Company's progress towards a more sustainable balance sheet and enabling the long-term growth of the business.
Chief Executive's report
EnQuest's priorities and performance in 2017
2017 was a transformational year for EnQuest, positioning the Group for profitable growth and transitioning from a period of heavy capital investment to one in which the Group can begin to reduce its debt. The Group focused on the Kraken development, completion of the asset acquisitions from BP, delivery against our financial and operational targets and the effective management of the Group's financial position.
Operational performance
EnQuest was proud to deliver first oil from Kraken on schedule while significantly reducing full cycle gross capital expenditure. Kraken is one of the largest developments in the North Sea in the last ten years, comprising a phased drilling campaign of 25 wells tied back to a complex new Floating Production, Storage and Offloading ('FPSO') vessel. The drilling performance has been excellent, with the first three programmes completed early and at a lower cost than originally planned. The FPSO has taken longer than expected to commission, leading to lower operational efficiency than planned. A systematic process to resolve these issues has improved uptime and, with the reservoir performing in line with expectations, production increased throughout 2017 and into 2018.
On 1 December 2017, EnQuest completed the acquisition of initial interests in Magnus, SVT and associated infrastructure from BP and assumed operatorship. This large and complex transition was achieved safely and efficiently, delivered on time and on budget, with the integration of these assets into the EnQuest business progressing well.
EnQuest's average production of 37,405 Boepd reflected Electrical Submersible Pump ('ESP') performance issues at Alma/Galia and lower than planned production from both Kraken and Scolty/Crathes. Overall the Group's production performance was disappointing and led to EnQuest reducing its 2017 production guidance in August last year. However, the combination of improving performance at Kraken, planned drilling and workover campaigns at a number of assets and a full year's contribution from Magnus underpins EnQuest's expectation of material production growth in 2018.
Net 2P reserves of 210 MMboe at the end of 2017 represented a 2.4% decrease on the 215 MMboe at the end of 2016. This small decline reflects some changes in long-term assumptions, combined with lower production performance in the North Sea, partially offset by the Magnus acquisition related increase and better performance in Malaysia. When EnQuest was formed in 2010, it had 81 MMboe of reserves. Our ability to exploit, develop, convert and selectively acquire or dispose of reserves has meant that by the end of 2017, EnQuest had produced almost the entirety of this initial reserve base, and still has 2P reserves with a current production life of around 17 years.
Financial performance
The Group's focus on financial discipline resulted in total operating expenditures of $349.3 million, unit opex of $25.6/Boe and cash capital expenditure of $367.6 million. While it is becoming more challenging to deliver the large decreases in operating costs of recent years, the Group will continue to pursue further operating cost reduction initiatives.
EBITDA of $303.6 million was materially lower than 2016. This reduction was driven by lower realised prices, which reflected the forward prices available at the time at which the commodity hedge programme was implemented, combined with lower production. The commodity hedge programme resulted in realised losses of $20.6 million in 2017 compared to realised gains of $255.8 million in 2016.
EnQuest's ongoing programme of prudent measures to improve liquidity included the completion of an $80 million oil prepayment transaction and execution of a $37.25 million refinancing agreement in relation to its Tanjong Baram project, which completed in February 2018. Combined, this provides over $100 million of additional financial resources. EnQuest continued its close dialogue with its lending banks, agreeing a relaxation of the Company's covenants and amending the amortisation schedule of its Term Loan and Revolving Credit Facility; these changes provided additional flexibility while Kraken continued to increase production rates. EnQuest finished the year with net debt of
$1,900.9 million, excluding Payment in Kind interest.
Health, Safety, Environment and Assurance ('HSE&A')
EnQuest delivered on its commitment to continual improvement in HSE&A performance, achieving good year-on-year improvement in 2017 with excellent results in many areas and meeting the majority of our performance targets.
In occupational safety, our Lost Time Incident ('LTI') performance remained strong in both Malaysia and the UK, with many assets recording an LTI-free year. We had no reportable hydrocarbon releases during 2017 on our UK operated assets having increased our focus on asset integrity and implemented hydrocarbon prevention plans across our sites. Our drive for operational excellence saw continued focus in the UK on coaching our workforce to identify and understand control of Major Accident Hazards ('MAH'), embedding our life saving rules and transitioning to a new control of work tool which enhances both system and behavioural compliance. In March, members of the Board visited a contractor's emergency response centre to help benchmark and refine EnQuest's own emergency response and crisis management plans.
EnQuest's focus on HSE&A is always a priority. Under our continual improvement programme, activities in 2018 focus further on control of MAH and developing and empowering employees to deliver safe results.
North Sea operations
In December, Faysal Hamza and Bob Davenport took over management of EnQuest's North Sea operations as Interim Head of North Sea and Managing Director, North Sea respectively.
Production in 2017 from the North Sea averaged 28,467 Boepd, down 7.0% compared to 2016. This reduction was driven by lower volumes from Alma/Galia reflecting ESP related well shut-ins, storm-related production outages and natural declines. Production at other assets was also reduced by lower water injection, natural declines and an unscheduled shutdown in December of the third-party operated Forties Pipeline.
Partially offsetting this decline was production from Kraken, a full year of production from Scolty/Crathes, limited by wax in the flowline, and the initial contribution from Magnus. Various production enhancement activities were successfully undertaken during the year, improving performance at a number of fields by year end.
The Kraken development
Following first oil on 23 June 2017, production increased throughout the second half of the year as both production and injection wells performed in line with expectations and the commissioning and operational efficiency issues, encountered during the initial production build up, were addressed. The second processing train, which was brought online during November, assisted in bringing gross production rates to over 40,000 Bopd. All production and water injection wells from the first three drill centres ('DCs') have been brought online and operational efficiency has significantly improved. Whilst production has been constrained, FPSO charter rates have been reduced in accordance with production levels. We continue to work with the operator to maximise production from Kraken.
The combination of excellent delivery of the DC3 drilling programme, lower market rates for the remaining subsea campaign and the renegotiation of the drilling rig contract with Transocean has resulted in significant reductions to the full cycle gross project capital expenditure, which is now expected to be c.$2.3 billion. This is more than 25% lower than originally sanctioned.
Magnus and Sullom Voe Oil Terminal
The acquisition is a good strategic and operational fit for EnQuest, providing opportunities for synergies and growth. We invest safely to realise value from opportunities presented in maturing assets, applying our differential capabilities to deliver high levels of production efficiency, asset life extension and cost control. The transaction is aligned with the UK's strategy of Maximising Economic Recovery by getting the right assets into the right hands. Magnus is a good quality reservoir with large volumes in place, providing opportunities for infill drilling and the revitalisation of wells. BP's confidence in EnQuest taking over operatorship underlines EnQuest's capabilities as an asset life extension expert.
Malaysia operations
Production in 2017 was broadly in line with 2016 at 8,938 Boepd, reflecting good operational uptime across PM8/Seligi and Tanjong Baram and the execution of key work scopes, such as the compression reliability improvement and well interventions at PM8/Seligi. Given the natural decline rates of these mature fields, this performance is testament to the team's capabilities in maximising hydrocarbon recovery in advance of the Group's first drilling campaign in PM8/Seligi, planned for 2018.
2018 performance and outlook
The Group expects material production growth in 2018 to between 50,000 and 58,000 Boepd, largely driven by performance at Kraken and a full year's contribution from Magnus, partially offset by natural declines elsewhere in the portfolio. Production performance in the first two months of 2018 was strong across the portfolio, with Kraken gross production averaging around 38,000 Bopd in this period. Extreme cold weather in early March resulted in brief shutdowns at a number of the Group's North Sea fields. While Kraken was shut down, the Group has undertaken much of the workscope previously scheduled for the planned shutdown in April and, as a result, this planned shutdown is no longer required. The Group continues to have planned maintenance shutdowns at a number of the Group's fields, including Kraken, in the third quarter. During 2018, EnQuest expects to drill three wells at Magnus and two wells at PM8/Seligi which, along with the workover programme at Alma/Galia, should result in an improved production performance later in the year, with the DC4 programme expected to come onstream in 2019, sustaining Kraken production.
Unit opex is expected to be approximately $24/Boe. Cash capital expenditure is expected to be lower than 2017 at approximately $250 million and primarily relates to drilling campaigns at Kraken, Heather and PM8/Seligi.
With production growing, a strong focus on cost control and a substantially reduced cash capital expenditure programme, the Group should generate positive net cash flow which will enable it to start reducing debt.
In January 2018, EnQuest received $30 million in cash in exchange for agreeing to undertake the management of the physical decommissioning at Thistle and Deveron and being liable to make payments to BP by reference to 3.7% of the gross decommissioning costs of these assets.
Future growth opportunities
With Kraken delivering and the Group transitioning from a period of heavy investment, our focus is now turning towards the next stage of EnQuest's development. The Group has significant potential within the existing portfolio, in particular at Magnus, PM8/Seligi and, in the longer term, Kraken. Each of these fields has substantial reserves and resources in place and with EnQuest's proven capabilities in enhancing hydrocarbon recovery from mature and underdeveloped assets, the Group is well placed to deliver long-term sustainable growth.
Operating review
North Sea operations overview
EnQuest delivered some notable achievements during the year, particularly the delivery of first oil from Kraken on schedule and completing the acquisition of initial interests in the Magnus oil field, the Sullom Voe Oil Terminal ('SVT') and associated infrastructure assets from BP.
Kraken is a landmark heavy oil development project, one of the largest developments in the North Sea in the last ten years. The drilling performance has been excellent, with programmes completed early and at a lower cost than originally planned. Although there were some initial issues with a prolonged commissioning of the Floating Production, Storage and Offloading vessel leading to lower operational efficiency, substantial progress has since been made and performance continues to improve.
On 1 December 2017, EnQuest completed the acquisition of assets from BP. Following a period of extensive preparation, the assets and operations were transitioned safely and smoothly to EnQuest and the integration programme is now well underway. Both assets offer excellent opportunities for EnQuest and the wider industry and are in the spirit of Maximising Economic Recovery in the UK Continental Shelf. Magnus is a good operational fit and is close to EnQuest's existing operated assets in the Northern North Sea. It has high quality reservoirs with significant future opportunities. EnQuest is drilling three wells in 2018 to deliver increased volumes. At SVT, approximately
one-third of the Group's North Sea production flows through the terminal. As such, it has the potential to play an important role in EnQuest's future growth.
The Group's North Sea production declined to 28,467 Boepd, down 7.0% on 2016. Underperformance at Alma/Galia and natural declines elsewhere were partially offset by a full year's contribution from Scolty/Crathes and initial contributions from Kraken and Magnus.
A focus on cost control and commercial agreements resulted in operating costs being in line with the Company's expectations. Such financial discipline is an essential part of the way in which EnQuest does business. Unit operating costs have reduced significantly from historical levels, particularly when the price of oil was above $100/bbl, but the Group recognises the need to continue to work on delivering further cost efficiencies.
Northern North Sea operations
Daily average net production:
- 2017: 15,627 Boepd* - 2016: 18,885 Boepd
* Includes net production from Magnus since the acquisition on 1 December 2017, averaged over the 12 months to the end of December 2017.
2017 performance summary
Production in 2017 of 15,627 Boepd was 17.3% lower than 2016. This reduction was primarily driven by lower water injection at Heather/Broom and Thistle/Deveron, combined with natural declines at these and the Dons fields. Production efficiency at Heather/Broom and the Dons fields was very good, and the contribution from Magnus also helped mitigate the reduced production.
During the year, work programmes to improve the reliability of water injection on Heather/Broom, Thistle/Deveron and the Dons were successful, delivering improved performance by year end. Water injection was reinstated at the Dons in December 2017 following the replacement of the water injection pipelines. On Thistle, work was undertaken to improve the reliability of water injection and shut off areas of the reservoir in which high volumes of water were being produced. The resulting improved water injection performance significantly increased reservoir pressure. Shutting off some water production from four wells that produced high levels of water increased oil production by around a thousand barrels per day, doubling the target uplift from this work scope. When combined with better plant uptime, these programmes enabled Thistle production rates to finish the year strongly.
Reservoir performance and production were above expectations at Don Southwest, with production improving chemical treatments completed at West Don and Don Southwest.
Average gross production of c.16,000 Boepd from Magnus during the full year 2017 was similar to 2016; a good result during this intensive period of preparation for transition. Upon completion of the acquisition on 1 December 2017, EnQuest became duty holder and operator.
As part of EnQuest's asset life extension strategy, a series of idle well reservoir abandonments were successfully undertaken at Thistle and Heather to reduce integrity risks and provide opportunities for future drilling of infill wells. The abandonment programme on Heather partially abandoned legacy wells which should safeguard sustained high water injection reservoir efficiency. The programme was well executed, delivered ahead of schedule and under budget. This allowed the team to include an additional well within the programme cost estimate. These programmes, co-funded by EnQuest's partners, demonstrate EnQuest's ability to execute low-cost well work and is an important new component of the strategy to extend the lives of these fields, benefiting all stakeholders in these fields.
Asset data and 2018 work programme
Thistle/Deveron
-- Working interest at end 2017: 99%
-- Decommissioning related costs: 3.7% (as defined below)(1)
-- Fixed steel platform
(1) EnQuest is liable for the decommissioning costs associated with investment since it assumed operatorship, with the balance remaining with the former owners. Following the exercise of the Thistle decommissioning option in January 2018, EnQuest will undertake the management of the physical decommissioning of Thistle and Deveron and is liable to make payments to BP by reference to 3.7% of the gross decommissioning costs of Thistle and Deveron. EnQuest has an outstanding option to receive $20 million in cash in exchange for making payments by reference to a further 2.4% of the gross decommissioning costs of the Thistle and Deveron fields.
2018 and beyond
A shutdown is planned in Q3, the timing of which is driven by the third-party shutdown of the Cormorant Alpha pipeline, which is Thistle's oil export route. EnQuest will co-ordinate this shutdown with its own planned programme of maintenance work on Thistle.
The well abandonment programme is continuing in 2018.
The Dons fields
-- Working interest at end 2017:
- Don Southwest 60% - Conrie 60% - West Don 78.6% - Ythan 60%
-- Decommissioning liabilities: As per working interests
-- Floating production unit with subsea wells
2018 and beyond
A shutdown is planned in Q3, the timing of which is driven by the third-party shutdown of the Cormorant Alpha pipeline, which is the Dons' oil export route. EnQuest will co-ordinate this shutdown with its own planned programme of maintenance work on the Dons.
A water injection optimisation programme will be undertaken during 2018.
Heather/Broom
-- Working interest at end 2017:
- Heather 100% - Broom 63%
-- Decommissioning liabilities:
- Heather 37.5% - Broom 63%
-- Fixed steel platform
2018 and beyond
Additional drilling is taking place on Heather. The H-67 sidetrack was completed in March following initial spud in January, while further well abandonments will take place later in the year.
A maintenance shutdown is planned in Q2.
Magnus
-- Working interest at end 2017: 25%
-- Decommissioning related costs: 7.5% (as defined below)(1)
-- Fixed steel platform
(1) BP has retained the decommissioning liability in respect of the existing Magnus wells and infrastructure. EnQuest will pay BP additional deferred consideration by reference to 7.5% of BP's actual decommissioning costs on an after-tax basis. The additional consideration payable is capped at the amount of cumulative positive cash flows received by EnQuest from Magnus, SVT and the associated infrastructure assets.
2018 and beyond
The post-acquisition integration programme will continue into 2018, ensuring the team understands the Group's culture, processes and controls, and how the team can contribute to EnQuest's success.
Following an upgrade of the drilling rig, the 2018 drilling programme includes a well intervention plan (logging and potentially also perforations) then two production wells and one injection well set to come onstream during 2018. In early Q1, the first wireline intervention was successfully completed, prior to the spudding of the first new sidetrack well.
New production efficiency enhancement opportunities are also being assessed.
Sullom Voe Oil Terminal
A strategic infrastructure hub
SVT was commissioned in 1978 and receives East of Shetland ('EoS') oil via the Brent Pipeline System, which services Brent, Thistle, Northern Producer, Alwyn and TENCCA, and the Ninian Pipeline System, which services Ninian, Magnus and Heather. Since 1998, the terminal has also provided services to West of Shetland ('WoS') fields, including Schiehallion, Clair and Foinaven. Gas from these three fields is 'sweetened' at SVT before being shipped to Magnus, for Enhanced Oil Recovery and onward export. The terminal also now processes condensate from the Laggan-Tormore development.
Following the safe and efficient transfer of operatorship to EnQuest on 1 December 2017, steady operations have continued.
Building on the work that BP as operator and EnQuest and other owners have undertaken in recent years, EnQuest is targeting cost improvements and exploring terminal life extension opportunities which could benefit wider Northern North Sea and WoS operations.
Central North Sea operations
Daily average net production:
- 2017: 8,131 Boepd - 2016: 11,718 Boepd*
* Includes net production from Scolty/Crathes since first oil on 21 November 2016, averaged over the 12 months to the end of December 2016.
2017 performance summary
Production in 2017 of 8,131 Boepd was 30.6% lower than 2016. This reduction was primarily driven by lower volumes at Alma/Galia reflecting Electric Submersible Pump ('ESP') related well shut-ins, storm-related production outages and natural declines. Field performance improved in the second half of the year following completion of the optimisation projects for power, produced water and sea water injection.
Good production has been delivered from the Greater Kittiwake Area ('GKA'), with high levels of plant uptime and production efficiency. The GKA work programme was focused on optimising production across the assets, including replacement of the Mallard/Gadwall water injection flowline and the E gas compressor crank shaft. The GKA team delivered a good HSE&A performance and was proud to have delivered 12 years of operations without an LTI.
In line with previous updates, the full year contribution from Scolty/Crathes was limited due to wax in the flowline. These wax issues continue to be managed with chemical and lift gas treatments. Full year production uptime has been very high with the reservoir performing well. The unscheduled shutdown in December of the third-party operated Forties Pipeline resulted in the GKA and Scolty/Crathes fields being shut down for approximately three weeks, during which time opportunistic maintenance work was undertaken.
Asset data and 2018 work programme
Greater Kittiwake Area ('GKA')
-- Working interest at end 2017 of 50% in each of:
- Kittiwake - Grouse - Mallard - Gadwall - Goosander
-- Decommissioning liabilities:
- Kittiwake 25% - Mallard 30.5% - Grouse, Gadwall and Goosander 50%
-- Fixed steel platform
-- 100% interest in export pipeline from GKA to Forties Unity platform
2018 and beyond
A maintenance shutdown is scheduled for Q3 2018. The work programme includes the installation of a new gas compressor.
Evaluation of the potential from the Eagle discovery (100% EnQuest) is ongoing, with the licence having been extended in early 2018.
Scolty/Crathes
-- Working interest at end 2017 of 50% in each of:
- Scolty - Crathes
-- Decommissioning liabilities: As per working interests
-- Tied back to the Kittiwake platform
2018 and beyond
A maintenance shutdown is scheduled for Q3 2018. EnQuest continues to undertake technical work with its partners in developing a permanent solution to debottleneck production in 2019.
Alma/Galia
-- Working interest at end 2017:
- 65% in both fields
-- Decommissioning liabilities: As per working interest
-- Floating Production, Storage and Offloading unit ('FPSO') with subsea wells
2018 and beyond
A well workover campaign is scheduled for the summer of 2018, aiming to increase production levels by replacing three failed ESPs.
Alba (non-operated)
The Alba oil field is operated by Chevron.
-- Working interest at end 2017: 8%
-- Decommissioning liabilities: As per working interest
-- Fixed steel platform
The Kraken development
-- Daily average net production:
- 2017: 4,709 Boepd(2) - 2016: N/A
(2) Net production since first oil on 23 June, averaged over the 12 months to the end of December 2017.
2017 performance summary
The Kraken FPSO arrived in the North Sea in early January and was on-station and securely moored by mid-February, with first oil delivered on 23 June 2017. The four wells from the first drill centre ('DC') and the three wells from DC2 produced at initial gross rates above expectations and with stabilised flow rates which confirmed the field development plan. Water injection wells performed in line with expectations.
During the period after first oil, prolonged commissioning of the complex Kraken FPSO vessel led to lower than expected production efficiency and to initial production volumes being lower than expected. EnQuest continued with its plan of bringing wells onstream in a phased manner, in line with good reservoir management practices aimed at maximising long-term productivity and value. The second processing train, which was brought online during November, assisted in bringing gross production rates to over 40,000 Bopd. Since late December, all DC3 wells have been brought online and operational uptime has improved.
Following the excellent delivery of the DC3 drilling programme and lower market rates for the remaining subsea campaign, full cycle gross Kraken project capital expenditure was further reduced during 2017.
Cargo offloads started in September and one was successfully completed in each subsequent month. The quality of the crude has been well received by buyers. By as early as November, a sale of cargo had been contracted at a discount to Brent of less than $5/bbl, this level of pricing being achieved earlier than targeted.
Asset data and 2018 work programme
-- Working interest at end 2017: 70.5%.
-- Decommissioning liabilities: As per working interest
-- Floating Production, Storage and Offloading ('FPSO') unit with subsea wells
2018 and beyond
Average gross production for the first two months of 2018 was around 38,000 Bopd, and has reached the targeted 50,000 Bopd, with improving production efficiency as we continue to optimise performance. The DC4 well campaign, which was not anticipated to impact 2018 production, is expected to commence in the second half of 2018, coming onstream in 2019 to sustain production.
Extreme cold weather in early March resulted in Kraken being shut down. During this period, the Group has undertaken much of the previously planned April shutdown workscope and, as a result, this planned shutdown is no longer required. EnQuest continues to have a summer shutdown planned for one week in September.
In early 2018, EnQuest agreed renegotiated terms with Transocean for the Transocean Leader drilling rig, reducing both the contract duration and the day rates, saving c.$60 million of net cash payments for capital expenditure in 2019. Full cycle gross project capital expenditure has been reduced by approximately $100 million and is now expected to be c.$2.3 billion, more than 25% lower than originally sanctioned.
Malaysian operations
-- Daily average net production:
- 2017: 8,937 Boepd (working interest): 5,884 Boepd (entitlement) - 2016: 9,148 Boepd (working interest): 6,426 Boepd (entitlement)
2017 performance summary
At PM8/Seligi, EnQuest continued to enhance production by investing in low-cost well interventions and facility projects to improve production efficiency, including gas compression package major overhauls, well test improvements with Multi-Phase Flow Meters and process simplifications to improve overall reliability. In addition, robust maintenance and integrity inspection campaigns of platform structures, topsides and subsea pipelines continued to ensure safe operations.
During 2017, the first new drilling projects were defined for execution in 2018, and significant progress was made on rebuilding of static and dynamic reservoir simulation models in support of longer-term field redevelopment. At Tanjong Baram, the focus remained on steady, safe and low-cost operations with high levels of production efficiency and uptime throughout the year.
Asset data and 2018 work programme
PM8/Seligi
-- Working interest at end 2017: 50%
-- Decommissioning liabilities:
- PM8 50%
- Seligi 50% of partial liability allocated based on ratio of remaining oil reserves and to estimated ultimate recovery
In addition to the main production platform and separate gas compression platform, there are 11 minimum facility satellite platforms tied back to the main platform.
2018 and beyond
EnQuest will commence its first drilling campaign with two PM8/Seligi commitment wells (appraisal and development) to be drilled around the middle of 2018, with first production in Q3. Idle well restoration and surveillance campaigns are planned for Q2 and Q3.
A maintenance shutdown is scheduled in Q3.
Longer term, EnQuest will extend field life through further investment in idle well restoration, facility improvements and upgrades and technical studies supporting development drilling and secondary recovery projects to increase ultimate recovery.
Tanjong Baram
-- Working interest at end 2017: 70%
-- Decommissioning liabilities: None
2018 and beyond
Maintenance shutdowns are scheduled in Q1 and Q3.
Financial review
(all figures quoted are in US Dollars and relate to Business performance unless otherwise stated)
Financial overview
EnQuest has continued to focus on project execution and financial discipline. The Company delivered first oil from the Kraken development in June 2017 and completed the acquisition of initial interests in the Magnus oil field and Sullom Voe Oil Terminal ('SVT') through an innovatively structured transaction in December. EnQuest also continues to focus on cost control and cash management, and as operating cash flows grow and capital expenditure reduces, this should facilitate reductions in debt. These key milestones, along with the effective management of the Group's liquidity position, continue to ensure that the Company is well placed to deliver value to stakeholders in the medium and long term.
Production on a working interest basis decreased by 5.9% to 37,405 Boepd, compared to 39,751 Boepd in 2016. Lower production at Alma/Galia and natural declines at the Group's other North Sea fields were partially offset by production from Kraken and a full year of production from Scolty/Crathes, which came onstream in November 2016.
Total revenue for 2017 was $635.2 million, 25.2% lower than 2016 ($849.6 million). This was as a result of lower realised oil prices, reflecting the forward prices available at the time at which the commodity hedge programme was implemented, combined with lower production. The commodity hedge programme resulted in realised losses of
$20.6 million in 2017 compared to realised gains of $255.8 million in 2016.
The Group's operating expenditures of $349.3 million were 2.3% lower than 2016 ($357.4 million), but unit operating costs increased by 4.0% to $25.6/Boe as a result of lower production.
Business performance
-----------------------
2017 2016
$ million $ million
Profit from operations before tax and finance income/(costs) 47.3 237.1
Depletion and depreciation 227.6 244.6
Net foreign exchange (gain)/loss 23.9 (51.9)
Realised (gain)/loss on FX derivatives related to capital expenditure(1) 4.8 47.3
EBITDA 303.6 477.1
----------- ----------
(1) Realised (gain)/loss on FX derivatives are recorded within cost of sales. Where the derivative
hedges capital expenditure, the (gain)/loss is added back when calculating EBITDA in order
to reflect the underlying result of operating activities.
EBITDA for 2017 was $303.6 million, down 36.4% compared to 2016 ($477.1 million), primarily as a result of lower revenue.
Business performance loss after tax for 2017 was $33.6 million (2016: profit of $121.5 million). After re-measurements and exceptional items, the Group recorded a net loss of $60.8 million (2016: net profit of $185.2 million).
Reflecting the ongoing investments EnQuest has made to develop its assets, notably Kraken, EnQuest's net debt increased from $1,796.5 million at the end of 2016 to $1,991.4 million at 31 December 2017. This includes $90.5 million of interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing ('PIK').
Net debt/(cash)
--------------------------
31 December 31 December
2017 2016
$ million $ million
Bonds(1) 944.9 868.7
Multi-currency Revolving Credit Facility(1) ('RCF') 1,100.0 1,037.5
Tanjong Baram Project Finance Facility(1) 8.5 24.9
Mercuria Prepayment Facility 75.5 -
SVT Working Capital Facility 25.6 -
Other loans(1) 10.0 40.0
Cash and cash equivalents (173.1) (174.6)
Net debt 1,991.4 1,796.5
============ ============
(1) Stated excluding accrued interest and excluding the net-off of unamortised fees (refer to note 19 of the consolidated financial statements).
There are no significant debt maturities until October 2018, when a single amortisation of the RCF of $270 million is due.
As at 31 December 2017, total cash and available facilities totalled $244.4 million, excluding $26.5 million of cash from the ring fenced working capital facility associated with SVT (2016: $330.9 million excluding $nil cash from the ring fenced SVT working capital facility).
UK corporate tax losses at the end of the year increased to $3,121.3 million. In the current environment, no material corporation tax or supplementary corporation tax is expected to be paid on UK operational activities for the foreseeable future. The Group paid cash corporate income tax on the Malaysian assets which will continue throughout the life of the Production Sharing Contract.
Income statement
Production and revenue
Net working interest production of 37,405 Boepd was 5.9% lower than 2016 (39,751 Boepd). This reduction primarily reflects the impact of ESP performance issues at Alma/Galia, natural declines in the Group's assets where there has been no recent drilling, partially offset by the impact of commencement of production at Kraken in June 2017 and a full year of production from Scolty/Crathes, which achieved first oil in November 2016.
On average, market prices for crude oil in 2017 were higher than in 2016. The Group's blended average realised oil price excluding the impacts of hedging was $53.9/bbl for 2017, 21.8% higher than 2016 ($44.3/bbl). Revenue is predominantly derived from crude oil sales and for 2017, crude oil sales totalled $637.0 million, 10.2% higher than 2016 ($577.8 million). The increase in revenue reflected higher market prices for crude oil, partially offset by lower production. Revenue from the sale of condensate and gas was $2.8 million (2016: $3.6 million) while tariffs and other income generated $16.0 million (2016: $12.4 million).
The Group's commodity hedges and other oil derivatives generated $20.6 million of realised losses (2016 income: $255.8 million), including $10.4 million of non-cash amortisation of option premiums (2016: $31.2 million).
Cost of sales
Business performance
-----------------------
2017 2016
$ million $ million
Production costs 287.1 279.7
Tariff and transportation expenses 62.2 58.1
Realised (gain)/loss on FX derivatives related to operating costs - 19.6
----------- ----------
Operating costs 349.3 357.4
Realised (gain)/loss on FX derivatives related to capital expenditure 4.8 47.3
Credit/(charge) relating to the Group's lifting position and inventory (20.4) 2.8
Depletion of oil and gas assets 223.1 240.6
Other cost of sales 12.7 5.4
----------- ----------
Cost of sales 569.5 653.5
----------- ----------
Operating cost per barrel(1) $/Boe $/Boe
-Production costs 21.0 20.4
-Tariff and transportation expenses 4.6 4.2
25.6 24.6
----------- ----------
(1) Calculated on a working interest basis.
Cost of sales were $569.5 million for the year ended 31 December 2017, 12.9% lower than 2016 ($653.5 million). Operating costs decreased by $8.1 million, reflecting the benefit of a weaker Sterling exchange rate and net lease charter payment credits of $19.5 million arising from the non-availability of the Kraken FPSO, partially offset by a full year of operations at Scolty/Crathes. The Group's average unit operating cost has increased by 4.0% to $25.6/Boe, primarily due to the 5.9% reduction in production volumes.
At 31 December 2017, the Group had moved to a net underlift position compared to the prior year end net overlift position, resulting in a $20.4 million credit to cost of sales (2016: charge of $2.8 million). The Group's change in lifting position and inventory reflected the unwind of the overlift balance that had accrued at 31 December 2016, primarily on Thistle and GKA, partially offset by the unwind of underlift at Alma/Galia and the build up of an overlift at Scolty/Crathes.
Depletion expense of $223.1 million was 7.3% lower than 2016 ($240.6 million), reflecting lower production in 2017. The average unit depletion rate decreased slightly from $16.6/Boe to $16.3/Boe.
Other cost of sales of $12.7 million were higher than 2016 ($5.4 million), principally driven by the impact of higher oil prices on the supplemental payment due on profit oil in Malaysia.
General and administrative expenses
General and administrative expenses were $0.8 million (2016: $10.9 million), reflecting the Group's ongoing efforts to reduce costs across the organisation.
Other income and expenses
Net other expenses of $17.6 million (2016: income of $51.9 million) primarily comprises net foreign exchange losses, which relate to the revaluation of Sterling denominated amounts in the balance sheet following the strengthening of Sterling against the US Dollar, offset by one-off general and administration recovery impacts. The prior year income comprised almost entirely of net foreign exchange gains.
Finance costs
Finance costs of $149.0 million were 21.9% higher than 2016 ($122.2 million). The charges include $137.9 million of bond and loan interest payable (2016: $110.5 million), $13.5 million unwinding of discount on provisions and liabilities, largely in respect of decommissioning (2016: $14.2 million), $2.8 million amortisation of arrangement fees for the bank facilities and bonds (2016: $5.9 million) and other financial expenses of $5.9 million (2016: $10.5 million), primarily commitment and letter of credit fees.
The Group capitalised interest of $42.3 million in 2017 in relation to the interest payable on borrowing costs on its capital development projects, primarily the Kraken development (2016: $55.3 million).
In June 2017, in line with first oil from Kraken, the Group's lease for the FPSO vessel from Armada Kraken PTE Limited ('BUMI') commenced. Finance lease interest of $31.3 million has been recognised within finance costs. In 2016, $36.5 million of finance costs related to the amortisation of put option premium related to the Group's oil hedge portfolio were recognised. No corresponding charge existed in 2017 as no put options had been used to hedge 2017 production.
Finance income
Finance income of $2.2 million (2016: $1.4 million) includes $1.8 million from the unwind of the discount on financial assets (2016: $1.0 million) and $0.4 million of bank interest receivable (2016: $0.3 million).
Taxation
The tax credit for 2017 of $66.0 million (2016: $5.2 million tax credit), excluding exceptional items, is mainly due to the Ring Fence Expenditure Supplement ('RFES') on UK activities.
Remeasurement and exceptional items
Revenue included unrealised losses of $7.7 million in respect of the mark to market movement on the Group's commodity contracts (2016: unrealised loss of $51.5 million).
Non-cash impairment charge on the Group's oil and gas assets arising from changes in assumptions combined with lower production performance in the North Sea totalled $172.0 million (2016: reversal of non-cash impairment of $147.9 million).
Other income and expense included the recognition of the accounting for the excess of fair value over consideration of $16.1 million associated with the Thistle decommissioning option and $10.3 million associated with the accounting impact of the acquisition of initial interests in assets from BP and the related discounted purchase option valuation of $22.3 million (see note 29). Other items include a $1.3 million gain from the disposal of Ascent Resources loan notes, a $10.3 million charge arising from a cost recovery settlement in Malaysia, a $6.4 million charge arising from the cancellation of contracts and a $2.8 million provision in relation to restricted cash.
A tax credit of $117.0 million (2016: charge of $37.3 million) has been presented as exceptional, representing the tax impact of the above items, together with a net write-back of $47.2 million of tax losses which had been previously impaired.
Earnings per share
The Group's reported basic loss per share was 5.4 cents (2016: earnings per share of 22.7 cents) and reported diluted loss per share was 5.4 cents (2016: earnings per share of 22.1 cents).
Cash flow and liquidity
Net debt at 31 December 2017 amounted to $1,991.4 million, including PIK of $90.5 million, compared with net debt of $1,796.5 million at 31 December 2016, including PIK of $27.7 million. The Group has remained in compliance with financial covenants under its debt facilities throughout the year and managing ongoing compliance remains a priority. Where necessary or appropriate, the Group has and would seek waivers and/or consents.
The movement in net debt was as follows:
Net debt 1 January 2017 (1,796.5) Operating cash flows 301.8 Cash capital expenditure (367.6) Proceeds on disposal of Ascent Resources loan notes 3.6 Net interest and finance costs paid (52.0) Non-cash capitalisation of interest to principal of bond and credit facility (PIK) (62.8) Other movements, primarily net foreign exchange loss on cash and debt (17.9) Net debt 31 December 2017 (1,991.4) ------------------------------------------------------------------------------------ ----------
The Group's reported operating cash flows for the year ended 31 December 2017 were $301.8 million, down 20.5% compared to 2016 ($379.5 million). The main driver for this reduction is the reduced contribution from commodity price hedging, where total cash flows received in 2017 were $3.6 million as compared to $198.8 million for 2016. This reduced cash flow was partially offset by the impact of higher market oil prices on revenue and reduced operating and general and administrative expenses.
Cash outflow on capital expenditure is set out in the table below:
Year ended Year ended
31 December 2017 31 December 2016
$ million $ million
North Sea development expenditure 355.3 592.2
Malaysia development expenditure 3.1 8.2
Exploration and evaluation capital expenditure 9.2 8.9
Other capital expenditure - 1.4
Other proceeds - (1.5)
367.6 609.2
================== ============================
In the North Sea, a total of $252.2 million was spent during the year on the Kraken development, primarily related to drilling and completing 14 wells across Drill Centres ('DC') 2 and 3. Excellent drilling performance resulted in the delivery of the wells ahead of schedule. In early 2018, EnQuest also agreed renegotiated terms for the drilling rig, reducing both the contract duration and day rates. Full cycle gross project capital expenditure is now expected to be c.$2.3 billion. The remaining 2017 cash capital expenditure is primarily the settlement of deferred invoices in respect of the Alma/Galia and Scolty/Crathes developments and the Eagle discovery.
Balance Sheet
The Group's total asset value has increased by $1,112.5 million to $5,038.5 million at 31 December 2017
(2016: $3,926.0 million), mainly attributable to the recognition of the $772.0 million Kraken FPSO finance lease asset in property, plant and equipment ('PP&E'). Net current liabilities have increased to $377.9 million as at 31 December 2017 (2016: $45.1 million), primarily driven by the scheduled $270 million RCF amortisation due in October 2018 and the impact of the Kraken FPSO finance lease commitments due within one year.
Property, plant and equipment
PP&E has increased by $885.2 million to $3,848.6 million at 31 December 2017 from $2,963.4 million at
31 December 2016 (see note 10).
This increase is explained by the recognition of the Kraken FPSO finance lease in June 2017 of $772.0 million, capital additions to PP&E of $323.6 million, additions of $124.5 million for the acquisition of interests in the Magnus oil field, SVT and associated infrastructure assets (see note 29), a net increase of $66.2 million for changes in estimates for decommissioning and other provisions, including the KUFPEC cost recovery provision, offset by depletion and depreciation charges of $229.2 million and non-cash impairments of $172.0 million.
The PP&E capital additions during the period, including capitalised interest, are set out 2017
in the table below:
$ million
Kraken 275.8
Thistle/Deveron 15.1
Other North Sea 30.4
Malaysia 2.3
323.6
==========
Intangible oil and gas assets
Intangible oil and gas assets marginally increased to $52.1 million at 31 December 2017 from $50.3 million at
31 December 2016 (see note 12).
Trade and other receivables
Trade and other receivables have increased by $25.1 million to $227.8 million at 31 December 2017 compared with $202.7 million at 31 December 2016. The increase relates mainly to the timing of crude oil sales, increased underlift and higher oil prices, partially offset by other working capital movements (see note 15).
Cash and net debt(1)
The Group had $173.1 million of cash and cash equivalents at 31 December 2017 and $1,991.4 million of net debt, including PIK of $90.5 million (2016: $174.6 million of cash and cash equivalents and $1,796.5 million of net debt, including PIK of $27.7 million). Net debt(1) comprises the following liabilities:
-- $224.1 million principal outstanding on the GBP155 million retail bond (2016: $191.3 million) including $14.9 million of interest capitalised as an amount payable in kind ('PIK') in the year;
-- $720.8 million principal outstanding on the high yield bond, including capitalised interest (PIK) of $70.8 million pursuant to the Restructuring (2016: $677.5 million and $27.5 million respectively);
-- $1,100.0 million carrying value of credit facility, comprising amounts drawn down of $1,095.2 million and PIK interest of $4.8 million (2016: $1,037.5 million comprising amounts drawn down of $1,037.3 million and PIK interest of $0.2 million);
-- $25.6 million relating to the SVT Working Capital Facility (2016: $nil); -- $75.5 million relating to the Mercuria Prepayment Facility (2016: $nil); -- $10.0 million outstanding from a trade creditor loan (2016: $40.0 million); and
-- $8.5 million principal outstanding on the Tanjong Baram Project Finance Facility (2016: $24.9 million).
(1) Net debt excludes accrued interest and the net-off of unamortised fees (see note 19 of the consolidated financial statements).
Provisions
The Group's decommissioning provision increased by $145.4 million to $639.3 million at 31 December 2017
(2016: $493.9 million). The movement is explained by additions to Kraken of $63.6 million based on drilling and developments carried out in the period, an increase of $80.9 million due to changes in estimates (including the impact of oil prices and foreign exchange rates) and $11.5 million unwinding of discount, partially offset by reductions of
$10.6 million for decommissioning carried out in the period.
Other key movements in provisions during the period include the addition of $66.6 million of outstanding contingent consideration for the acquisition of the Magnus oil field, SVT and associated infrastructure assets from BP completed in December 2017 (see note 29) and $10.3 million for PM8/Seligi cost recovery. This is largely offset by a $77.8 million reduction for changes in estimates and the fair value of cost recovery provisions combined with payments of $9.0 million contingent consideration to Centrica pursuant to the Greater Kittiwake Area acquisition agreement and $5.5 million for the final settlement due to Cairn under the carry agreement (see note 22).
Income tax
The Group had no UK corporation tax or supplementary corporation tax liability at 31 December 2017, which remains unchanged from 31 December 2016. The income tax asset at 31 December 2017 represents UK corporation tax receivable in relation to non-upstream activities and the income tax payable is in relation to the Group's activities in Malaysia (see note 7).
Deferred tax
The Group's net deferred tax asset has increased from $191.7 million at 31 December 2016 to $335.6 million at
31 December 2017. The increase is mainly due to the RFES, together with the recognition of $9.7 million of previously derecognised tax losses. Total UK tax losses carried forward at the year end amount to $3,121.3 million
(2016: $2,893.7 million) (see note 7).
Trade and other payables
Trade and other payables of $446.1 million at 31 December 2017 are $6.7 million lower than at 31 December 2016 ($452.8 million). $367.3 million are payable within one year (2016: $410.2 million) and $78.8 million are payable after more than one year (2016: $42.6 million). The decrease in current payables mainly reflects the settlement of deferred invoices and an $11.9 million reduction in the overlift position, offset by accruals (see note 23).
Other financial liabilities
Other current financial liabilities have increased by $16.9 million to $61.2 million. The increase primarily relates to mark to market movements on the Group's commodity derivatives following the strengthening of the oil price, waiver fees payable to credit facility lenders due in March 2018 (previously non-current) and the Group's liability to carry PETRONAS Carigali for its share of exploration or appraisal well commitments in relation to the PM8/Seligi asset in Malaysia (previously non-current).
Other non-current financial liabilities of $7.1 million (2016: $19.8 million) relate mainly to the Magnus field liabilities acquired as part of the transaction that completed in December 2017 (see note 20).
Financial risk management
Oil price
The Group is exposed to the impact of changes in Brent crude oil prices on its revenue and profits. EnQuest's policy is to manage the impact of commodity prices to protect against volatility and allow availability of cash flow for reinvestment in capital programmes that are driving business growth.
In November 2017, the Group entered into an 18-month collar structure for the Mercuria Prepayment Facility of
$80 million (see note 19). Repayment will be in equal monthly instalments over 18 months, through the delivery of an aggregate of approximately 1.8 mmbbls of oil. EnQuest will receive the average Brent price over each month subject to a floor of $45 per barrel and a cap of approximately $64 per barrel. Losses totalling $5.2 million were included within unrealised revenue in the income statement.
The marking to market of the Group's open contracts as at 31 December 2017 gave rise to a loss of $29.2 million in respect of fixed price swap contracts for 4.15 MMbbls of 2018 production at a weighted average price of $59.1/bbl (2016: loss of $40.5 million in respect of fixed price swap contracts for 5.99 MMbls of 2017 production at a weighted average price of $51.3/bbl).
During 2016, the Group entered into commodity hedging contracts to hedge a portion of its 2017 production against fluctuations in oil prices. This hedging generated cash outflows of $0.9 million (including $2.0 million outflow in respect of the settlement of December 2016 hedges) while revenue and other operating income included a loss of
$31.1 million during 2017. These amounts were mostly in respect of the settlement of swaps in respect of 6.0 MMbbls, plus the maturity of certain other commodity derivatives. The Group's marketing and trading activities, which are designed to manage price exposures on certain individual cargos, generated $6.7 million of cash, and contributed $10.6 million to revenue and other operating income.
Foreign exchange
EnQuest's functional currency is US Dollars. Foreign currency risk arises on purchases and the translation of assets and liabilities denominated in currencies other than US Dollars. To mitigate the risks of large fluctuations in the currency markets, the hedging policy agreed by the Board allows for up to 70% of the non-US Dollar portion of the Group's annual capital budget and operating expenditure to be hedged. For specific contracted capital expenditure projects, up to 100% can be hedged.
During 2017, the Group has continued to use an exchange structure to manage risk. The first exchange structure was entered into in 2016 and allowed the counterparty to elect to sell GBP47.5 million to EnQuest at an exchange rate of $1.4:GBP1, or purchase 1.3 MMbbls of oil at $58/bbl. This structure expired on 30 June 2017. The second exchange structure allowed the counterparty to elect to sell GBP66.0 million to EnQuest at an exchange rate of $1.2:GBP1 or purchase 1.5 MMbbls of oil at $60/bbl. This structure expired on 31 December 2017. As a result of these exchange structures, $4.4 million was recognised within other foreign currency contracts and no costs within other operating income during the year (2016: $9.3 million and $nil respectively).
EnQuest continually reviews its currency exposures and when appropriate looks at opportunities to enter into foreign exchange hedging contracts.
Surplus cash balances are deposited as cash collateral against in-place letters of credit as a way of reducing interest costs. Otherwise cash balances can be invested in short-term bank deposits and AAA-rated liquidity funds, subject to Board-approved limits and with a view to minimising counterparty credit risks.
Going concern
The Group closely monitors and manages its funding position and liquidity risk throughout the year, including monitoring forecast covenant results, to ensure that it has access to sufficient funds to meet forecast cash requirements. Cash forecasts are regularly produced and sensitivities considered for, but not limited to, changes in crude oil prices (adjusted for hedging undertaken by the Group), production rates and project timing and costs. These forecasts and sensitivity analyses allow management to mitigate any liquidity or covenant compliance risks in a timely manner. Management has also continued to take action to implement cost saving programmes to reduce planned operational, general and administrative and capital expenditures in 2017 and 2018. At 31 December 2017, the Group had cash and available bank facilities of $244.4 million, excluding $26.5 million of cash from the ring fenced working capital facility associated with SVT.
The Group's business plan ('Base case'), which underpins this assessment, assumes Kraken production rates are in line with the Group's production guidance. The Base case has been updated for the forward curve and uses an oil price assumption of c.$67/bbl throughout 2018 and c.$63/bbl for the first quarter of 2019. This has been further stressed tested under a plausible downside case ('Downside case') as described in the viability statement. Both cases reflect the bank debt amortisation profile due in the going concern period. The Directors consider the Base case and Downside case to be an appropriate basis on which to make their assessment.
The Group has historically reviewed farm down options and continues to do so. The Base case and Downside case indicate that the Company is covenant compliant and will be able to operate within the headroom of its existing borrowing facilities for 12 months from the date of approval of the Annual Report and Accounts.
Should there be any liquidity shortages or covenant breaches due to events not included in the Base or Downside cases, the Directors believe that a number of mitigating actions, including assets sales or other funding options, can be executed successfully in the necessary timeframe to meet debt repayment obligations as they become due and in order to maintain liquidity.
Nevertheless, there remains the risk that the Group is unable successfully to achieve farm down options, other potential asset sales or other funding options. The risk represents a material uncertainty that may cast doubt upon the Group's ability to continue to apply the going concern basis of accounting.
Notwithstanding the material uncertainty described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group will be able to continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors therefore continue to adopt the going concern basis in preparing the financial statements.
Viability statement
The Directors have assessed the viability of the Group over a three-year period to March 2021. This assessment has taken into account the Group's financial position as at March 2018, the future projections and the Group's principal risks and uncertainties. The Directors' approach to risk management, their assessment of the Group's principal risks and uncertainties, and the actions management are taking to mitigate these risks, are outlined in the Risks and uncertainties section of this statement.
The period of three years is deemed appropriate as it provides a sufficient time horizon to assess the performance of the Kraken project and covers the period within which the Group's Facility will be largely repaid.
Based on the Group's projections, the Directors 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 to March 2021.
The Group's business plan process has underpinned this assessment and has been used as the Base case. The business plan process takes account of the Group's principal risks and uncertainties, and has further been stress tested to understand the impact on the Group's liquidity and financial position of reasonably possible changes in these risks and/or business plan assumptions.
The forecasts which underpin this assessment use the same oil price assumption as for the going concern assessment with a longer-term price assumption for the viability period being aligned to a recent forward curve. The Base case reflects significant steps already undertaken to reduce operating and capital expenditure.
For the current assessment, the Directors also draw attention to the specific principal risks and uncertainties (and mitigants) identified below, which, individually or collectively, could have a material impact on the Group's viability during the period of review. In forming this view, it is recognised that such future assessments are subject to a level of uncertainty that increases with time and, therefore, future outcomes cannot be guaranteed or predicted with certainty. The impact of these risks and uncertainties, including their combined impact, has been reviewed by the Directors and the effectiveness and achievability of the potential mitigating actions have been considered.
Oil price volatility
A material decline in oil and gas prices would adversely affect the Group's operations and financial condition. To mitigate oil price volatility, the Directors have hedged c.7.5 million barrels of 2018 production at an average price of c.$62/bbl. As further mitigation, the Directors, in line with Group policy, will continue to pursue hedging at the appropriate time and price.
Kraken production and related asset disposal
All production and injector wells on the first three Drilling Centres ('DC') are onstream and are, in aggregate, operating as per the Field Development Plan ('FDP'). Both production processing trains are also onstream. Kraken gross production averaged around 38,000 Bopd (gross) in the first two months of 2018 and has already delivered the targeted 50,000 Bopd (gross) as planned. The remaining development wells (DC4) will be drilled from Q4 2018 and onstream from Q1 2019, concluding the execution of the FDP. On the basis of this performance, and subject to delivering on the Group's plans to further optimise production and improving plant uptime, EnQuest expects to deliver sustained production rates.
The Group has historically reviewed farm down options and continues to do so.
Access to funding
The Group's Facility contains certain covenants (based on the ratio of indebtedness incurred under the term loan and revolving facility to EBITDA, finance charges to EBITDA, and requirement for liquidity testing). Prolonged low oil prices, cost increases and production delays or outages could further threaten the Group's liquidity and/or ability to comply with relevant covenants.
The Directors recognise the importance of ensuring medium-term liquidity and in particular to protect against potential future declines in the oil price. EnQuest has a committed $1.125 billion Tranche A Term Loan and a further Tranche B $75 million Revolving Credit Facility (collectively the 'Facility'). Across the Facility, $98 million remains available at 31 December 2017.
In addition, the maturity dates of the $721 million high yield bond and the GBP166 million retail notes (both figures inclusive of the PIK notes), have been amended to April 2022, with an option exercisable by the Group (at its absolute discretion) to extend the maturity date by one year and an automatic further extension of the maturity date to October 2023 if the existing Facility is not fully repaid or refinanced by October 2020.
A further condition to the payment of interest on both the high yield bond and retail notes in cash is based on, amongst other things, the average prevailing oil price (dated Brent future (as published by Platts)) for the six-month period immediately preceding the day which is one month prior to the relevant interest payment date being at least $65/bbl; otherwise interest payable is to be capitalised.
In conducting the viability review, these risks have been taken into account in the stress testing performed on the Base case described above.
Specifically the Base case has been subjected to stress testing by considering the impact of the following plausible downside risks:
-- a 10% discount to the oil price forward curve; -- a 5% increase in operating costs except for fixed costs related to the Kraken FPSO; and -- a lower value achieved from the sale of an interest in Kraken.
A scenario has been run illustrating the impact of the above risks on the Base case. This plausible Downside case indicates no mitigating actions need be undertaken for the Group to be viable in the three-year period.
Notwithstanding the principal risks and uncertainties described above, after making enquiries and, assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group will be able to continue in operation and meet its commitments as they fall due over the viability period ending March 2021. Accordingly, the Directors therefore support this viability statement.
Risks and uncertainties
Management of risks and uncertainties
The Board has articulated EnQuest's vision to be the operator of choice for maturing and underdeveloped hydrocarbon assets. As EnQuest moves from a period of heavy investment to one focused on realising value from existing resources, it will focus on driving improved cash flow and managing its capital structure and liquidity.
EnQuest seeks to balance its risk position between investing in activities that can drive growth with the appropriate returns, including any appropriate market opportunities that may present themselves, and the continuing need to remain financially disciplined. This financial discipline drives cost efficiency and cash flow generation to reduce the Group's debt. In this regard, the Board has developed certain strategic tenets to guide the Company during the current phase of its evolution which link with its strategy and appetite for risk. Broadly, these reflect a focus by the Company on:
-- Maintaining discipline across metrics such as financial headroom, leverage ratio and gearing;
-- Enhancing diversity within our portfolio of assets, with a focus on underdeveloped producing assets and maturing assets with investment potential; and
-- Ensuring the quality of the investment decision-making process.
In pursuit of its strategy, EnQuest has to face and manage a variety of risks. Accordingly, the Board has established a Risk Management Framework to enhance effective risk management within the following Board-approved overarching statement of risk appetite (which has been further refined in light of the Company's strategic tenets):
-- We make investments and manage the asset portfolio against agreed key performance indicators consistent with the strategic objectives of enhancing net cash flow, reducing leverage, managing costs and diversifying our asset base;
-- We seek to avoid reputational risk by ensuring that our operational processes and practices reduce the potential for error to the greatest extent practicable;
-- We seek to embed a risk culture within our organisation corresponding to the risk appetite which is articulated for each of our principal risks;
-- We seek to manage operational risk by means of a variety of controls to prevent or mitigate occurrence; and
-- We set clear tolerances for all material operational risks to minimise overall operational losses, with zero tolerance for criminal conduct.
The Board reviews the Company's risk appetite annually in light of changing market conditions and the Company's performance and strategic focus. The Executive Committee periodically reviews and updates the Group Risk Register based on the individual risk registers of the business. The Group Risk Register, along with an assurance mapping exercise and a risk report (focused on the most critical risks and emerging and changing risk profiles), is periodically reviewed by the Board (with senior management), to ensure that key issues are being adequately identified and actively managed. In addition, a sub-Committee of the Board has been established (the Risk Committee) to provide a forum for the Board to review selected individual risk areas in greater depth.
The Board, supported by the Audit Committee, has reviewed the Group's system of risk management and internal control for the period from 1 January 2017 to the date of this report, and is satisfied that it is effective and that the Group complies in this respect with the Financial Reporting Council's 'Guidance on Risk Management, Internal Control and Related Financial and Business Reporting'.
Key business risks
The Group's principal risks are those which could prevent the business from executing its strategy and creating value for shareholders or lead to a significant loss of reputation. The Board has carried out a robust assessment of the principal risks facing the Company, including those that would threaten its business model, future performance, solvency or liquidity.
Cognisant of the Group's 2016 financial restructuring (and consequent strategic focus on reducing the Company's debt and strengthening its balance sheet), the Board is satisfied that the Group's risk management system works effectively in assessing and managing the Group's risk appetite and has supported a robust assessment by the Directors of the principal risks facing the Group.
Set out below are:
-- The principal risks and mitigations;
-- An estimate of the potential impact and likelihood of occurrence after the mitigation actions, along with how these have changed in the past year; and
-- An articulation of the Group's risk appetite for each of these principal risks.
Amongst these, the key risks the Group currently faces are a prolonged low oil price environment and/or a sustained decline in oil prices and materially lower than expected production performance for a prolonged period, particularly at the Kraken field.
Risk Appetite Mitigation
------------------------------ ---------------------------- ------------------------------
Health, safety The Group's principal The Group maintains,
and environment aim is safe results in conjunction
('HSE') with no harm with its core
Oil and gas development, to people and contractors, a
production and respect for the comprehensive
exploration activities environment. programme of HSE,
are complex and Should operational asset integrity
HSE risks cover results and safety and assurance
many areas including ever come into activities and
Major Accident conflict, employees has implemented
Hazards, personal have a responsibility a continual improvement
health and safety, to choose safety programme, promoting
compliance with over operational a culture of transparency
regulatory requirements, results and are in relation to
asset integrity empowered to HSE matters. HSE
issues and potential stop operations performance is
environmental if required. discussed at each
harm. The Group's desire Board meeting.
is to maintain During 2017, the
Potential impact upper quartile Group continued
- Medium (2016 HSE performance to focus on control
Medium) measured against of Major Accident
Likelihood - suitable industry Hazards and 'Safe
Low (2016 Low) metrics. Behaviours' which
has resulted in
There has been significant improvement
no material change in safety and
in the potential environmental
impact or likelihood performance.
and the Group's In addition, the
overall record Group has a positive
on HSE remains and transparent
robust. relationship with
the UK Health
and Safety Executive
and Department
for Business,
Energy & Industrial
Strategy.
EnQuest's HSE
Policy is now
fully integrated
across all of
our operated sites
and this has enabled
an increased focus
on Health, Safety
and the Environment.
There is a strong
assurance programme
in place to ensure
that EnQuest complies
with its Policy
and Principles
and regulatory
commitments.
EnQuest has now
extended the application
of its HSE policy,
activities and
programmes to
operatorship of
the Magnus oil
field, Sullom
Voe Terminal and
associated pipelines.
------------------------------ ---------------------------- ------------------------------
Production Since production The Group's programme
The Group's production efficiency and of asset integrity
is critical to meeting production and assurance
its success and targets is core activities provide
is subject to to our business leading indicators
a variety of and the Group of significant
risks including: seeks to maintain potential issues
subsurface uncertainties; a high degree which may result
operating in of operational in unplanned shutdowns
a mature field control over or which may ,in
environment; production assets other respects,
potential for in its portfolio, have the potential
significant unexpected EnQuest has a to undermine asset
shutdowns; and very low tolerance availability and
unplanned expenditure for operational uptime. The Group
(particularly risks to its continually assesses
where remediation production (or the condition
may be dependent the support systems of its assets
on suitable weather that underpin and operates extensive
conditions offshore). production). maintenance and
Lower than expected inspection programmes
reservoir performance designed to minimise
or insufficient the risk of unplanned
addition of new shutdowns and
resources may expenditure. The
have a material Group monitors
impact on the both leading and
Group's future lagging KPIs in
growth. relation to its
The Group's delivery maintenance activities
infrastructure and liaises closely
in the UKCS is, with its downstream
to a significant operators to minimise
extent, dependent pipeline and terminal
on the Sullom production impacts.
Voe Terminal. Production efficiency
Longer-term production is continually
is threatened monitored with
if low oil prices losses being identified
bring forward and remedial and
decommissioning improvement opportunities
timelines. undertaken as
required. A continual,
Potential impact rigorous cost
- High (2016 focus is also
High) maintained.
Likelihood - Life of asset
Low (2016 Low) production profiles
are audited by
There has been independent reserves
no material change auditors. The
in the potential Group also undertakes
impact or likelihood. regular internal
Whilst reliance reviews. The Group's
on the Sullom forecasts of production
Voe Terminal are risked to
has decreased reflect appropriate
due to the Scolty/Crathes production uncertainties.
and Kraken projects The Sullom Voe
coming onstream, Terminal has a
production at good safety record
Alma/Galia has and its safety
been below expectations. and operational
Until the Kraken performance levels
project is at are regularly
full production, monitored and
there remains challenged by
a possibility the Group and
that production other terminal
at the field owners and users
could be below to ensure that
expectations. operational integrity
is maintained.
Further, EnQuest
expects to be
well positioned
to manage potential
operational risks
related to Sullom
Voe Terminal having
assumed operatorship
of the terminal
and with the workforce
having transferred
with the asset.
Nevertheless,
the Group actively
continues to explore
the potential
of alternative
transport options
and developing
hubs that may
provide both risk
mitigation and
cost savings.
The Group also
continues to consider
new opportunities
for expanding
production.
------------------------------ ---------------------------- ------------------------------
Project execution The efficient The Group has
and delivery delivery of new project teams
The Group's success project developments which are responsible
will be partially has been a key for the planning
dependent upon feature of the and execution
the successful Group's long-term of new projects
execution and strategy. Following with a dedicated
delivery of development the entry into team for each
projects. production of development. The
the Alma/Galia, Group has detailed
Potential impact Scolty/Crathes controls, systems
- High (2016 and Kraken projects, and monitoring
High) the Company's processes in place
Likelihood - exposure to development to ensure that
Low (2016 Low) risks has now deadlines are
reduced. While met, costs are
The potential the Group necessarily controlled and
impact has been assumes significant that design concepts
partially offset risk when it and the Field
by the Alma/Galia, sanctions a new Development Plan
Scolty/Crathes development (for are adhered to
and Kraken projects example, by incurring and implemented.
coming into production costs against These are modified
in 2015, 2016 oil price assumptions), when circumstances
and 2017 respectively. it requires that require and only
risks to the through a controlled
Further, as the efficient implementation management of
Group focuses of the project change process
on reducing its are minimised. and with the necessary
debt, executing internal and external
new large-scale authorisation
developments and communication.
is not considered The Group also
a strategic priority engages third-party
in the short assurance experts
term. to review, challenge
and, where appropriate,
make recommendations
to improve the
processes for
project management,
cost control and
governance of
major projects.
EnQuest ensures
that responsibility
for delivering
time-critical
supplier obligations
and lead times
are fully understood,
acknowledged and
proactively managed
by the most senior
levels within
supplier organisations.
EnQuest also supports
its partners and
suppliers through
the provision
of appropriate
secondees if required.
The Kraken development
was sanctioned
by DECC and EnQuest's
partners in November
2013. First oil
production was
achieved on 23
June 2017. Prior
to sanction, EnQuest
identified and
optimised the
development plan
using EnQuest's
pre-investment
assurance processes.
The Group also
continues to explore
opportunities
to reduce capital
costs and optimise
drilling programmes
with a view to
achieving the
most cost efficient
development outcome
at the field.
------------------------------ ---------------------------- ------------------------------
Subsurface risk Reserves replacement The Group puts
and reserves is an element a strong emphasis
replacement of the sustainability on subsurface
Failure to develop of the Group analysis and employs
its contingent and its ability industry-leading
and prospective to grow. The professionals.
resources or Group has some The Group continues
secure new licences tolerance for to recruit in
and/or asset the assumption a variety of technical
acquisitions of risk in relation positions which
and realise their to the key activities enables it to
expected value. required to deliver manage existing
reserves growth, assets and evaluate
Potential impact such as drilling the acquisition
- High (2016 and acquisitions. of new assets
High) and licences.
Likelihood - All analysis is
Medium (2016 subject to internal
Medium) and, where appropriate,
external review
There has been and relevant stage
no material change gate processes.
in the potential All reserves are
impact or likelihood currently externally
as oil price reviewed by a
volatility and Competent Person.
a focus on strengthening In addition, EnQuest
the balance sheet has active business
continues to development teams
limit business both in the UK
development activity and internationally
to the pursuit developing a range
of reserves enhancing, of opportunities
selective, cash-accretive and liaising with
opportunities. vendors/government.
Low oil prices The Group continues
can potentially to consider potential
affect development opportunities
of contingent to acquire new
and prospective production resources
resources and that meet its
can also affect criteria.
reserve certifications.
------------------------------ ---------------------------- ------------------------------
Financial The Group recognises During the year,
Inability to that significant the Group completed
fund financial leverage has an $80 million
commitments or been required crude oil prepayment
maintain adequate to fund its growth transaction and
cash flow and as low oil prices executed a $37.25
liquidity and/or have impacted million refinancing
reduce costs. revenues. However, for its Tanjong
The Group's term it is intent Baram project
loan and revolving on reducing its in Malaysia; the
credit facility leverage levels, Group also secured
contains certain maintaining liquidity, consents from
financial covenants enhancing profit its term loan
(based on the margins, reducing and revolving
ratio of indebtedness costs and complying credit facility
incurred under with its obligations lenders to waive
the term loan to finance providers certain financial
and revolving while delivering covenants tests
facility to EBITDA, shareholder value, and amend the
finance charges recognising that amortisation schedule
to EBITDA and reasonable assumptions under the facility.
a requirement relating to external These steps, together
for liquidity risks need to with other mitigating
testing). Prolonged be made in transacting actions available
low oil prices, with finance to management,
cost increases providers. are expected to
and production provide the Group
delays or outages with sufficient
could threaten liquidity to strengthen
the Group's liquidity its balance sheet
and/or ability for longer-term
to comply with growth.
relevant covenants. Ongoing compliance
with the financial
Potential impact covenants under
- High (2016 the Group's term
High) loan and revolving
Likelihood - credit facility
Medium (2016 is actively monitored
Medium) and reviewed.
Funding from the
There has been bonds and revolving
no material change credit facility
in the potential is supplemented
impact or likelihood; by operating cash
however, adhering inflow from the
to the RCF amortisation Group's producing
schedule remains assets. The Group
partially dependant reviews its cash
on the successful flow requirements
increase in production on an ongoing
at the Kraken basis to ensure
development, it has adequate
aggregate production resources for
at other assets its needs.
being materially The Group is continuing
in line with to enhance its
expectations financial position
and no significant through maintaining
reduction in a focus on controlling
oil prices. Further and reducing costs
information is through supplier
contained in renegotiations,
the going concern assessing counterparty
and viability credit risk, hedging
paragraphs in and trading, cost-cutting
the Financial and rationalisation.
Review. Where costs are
incurred by external
service providers,
the Group actively
challenges operating
costs. The Group
also maintains
a framework of
internal controls.
------------------------------ ---------------------------- ------------------------------
Human resources As a low-cost, The Group has
The Group's success lean organisation, established an
continues to the Group relies able and competent
be dependent on motivated employee base
upon its ability and high quality to execute its
to attract and employees to principal activities.
retain key personnel achieve its targets In addition to
and develop organisational and manage its this, the Group
capability to risks. The Group seeks to maintain
deliver strategic recognises that good relationships
growth. Industrial the benefits with its employees
action across of a lean and and contractor
the sector could flexible organisation companies and
also impact on require agility regularly monitors
the operations to assure against the employment
of the Group. the risk of skills market to provide
shortages. remuneration packages,
Potential impact bonus plans and
- Low (2016 Low) long-term share-based
Likelihood - incentive plans
Medium (2016 that incentivise
Low) performance and
long-term commitment
The impact has from our employees
remained static to the Group.
due to low oil We recognise that
prices impacting our people are
the buoyancy critical to our
of the employment success and so
market. The likelihood are continually
has increased evolving our end-to-end
due to the erosion people management
in value of long-term processes, including
share-based incentive recruitment and
plans. selection, career
development and
performance management.
This ensures that
we have the right
person for the
job and that we
provide appropriate
training, support
and development
opportunities
with feedback
to drive continuous
improvement whilst
delivering safe
results. The culture
of the Group is
an area of increased
focus given the
rapid growth of
the workforce
as we absorb a
significant number
of personnel into
the business with
the acquisition
of operating interests
in the Magnus
field and the
Sullom Voe Oil
Terminal.
The Group also
maintains market-competitive
contracts with
key suppliers
to support the
execution of work
where the necessary
skills do not
exist within the
Group's employee
base. The Group
recognises that
there is a Gender
Pay gap within
the organisation
but that there
is no issue with
equal pay for
the same tasks.
EnQuest aims to
attract the best
talent, regardless
of gender.
The focus on executive
and senior management
retention, succession
planning and development
remains an important
priority for the
Board. It is a
Board-level priority
that executive
and senior management
possess the appropriate
mix of skills
and experience
to realise the
Group's strategy;
succession planning
therefore remains
a key priority.
------------------------------ ---------------------------- ------------------------------
Reputation The Group has All activities
The reputational no tolerance are conducted
and commercial for conduct which in accordance
exposures to may compromise with approved
a major offshore its reputation policies, standards
incident or non-compliance for integrity and procedures.
with applicable and competence. Interface agreements
law and regulation are agreed with
are significant. all core contractors.
The Group requires
Potential impact adherence to its
- High (2016 Code of Conduct
High) and runs compliance
Likelihood - programmes to
Low (2016 Low) provide assurance
on conformity
There has been with relevant
no material change legal and ethical
in the potential requirements.
impact or likelihood. The Group undertakes
regular audit
activities to
provide assurance
on compliance
with established
policies, standards
and procedures.
All EnQuest personnel
and contractors
are required to
pass an annual
anti-bribery,
corruption and
anti-facilitation
of tax evasion
course.
------------------------------ ---------------------------- ------------------------------
Oil price The Group recognises This risk is being
A material decline that considerable mitigated by a
in oil and gas exposure to this number of measures
prices adversely risk is inherent including hedging
affects the Group's to its business. oil price, renegotiating
operations and supplier contracts,
financial condition. reducing costs
and commitments
Potential impact and institutionalising
- High (2016 a lower cost base.
High) The Group monitors
Likelihood - oil price sensitivity
Medium (2016 relative to its
High) capital commitments
and has a policy
There has been which allows hedging
no material change of its production.
in the potential As at 19 March
impact; the likelihood 2018, the Group
has decreased had hedged approximately
due to rising/stabilising 7.5 million bbls
oil prices. for 2018 at a
price of approximately
$62/bbl. This
ensures that the
Group will receive
a minimum oil
price for its
production.
In order to develop
its resources,
the Group needs
to be able to
fund the required
investment. The
Group will therefore
regularly review
and implement
suitable policies
to hedge against
the possible negative
impact of changes
in oil prices
while remaining
within the limits
set by its term
loan and revolving
credit facility.
The Group has
established an
in-house trading
and marketing
function to enable
it to enhance
its ability to
mitigate the exposure
to volatility
in oil prices.
Further, as described
above, the Group's
focus on production
efficiency supports
mitigation of
a low oil price
environment
------------------------------ ---------------------------- ------------------------------
Fiscal risk and The Group faces It is difficult
government take an uncertain for the Group
Unanticipated macro-economic to predict the
changes in the and regulatory timing or severity
regulatory or environment. of such changes.
fiscal environment Due to the nature However, through
can affect the of such risks Oil & Gas UK and
Group's ability and their relative other industry
to deliver its unpredictability, associations,
strategy/business it must be tolerant the Group engages
plan and potentially of certain inherent with government
impact revenue exposure. and other appropriate
and future developments. organisations
in order to keep
Potential impact abreast of expected
- High (2016 and potential
High) changes; the Group
Likelihood - also takes an
Medium (2016 active role in
Medium) making appropriate
representations.
There has been All business development
no material change or investment
in the potential activities recognise
impact or likelihood. potential tax
implications and
the Group maintains
relevant internal
tax expertise.
At an operational
level, the Group
has procedures
to identify impending
changes in relevant
regulations to
ensure legislative
compliance.
------------------------------ ---------------------------- ------------------------------
Joint venture The Group requires The Group operates
partners partners of high regular cash call
Failure by joint integrity. It and billing arrangements
venture parties recognises that with its co-venturers
to fund their it must accept to mitigate the
obligations. a degree of exposure Group's credit
Dependence on to the creditworthiness exposure at any
other parties of partners and one point in time
where the Group evaluates this and keeps in regular
is not the operator. aspect carefully dialogue with
as part of every each of these
Potential impact investment decision. parties to ensure
- Medium (2016 payment. Risk
Medium) of default is
Likelihood - mitigated by joint
Medium (2016 operating agreements
Medium) allowing the Group
to take over any
There has been defaulting party's
no material change share in an operated
in the potential asset and rigorous
impact or likelihood; and continual
however, due assessment of
to the assumption the financial
of operatorship situation of partners.
at Sullom Voe The Group generally
Terminal, the prefers to be
Group has now the operator.
assumed exposure The Group maintains
to a larger number regular dialogue
of counterparties. with its partners
to ensure alignment
of interests and
to maximise the
value of joint
venture assets.
------------------------------ ---------------------------- ------------------------------
Competition The Group operates The Group has
The Group operates in a mature industry strong technical
in a competitive with well-established and business development
environment across competitors and capabilities to
many areas including aims to be the ensure that it
the acquisition leading operator is well positioned
of oil and gas in the sector; to identify and
assets, the marketing it thus has a execute potential
of oil and gas, high appetite acquisition opportunities.
the procurement for this risk. The Group maintains
of oil and gas good relations
services and with oil and gas
access to human service providers
resources. and constantly
keeps the market
Potential impact under review.
- Medium (2016
Medium)
Likelihood -
Medium (2016
Medium)
There has been
no material change
in the impact
or likelihood.
------------------------------ ---------------------------- ------------------------------
Portfolio concentration Although the This risk is mitigated
The Group's assets extent of portfolio in part through
are concentrated concentration acquisitions.
in the UK North is moderated For all acquisitions,
Sea around a by production the Group uses
limited number generated internationally, a number of business
of infrastructure the majority development resources
hubs and existing of the Group's to evaluate and
production (principally assets remain transact acquisitions
only oil) is relatively concentrated in a commercially
from mature fields. in the UK North sensitive matter.
This amplifies Sea and therefore This includes
exposure to key this risk remains performing extensive
infrastructure intrinsic to due diligence
(including aging the Group. (using in-house
pipelines and and external personnel)
terminals), political/fiscal and actively involving
changes and oil executive management
price movements. in reviewing commercial,
technical and
Potential impact other business
- High (2016 risks together
Medium) with mitigation
Likelihood - measures.
Medium (2016 The Group also
Low) constantly keeps
its portfolio
The acquisition under rigorous
of an interest review and, accordingly,
in the Magnus actively considers
oil field and the potential
Sullom Voe Terminal for making disposals
(and associated and divesting,
pipelines) has executing development
elevated this projects, making
risk in the long international
term (by further acquisitions and
concentrating expanding hubs
the Group's portfolio where such opportunities
in the UK North are consistent
Sea). In addition, with the Group's
although production focus on enhancing
from Kraken represents net revenues,
a new production generating cash
hub for the Group, flow and strengthening
it does further the balance sheet.
extend geographic The acquisition
concentration of the Greater
of the Group's Kittiwake Area
production in in 2014, which
the UK North produces via the
Sea. Forties Pipeline
System ('FPS'),
and the start-up
of Alma/Galia
and Kraken, which
produce to shuttle
tankers, reduced
the Group's prior
concentration
to the Brent Pipeline
System ('BPS')
and the Sullom
Voe Terminal.
Although, due
to successful
completion of
the Group's acquisition
of the Magnus
field and Sullom
Voe Terminal from
BP, the Group
will see a further
concentration
in Sullom Voe.
As the Magnus
field produces
via the Ninian
Pipeline System
('NPS'), this
will not concentrate
risk further in
BPS. It should
also be noted
that the Heather
and Broom fields
also produce via
NPS. Although
the Group has
concentration
risk at Sullom
Voe Terminal,
taking operatorship
of the terminal
will put the Group
in a position
of more direct
control of such
risk.
------------------------------ ---------------------------- ------------------------------
International In light of its Prior to entering
business long-term growth a new country,
While the majority strategy, the EnQuest evaluates
of the Group's Group seeks to the host country
activities and expand and diversify to assess whether
assets are in its production there is an adequate
the UK, the international (geographically and established
business is still and in terms legal and political
material. The of quantum); framework in place
Group's international as such, it is to protect and
business is subject tolerant of assuming safeguard first
to the same risks certain commercial its expatriate
as the UK business risks which may and local staff
(e.g. HSE, production accompany the and, second, any
and project execution); opportunities investment within
however, there it pursues. However, the country in
are additional such tolerance question.
risks that the does not impair When evaluating
Group faces including the Group's commitment international
security of staff to comply with business risks,
and assets, political, legislative and executive management
foreign exchange regulatory requirements reviews commercial,
and currency in the jurisdictions technical and
control, taxation, in which it operates. other business
legal and regulatory, Opportunities risks together
cultural and should enhance with mitigation
language barriers net revenues and how risks
and corruption. and facilitate can be managed
strengthening by the business
Potential impact of the balance on an ongoing
- Medium (2016 sheet. basis.
Medium) EnQuest looks
Likelihood - to employ suitably
Medium (2016 qualified host
Medium) country staff
and work with
There has been good quality local
no material change advisers to ensure
in the impact it complies within
or likelihood. national legislation,
business practices
and cultural norms
while at all times
ensuring that
staff, contractors
and advisers comply
with EnQuest's
business principles,
including those
on financial control,
cost management,
fraud and corruption.
Where appropriate,
the risks may
be mitigated by
entering into
a joint venture
with partners
with local knowledge
and experience.
After country
entry, EnQuest
maintains a dialogue
with local and
regional government,
particularly with
those responsible
for oil, energy
and fiscal matters,
and may obtain
support from appropriate
risk consultancies.
When there is
a significant
change in the
risk to people
or assets within
a country, the
Group takes appropriate
action to safeguard
people and assets.
------------------------------ ---------------------------- ------------------------------
IT security and The Group endeavours The Group has
resilience to provide a established IT
The Group is secure IT environment capabilities and
exposed to risks that is able endeavours to
arising from to resist and be in a position
interruption withstand any to defend its
to, or failure attacks or unintentional systems against
of, IT infrastructure. disruption that disruption or
The risks of may compromise attack.
disruption to sensitive data, The Risk Committee
normal operations impact operations undertook an analysis
range from loss or destabilise of cyber security
in functionality its financial risks in 2017,
of generic systems systems; it has recognising it
(such as email a very low appetite is one of the
and internet for this risk. Group's key focus
access) to the areas. Work on
compromising assessing the
of more sophisticated cyber security
systems that environment and
support the Group's implementing improvements
operational activities. as necessary will
These risks could be continuing
result from malicious during 2018.
interventions
such as cyber-attacks.
Potential impact
- Medium (2016
N/A)
Likelihood -
Low (2016 N/A)
------------------------------ ---------------------------- ------------------------------
KEY PERFORMANCE INDICATORS
2017 2016 2015
North Sea Lost Time Incident
Frequency ('LTIF') 1.05 0.82 2.14
Malaysia LTIF 0.00 0.00 0.00
--------------------------------------- -------- -------- --------
Production (Boepd) 37,405 39,751 36,567
--------------------------------------- -------- -------- --------
Net 2P reserves (MMboe) 210 215 203
--------------------------------------- -------- -------- --------
Business performance data:
Revenue and other operating income(1)
($ million) 627.5 849.6 906.6
Realised blended average oil
price per barrel(1) ($) 52.2 63.8 72.0
Opex per barrel (production and
transportation costs) ($) 25.6 24.6 29.7
EBITDA(2) ($ million) 303.6 477.1 474.2
Cash capex(3) on property, plant
and equipment oil and gas assets
($ million) 367.6 609.2 751.1
--------------------------------------- -------- -------- --------
Reported data:
Cash generated from operations
($ million) 327.0 408.3 221.7
Net debt including PIK ($ million) 1,991.4 1,796.5 1,548.0
--------------------------------------- -------- -------- --------
(i) Including realised loss of $20.6 million in 2017 associated with EnQuest's oil price hedges (2016: realised gain of $255.8 million, 2015: realised gain of $261.2 million).
(ii) EBITDA is calculated on a business performance basis, and is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion, depreciation, foreign exchange movements and the realised gains/loss on foreign currency derivatives related to capital expenditure.
(iii) Net of proceeds from disposal of $nil million (2016: $1.5 million, 2015: $75.5 million).
OIL AND GAS RESERVES AND RESOURCES
At 31 December 2017
UKCS Other Regions Total
-------------- ---------------- ------
MMboe MMboe MMboe MMboe MMboe
Proven and probable reserves
(notes 1,2,3,6 and 8)
At 31 December 2016 199 17 215
Revisions of previous
estimates (13) 6 (7)
Discoveries, extensions
and additions
Acquisitions and disposals
(note 7) 14 14
Production
Export Meter (10) (3)
Volume Adjustments
(note 5) 0 1
Production during period: (10) (2) (12)
Total at 31 December
2017 190 21 210
Contingent resources
(notes 1,2 and 4)
At 31 December 2016 95 55 151
Revisions of previous
estimates 10 12 22
Discoveries, extensions
and additions
Acquisitions and disposals
(note 7) (8) (8)
Promoted to reserves
Total at 31 December
2017 98 67 164
Notes:
1 Reserves are quoted on a net entitlement basis,
resources are quoted on a working interest basis.
2 Proven and probable reserves and contingent
resources have been assessed by the Group's
internal reservoir engineers, utilising geological,
geophysical, engineering and financial data.
3 The Group's underlying technical data underpinning
proven and probable reserve profiles has been
audited by a recognised Competent Person in
accordance with the definitions set out under
the 2007 Petroleum Resources Management System
and supporting guidelines issued by the Society
of Petroleum Engineers.
4 Contingent resources relate to technically recoverable
hydrocarbons for which commerciality has not
yet been determined and are stated on a best
technical case or '2C' basis.
5 Correction of export to sales volumes.
6 All UKCS volumes are presented pre-SVT value
adjustment.
7 Proven and probable reserves: Acquisition of
25% equity in Magnus. Contingent resources:
Acquisition of 25% equity in Magnus offset by
relinquishment of the Group's equity interests
in Crawford, Porter and Elke licences and expiry
of 50% of the Kildrummy licence.
8 The above proven and probable reserves include
5.8 MMboe that will be consumed as lease fuel
on the Kraken FPSO and fuel gas on Heather,
Broom, West Don, Don SW, Conrie and Ythan.
9 The above table excludes Tanjong Baram in Malaysia.
GROUP STATEMENT OF COMPREHENSIVE INCOME
For the year ended 31 December 2017
2017 2016
------------- ------------------ ---------- ------------- ---------------- ----------
Notes Re-measurements, Re-measurements
Business and exceptional Reported Business and exceptional Reported
performance items (note 4) in year performance items (note 4) in year
$'000 $'000 $'000 $'000 $'000 $'000
Revenue and
other
operating
income 5(a) 635,167 (7,716) 627,451 849,627 (51,504) 798,123
Cost of sales 5(b) (569,506) 5,481 (564,025) (653,518) (2,848) (656,366)
---------------- ------ ------------- ------------------ ---------- ------------- ---------------- ----------
Gross
profit/(loss) 65,661 (2,235) 63,426 196,109 (54,352) 141,757
Net impairment
(charge)/
reversal to
oil and gas
assets 4 - (171,971) (171,971) - 147,871 147,871
(Loss)/gain on
disposal of
intangible oil
and gas assets 4 - - - - (16,178) (16,178)
General and
administration
expenses 5(c) (848) - (848) (10,890) - (10,890)
Other income 5(d) 6,807 50,613 57,420 51,936 31,554 83,490
Other expenses 5(e) (24,363) (20,358) (44,721) (77) (894) (971)
---------------- ------ ------------- ------------------ ---------- ------------- ---------------- ----------
Profit/(loss)
from
operations
before tax and
finance
income/(costs) 47,257 (143,951) (96,694) 237,078 108,001 345,079
Finance costs 6 (149,020) (272) (149,292) (122,232) (7,043) (129,275)
Finance income 6 2,213 - 2,213 1,440 - 1,440
---------------- ------ ------------- ------------------ ---------- ------------- ---------------- ----------
Profit/(loss)
before tax (99,550) (144,223) (243,773) 116,286 100,958 217,244
Income tax 7 65,996 116,947 182,943 5,224 (37,256) (32,032)
---------------- ------ ------------- ------------------ ---------- ------------- ---------------- ----------
Profit/(loss)
for the year
attributable
to owners of
the parent (33,554) (27,276) (60,830) 121,510 63,702 185,212
================ ====== ============= ================== ========== ============= ================ ==========
Other comprehensive
income
Items that may be
reclassified to profit
or loss:
Fair value gains/(losses)
on cash flow hedges - (29,048)
Transfers to income
statement of cash
flow hedges (5) (239,565)
Transfers to balance
sheet of cash flow
hedges - 278
Deferred tax on cash
flow hedges - 134,177
---------------------------------- --------- ------ ----------
Other comprehensive
income for the year,
net of tax (5) (134,158)
---------------------------------- --------- ------ ----------
Total comprehensive
income for the year,
attributable to owners
of the parent (60,835) 51,054
================================== ========= ====== ==========
Earnings $ $ $ $
per share 8
Basic (0.030) (0.054) 0.149 0.227
Diluted (0.030) (0.054) 0.145 0.221
The attached notes 1 to 30 form part of these Group financial statements.
GROUP BALANCE SHEET
At 31 December 2017
Notes 2017 2016
ASSETS $'000 $'000
Non-current assets
Property, plant and equipment 10 3,848,622 2,963,446
Goodwill 11 189,317 189,317
Intangible oil and gas assets 12 52,103 50,332
Investments 13 152 171
Deferred tax assets 7 398,263 206,742
Other financial assets 20 8,191 23,429
----------- ----------
4,496,648 3,433,437
----------- ----------
Current assets
Inventories 14 78,045 74,985
Trade and other receivables 15 227,754 202,666
Current tax receivable 1,159 925
Cash and cash equivalents 16 173,128 174,634
Other financial assets 20 61,737 39,342
----------- ----------
541,823 492,552
----------- ----------
TOTAL ASSETS 5,038,471 3,925,989
EQUITY AND LIABILITIES
Equity
Share capital and premium 17 210,402 208,639
Merger reserve 662,855 662,855
Cash flow hedge reserve 36 41
Share-based payment reserve (5,516) (6,602)
Retained earnings (106,911) (46,081)
----------- ----------
TOTAL EQUITY 760,866 818,852
----------- ----------
Non-current liabilities
Borrowings 19 888,993 1,052,075
Bonds 19 934,351 855,739
Obligations under finance leases 24 679,924 -
Provisions 22 705,999 584,266
Trade and other payables 23 78,777 42,587
Other financial liabilities 20 7,121 19,767
Deferred tax liabilities 7 62,685 15,027
----------- ----------
3,357,850 2,569,461
----------- ----------
Current liabilities
Borrowings 19 330,012 49,601
Obligations under finance leases 24 118,009 -
Provisions 22 43,215 30,041
Trade and other payables 23 367,312 410,261
Other financial liabilities 20 61,207 44,274
Current tax payable - 3,499
----------- ----------
919,755 537,676
----------- ----------
TOTAL LIABILITIES 4,277,605 3,107,137
TOTAL EQUITY AND LIABILITIES 5,038,471 3,925,989
=========== ==========
The attached notes 1 to 30 form part of these Group financial statements.
The financial statements were approved by the Board of Directors on 19 March 2018 and signed on its behalf by:
Jonathan Swinney
Chief Financial Officer
GROUP STATEMENT OF CHANGES IN EQUITY
For the year ended 31 December 2017
Share capital
and share Merger Cash flow hedge Share-based
premium reserve reserve payments reserve Retained earnings Total
$'000 $'000 $'000 $'000 $'000 $'000
Balance at 1
January 2016 113,433 662,855 134,199 (11,995) (231,293) 667,199
Profit for the
year - - - - 185,212 185,212
Other
comprehensive
income - - (134,158) - - (134,158)
------------------ ----------------- --------- ----------------- ----------------- ------------------ ----------
Total
comprehensive
income for the
year - - (134,158) - 185,212 51,054
Issue of share
capital, net of
expenses 95,206 - - - - 95,206
Share-based
payment - - - 8,452 - 8,452
Shares purchased
on behalf of
Employee Benefit
Trust - - - (3,059) - (3,059)
------------------
Balance at 31
December 2016 208,639 662,855 41 (6,602) (46,081) 818,852
Profit/(loss) for
the year - - - - (60,830) (60,830)
Other
comprehensive
income - - (5) - - (5)
------------------
Total
comprehensive
income for the
year - - (5) - (60,830) (60,835)
Share-based
payment - - - 2,849 - 2,849
Shares issued on
behalf of
Employee Benefit
Trust 1,763 - - (1,763) - -
Balance at 31
December 2017 210,402 662,855 36 (5,516) (106,911) 760,866
------------------ ----------------- --------- ----------------- ----------------- ------------------ ----------
The attached notes 1 to 30 form part of these Group financial statements.
GROUP STATEMENT OF CASH FLOWS
For the year ended 31 December 2017
2017 2016
Notes $'000 $'000
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations 30 327,034 408,247
Cash (paid)/received on sale/(purchase) of financial instruments (1,185) (14,541)
Decommissioning spend 22 (10,605) (6,355)
Income taxes paid (13,463) (7,890)
------------------------------------------------------------------ ------
Net cash flows from/(used) operating activities 301,781 379,461
------------------------------------------------------------------ ------ ----------- ----------
INVESTING ACTIVITIES
Purchase of property, plant and equipment (358,420) (601,696)
Purchase of intangible oil and gas assets (9,171) (8,928)
Proceeds from disposal of intangible oil and gas assets - 1,466
Proceeds from disposal of Ascent loan notes 3,561 -
Interest received 340 422
------------------------------------------------------------------ ------ ----------- ----------
Net cash flows (used)/from in investing activities (363,690) (608,736)
------------------------------------------------------------------ ------ ----------- ----------
FINANCING ACTIVITIES
Proceeds from bank facilities 162,970 174,997
Repayment of bank facilities (50,969) (10,150)
Gross proceeds from issue of shares - 101,628
Shares purchased by Employee Benefit Trust - (3,059)
Share issue and debt restructuring costs paid (1,356) (21,152)
Repayment of obligations under finance leases - (35)
Interest paid (46,052) (83,207)
Other finance costs paid (6,286) (9,842)
------------------------------------------------------------------ ------ ----------- ----------
Net cash flows from/(used) financing activities 58,307 149,180
------------------------------------------------------------------ ------ ----------- ----------
NET (DECREASE)/INCREASE IN CASH AND CASH EQUIVALENTS (3,602) (80,095)
Net foreign exchange on cash and cash equivalents 5,210 (9,385)
Cash and cash equivalents at 1 January 168,060 257,540
------------------------------------------------------------------ ------ ----------- ----------
CASH AND CASH EQUIVALENTS AT 31 DECEMBER 169,668 168,060
================================================================== ====== =========== ==========
Reconciliation of cash and cash equivalents
Cash and cash equivalents per statement of cash flows 169,668 168,060
Restricted cash 16 3,460 6,574
------------------------------------------------------------------ ------ ----------- ----------
Cash and cash equivalents per balance sheet 173,128 174,634
================================================================== ====== =========== ==========
The attached notes 1 to 30 form part of these Group financial statements.
NOTES TO THE GROUP FINANCIAL STATEMENTS
For the year ended 31 December 2017
1. Corporate information
EnQuest PLC ('EnQuest' or 'the Company') is a limited liability Company incorporated and registered in England and is listed on the London Stock Exchange and on the Stockholm NASDAQ OMX.
The principal activities of the Company and its subsidiaries (together the 'Group') is to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner.
The Group's financial statements for the year ended 31 December 2017 were authorised for issue in accordance with a resolution of the Board of Directors on 19 March 2018.
A listing of the Group companies is contained in note 28 to these Group financial statements.
2. Summary of significant accounting policies
New standards and interpretations
The Group has adopted and applied the following standards that are relevant to its operations for the first time for the annual reporting period commencing 1 January 2017:
-- Amendments to IAS 12 Income Taxes - Recognition of Deferred Tax Assets for Unrealised Losses;
-- Annual Improvements to IFRSs (2014 - 2016 Cycle): IFRS 12 Disclosure of interests in other entities; and
-- Disclosure Initiative Amendments - IAS 7 Statement of Cash Flows.
There were no new standards or interpretations effective for the first time for periods beginning on or after 1 January 2017 that had a significant effect on the Group's financial statements, although an amendment to IAS 7 Statement of Cash Flows has resulted in a reconciliation of liabilities disclosed for the first time in note 30.
Standards issued but not yet effective
Standards issued and relevant to the Group, but not yet effective up to the date of issuance of the Group's financial statements, are listed below. This listing is of standards and interpretations issued, which the Group reasonably expects to be applicable at a future date. The Group intends to adopt these standards when they become effective. The Directors do not anticipate that the adoption of these standards will have a material impact on the Group's financial statements in the period of initial application.
IFRS 9 Financial Instruments
In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments which replaces IAS 39 Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. The standard introduces new requirements for classification and measurement, impairment under the 'expected credit loss' ('ECL') model and hedge accounting. IFRS 9 is effective for annual periods beginning on or after 1 January 2018, with early application permitted. The Group plans to adopt the new standard on the required effective date and will not restate comparative information.
During 2017, the Group has performed an impact assessment for the application of IFRS 9. This assessment is based on currently available information and may be subject to changes arising from further reasonable and supportable information being made available to the Group in 2018 when the Group will adopt IFRS 9. The Group continues to assess its accounting processes, controls and policies on an on-going basis.
Classification and measurement
The Group expects that all financial assets will continue to be measured at amortised cost or fair value and will be measured on the same basis as is currently adopted under IAS 39.
The Group has not designated any financial liabilities at fair value through profit or loss ('FVTPL') and the assessment did not indicate any material impact regarding the classification of financial liabilities. The Group does not currently designate any hedge relationships for hedge accounting.
Impairment
The Group's receivables have a good credit rating, hence the expected credit losses are low (see note 15). There has been no noted change in the credit risk of receivables in the year, therefore the Group does not believe that the new ECL impairment methodology will have a material impact on the valuation of financial assets.
Non-current assets are held with reputable businesses with whom the Group has good working relationships. The scheduled repayment of cash flows have been and continue to be received in line with expectations. There has been no noted change in the credit risk of receivables in the year, therefore the Group does not believe that the new ECL impairment methodology will have a material impact on the valuation of financial assets.
Cash is held with bank and financial institution counterparties, which are rated with an A-/A3 credit rating or better
(see note 16). The Group considers that the available cash balances have low credit risk based on the external credit rating of the counterparties.
2. Summary of significant accounting policies (continued)
Standards issued but not yet effective (continued)
IFRS 9 Financial Instruments (continued)
Modification of debt
In July 2017 the IASB confirmed the accounting for modifications of financial liabilities under IFRS 9. When a financial liability measured at amortised cost is modified without this resulting in derecognition, a gain or loss should be recognised in profit or loss. The gain or loss is calculated as the difference between the original contractual cash flows and the modified cash flows discounted at the original effective interest rate. Any fees and costs incurred are amortised over the remaining term of the asset.
During the 2016 refinancing, the modification of the Bonds was not considered to be significant. As a result, the change in contractual cash flows on the Bonds was amortised over the new life of the bonds, rather than taken straight to profit or loss (see note 19). Under IFRS 9, the refinancing is a modification of the debt in which the difference in contractual cash flows should be taken straight to profit or loss. On the implementation of IFRS 9 on 1 January 2018, an adjustment will be taken through opening reserves and through the value of both bonds, High Yield Bond and Retail Bond of $34.0m ($9.2m and $24.8m respectively).
IFRS 15 Revenue from Contracts with Customers
IFRS 15 was issued in May 2014, and amended in April 2016, and establishes a single comprehensive model that will apply to revenue arising from contracts with customers. IFRS 15 will supersede the current revenue recognition guidance including IAS 18 Revenue and related interpretations when it becomes effective, for annual periods beginning on or after 1 January 2018.
The core principle of IFRS 15 is that an entity should recognise revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. The five step model recognises revenue when (or as) a performance obligation is satisfied, i.e. when 'control' of the goods or services underlying the particular performance obligation is transferred to the customer. Extensive new disclosures are required by IFRS 15.
During 2017, the Group has performed an impact assessment for the application of IFRS 15. This assessment is based on currently available information and may be subject to changes arising from further reasonable and supportable information being made available to the Group in 2018 when the Group will adopt IFRS 15. The Group continues to assess its accounting processes, controls and policies on an on-going basis. The Group plans to adopt the new standard on the required effective date using the modified retrospective method.
The Group recognises revenue from the following major sources:
-- Sale of crude oil, gas and condensate; -- Tariff revenue for the use of Group infrastructure; -- Production imbalances.
Interest income and dividend income from debt and equity investments were covered by IAS 18. These are now within the scope of IFRS 9.
Sale of crude oil, gas and condensate
The Directors have assessed the sale of crude oil, gas or condensate and determined that these represent a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue will accordingly be recognised for this performance obligation when control over the corresponding commodity is transferred to the customer. This is in line with the current recognition of revenue under IAS 18. Variable revenue conditions can arise on either party based on the failure to provide commitments detailed within the contract. These variations arise as an event occurs and therefore the transaction price is known at the timing of the performance obligations with no judgement required. Revenue recognition is therefore consistent with current practice.
A Production Sharing Contract (PSC) is in place in Malaysia with Petronas, the custodian for Malaysia's national oil and gas resources. The production is shared in line with the risks and benefits that result from the activity of the PSC and therefore this is a collaborative arrangement. Revenue is recognised on the sale of the crude oil, as per the analysis of sale of crude oil above. This is in line with the current recognition of revenue under IAS 18.
2. Summary of significant accounting policies (continued)
Standards issued but not yet effective (continued)
IFRS 15 Revenue from Contracts with Customers (continued)
Tariff revenue for the use of Group infrastructure
The Directors have assessed the revenue arising from tariffs, which are charged to customers for the use of infrastructure owned by the Group in the North Sea. There is one contract per customer which is for a period of 12 months of less and is based on one performance obligation for the use of Group assets. The use of the assets is not separable as they are all dependent on one another in order to fulfil the contract and no one item of infrastructure can be individually identified. Revenue will accordingly be recognised over the performance of the contract as services are provided for the use of the infrastructure on a throughput basis. Revenue recognition is therefore consistent with current practice under IAS 18.
Production imbalances
Production imbalances arise on fields as oil is lifted per each joint venture party, resulting in a variance in the volume of oil lifted versus the entitlement per owner per their working interest. The change in production imbalances is currently taken through cost of sales (see note 5(b)) at fair value at the date of lifting. All Group fields are operated through a Joint Venture Agreement ('JVA') through which production imbalances are settled. These transactions are settled by the JVA through lifting schedules and are not settled in cash, with the exception of a misbalance at the cessation of contract.
These are collaborative agreements through the JVA and non-monetary exchanges, and therefore do not meet the definition of a customer under IFRS 15. Production imbalances will continue to be recognised through cost of sales, as per the current accounting treatment, with no change on the application of IFRS 15.
IFRS 16 Leases
IFRS 16 Leases, issued in January 2016, sets out the principles for the recognition, measurement, presentation and disclosure of leases for both lessors and lessees. It replaces the previous leases standard IAS 17 Leases and is effective from 1 January 2019.
IFRS 16 introduces a single, on-balance sheet lease accounting model for lessees. A lessee recognises a right-of-use asset representing its right to use the underlying asset and a lease liability representing its obligation to make lease payments. There are recognition exemptions for short-term leases and leases of low-value items. Lessor accounting remains similar to the current standard i.e. lessors continue to classify leases as finance or operating leases.
The Group has completed an initial assessment of the potential impact on its consolidated financial statements, but has not yet completed its detailed assessment. The actual impact of applying IFRS 16 on the financial statements in the period of initial application will depending on future economic condition, including the Group's borrowing rate at
1 January 2019, the composition of the Group's lease portfolio at that date, the Group's latest assessment of whether it will exercise any lease renewal options and the extent to which the Group chooses to use practical expedients and recognition exemptions.
As at 31 December 2017, the Group has non-cancellable operating lease commitments of $110 million (see note 24). A preliminary assessment indicates that these arrangements will meet the definition of a lease under IFRS 16, and hence the Group will recognise a right-of-use asset and a corresponding liability in respect of these leases, unless they qualify for low value or short-term leases upon the application of IFRS 16. The new requirement to recognise a
right-of-use asset and a related lease liability is expected to have a significant impact on the amounts recognised in the Group's consolidated financial statements and the Directors are currently assessing its potential impact. It is not practicable to provide a reasonable estimate of the financial effect until the Directors complete the review.
The Group plans to apply the practical expedient to grandfather the definition of a lease on transition. This means that it will apply IFRS 16 to all contracts entered into before 1 January 2019 and identified as leases in accordance with
IAS 17. Contracts which have not been considered or identified as a lease will continue to be accounted for in line with their historical treatment.
In contrast, for finance leases where the Group is a lessee, as the Group has already recognised an asset and a related finance lease liability for the lease arrangement, and in cases where the Group is a lessor (for both operating and finance leases), the Directors of the Company do not anticipate that the application of IFRS 16 will have a significant impact on the amounts recognised in the Group's consolidated financial statements.
2. Summary of significant accounting policies (continued)
Basis of preparation
The Group financial information has been prepared in accordance with International Financial Reporting Standards ('IFRS') as adopted by the European Union as they apply to the financial statements of the Group for the year ended 31 December 2017 and applied in accordance with the Companies Act 2006. The accounting policies which follow set out those policies which apply in preparing the financial statements for the year ended 31 December 2017.
The Group financial information has been prepared on an historical cost basis, except for the fair value remeasurement of certain financial instruments, including derivatives, as set out in the accounting policies below. The presentation currency of the Group financial information is United States Dollars and all values in the Group financial information are rounded to the nearest thousand ($'000) except where otherwise stated.
The financial statements have been prepared on the going concern basis. Further information relating to the use of the going concern assumption is provided in the 'Going Concern' section of the Financial Review.
Basis of consolidation
Subsidiaries
Subsidiaries are all entities over which the Group has the sole right to exercise control over the operations and govern the financial policies generally accompanying a shareholding of more than half of the voting rights. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing the Group's control. Subsidiaries are fully consolidated from the date on which control is transferred to the Group and are de-consolidated from the date that control ceases.
Intercompany profits, transactions and balances are eliminated on consolidation. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Group.
Joint arrangements
Oil and gas operations are usually conducted by the Group as co-licensees in unincorporated joint operations with other companies. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the consent of the relevant parties sharing control.
Most of the Group's activities are conducted through joint operations, whereby the parties that have joint control of the arrangement have the rights to the assets, and obligations for the liabilities, relating to the arrangement. The Group reports its interests in joint operations using proportionate consolidation - the Group's share of the production, assets, liabilities, income and expenses of the joint operation are combined with the equivalent items in the consolidated financial statements on a line-by-line basis.
Business combinations
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value, and the amount of any controlling interest in the acquiree. For each business combination, the acquirer measures the non-controlling interest in the acquiree either at fair value or at the proportionate share of the acquiree's identifiable net assets. Those petroleum reserves and resources that are able to be reliably valued are recognised in the assessment of fair values on acquisition. Other potential reserves, resources and rights, for which fair values cannot be reliably determined, are not recognised.
Where applicable, the consideration for the acquisition includes any asset or liability resulting from a contingent consideration arrangement, measured at its acquisition-date fair value. Subsequent changes in such fair values are adjusted against the cost of acquisition where they qualify as measurement period adjustments. All other subsequent changes in the fair value of contingent consideration classified as a financial liability are remeasured through profit or loss. If the contingent consideration is not within the scope of IAS 39, it is measured at fair value in accordance with the appropriate IFRS. Contingent consideration that is classified as equity is not remeasured and subsequent settlement is accounted for within equity.
If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Group reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the measurement period (see below), or additional assets or liabilities are recognised to reflect new information obtained about facts and circumstances that existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date.
The measurement period is the period from the date of acquisition to the date the Group obtains complete information about facts and circumstances that existed as of the acquisition date, and is subject to a maximum of one year.
2. Summary of significant accounting policies (continued)
Goodwill
Goodwill arising on a business combination is initially measured at cost, being the excess of the cost of the business combination over the net fair value of the identifiable assets, liabilities and contingent liabilities of the entity at the date of acquisition.
If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Group re-assesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, the gain is recognised in profit or loss.
Following initial recognition, goodwill is stated at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that such carrying value may be impaired.
For the purposes of impairment testing, goodwill acquired is allocated to the cash generating units ('CGU') that are expected to benefit from the synergies of the combination. Each unit or units to which goodwill is allocated represents the lowest level within the Group at which the goodwill is monitored for internal management purposes.
Impairment is determined by assessing the recoverable amount of the cash generating unit to which the goodwill relates. Where the recoverable amount of the CGU is less than the carrying amount of the CGU and related goodwill, an impairment loss is recognised. Impairment losses relating to goodwill cannot be reversed in future periods.
Critical accounting estimates and judgements
The management of the Group has to make estimates and judgements when preparing the financial statements of the Group. Uncertainties in the estimates and judgements could have an impact on the carrying amount of assets and liabilities and the Group's result. The most important estimates and judgements in relation thereto are:
Estimates in oil and gas reserves
The business of the Group is to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner. Estimates of oil and gas reserves are used in the calculations for impairment tests and accounting for depletion and decommissioning. Changes in estimates of oil and gas reserves resulting in different future production profiles will affect the discounted cash flows used in impairment testing, the anticipated date of decommissioning and the depletion charges in accordance with the unit of production method.
Estimates in impairment of oil and gas assets, goodwill and the estimate of the cost recovery provision
Determination of whether oil and gas assets or goodwill have suffered any impairment requires an estimation of the fair value less costs to dispose of the CGU to which oil and gas assets and goodwill have been allocated. The calculation requires the entity to estimate the future cash flows expected to arise from the CGU using discounted cash flow models comprising asset-by-asset life of field projections using Level 3 inputs (based on IFRS 13 fair value hierarchy). Key assumptions and estimates in the impairment models relate to: commodity prices that are based on forward curve prices for the first three years and thereafter at $70/bbl inflated at 2.0% per annum from 2022; discount rates derived from the Group's post-tax weighted average cost of capital of 10.0% (2016: 10.0%); commercial reserves and the related cost profiles. As the production and related cash flows can be estimated from EnQuest's experience, management believes that the estimated cash flows expected to be generated over the life of each field is the appropriate basis upon which to assess goodwill and individual assets for impairment.
These same models and assumptions are used in the calculation of the cost recovery provision (see note 22).
Determining the fair value of property, plant and equipment on business combinations
The Group determines the fair value of property, plant and equipment acquired in a business combination based on the discounted cash flows at the time of acquisition from the proven and probable reserves. In assessing the discounted cash flows, the estimated future cash flows attributable to the asset are discounted to their present value using a discount rate that reflects the market assessments of the time value of money and the risks specific to the asset at the time of the acquisition. In calculating the asset fair value the Group will apply a forward curve followed by an oil price assumption representing management's view of the long-term oil price.
2. Summary of significant accounting policies (continued)
Critical accounting estimates and judgements (continued)
Decommissioning provision
Amounts used in recording a provision for decommissioning are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements and technology and price levels, the carrying amounts of decommissioning provisions are reviewed on a regular basis.
The effects of changes in estimates do not give rise to prior year adjustments and are dealt with prospectively. While the Group uses its best estimates and judgement, actual results could differ from these estimates.
In estimating decommissioning provisions, the Group applies an annual inflation rate of 2.0% (2016: 2.0%) and an annual discount rate of 2.0% (2016: 2.3%).
Debt restructuring
The Group undertook debt restructuring during 2016 resulting in a substantial modification of the terms of its Revolving Credit Facility ('RCF') (see note 19). Accordingly, extinguishment accounting was applied, resulting in the derecognition of the carrying value of the facility, including any unamortised arrangement fees, and the recognition of a new financial liability for the revised facility at fair value. Costs associated with the renegotiation of the facility were expensed to the income statement as exceptional finance costs (see note 4).
Going concern
The Directors' assessment of going concern concludes that the use of the going concern basis is appropriate and that, notwithstanding the material uncertainty as provided in the 'Going Concern' section of the Financial Review, the Directors have a reasonable expectation that the Group will be able to continue in operation and meet its commitments as they fall due over the going concern period.
The going concern assumption is highly sensitive to economic conditions. The Group closely monitors and manages its funding position and liquidity risk throughout the year, including monitoring forecast covenant results, to ensure it has access to sufficient funds to meet forecast cash requirements. Cash forecasts are regularly produced and sensitivities considered for, but not limited to, changes in crude oil prices (adjusted for hedging undertaken by the Group), production rates and development project timing and costs. These forecasts and sensitivity analyses allow management to mitigate any liquidity or covenant compliance risks in a timely manner. See the Financial Review for further details.
Taxation
The Group's operations are subject to a number of specific tax rules which apply to exploration, development and production. In addition, the tax provision is prepared before the relevant companies have filed their tax returns with the relevant tax authorities and, significantly, before these have been agreed. As a result of these factors, the tax provision process necessarily involves the use of a number of estimates and judgements including those required in calculating the effective tax rate. In considering the tax on exceptional items, the Group applies the appropriate statutory tax rate to each item to calculate the relevant tax charge on exceptional items.
The Group recognises deferred tax assets on unused tax losses where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the likelihood of future taxable profits and the amount of deferred tax that can be recognised.
Foreign currencies
Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates (functional currency). The Group financial statements are presented in United States Dollars ($), the currency which the Group has elected to use as its presentation currency.
In the accounts of the Company and its individual subsidiaries, transactions in currencies other than a company's functional currency are recorded at the prevailing rate of exchange on the date of the transaction. At the year end, monetary assets and liabilities denominated in foreign currencies are retranslated at the rates of exchange prevailing at the balance sheet date. Non-monetary assets and liabilities that are measured at historical cost in a foreign currency are translated using the rate of exchange as at the dates of the initial transactions. Non-monetary assets and liabilities measured at fair value in a foreign currency are translated using the rate of exchange at the date the fair value was determined. All foreign exchange gains and losses are taken to profit and loss in the statement of comprehensive income.
2. Summary of significant accounting policies (continued)
Property, plant and equipment
Property, plant and equipment is stated at cost less accumulated depreciation and any impairment in value. Cost comprises the purchase price or construction cost and any costs directly attributable to making that asset capable of operating as intended by management. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.
Oil and gas assets are depleted, on a field-by-field basis, using the unit of production method based on entitlement to proven and probable reserves, taking account of estimated future development expenditure relating to those reserves.
Depreciation on other elements of property, plant and equipment is provided on a straight line basis at the following rates:
Office furniture and equipment 5 years Fixtures and fittings 10 years Long leasehold land period of lease
Each asset's estimated useful life, residual value and method of depreciation are reviewed and adjusted if appropriate at each financial year end.
No depreciation is charged on assets under construction.
Oil and gas assets
Exploration and appraisal assets
The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Pre-licence costs are expensed in the period in which they are incurred. Expenditure directly associated with exploration, evaluation or appraisal activities is initially capitalised as an intangible asset. Such costs include the costs of acquiring an interest, appraisal well drilling costs, payments to contractors and an appropriate share of directly attributable overheads incurred during the evaluation phase. For such appraisal activity, which may require drilling of further wells, costs continue to be carried as an asset whilst related hydrocarbons are considered capable of commercial development. Such costs are subject to technical, commercial and management review to confirm the continued intent to develop, or otherwise extract value. When this is no longer the case, the costs are written off as exploration and evaluation expenses in the statement of comprehensive income. When exploration licences are relinquished without further development, any previous impairment loss is reversed and the carrying costs are written off through the statement of comprehensive income. When assets are declared part of a commercial development, related costs are transferred to property, plant and equipment. All intangible oil and gas assets are assessed for any impairment prior to transfer and any impairment loss is recognised in the statement of comprehensive income.
Development assets
Expenditure relating to development of assets including the construction, installation and completion of infrastructure facilities such as platforms, pipelines and development wells, is capitalised within property, plant and equipment.
Farm-outs - in the exploration and evaluation phase
The Group does not record any expenditure made by the farmee on its account. In the event of a partial farm out, the Group also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements but redesignates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.
Farm-outs - outside the exploration and evaluation phase
In accounting for a farm-out arrangement outside the exploration and evaluation phase, the Group:
-- derecognises the proportion of the asset that it has sold to the farmee;
-- recognises the consideration received or receivable from the farmee, which represents the cash received and/or the farmee's obligation to fund the capital expenditure in relation to the interest retained by the farmor and/or any deferred consideration;
-- recognises a gain or loss on the transaction for the difference between the net disposal proceeds and the carrying amount of the asset disposed of. A gain is only recognised when the value of the consideration can be determined reliably. If not, then the Group accounts for the consideration received as a reduction in the carrying amount of the underlying assets; and
-- tests the retained interests for impairment if the terms of the arrangement indicate that the retained interest may be impaired.
The consideration receivable on disposal of an item of property, plant and equipment or an intangible asset is recognised initially at its fair value by the Group. However, if payment for the item is deferred, the consideration received is recognised initially at the cash price equivalent. The difference between the nominal amount of the consideration and the cash price equivalent is recognised as interest revenue. Any part of the consideration that is receivable in the form of cash is treated as a financial asset and is accounted for at amortised cost.
2. Summary of significant accounting policies (continued)
Oil and gas assets (continued)
Carry arrangements
Where amounts are paid on behalf of a carried party these are capitalised. Where there is an obligation to make payments on behalf of a carried party and the timing and amount are uncertain, a provision is recognised. Where the payment is a fixed monetary amount, a financial liability is recognised.
Changes in unit of production factors
Changes in factors which affect unit of production calculations are dealt with prospectively, not by immediate adjustment of prior years' amounts.
Borrowing costs
Borrowing costs directly attributable to the construction of qualifying assets, which are assets that necessarily take a substantial period of time to prepare for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use. All other borrowing costs are recognised as interest payable in the statement of comprehensive income in accordance with the effective interest method.
Impairment of tangible and intangible assets (excluding goodwill)
At each balance sheet date, the Group reviews the carrying amounts of its oil and gas assets to assess whether there is an indication that those assets may be impaired. If any such indication exists, the Group makes an estimate of the asset's recoverable amount. An asset's recoverable amount is the higher of an asset's fair value less costs of disposal and its value in use. In assessing value in use, the estimated future cash flows attributable to the asset are discounted to their present value using a post tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.
If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. An impairment loss is recognised immediately in the statement of comprehensive income.
Where an impairment loss subsequently reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset in prior years.
A reversal of an impairment loss is recognised immediately in the statement of comprehensive income.
Non-current assets held for sale
Non-current assets classified as held for sale are measured at the lower of carrying amount and fair value less costs of disposal.
Non-current assets 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 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.
Financial assets
Financial assets within the scope of IAS 39 are classified as financial assets at fair value through profit or loss, loans and receivables, held-to-maturity investments, available-for-sale financial investments, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. The Group determines the classification of its financial assets at initial recognition.
All assets are recognised initially at fair value plus transaction costs, except in the case of financial assets recorded at fair value through profit or loss.
Purchases or sales of financial assets that require delivery of assets within a timeframe established by regulation or convention in the marketplace (regular way trades) are recognised on the trade date.
The Group's financial assets include cash and short-term deposits, trade and other receivables, loans and other receivables, quoted and unquoted financial instruments and derivative financial instruments.
2. Summary of significant accounting policies (continued)
Financial assets (continued)
Subsequent measurement of financial assets depends on their classification as described below:
Financial assets at fair value through profit or loss ('FVTPL')
Financial assets are classified as at FVTPL when the financial asset is either held for trading or designated as at FVTPL. Financial assets are classified as held for trading if they are acquired for the purpose of selling or repurchasing in the near term. Derivatives are also classified as held for trading unless they are designated as effective hedging instruments as defined by IAS 39.
Financial assets at FVTPL, including commodity and foreign exchange derivatives, are stated at fair value, with any gains or losses arising on remeasurement recognised immediately in the income statement.
Financial assets designated upon initial recognition at FVTPL are designated at their initial recognition date and only if the criteria under IAS 39 are satisfied.
Available-for-sale financial investments
Listed and unlisted shares held by the Group that are traded in an active market are classified as being
available-for-sale and are stated at fair value. Gains and losses arising from changes in fair value are recognised in other comprehensive income and accumulated in the available-for-sale reserve with the exception of impairment losses which are recognised directly in profit or loss. Where the investment is disposed of or is determined to be impaired, the cumulative gain or loss previously recognised in the available-for-sale reserve is reclassified to profit or loss.
Loans and receivables
These include trade receivables, loans and other receivables that have fixed or determinable payments that are not quoted in an active market and 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.
Impairment of financial assets
The Group assesses, at each reporting date, whether there is any objective evidence that a financial asset is impaired. A financial asset is deemed to be impaired where there is objective evidence of impairment that, as a result of one or more events that have occurred after the initial recognition of the asset, the estimated future cash flows of the investment have been affected.
For listed and unlisted equity investments classified as available-for-sale, a significant or prolonged decline in the fair value of the security below its cost is considered to be objective evidence of impairment. When an available-for-sale financial asset is considered to be impaired, cumulative gains and losses previously recognised in other comprehensive income are reclassified to profit or loss in the period. In respect of equity securities, impairment losses previously recognised in profit or loss are not reversed through profit or loss but through other comprehensive income. Any increase in fair value subsequent to an impairment loss is recognised in other comprehensive income.
For financial assets carried at amortised cost, the amount of the impairment is the difference between the asset's carrying amount and the present value of estimated future cash flows, discounted at the financial asset's original effective interest rate. The carrying amount is reduced through use of an allowance account and the amount of the loss is recognised in profit or loss.
Derivatives
Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently remeasured at their fair value. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument.
The Group categorises derivatives as follows:
Fair value hedge
Changes in the fair value of derivatives that qualify as fair value hedging instruments are recorded in the profit or loss, together with any changes in the fair value of the hedged asset or liability.
Cash flow hedge
The effective portion of changes in the fair value of derivatives that qualify as cash flow hedges are recognised in other comprehensive income. The gain or loss relating to the ineffective portion is recognised immediately in the profit or loss. Amounts accumulated in other comprehensive income are transferred to the profit or loss in the period when the hedged item will affect the profit or loss. When the hedged item no longer meets the requirements for hedge accounting, expires or is sold, any accumulated gain or loss recognised in other comprehensive income is transferred to profit and loss when the forecast transaction which was the subject of the hedge occurs.
Where put options are used as hedging instruments, only the intrinsic value of the option is designated as the hedge, with the change in time value recorded in finance costs within the income statement.
2. Summary of significant accounting policies (continued)
Derivatives
Derivatives that do not qualify for hedge accounting
When derivatives do not qualify for hedge accounting, changes in fair value are recognised immediately in the profit or loss within 'Re-measurements and exceptional items' profit or loss on the face of the income statement. When a derivative reaches maturity, the realised gain or loss is included within the Group's Business performance results with a corresponding reclassification from 'Re-measurements and exceptional items'.
Option premium
Option premium received or paid for commodity derivatives are amortised into Business performance revenue over the period between the inception of the option, and that options expiry date. This results in a corresponding reclassification from 'Re-measurements and exceptional items' revenue.
As noted above, where put options are designated as an effective hedge, the change in time value is recorded in finance costs. As the cost of a put option represents the initial time value of that option, option premium paid for put options which have been designated as effective hedges are amortised in Business performance finance costs, with an offsetting reclassification from 'Re-measurements and exceptional items' finance costs.
Trade receivables
Trade receivables are recognised initially at fair value and subsequently measured at amortised cost less provision for impairment.
Financial liabilities
Financial liabilities within the scope of IAS 39 are classified as financial liabilities at fair value through profit or loss or other financial liabilities at amortised cost. The Group determines the classification of its financial liabilities at initial recognition.
All liabilities are recognised initially at fair value net transaction costs, except in the case of financial liabilities recorded at fair value through profit or loss.
The Group's financial liabilities include loans and borrowings, trade and other payables, quoted and unquoted financial instruments and derivative financial instruments.
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.
Interest bearing loans and borrowings
Interest bearing loans and borrowings are recognised initially at fair value, net of transaction costs incurred. Transaction costs are amortised over the life of the facility.
Borrowing costs are stated at amortised cost using the effective interest method.
The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or a shorter period to the net carrying amount of the financial liability where appropriate.
Bonds
Bonds are measured on an amortised cost basis.
Derecognition of financial assets and liabilities
Financial assets
A financial asset (or, where applicable, a part of a financial asset) is derecognised where:
-- the rights to receive cash flows from the asset have expired;
-- the Group retains the right to receive cash flows from the asset, but has assumed an obligation to pay them in full without material delay to a third party under a 'pass-through' arrangement; or
-- the Group has transferred its rights to receive cash flows from the asset and either (a) has transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset.
2. Summary of significant accounting policies (continued)
Derecognition of financial assets and liabilities (continued)
Financial liabilities
A financial liability is derecognised when the obligation under the liability is discharged, cancelled or expires.
If an existing financial liability is replaced by another from the same lender, on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability such that the difference in the respective carrying amounts, together with any costs or fees incurred, are recognised in profit or loss. IAS 39 Financial Instruments: Recognition and Measurement regards the terms of exchanged or modified debt as 'substantially different' if the net present value of the cash flows under the new terms (including any fees paid net of fees received) discounted at the original effective interest rate is at least 10.0% different from the discounted present value of the remaining cash flows of the original debt instrument. The Group also considers qualitative factors in assessing whether a modified financial liability is 'substantially different'. Where the modification is substantially different, it accounts for this as an extinguishment of the original liability even though a quantitative analysis may indicate a less than 10.0% cash flow change.
Inventories
Inventories of consumable well supplies are stated at the lower of cost and net realisable value, cost being determined on an average cost basis. Inventories of hydrocarbons are stated at the lower of cost and net realisable value.
Under/over-lift
Under or over-lifted positions of hydrocarbons are valued at market prices prevailing at the balance sheet date. An under-lift of production from a field is included in current receivables and valued at the reporting date spot price or prevailing contract price. An over-lift of production from a field is included in current liabilities and valued at the reporting date spot price or prevailing contract price. Movements in under or over-lifted positions are accounted for through cost of sales.
Cash and cash equivalents
Cash and cash equivalents includes cash at bank, cash in hand, outstanding bank overdrafts and highly liquid interest bearing securities with original maturities of three months or less.
Equity
Share capital
The balance classified as equity share capital includes the total net proceeds (both nominal value and share premium) on issue of registered share capital of the parent Company. Share issue costs associated with the issuance of new equity are treated as a direct reduction of proceeds.
Merger reserve
Merger reserve represents the difference between the market value of shares issued to effect business combinations less the nominal value of shares issued. The merger reserve in the Group financial statements also includes the consolidation adjustments that arise under the application of the pooling of interest method.
Cash flow hedge reserve
For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognised directly as other comprehensive income in the cash flow hedge reserve. Upon settlement of the hedged item, the change in fair value is transferred to profit or loss.
Available-for-sale reserve
Gains and losses (with the exception of impairment losses) arising from changes in available-for-sale financial investments are recognised in the available-for-sale reserve until such time that the investment is disposed of, where it is reclassified to profit or loss.
Share-based payments reserve
Equity-settled share-based payment transactions are measured at the fair value of the services received, and the corresponding increase in equity is recorded directly at the fair value of the services received. The share-based payments reserve includes shares held within the Employee Benefit Trust.
Retained earnings
Retained earnings contain the accumulated results attributable to the shareholders of the parent Company.
Employee Benefit Trust
EnQuest PLC shares held by the Group are deducted from the share-based payments reserve and are recognised at cost. Consideration received for the sale of such shares is also recognised in equity, with any difference between the proceeds from the sale and the original cost being taken to reserves. No gain or loss is recognised in the statement of comprehensive income on the purchase, sale, issue or cancellation of equity shares.
2. Summary of significant accounting policies (continued)
Provisions
Decommissioning
Provision for future decommissioning costs is made in full when the Group has an obligation: to dismantle and remove a facility or an item of plant; to restore the site on which it is located; and when a reasonable estimate of that liability can be made. The amount recognised is the present value of the estimated future expenditure. An amount equivalent to the discounted initial provision for decommissioning costs is capitalised and amortised over the life of the underlying asset on a unit of production basis over proven and probable reserves. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the oil and gas asset.
The unwinding of the discount applied to future decommissioning provisions is included under finance costs in the statement of comprehensive income.
Other
Provisions are recognised when: the Group has a present legal or constructive obligation as a result of past events; it is probable that an outflow of resources will be required to settle the obligation; and a reliable estimate can be made of the amount of the obligation.
Leases
The determination of whether an arrangement is or contains a lease is based on the substance of the arrangement at the inception date. The arrangement is assessed for whether fulfilment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys a right to use the asset or assets, even if that right is not explicitly specified in an arrangement.
Finance leases that transfer substantially all the risks and benefits incidental to ownership of the leased item to the Group, are capitalised at the commencement of the lease at the fair value of the leased asset or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are recognised in finance costs in the income statement.
A leased asset is depreciated over the useful life of the asset. However, if there is no reasonable certainty that the Group will obtain ownership by the end of the lease term, the asset is depreciated over the shorter of the estimated useful life of the asset and the lease term.
Lease charter payment credits, arising from the non-performance of the leased asset, are recognised as an operating expense in the income statement for the period to which they relate.
Operating lease payments are recognised as an operating expense in the income statement on a straight line basis over the lease term.
Revenue and other operating income
Revenue is recognised to the extent that it is probable economic benefits will flow to the Group and the revenue can be reliably measured.
Oil and gas revenues comprise the Group's share of sales from the processing or sale of hydrocarbons on an entitlement basis, when the significant risks and rewards of ownership have been passed to the buyer.
Tariff revenue is recognised in the period in which the services are provided at the agreed contract rates.
Rental income is accounted for on a straight line basis over the lease terms and is included in revenue in the income statement.
The Group uses various commodity derivative instruments to manage some of the risks arising from fluctuations in commodity prices. Such contracts include options, swaps and futures. Where these derivatives have been designated as cash flow hedges of underlying commodity price exposures, certain gains and losses attributable to these instruments are deferred in other comprehensive income and recognised in the income statement within revenue and other operating income when the underlying hedged transaction crystallises or is no longer expected to occur.
All other commodity derivatives within the scope of IAS 39 are measured at fair value with changes in fair value recognised in the income statement within revenue and other operating income. Unrealised mark to market changes in the remeasurement of derivative contracts are initially included in exceptional items within profit or loss. When the derivative reaches maturity, the gain or loss is realised and recycled to be included within Business performance.
2. Summary of significant accounting policies (continued)
Re-measurements and exceptional items
As permitted by IAS 1 (Revised): Presentation of Financial Statements, certain items are presented separately. The items that the Group separately presents as exceptional on the face of the statement of comprehensive income are those material items of income and expense which, because of the nature or expected infrequency of the events giving rise to them, merit separate presentation to allow shareholders to understand better the elements of financial performance in the year, so as to facilitate comparison with prior periods and to better assess trends in financial performance.
The following items are routinely classified as Remeasurements and exceptional items ('exceptional'):
-- Unrealised mark to market changes in the remeasurement of derivative contracts are included in exceptional profit or loss. This includes the recycling of realised amounts from exceptional items into Business performance income when a derivative instrument matures, together with the recycling of option premium amortisation from exceptional to Business performance as set out in the Derivatives policy previously;
-- Impairments and write offs/write downs are deemed to be exceptional in nature. This includes impairments of tangible and intangible assets, and write offs/write downs of unsuccessful exploration. Other non-routine write offs/write downs, where deemed material, are also included in this category; and
-- The depletion of a fair value uplift to property, plant and equipment that arose from the merger accounting applied at the time of EnQuest's formation.
Employee benefits
Short-term employee benefits
Short-term employee benefits such as salaries, social premiums and holiday pay, are expensed when incurred.
Pension obligations
The Group's pension obligations consist of defined contribution plans. A defined contribution plan is a pension plan under which the Group pays fixed contributions. The Group has no further payment obligations once the contributions have been paid. The amount charged to the statement of comprehensive income in respect of pension costs reflects the contributions payable in the year. Differences between contributions payable during the year and contributions actually paid are shown as either accrued liabilities or prepaid assets in the balance sheet.
Share-based payment transactions
Eligible employees (including Directors) of the Group receive remuneration in the form of share-based payment transactions, whereby employees render services in exchange for shares or rights over shares (equity-settled transactions) of EnQuest PLC.
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value at the date on which they are granted. Fair value is measured in reference to the scheme rules, as detailed in note 18. In valuing
equity-settled transactions, no account is taken of any service or performance conditions, other than conditions linked to the price of the shares of EnQuest PLC (market conditions) or 'non-vesting' conditions, if applicable.
The cost of equity-settled transactions is recognised over the period in which the relevant employees become fully entitled to the award (the vesting period). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The statement of comprehensive income charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.
No expense is recognised for awards that do not ultimately vest, except for awards where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance conditions are satisfied. Equity awards cancelled are treated as vesting immediately on the date of cancellation, and any expense not previously recognised for the award at that date is recognised in the statement of comprehensive income.
2. Summary of significant accounting policies (continued)
Taxes
Income taxes
Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities, based on tax rates and laws that are enacted or substantively enacted by the balance sheet date.
Deferred tax is provided in full on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Group financial statements. However, deferred tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred tax is measured on an undiscounted basis using tax rates (and laws) that have been enacted or substantively enacted by the balance sheet date and are expected to apply when the related deferred tax asset is realised or the deferred tax liability is settled. Deferred tax assets are recognised to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilised.
Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.
The carrying amount of deferred income tax assets is reviewed at each balance sheet date. Deferred income tax assets and liabilities are offset only if a legal right exists to offset current tax assets against current tax liabilities, the deferred income taxes relate to the same taxation authority and that authority permits the Group to make a single net payment.
Production taxes
In addition to corporate income taxes, the Group's financial statements also include and disclose production taxes on net income determined from oil and gas production.
Production tax relates to Petroleum Revenue Tax ('PRT') and is accounted for under IAS 12 Income Taxes since it has the characteristics of an income tax as it is imposed under Government authority and the amount payable is based on taxable profits of the relevant fields. Current and deferred PRT is provided on the same basis as described above for income taxes.
Investment allowances
The UK taxation regime provides for a reduction in ring fence supplementary corporation tax where investments in new or existing UK assets qualify for a relief known as investment allowances. Investment allowances are only triggered when production from the field commences. The Group is eligible for a number of investment allowances which will materially reduce the level of future supplementary corporation taxation. Investment allowances are recognised as a reduction in the charge to taxation in the years claimed.
3. Segment information
Management have considered the requirements of IFRS 8: Operating Segments in regard to the determination of operating segments and concluded that the Group has two significant operating segments; the North Sea and Malaysia. Operations are managed by location and all information is presented per geographical segment. The information reported to the Chief Operating Decision Maker does not include an analysis of assets and liabilities and accordingly this information is not presented.
Year ended 31 Adjustments and
December 2017 North Sea Malaysia All other segments Total segments eliminations Consolidated
$'000
-------------------- ---------- --------- ------------------- --------------- -------------------- -------------
Revenue:
External customers 535,850 119,892 - 655,742 (28,291) 627,451
Total Group revenue 535,850 119,892 - 655,742 (28,291) 627,451
========== ========= =================== =============== ==================== =============
Income/(expenses):
Depreciation and
depletion (201,684) (27,514) - (229,198) - (229,198)
Net impairment
reversal/(charge)
to oil and gas
assets (187,716) 15,745 - (171,971) - (171,971)
Impairment reversal
of investments (19) - - (19) - (19)
Exploration write
offs and
impairments 193 - - 193 - 193
Segment
profit/(loss) (135,187) 39,062 22,844 (73,281) (23,413) (96,694)
========== ========= =================== =============== ==================== =============
Other disclosures:
Capital expenditure 322,398 2,299 - 324,697 - 324,697
========== ========= =================== =============== ==================== =============
Year ended 31 Adjustments and
December 2016 North Sea Malaysia All other segments Total segments eliminations Consolidated
$'000
-------------------- ----------- ---------- ------------------- --------------- ------------------ -------------
Revenue:
External customers 485,609 108,215 - 593,824 204,299 798,123
Total Group revenue 485,609 108,215 - 593,824 204,299 798,123
=========== ========== =================== =============== ================== =============
Income/(expenses):
Depreciation and
depletion (209,194) (36,582) (33) (245,809) - (245,809)
Net impairment
reversal/(charge)
to oil and gas
assets 167,838 (19,967) - 147,871 - 147,871
Impairment reversal
of investments 48 - - 48 - 48
Exploration write
offs and
impairments (776) - - (776) - (776)
Loss on disposal of
assets (16,178) - - (16,178) - (16,178)
Segment
profit/(loss) 216,658 (5,836) (1,561) 209,261 135,818 345,079
=========== ========== =================== =============== ================== =============
Other disclosures:
Capital expenditure 646,489 4,585 9 651,083 277 651,360
=========== ========== =================== =============== ================== =============
3. Segment information (continued)
Adjustments and eliminations
Finance income and costs and gains and losses on derivatives are not allocated to individual segments as the underlying instruments are managed on a Group basis.
Capital expenditure consists of property, plant and equipment and intangible assets, including assets from the acquisition of subsidiaries.
Inter-segment revenues are eliminated on consolidation. All other adjustments are part of the reconciliations presented further below.
Reconciliation of (loss)/profit:
Year ended 31 December Year ended
2017 31 December 2016
$'000 $'000
Segment profit/(loss) (73,281) 209,261
Finance income 2,213 1,440
Finance expense (149,292) (129,275)
Gains and losses on oil and foreign exchange derivatives (23,413) 135,818
Profit/(loss) before tax (243,773) 217,244
======================= ==================
Revenue from two customers (2016: three customers) each exceed 10% of the Group's consolidated revenue arising from sales of crude oil and amounted respectively to $206.1 million in the North Sea operating segment and $105.2 million in the Malaysia operating segment (2016: $321.0 million and $85.7 million arising in the North Sea operating segment and $89.9 million in Malaysia operating segment).
All of the Group's segment assets (non-current assets excluding financial instruments, deferred tax assets and other financial assets) are located in the United Kingdom except for $119.1 million located in Malaysia (2016: $128.1 million).
4. Re-measurements and exceptional items
Fair value
Year ended 31 December 2017 re-measurement Impairments and write offs Other Total
$'000 (i) (ii) (iii)
----------------------------------------------- ---------------- --------------------------- --------- -----------
Revenue and other operating income (7,716) - - (7,716)
Cost of sales 9,726 (2,682) (1,563) 5,481
Net impairment (charge)/reversal on oil and
gas assets - (171,971) - (171,971)
Other income 1,685 193 48,735 50,613
Other expenses - (19) (20,339) (20,358)
Finance costs - - (272) (272)
----------------------------------------------- ---------------- --------------------------- --------- -----------
3,695 (174,479) 26,561 (144,223)
Tax on items above (1,473) 65,730 5,482 69,739
Other tax exceptional items (iv) - - 47,208 47,208
-----------------------------------------------
2,222 (108,749) 79,251 (27,276)
----------------------------------------------- ---------------- --------------------------- --------- -----------
(i) Fair value re-measurements include unrealised mark to market movements on derivative contracts and other financial instruments where the Group does not classify them as effective hedges. It also includes the impact of recycling realised gains and losses (including option premia) out of 'Re-measurements and exceptional items' and into 'Business performance' profit or loss. In addition a $1.3 million gain in respect to the disposal of Ascent Resources loan notes was recognised in 2017. Refer to note 2 for further details on the Group's accounting policies for derivatives and 'Re-measurements and exceptional items'.
(ii) Impairments and write offs includes an impairment of tangible oil and gas assets totalling $172.0 million (2016: impairment reversal of $147.9 million), together with a charge of $2.7 million in relation to inventory write downs, a $0.02 million impairment on the investment in Ascent Resources (2016: $0.05 million impairment) and a $0.2 million write back of previously impaired exploration costs (2016: $0.8 million impairment/write off). Further details on the tangible impairment are provided in note 10.
(iii) Other mainly includes a gain in relation to the excess of fair value over cost arising on the acquisition of the Magnus oil field and other interests compromising of the $22.3 million purchase option, $16.1 million Thistle decommissioning option and $10.3 million 25% acquisition value, totalling a gain of $48.7 million (see note 29). Other items include a charge of $10.3 million in relation to the 2014 PM8 cost recovery settlement agreement, a charge of $6.4 million for the cancellation of contracts and a charge of $2.8 million in relation to the provision on restricted cash (see note 16). Other income also includes other items of income and expense which, because of the nature or expected infrequency of the events giving rise to them, merit separate presentation to allow shareholders to understand better the elements of financial performance in the year so as to facilitate comparison with prior periods and to better assess trends in financial performance.
(iv) Other tax exceptional items include $13.2 million for the recognition of previously de-recognised tax losses, together with $34.0 million for the impact on deferred tax of a revision to the balance of non-qualifying expenditure.
4. Re-measurements and exceptional items (continued)
Impairments
Year ended 31 Fair value and write Debt Surplus lease Loss on
December 2016 re-measurement offs restructuring provision disposal Other Total
$'000 (i) (ii) (iii) (iv)
--------------- --------------- -------------- -------------- -------------- -------------- --------- ---------
Revenue and
other
operating
income (51,504) - - - - - (51,504)
Cost of sales (1,584) - - - - (1,264) (2,848)
Net impairment
reversal on
oil and gas
assets - 147,871 - - - - 147,871
Loss on
disposal of
intangible
oil and gas
assets - - - - (16,178) - (16,178)
Other income 2,837 48 - 22,948 - 5,721 31,554
Other expenses - (776) - - - (118) (894)
Finance costs 31,072 - (38,115) - - - (7,043)
--------------- --------------- -------------- -------------- -------------- -------------- --------- ---------
(19,179) 147,143 (38,115) 22,948 (16,178) 4,339 100,958
Tax on items
above 8,797 (67,037) 10,323 (9,179) - 506 (56,590)
Change in tax
rate (v) - - - - - (29,483) (29,483)
Increase in
the carrying
amount of
deferred tax
assets (vi) - - - - - 48,817 48,817
---------------
(10,382) 80,106 (27,792) 13,769 (16,178) 24,179 63,702
--------------- --------------- -------------- -------------- -------------- -------------- --------- ---------
(i) The Group's restructuring was deemed to result in a substantial modification of the terms of the Group's credit facility (see note 19). In accordance with IAS 39, the Group has accounted for this substantial modification as an extinguishment of the liability for the original credit facility and the recognition of a new liability for the revised credit facility. In 2016, this resulted in $15.0 million of unamortised costs associated with the previous credit facility being expensed on extinguishment. The costs of negotiating the modifications to the credit facility, totalling $11.1 million and a $12.0 million restructuring fee, payable to the credit facility lenders by March 2018, were expensed. In 2016, these comprised an aggregate of $38.1 million of debt restructuring costs.
(ii) The Group had an agreement to hire the Stena Spey drilling vessel. Based on the drilling forecasts for 2016, it was expected that the vessel would not be fully utilised over this period and therefore a provision was recognised for unavoidable contracted costs of $22.9 million. During the year ended 31 December 2016, following changes to the Group's drilling schedule, the contracted days were utilised in full and the provision of $22.9 million was reversed in full.
(iii) During the year ended 31 December 2016, the Group disposed of its interest in the Avalon prospect for cash proceeds of $1.5 million, resulting in a loss on disposal of $16.2 million (see note 12).
(iv) In 2016, other primarily included a $3.4 million reversal of a provision for contingent consideration which was no longer required following the results of the Eagle well drilled during the year and a $1.3 million depreciation of the fair value uplift.
(v) The Finance Act 2016 enacted a change in the supplementary charge tax rate, reducing it from 20% to 10%, and a change to petroleum revenue tax rate, reducing it from 35% to 0%, both effective from 1 January 2016. The Finance Act 2016 also enacted a reduction in the mainstream corporation tax rate reducing it from 18% to 17% with effect from 1 April 2020.
The impact of these changes in tax rates in 2016 was a tax charge of $29.5 million.
(vi) At the year ended 31 December 2016, the recovery of deferred tax assets was reviewed which has led to a recognition of previously impaired tax losses totalling $48.8 million. This write back reflects the increase in value of the Group's assets following a partial recovery of oil prices.
5. Revenue and expenses
(a) Revenue and other operating income
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Revenue from crude oil sales 636,966 577,822
Revenue from gas and condensate sales 2,822 3,628
Realised (losses)/gains on oil derivative contracts (see note 20(e)) (20,575) 255,803
Tariff revenue 7,029 4,915
Other operating revenue 1,851 142
Rental income 7,074 7,317
------------- -------------
Business performance revenue 635,167 849,627
Unrealised (losses)/gains on oil derivative contracts* (see note 20(e)) (7,716) (51,504)
------------- -------------
Total revenue and other operating income 627,451 798,123
============= =============
* Unrealised gains and losses on oil derivative contracts which are either ineffective for hedge accounting purposes or held for trading are disclosed as exceptional items in the income statement (see note 4).
(b) Cost of sales
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Cost of operations 299,721 285,040
Tariff and transportation expenses 62,208 58,139
Realised loss/(gain) on foreign exchange derivative contracts(i) (see note 20(e)) 4,848 66,898
Change in lifting position (20,643) 4,656
Crude oil inventory movement 237 (1,830)
Depletion of oil and gas assets (see note 10) 223,135 240,615
------------- -------------
Business performance cost of sales 569,506 653,518
Depletion of oil and gas assets (see note 10) 1,563 1,264
Write down of inventory 2,682 -
Unrealised (gains)/losses on foreign exchange derivative contracts(ii) (see note 20(e)) (9,726) 1,584
------------- -------------
Total cost of sales 564,025 656,366
============= =============
(i) The realised loss on foreign exchange derivative contracts was $4.8 million for contracts related to capital expenditure (2016: loss of $19.6 million related to operating expenditure and loss of $47.3 million related to capital expenditure).
(ii) Unrealised gains and loss on foreign exchange derivative contracts which are either ineffective for hedge accounting purposes or held for trading are disclosed as exceptional in the income statement (see note 4).
(c) General and administration expenses
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Staff costs (see note 5(f)) 79,138 86,773
Depreciation (see note 10) 4,500 3,930
Other general and administration costs 20,077 32,355
Recharge of costs to operations and joint venture partners (102,867) (112,168)
------------- -------------
848 10,890
============= =============
5. Revenue and expenses (continued)
(d) Other income
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Net foreign exchange gains - 51,867
Prior year general and administrative expenses recovery 5,101 -
Other income 1,706 69
------------- -------------
Business performance other income 6,807 51,936
Excess of fair value over consideration: Purchase option (see note 29) 22,300 -
Excess of fair value over consideration: Thistle decommissioning option (see note 29) 16,120 -
Excess of fair value over consideration: 25% acquisition value (see note 29) 10,314 -
Release of surplus lease provision - 22,948
Gain on disposal of financial assets 1,263 -
Change in provision for contingent consideration 423 4,056
Fair value movements on financial assets - 2,151
Decommissioning provision reduction - 1,627
Acquisition accounting adjustment - 694
Other exceptional income 193 78
Total other income 57,420 83,490
============= =============
(e) Other expenses
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Net foreign exchange losses 23,910 -
Exploration and evaluation expenses: Pre-licence costs expensed 43 68
Other 410 9
------------- -------------
Business performance other expenses 24,363 77
2014 PM8 cost recovery settlement agreement 10,329 -
Early termination of contracts 6,435 -
Write down of receivable 2,808 118
Exploration and evaluation expenses: written off and impaired - 776
Other expenses 786 -
Total other expenses 44,721 971
============= =============
(f) Staff costs
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Wages and salaries 48,773 47,089
Social security costs 4,686 4,458
Defined contribution pension costs 3,057 3,522
Expense of share-based payments (see note 18) 2,849 8,452
Other staff costs 2,486 2,709
Total employee costs 61,851 66,230
Contractor costs 17,287 20,543
Total staff costs 79,138 86,773
============= =============
The average number of persons employed by the Group during the year was 506 (2016: 477).
5. Revenue and expenses (continued)
(g) Auditor's remuneration
The following amounts were payable by the Group to its auditor, Ernst & Young LLP, during the year:
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Fees payable to the Company's auditor for the audit of the parent company
and Group financial statements 584 515
------------- -------------
Fees payable to the Company's auditor and its associates for other services:
The audit of the Company's subsidiaries 114 74
Audit related assurance services (interim review) 181 71
Tax advisory services 5 58
Corporate finance services(*) - 312
------------- -------------
300 515
------------- -------------
884 1,030
============= =============
*Relates to the reporting accountant's report on the unaudited pro forma financial information in Company's prospectus for the placing and open offer (see note 17).
6. Finance costs/income
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Finance costs:
Loan interest payable 74,434 50,789
Bond interest payable 63,463 59,689
Unwinding of discount on decommissioning provisions (see note 22) 11,471 10,724
Unwinding of discount on other provisions (see note 22) 1,838 3,173
Unwinding of discount on financial liabilities (see note 20(f)) 163 279
Fair value (gain)/loss on financial instruments at FVTPL (see note 20(e)) (15) 36,516
Finance charges payable under finance leases 31,273 -
Amortisation of finance fees on loans and bonds 2,760 5,910
Other financial expenses 5,902 10,501
191,289 177,581
Less: amounts capitalised to the cost of qualifying assets (42,269) (55,349)
------------- -------------
Business performance finance expenses 149,020 122,232
Fair value loss on financial instruments at FVTPL (see note 20(e)) - (31,072)
Debt restructuring costs (see note 4) - 38,115
Unwinding of discounts on other provisions 272 -
149,292 129,275
============= =============
Finance income:
Bank interest receivable 381 337
Unwinding of discount on financial asset (see note 20(f)) 1,832 1,017
Other financial income - 86
------------- -------------
2,213 1,440
============= =============
7. Income tax
(a) Income tax
The major components of income tax (credit)/expense are as follows:
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
Current income tax
Current income tax charge 214 -
Adjustments in respect of current income tax of previous years (932) -
Current overseas income tax
Current income tax charge 11,191 11,269
Adjustments in respect of current income tax of previous years 263 (1,294)
------------- -------------
Total current income tax 10,736 9,975
Deferred income tax
Relating to origination and reversal of temporary differences (202,173) (4,756)
Adjustments in respect of changes in tax rates - 29,483
Adjustments in respect of deferred income tax of previous years 14,469 3,021
Deferred overseas income tax
Relating to origination and reversal of temporary differences (5,840) (7,511)
Adjustments in respect of deferred income tax of previous years (135) 1,820
------------- -------------
Total deferred income tax (193,679) 22,057
Income tax (credit)/expense reported in profit or loss (182,943) 32,032
============= =============
(b) Reconciliation of total income tax charge
A reconciliation between the income tax charge and the product of accounting profit multiplied by the UK statutory tax rate is as follows:
Year ended Year ended
31 December 31 December
2017 2016
$'000 $'000
(Loss)/profit before tax (243,773) 217,244
------------- -------------
Statutory rate of corporation tax in the UK of 40% (2016: 40%) (97,509) 86,898
Supplementary corporation tax non-deductible expenditure 21,170 (11,390)
Non-deductible expenditure(i) (7,673) 32,631
Non-deductible loss on disposals - 4
Petroleum revenue tax (net of income tax benefit)(ii) 3,703 (3,702)
North Sea tax reliefs (93,234) (102,149)
Tax in respect of non-ring fence trade (9,085) 27,653
Tax losses not recognised(iii) (11,230) (39,198)
Deferred tax rate changes - 29,483
Adjustments in respect of prior years 13,665 3,547
Overseas tax rate differences (4,163) 4,362
Share-based payments 1,475 3,154
Other differences (62) 739
------------- -------------
At the effective income tax rate of 75% (2016: 15%) (182,943) 32,032
============= =============
(i) Movement is primarily the impact of the excess of fair value over consideration
(ii) Movement is primarily the derecognition of Alba decommissioning asset
(iii) Current year tax credit is the re-recognition of non-ring fence losses de-recognised in 2016
7. Income tax (continued)
(c) Deferred income tax
Deferred income tax relates to the following:
(Credit)/charge for the year recognised in profit or loss
Group balance sheet
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Deferred tax liability
Accelerated capital
allowances 1,163,562 1,085,456 28,290 73,310
Other temporary differences - - - (36,850)
------------ ------------
1,163,562 1,085,456
Deferred tax asset
Losses (1,228,034) (1,060,036) (167,998) (59,477)
Decommissioning liability (254,008) (185,418) (68,590) 48,891
Other temporary differences (17,098) (31,717) 14,619 (3,817)
------------ ------------ --------------------------- ---------------------------
(1,499,140) (1,277,171)
Deferred tax expense (193,679) 22,057
=========================== ===========================
Net deferred tax
(assets)/liabilities (335,578) (191,715)
============ ============
Reflected in the balance
sheet as follows:
Deferred tax assets (398,263) (206,742)
Deferred tax liabilities 62,685 15,027
------------ ------------
Net deferred tax
(assets)/liabilities (335,578) (191,715)
============ ============
Reconciliation of net deferred tax assets/(liabilities) 2017 2016
$'000 $'000
At 1 January 191,715 79,327
Tax income/(expense) during the period recognised in profit or loss 193,679 (22,057)
Tax income/(expense) during the period recognised in other comprehensive income - 134,177
Deferred taxes acquired (see note 29) (49,816) 268
--------- ---------
At 31 December 335,578 191,715
========= =========
(d) Tax losses
The Group's deferred tax assets at 31 December 2017 are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised. In accordance with IAS 12 Income Taxes the Group assessed the recoverability of its deferred tax assets at 31 December 2017 with respect to ring fence tax losses and allowances. The impairment model used to assess the extent to which it is appropriate to recognise the Group's UK tax losses as deferred tax assets was run, using an oil price assumption of Dated Brent forward curve in the years 2018 to 2021 followed by $70/bbl inflated at 2.0% per annum from 2022. The results of the impairment model demonstrated that it was appropriate to recognise a deferred tax asset on $24.2 million
(2016: $214.3 million recognised deferred tax asset) of the Group's UK ring fence corporate tax losses at
31 December 2017 based on expected future profitability. The recognised loss amount results in a deferred tax credit of $9.7 million (2016: $85.7 million credit) for the year in respect of losses and allowances that were previously not recognised as a deferred tax asset.
The Group has unused UK mainstream corporation tax losses of $290.2 million (2016: $285.8 million) for which no deferred tax asset has been recognised at the balance sheet date due to uncertainty of recovery of these losses.
The Group has unused overseas tax losses in Canada of approximately CAD$13.5 million (2016: CAD$13.4 million) for which no deferred tax asset has been recognised at the balance sheet date. The tax losses in Canada have expiry periods of 20 years, none of which expire in 2018, and which arose following the change in control of the Stratic group in 2010.
The Group has unused Malaysian income tax losses of $5.2 million (2016: $3.1 million) arising in respect of the Tanjong Baram RSC for which no deferred tax asset has been recognised at the balance sheet date due to uncertainty of recovery of these losses.
No deferred tax has been provided on unremitted earnings of overseas subsidiaries, Finance Act 2009 exempted foreign dividends from the scope of UK corporation tax where certain conditions are satisfied.
7. Income tax (continued)
(e) Change in legislation
Finance Act 2016 enacted a change in the mainstream corporation tax rate, reducing it from 18% to 17% with effect from 1 April 2020. The impact of the change in tax rate in 2016 was a tax charge of $0.7 million.
Finance Act 2016 also enacted a change in the supplementary charge tax rate, reducing it from 20% to 10% with effect from 1 January 2016 and a change to the petroleum revenue tax rate, reducing it from 35% to 0% with effect from
1 January 2016. The impact of the change in tax rate in 2016 was a tax charge of $28.9 million.
Finance Act 2017 enacted legislation in relation to the restriction of corporate interest deductions from 1 April 2017 and the restriction of relief for mainstream corporate tax losses with effect from 1 April 2017. While these changes do not impact North Sea ring fence activities directly, they have an impact on the current year Group tax charge where North Sea ring fence losses are offset against mainstream corporate tax profits which would otherwise be exposed due to the operation of these new rules. The impact of these changes in the current year was a tax charge of $15.1 million.
8. Earnings per share
The calculation of earnings per share is based on the profit after tax and on the weighted average number of Ordinary shares in issue during the period.
Basic and diluted earnings per share are calculated as follows:
Weighted average number of
Profit /(loss) after tax Ordinary shares Earnings per share
Year ended 31 December Year ended 31 December Year ended 31 December
2017 2016 2017 2016 2017 2016
$'000 $'000 million million $ $
Basic (60,830) 185,212 1,128.1 815.3 (0.054) 0.227
Dilutive potential of
Ordinary shares
granted under
share-based incentive
schemes - - 53.0 24.6 - (0.006)
Diluted (60,830) 185,212 1,181.1 839.9 (0.054) 0.221
=============== ============ ================ ================ ============ ===========
Basic (excluding
exceptional items) (33,554) 121,510 1,128.1 815.3 (0.030) 0.149
=============== ============ ================ ================ ============ ===========
Diluted (excluding
exceptional items) (33,554) 121,510 1,181.1 839.9 (0.030) 0.145
=============== ============ ================ ================ ============ ===========
9. Dividends paid and proposed
The Company paid no dividends during the year ended 31 December 2017 (2016: none). At 31 December 2017, there are no proposed dividends (2016: none).
10. Property, plant and equipment
Oil and gas assets Office furniture, fixtures and fittings Total
$'000 $'000 $'000
Cost:
At 1 January 2016 6,165,488 51,865 6,217,353
Additions 629,654 2,857 632,511
Acquired (see note 29) 40,695 - 40,695
Change in cost carry liabilities 26,042 - 26,042
Change in decommissioning provision (34,423) - (34,423)
Change in cost recovery provision (40,389) - (40,389)
Reclassification from intangible assets
(see note 12) 276 - 276
At 31 December 2016 6,787,343 54,722 6,842,065
Additions 320,627 2,994 323,621
Initial recognition of finance lease
asset (see note 24) 771,975 - 771,975
Acquired (see note 29) 124,542 - 124,542
Change in decommissioning provision (see
note 22) 143,992 - 143,992
Change in cost recovery provision (see
note 22) (77,785) - (77,785)
At 31 December 2017 8,070,694 57,716 8,128,410
------------------- ---------------------------------------- -----------
Accumulated depletion and impairment:
At 1 January 2016 3,752,020 28,661 3,780,681
Charge for the year 241,879 3,930 245,809
Net impairment reversal for the year (147,871) - (147,871)
At 31 December 2016 3,846,028 32,591 3,878,619
Charge for the year 224,698 4,500 229,198
Impairment charge for the year 171,971 - 171,971
At 31 December 2017 4,242,697 37,091 4,279,788
------------------- ---------------------------------------- -----------
Net carrying amount:
At 31 December 2017 3,827,997 20,625 3,848,622
=================== ======================================== ===========
At 31 December 2016 2,941,315 22,131 2,963,446
=================== ======================================== ===========
At 1 January 2016 2,413,468 23,204 2,436,672
=================== ======================================== ===========
10. Property, plant and equipment (continued)
During 2017 the Group acquired a 25% interest in Magnus oil field and other interests (see note 29), resulting in an acquisition of assets at a value of $124.5 million allocated to property, plant and equipment.
During the year ended 31 December 2017, the Group's lease from Armada Kraken PTE Limited ('BUMI') of the FPSO for the Kraken field commenced. The lease has been assessed as a finance lease, and a $772.0 million lease liability and lease asset were recognised in June 2017. The liability was calculated based on the present value of the minimum lease payments at inception of the lease (see note 24).
During the year ended 31 December 2016, the Group acquired an additional 10.5% interest in the Kraken asset and an additional 15.15% interest in the West Don field, resulting in aggregate purchase consideration of $40.7 million allocated to property, plant and equipment (see note 29).
During the year ended 31 December 2016, a liability of $26.6 million was recognised for the carry payable for the Kraken field following the finalisation of a reserve determination (see note 22). The amount payable was dependent upon the dated Brent forward curve at the date of the reserve determination. Change in carry liabilities also includes a $0.2 million decrease in the liability (see note 20(f)) for Malaysian assets (2016: decrease of $0.5 million).
Impairments to the Group's producing oil and gas assets and reversals of impairments are is set out in the table below:
Impairment (charge)/reversal Recoverable amount(iv)
------------------------------- --------------------------
Year ended Year ended
31 December 31 December 31 December 31 December
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Central North Sea(i) (93,288) (184,437) 16,873 296,989
Northern North Sea(ii) (94,428) 352,275 284,858 848,628
Malaysia(iii) 15,745 (19,967) 48,301 39,748
Net impairment reversal/(charge) (171,971) 147,871
--------------- --------------
(i) Amounts disclosed for Central North Sea include Alma/Galia and Alba. The impairment of Alma/Galia is primarily driven by performance issues relating to Electric Submersible Pumps and underlying natural declines in fields.
(ii) Northern North Sea includes Heather Broom, Thistle/Deveron and the Dons fields. The impairments are attributable primarily to underlying natural declines in the fields.
(iii) The amounts disclosed for Malaysia relate to the Tanjong Baram field.
(iv) Recoverable amount has been determined on a fair value less costs of disposal basis (see note 11 for further details of methodology and assumptions used, and note 2 Critical Accounting Estimates and Judgements for information on significant estimates and judgements made in relation to impairments). The amounts disclosed above are in respect of assets where an impairment (or reversal) has been recorded. Assets which did not have any impairment or reversal are excluded from the amounts disclosed.
The net book value at 31 December 2017 includes $71.1 million (2016: $1,536.6 million) of pre-development assets and development assets under construction which are not being depreciated.
The amount of borrowing costs capitalised during the year ended 31 December 2017 was $42.3 million
(2016: $55.3 million) and relate to the Kraken development project (2016: Kraken and Scolty/Crathes development projects). The weighted average rate used to determine the amount of borrowing costs eligible for capitalisation is 7.0% (2016: 6.2%).
The net book value of property, plant and equipment held under finance leases and hire purchase contracts at
31 December 2017 was $756.3 million (2016: $nil) of oil and gas assets.
11. Goodwill
A summary of goodwill is presented below:
2017 2016
$'000 $'000
Cost and net carrying amount
At 1 January and 31 December 189,317 189,317
--------- ---------
The goodwill balance arose from the acquisition of Stratic and PEDL in 2010 and the Greater Kittiwake Area asset in 2014.
Goodwill acquired through business combinations has been allocated to a single CGU, the UK Continental Shelf ('UKCS'), and this is therefore the lowest level at which goodwill is reviewed.
Impairment testing of oil and gas assets and goodwill
In accordance with IAS 36: Impairment of Assets, goodwill and oil and gas assets have been reviewed for impairment at the year end. In assessing whether goodwill and oil and gas assets have been impaired, the carrying amount of the CGU for goodwill and at field level for oil and gas assets is compared with their recoverable amounts.
The recoverable amounts of the CGU and fields have been determined on a fair value less costs to sell basis. Discounted cash flow models comprising asset-by-asset life of field projections using Level 3 inputs (based on IFRS 13 fair value hierarchy) have been used to determine the recoverable amounts. The cash flows have been modelled on a post-tax and post-decommissioning basis discounted at the Group's post-tax weighted average cost of capital ('WACC') of 10.0% (2016: 10.0%). Risks specific to assets within the CGU are reflected within the cash flow forecasts.
Key assumptions used in calculations
The key assumptions required for the calculation of the recoverable amounts are:
-- oil prices; -- currency exchange rates; -- production volumes; -- discount rates; and -- opex, capex and decommissioning costs.
Oil prices are based on Dated Brent forward price curve for the first three years and thereafter at $70/bbl from 2021.
Production volumes are based on life of field production profiles for each asset within the CGU. The production volumes used in the calculations were taken from the report prepared by the Group's independent reserve assessment experts.
Operating expenditure, capital expenditure and decommissioning costs are derived from the Group's Business Plan adjusted for changes in timing based on the production model used for the assessment of proven and probable ('2P') reserves.
The discount rate reflects management's estimate of the Group's WACC. The WACC takes into account both debt and equity. The cost of equity is derived from the expected return on investment by the Group's investors. The cost of debt is based on its interest bearing borrowings. Segment risk is incorporated by applying a beta factor based on publicly available market data. The post-tax discount rate applied to the Group's post-tax cash flow projections was 10.0% (2016: 10.0%). Management considers this to be the best estimate of a market participant's discount rate.
Sensitivity to changes in assumptions
The Group's recoverable value of assets is highly sensitive, inter alia, to oil price achieved and production volumes. The recoverable amount of the CGU would be equal to the carrying amount of goodwill if either the oil price or production volumes (on a CGU weighted average basis) were to fall by 7% (2016: 9%) from the prices outlined above. Goodwill would need to be fully impaired if the oil price or production volumes (on a CGU weighted average basis) were to fall by 16% from the prices outlined above (2016: 13%). The above sensitivities have flexed revenues and tax cash flows, but operating costs and capital expenditures have been kept constant.
12. Intangible oil and gas assets
Cost Accumulated impairment Net carrying amount
$'000 $'000 $'000
At 1 January 2016 226,715 (180,185) 46,530
Additions 18,849 - 18,849
Disposal of interests in licences (17,644) - (17,644)
Write off of relinquished licences previously impaired (1,311) 1,311 -
Unsuccessful exploration expenditure written off (458) - (458)
Change in decommissioning provision 3,649 - 3,649
Reclassified to tangible fixed assets (see note 10) (276) - (276)
Impairment charge for the year - (318) (318)
----------
At 31 December 2016 229,524 (179,192) 50,332
Additions 1,076 - 1,076
Write off of relinquished licences previously impaired (3,076) 3,076 -
Unsuccessful exploration expenditure previously written
off - 159 159
Change in decommissioning provision (see note 22) 502 - 502
Impairment charge for the year - 34 34
---------- ----------------------- --------------------
At 31 December 2017 228,026 (175,923) 52,103
========== ======================= ====================
During the year ended 31 December 2017, the Group continued to develop the Kraken field resulting in the additions to intangibles. The Group also concluded on the unsuccessful exploration costs resulting in a write off of $3.1 million.
During the year ended 31 December 2016, the Group disposed of its interest in the Avalon prospect for $1.5 million, realising a loss on disposal of $16.2 million (see note 4). The additions in 2016 and the related change in decommissioning provision primarily related to the Eagle well which was drilled during 2016.
13. Investments
$'000
Cost:
At 1 January 2016, 31 December 2016 and 31 December 2017 19,231
=========
Provision for impairment:
At 1 January 2016 (19,108)
Impairment reversal/(charge) for the year 48
At 31 December 2016 (19,060)
Impairment (charge)/reversal for the year (19)
At 31 December 2017 (19,079)
=========
Net carrying amount:
At 31 December 2017 152
=========
At 31 December 2016 171
=========
At 1 January 2016 123
=========
The accounting valuation of the Group's shareholding (based on the quoted share price of Ascent) resulted in a non-cash impairment charge of $0.02 million in the year to 31 December 2017 (2016: impairment reversal of $0.05 million).
14. Inventories
2017 2016
$'000 $'000
Crude oil 12,422 13,199
Well supplies 65,623 61,786
78,045 74,985
======== =======
During 2017, inventories of $2.9 million (2016: $2.0 million) were recognised within cost of sales in the statement of comprehensive income. Included within this balance is $2.7 million as a result of the write down of inventories to net realisable value (2016: $2.0 million). The write downs are included in cost of sales.
15. Trade and other receivables
2017 2016
$'000 $'000
Current
Trade receivables 80,743 44,363
Joint venture receivables 87,037 91,220
Under-lift position 32,299 11,886
VAT receivable 11,739 9,098
Other receivables 1,844 17,971
--------- --------
213,662 174,538
Prepayments and accrued income 14,092 28,128
--------- --------
227,754 202,666
========= ========
Trade receivables are non-interest bearing and are generally on 15 to 30 day terms. Trade receivables are reported net of any provisions for impairment. As at 31 December 2017, no impairment provision for trade receivables was necessary (2016: nil).
Joint venture receivables relate to amounts billable to, or recoverable from, joint venture partners and were not impaired. Under-lift is valued at market prices prevailing at the balance sheet date. As at 31 December 2017 and
31 December 2016, no other receivables were determined to be impaired.
The carrying value of the Group's trade, joint venture and other receivables as stated above is considered to be a reasonable approximation to their fair value largely due to their short-term maturities.
16. Cash and cash equivalents
The carrying value of the Group's cash and cash equivalents is considered to be a reasonable approximation to their fair value due to their short-term maturities. Included within the cash balance at 31 December 2017 is restricted cash of $3.5 million (2016: $6.6 million). $2.8 million of this relates to cash held in escrow in respect of the unwound acquisition of the Tunisian assets of PA Resources (2016: $6.0 million) and the remainder relates to cash collateral held to issue bank guarantees in Malaysia.
Cash and cash equivalents also include an amount of $3.9 million (2016: $9.4 million) held in a Malaysian bank account which can only be used to pay cash calls for the Tanjong Baram asset and amounts related to the Tanjong Baram project finance loan.
At 31 December 2017, $7.0 million was placed on short-term deposit in order to cash collateralise the Group's letter of credit.
17. Share capital and premium
The movement in the share capital and share premium of the Company was as follows:
Ordinary shares of GBP0.05 each Share capital Share premium Total
Authorised, issued and fully paid Number $'000 $'000 $'000
At 1 January 2017 1,159,398,871 83,342 125,297 208,639
Issuance of equity shares 26,685,433 1,763 - 1,763
At 31 December 2017 1,186,084,304 85,105 125,297 210,402
================================ ============== ============== ========
The share capital comprises only one class of Ordinary share. Each Ordinary share carries an equal voting right and right to a dividend.
On 21 November 2016, the Company completed a placing and open offer, pursuant to which 356,738,114 new Ordinary shares were issued at a price of GBP0.23 per share, generating gross aggregate proceeds of $101.6 million. 233,858,061 of the new shares issued resulted from existing shareholders taking up their entitlement under the open offer to acquire four new Ordinary shares for every nine Ordinary shares previously held. On 21 November 2016, 10,739,486 shares were acquired by the Employee Benefit Trust pursuant to the open offer.
At 31 December 2017, there were 56,023,671 shares held by the Employee Benefit Trust (2016: 33,563,282).
On 18 October 2017, 26,685,433 shares were issued to the Employee Benefit Trust with the remainder of the movement in the year due to shares used to satisfy awards made under the Company's share-based incentive schemes.
18. Share-based payment plans
On 18 March 2010, the Directors of the Company approved three share schemes for the benefit of Directors and employees, being a Deferred Bonus Share Plan, a Restricted Share Plan and a Performance Share Plan. A Sharesave Plan was approved in 2012.
The share-based payment expense recognised for each scheme was as follows:
2017 2016
$'000 $'000
Deferred Bonus Share Plan 1,069 1,274
Restricted Share Plan 1,024 920
Performance Share Plan (68) 4,378
Sharesave Plan 230 93
Executive Director bonus awards 594 1,787
------ ------
2,849 8,452
====== ======
The fair value of awards is calculated at the 'market value', being the average middle market quotation of a share for the three immediately preceding dealing days as derived from the Daily Official List of the London Stock Exchange, provided such dealing days do not fall within any period when dealings in shares are prohibited because of any dealing restriction. The fair values of awards granted to employees during the year are based on the 'market value' on the date of grant, or date of invitation in respect to the Sharesave Plan.
Deferred Bonus Share Plan ('DBSP')
Eligible employees are invited to participate in the DBSP scheme. Participants may be invited to elect or, in some cases, be required, to receive a proportion of any bonus in Ordinary shares of EnQuest (invested awards). Following such award, EnQuest will generally grant the participant an additional award over a number of shares bearing a specified ratio to the number of his or her invested shares (matching shares). The awards granted will vest 33% on the first anniversary of the date of grant, a further 33% after year two and the final 34% on the third anniversary of the date of grant. Awards, both invested and matching, are forfeited if the employee leaves the Group before the awards vest.
The fair values of DBSP awards granted to employees during the year, based on the defined market value on the date of grant, are set out below:
2017 2016
----- -----
Weighted average fair value per share 37p 32p
The following shows the movement in the number of share awards held under the DBSP scheme:
2017 2016
Number Number
Outstanding at 1 January 2,508,026 2,554,269
Granted during the year (i) 1,357,040 1,256,836
Exercised during the year (1,214,427) (1,199,434)
Forfeited during the year (18,842) (103,645)
Outstanding at 31 December 2,631,797 2,508,026
Exercisable at 31 December - -
(i) On 21 November 2016, at its discretion, the Company increased the number of shares receivable by participants in the DBSP by a factor of 1.09265387 so that the value of their rights under outstanding awards was not adversely affected by the open offer. This resulted in the grant of 263,790 additional share awards. The fair value of these awards of $0.1 million is being expensed over the remaining vesting period of the original awards to which they relate.
The weighted average contractual life for the share awards outstanding as at 31 December 2017 was 0.9 years
(2016: 1.0 years).
18. Share-based payment plans (continued)
Restricted Share Plan ('RSP')
Under the RSP scheme, employees are granted shares in EnQuest over a discretionary vesting period at the discretion of the Remuneration Committee of the Board of Directors of EnQuest, which may or may not be subject to the satisfaction of performance conditions. Awards made under the RSP will vest over periods between one and four years. At present, there are no performance conditions applying to this scheme nor is there currently any intention to introduce them in the future.
The fair values of RSP awards granted to employees during the year, based on the defined market value on the date of grant, are set out below:
2017 2016
----- -----
Weighted average fair value per share 33p 32p
The following table shows the movement in the number of share awards held under the RSP scheme:
2017 2016
Number Number
Outstanding at 1 January 12,564,319 5,815,692
Granted during the year (i) 587,216 8,526,792
Exercised during the year (893,465) (530,109)
Forfeited during the year (77,299) (1,248,056)
Outstanding at 31 December 12,180,771 12,564,319
Exercisable at 31 December 3,451,209 3,369,261
(i) On 21 November 2016, at its discretion, the Company increased the number of shares receivable by participants in the RSP by a factor of 1.09265387 so that the value of their rights under outstanding awards was not adversely affected by the open offer. This resulted in the grant of 1,164,647 additional share awards. The fair value of these awards of $0.4 million is being expensed over the remaining vesting period of the original awards to which they relate.
The weighted average contractual life for the share awards outstanding as at 31 December 2017 was 4.8 years
(2016: 5.6 years).
Performance Share Plan ('PSP')
Under the PSP, the shares vest subject to performance conditions. The PSP share awards granted during the year had four sets of performance conditions associated with them: 30% of the award relates to Total Shareholder Return ('TSR') against a number of comparator group oil and gas companies listed on the FTSE 350, AIM Top 100 and Stockholm NASDAQ OMX; 30% relates to reduction in net debt; 30% relates to production growth per share; and 10% relates to new 2P reserve additions over the three year performance period. Awards will vest on the third anniversary.
The fair values of PSP awards granted to employees during the year, based on the defined market value on the date of grant and which allow for the effect of the TSR condition which is a market-based performance condition, are set out below:
2017 2016
----- -----
Weighted average fair value per share 33p 8p
The following table shows the movement in the number of share awards held under the PSP scheme:
2017 2016
Number Number
Outstanding at 1 January 61,023,323 20,348,024
Granted during the year (i) 16,302,086 47,934,689
Exercised during the year (2,412,846) (2,139,477)
Forfeited during the year (4,730,839) (5,119,913)
------------ ------------
Outstanding at 31 December 70,181,724 61,023,323
Exercisable at 31 December 2,816,844 2,104,559
(i) On 21 November 2016, at its discretion, the Company increased the number of shares receivable by participants in the PSP by a factor of 1.09265387 so that the value of their rights under outstanding awards was not adversely affected by the open offer. This resulted in the grant of 5,343,888 additional share awards. The fair value of these awards of $1.0 million is being expensed over the remaining vesting period of the original awards to which they relate.
The weighted average contractual life for the share awards outstanding as at 31 December 2017 was 4.0 years
(2016: 4.5 years).
18. Share-based payment plans (continued)
Sharesave plan
The Group operates an approved savings related share option scheme. The plan is based on eligible employees being granted options and their agreement to opening a sharesave account with a nominated savings carrier and to save over a specified period, either three or five years. The right to exercise the option is at the employee's discretion at the end of the period previously chosen, for a period of six months.
The fair values of Sharesave awards granted to employees during the year, based on the defined market value on the date the invitation for the scheme opens, are shown below:
2017 2016
Weighted average fair value per share 8p 4p
The following shows the movement in the number of share options held under the Sharesave plan:
2017 2016
Number Number
Outstanding at 1 January 12,657,432 6,949,242
Granted during the year (i) 1,299,185 10,823,513
Exercised during the year (17,213) (9,562)
Forfeited during the year (1,105,135) (5,105,761)
Outstanding at 31 December 12,834,269 12,657,432
Exercisable at 31 December - -
(i) On 21 November 2016, at its discretion, the Company increased the number of options receivable by participants in the Sharesave plan by a factor of 1.09265387 so that the value of their rights under outstanding awards was not adversely affected by the open offer. This resulted in the grant of 1,098,593 additional share options. The exercise price of outstanding options was also reduced by multiplying by a factor 0.91520291. The incremental fair value of these adjustments of $0.1 million is being expensed over the remaining vesting period of the options to which they relate.
The weighted average contractual life for the share options outstanding as at 31 December 2017 was 1.7 years
(2016: 3.1 years).
Executive Director bonus awards
As detailed in the Directors' Remuneration Report, the remuneration of the Executive Directors includes the participation in an annual bonus plan. Any bonus amount in excess of 100% of salary will be deferred into EnQuest shares for two years, subject to continued employment.
The fair value of the Executive Director bonus awards granted during the year, based on the defined market value on the date of grant, are set out below:
2017 2016
Restated
Weighted average fair value per share 39p 32p
The following table shows the movement in the number of share awards held under the Executive Director bonus plan:
2017 2016
Restated
Number Number
Outstanding at 1 January 2,869,393 1,203,517
Granted during the year 779,846 1,665,876
Cash settled in the year (726,505) -
Exercised during the year (477,012) -
Forfeited during the year - -
Outstanding at 31 December 2,445,722 2,869,393
Exercisable at 31 December - -
The weighted average contractual life for the share awards outstanding as at 31 December 2017 was 0.6 years
(2016: 0.6 years).
19. Loans and borrowings
The Group's loans are carried at amortised cost as follows:
2017 2016
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
Credit facility 1,099,966 - 1,099,966 1,037,516 - 1,037,516
Crude oil prepayment 75,556 (378) 75,178 - - -
SVT Working Capital Facility 25,622 - 25,622 - - -
Tanjong Baram project finance loan 8,531 (292) 8,239 24,850 (690) 24,160
Trade creditor loan 10,000 - 10,000 40,000 - 40,000
Total loans 1,219,675 (670) 1,219,005 1,102,366 (690) 1,101,676
Due within one year 330,012 49,601
Due after more than one year 888,993 1,052,075
Total loans 1,219,005 1,101,676
Credit facility
In October 2013, the Group entered into a six-year $1.7 billion multi-currency revolving credit facility (the 'RCF'), comprising of a committed amount of $1.2 billion (subject to the level of reserves) with a further $500 million available through an accordion structure. Interest on the revolving credit facility was payable at LIBOR plus a margin of 2.50% to 4.25%, dependent on specified covenant ratios.
On 21 November 2016, pursuant to the Restructuring the Group entered into an amended and restated credit agreement, which included the following terms:
-- commitments split into a term facility of $1.125 billion and a revolving facility of $75 million (together the 'Credit Facility');
-- maturity date extended to October 2021; -- amortisation profile amended, with 1 April 2018 the first scheduled amortisation date;
-- borrowings subject to mandatory repayment out of excess cash flow (excluding amounts required for approved capital expenditure), assessed on a six monthly basis;
-- borrowings up to $890.7 million subject to interest at LIBOR plus a margin of 4.75%, paid in cash;
-- borrowings in excess of $890.7 million subject to interest at LIBOR plus a margin of 5.25%, paid in cash, with a further 3.75% interest accrued and added to the Payment In Kind ('PIK') amount at maturity of each loan's maturity period;
-- PIK amount repayable at maturity and subject to 9.0% interest, which is capitalised and added to the PIK amount on each 30 June and 31 December;
-- accordion feature cancelled; and -- $12 million waiver fee payable to lenders on 31 March 2018.
The Group concluded that the above amendments to the RCF are a substantial modification, resulting in the previous loan carrying amount of $1,002.3 million ($1,017.3 million principal less unamortised issuance costs of $15.0 million) being derecognised and a new loan of $1,017.3 million being recognised at fair value. The difference of $15.0 million, which equated to the unamortised fees of the previous loan, was recognised as loss on extinguishment (see 2016 debt restructuring costs, note 4). The $12 million waiver fee along with $11.1 million of advisors' fees were directly attributable to the modification of the RCF and were also expensed as part of the loss on extinguishment (see note 4).
At 31 December 2017, the carrying amount of the Credit Facility on the balance sheet was $1,100.0 million, comprising the loan principal drawn down of $1,095.2 million, plus $4.8 million of interest capitalised to the PIK amount
(2016: $1,037.5 million, being loan principal drawn down of $1,037.3 million plus $0.2 million of interest capitalised to the PIK amount).
At 31 December 2017, after allowing for letter of credit utilisation of $7.0 million, $97.8 million remained available for drawdown under the Credit Facility (2016: $6.4 million and $156.3 million respectively).
During November 2017, the Group agreed additional amendments to its Term Loan and Revolving Credit Facility. These changes include the deferral of the scheduled $140 million reduction in the Term Loan facility from 1 April 2018 to 1 October 2018. A single amortisation of the RCF is due of $270 million in October 2018.
19. Loans and borrowings (continued)
Crude oil prepayment transaction
On 25 October 2017, the Group entered into a $80 million crude oil prepayment ('Prepay') with Mercuria Energy Trading SA.
Repayment will be made in equal monthly instalments over 18 months, through the delivery of an aggregate of approximately 1.8 mmbbls of oil. EnQuest will receive the average Brent price over each month subject to a floor of $45/bbl and a cap of approximately $64/bbl. Interest on the Prepay is payable at 1 month USD LIBOR plus a margin of 7.0%. The prepayment transaction is being undertaken on an unsecured basis.
At 31 December 2017, the carrying amount of the Prepay on the balance sheet was $75.6 million, compromising of the initial draw down of $80.0 million, less the repayment of $4.4 million of the principal. $0.3 million of interest is accrued on the balance sheet.
SVT Working Capital Facility
On 1 December 2017, EnQuest NNS Limited entered into a GBP42 million revolving loan facility with a joint operator partner to fund the short-term working capital cash requirements on the acquisition of SVT and other interests
(see note 29). The facility is able to be drawn down against in installments and accrues interest at 1.0% per annum plus GBP LIBOR. The facility is repayable three years from the initial availability of the facility.
Tanjong Baram project finance loan
During the year ended 31 December 2015, the Group entered into a five year $35 million loan facility in Malaysia. Interest is payable at USD LIBOR plus a margin of 2.25%.
Trade creditor loan
In October 2016, the Group borrowed $40 million under a loan facility with a trade creditor to fund the settlement of deferred amounts for the Kraken project. The loan, together with accrued interest at a rate of 7.0% per annum, is repayable in instalments from 2018. A bonus of up to $1.7 million was payable at 31 December 2017 if the oil price was above $75/bbl in any period of 180 consecutive days between 1 October 2016 and 31 December 2017. At 31 December 2017, no bonus payment had been made or was due to be paid.
The bonus amount was accounted as an embedded derivative, which had a valuation of $nil at 31 December 2017 and 2016.
19. Loans and borrowings (continued)
Bonds
The Group's bonds are carried at amortised cost as follows:
2017 2016
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
High yield bond 720,827 (8,467) 712,360 677,482 (10,460) 667,022
Retail bond 224,048 (2,057) 221,991 191,258 (2,541) 188,717
Total bonds due after more than one year 944,875 (10,524) 934,351 868,740 (13,001) 855,739
High yield bond
In April 2014, the Group issued a $650 million high yield bond with an originally scheduled maturity of 15 April 2022 and paying a 7.0% coupon semi-annually in April and October.
On 21 November 2016, the high yield bond was amended pursuant to a scheme of arrangement whereby all existing notes were exchanged for new notes. The new high yield notes continue to accrue a fixed coupon of 7.0% payable semi-annually in arrears. The interest will only be payable in cash if the 'Cash Payment Condition' is satisfied, being the average of the Daily Brent Oil Prices during the period of six calendar months immediately preceding the 'Cash Payment Condition Determination Date' is equal to or above $65/bbl. The 'Cash Payment Condition Determination Date' is the date falling one calendar month prior to the relevant interest payment date. If the 'Cash Payment Condition' is not satisfied, interest will not be paid in cash but instead will be capitalised and satisfied through the issue of additional high yield Notes ('Additional HY Notes'). $27.5 million of accrued, unpaid interest as at the restructuring date was capitalised and added to the principal amount of the new high yield notes issued pursuant to the scheme. The maturity of the new high yield notes was extended to 15 April 2022 and the Company has the option to extend the maturity date of the new high yield notes to 15 April 2023. Further, the maturity date of the new high yield notes will be automatically extended to 15 October 2023 if the Credit Facility is not repaid or refinanced in full prior to 15 October 2020.
The amendments to the high yield bond were not deemed to be a substantial modification and therefore $5.0 million of advisors' fees directly attributable to the modification of the high yield bond were adjusted against the carrying value of the bond and are being amortised over bond's remaining term.
The fair value of the high yield bond was estimated to be $519.9 million (2016: $488.0 million). The price quoted for the retail bond was used to estimate the fair value of the high yield bond on the basis that, since the restructuring, both bonds carry similar rights.
Retail bond
In 2013, the Group issued a GBP155 million retail bond with an originally scheduled maturity of 15 February 2022 and paying a 5.5% coupon semi-annually in February and August. For the interest period commencing 15 August 2016, in accordance with the terms of the bond, the rate of interest increased to 7.0% following the determination of the Company's leverage ratio at 31 December 2015.
On 21 November 2016, the retail bond was amended pursuant to a scheme of arrangement whereby all existing notes were exchanged for new notes. The new retail notes continue to accrue a fixed coupon of 7.0% payable semi-annually in arrears. The interest will only be payable in cash if the 'Cash Payment Condition' is satisfied, being the average of the Daily Brent Oil Prices during the period of six calendar months immediately preceding the 'Cash Payment Condition Determination Date' is equal to or above $65/bbl. The 'Cash Payment Condition Determination Date' is the date falling one calendar month prior to the relevant interest payment date. If the 'Cash Payment Condition' is not satisfied, interest will not be paid in cash but instead will be capitalised and satisfied through the issue of additional Retail Notes ('Additional Retail Notes'). The maturity of the new retail notes was extended to 15 April 2022 and the Company has the option to extend the maturity date to 15 April 2023. Further, the maturity date of the new retail notes will be automatically extended to 15 October 2023 if the Credit Facility is not repaid or refinanced in full prior to 15 October 2020.
The amendments to the retail bond were not deemed to be a substantial modification and therefore $0.8 million of advisors' fees directly attributable to the modification of the retail yield bond were adjusted against the carrying value of the bond and are being amortised over bond's remaining term.
The bond had a fair value of $161.6 million (2016: $138.7 million). The fair value of the retail bond has been determined by reference to the price available from the market on which the bond is traded.
20. Other financial assets and financial liabilities
(a) Summary
2017 2016
Assets Liabilities Assets Liabilities
$'000 $'000 $'000 $'000
Commodity contracts (at fair value through profit or loss) - 41,996 2,973 34,548
Foreign exchange contracts (at fair value through profit or loss) - - - 9,726
Interest rate swap designated as cash flow hedge (at fair value through
OCI) 36 - 41 -
Other receivables (loans and receivables) 61,701 - 36,328 -
Other liabilities (at amortised cost) - 19,211 - -
Total current 61,737 61,207 39,342 44,274
Other receivables (loans and receivables) 8,191 - 23,429 -
Other liabilities (at amortised cost) - 7,121 - 19,767
Total non-current 8,191 7,121 23,429 19,767
(b) Commodity contracts
The Group uses put and call options and swap contracts to manage its exposure to the oil price.
Oil price hedging
In October 2017, the Group entered into an 18-month collar structure for $80 million (see note 19). The collar includes 18 separate call options and 18 separate put options, subject to a floor of $45/bbl and a cap of approximately $64/bbl. During 2017, losses totalling $5.2 million were recognised within unrealised revenue in the income statement.
The Group has not entered into any other put options within 2017. All put options entered into in 2016 matured within the year ended 31 December 2016. In 2016, gains of $193.2 million were included in realised revenue in the income statement in respect of these matured options and $2.5 million of gains deferred in the prior year on the early close-out of effective hedges were recognised in realised revenue. Mark to market losses on the time value element of the put options in 2016 totalling $5.4 million was recognised in finance costs. Of this amount, $36.5 million was recognised within the Group's Business performance results as it relates to the amortisation of the option premium paid, over the life of the option. The balance of the mark to market losses were recognised as an exceptional credit/charge in line with the Group's accounting policy.
Gains totalling $43.9 million were realised during 2016 in respect to fixed price oil swap contracts. These contracts were for 2 million barrels of 2016 production with a fixed price of $66.64/bbl and were designated as effective hedges at 31 December 2015. An unrealised gain of $5.8 million was recognised as an exceptional item in the income statement.
Commodity derivative contracts at fair value through profit or loss ('FVTPL')
Commodity derivative are designated as at FVTPL, and gains and losses on these contracts are recognised as a component of revenue. These contracts typically include bought and sold call options, bought put options and commodity swap contracts.
For the year ended 31 December 2017, losses totalling $28.3 million (2016: losses of $35.3 million) were recognised in respect of commodity contracts designated as FVTPL. This included losses totalling $20.6 million (2016: gains of
$16.2 million) realised on contracts that matured during the year, and mark to market losses totalling $7.7 million (2016: losses of $51.5 million). Of the realised amounts recognised during the year, $10.4 million (2016: $31.2 million) was realised in Business performance revenue in respect of the amortisation of premium income received on sale of these options. The premiums received are amortised into Business performance revenue over the life of the option.
The mark to market of the Group's open contracts as at 31 December 2017 was a loss of $29.2 million in respect of fixed price swap contracts for 4,150,000 barrels of 2018 production at a weighted average price of $59.1/bbl
(2016: $40.5 million in respect of fixed price swap contracts for 5,998,000 barrels of 2017 production at a weighted average price of $51.3/bbl). The mark to market position on the Group's other commodity derivative contracts (including contracts to purchase crude oil for trading purposes which are accounted for as a derivative), was $nil
(2016: asset of $8.9 million).
20. Other financial assets and financial liabilities (continued) (c) Foreign currency contracts
The Group enters into a variety of foreign currency contracts, including Sterling, Euros and Norwegian Kroner. During the year ended 31 December 2017, these contracts resulted a realised gain of $0.4 million recognised in the income statement (2016: similar contracts resulted in a realised loss of $57.6 million and an unrealised gain of $7.7 million).
During 2017, the Group has continued to use an exchange structure to manage risk. The first exchange structure was entered into in 2016 and allowed the counterparty to elect to sell GBP47.5 million to EnQuest at an exchange rate of $1.4:GBP1 or purchase 1.3 million barrels of oil at $58/bbl. This structure expired on 30 June 2017. The second exchange structure allowed the counterparty to elect to sell GBP66 million to EnQuest at an exchange rate of $1.2:GBP1 or purchase 1.5 million barrels of oil at $60/bbl. This structure expired on 31 December 2017. From the exchange structures in the year, $4.8 million was recognised within other foreign currency contracts within cost of sales and no costs within other operating income (2016: $9.3 million and $nil respectively).
(d) Interest rate swap
During the year ended 31 December 2015, the Group entered an interest rate swap which effectively swaps 50% of floating USD LIBOR rate interest on the Groups Malaysian loan into a fixed rate of 1.035% until 2018. The swap, which is effective from a hedge accounting perspective, has a net asset fair value of $0.04 million (2016: $0.04 million). The impact recognised within finance expenses on the income statement was $0.02 million (2016: $0.06 million).
(e) Income statement impact
The income/(expense) recognised for commodity, currency and interest rate derivatives are as follows:
Revenue and other operating income
Cost of sales Finance costs
Year ended Realised Unrealised Realised Unrealised Realised Unrealised
31 December 2017 $'000 $'000 $'000 $'000 $'000 $'000
---------
Call options 880 (18,670) - - - -
Put options - - - - - -
Commodity swaps (23,754) 14,144 - - - -
Commodity futures (437) (363) - - - -
Purchase and sale of crude oil 2,736 (2,827) - - - -
Foreign exchange swaps - - - 433 - -
Other forward currency contracts - - (4,848) 9,293 - -
Interest rate swap - - - - 15 (38)
(20,575) (7,716) (4,848) 9,726 15 (38)
Revenue and other operating income
Cost of sales Finance costs
Year ended Realised Unrealised Realised Unrealised Realised Unrealised
31 December 2016 $'000 $'000 $'000 $'000 $'000 $'000
---------
Call options 27,916 (16,654) - - - -
Put options 195,701 - - - (36,458) 31,072
Commodity swaps 31,084 (37,823) - - - -
Commodity futures 426 146 - - - -
Purchase and sale of crude oil 676 2,827 - - - -
Foreign exchange swap contracts - - (1,034) - - -
Other forward currency contracts - - (65,865) (1,584) - -
Interest rate swap - - - - (58) -
255,803 (51,504) (66,899) (1,584) (36,516) 31,072
20. Other financial assets and financial liabilities (continued)
(f) Other receivables and liabilities
Other receivables Other liabilities
$'000 $'000
At 1 January 2016 22,897 7,684
Additions during the year 42,878 12,379
Change in fair value 2,151 (575)
Utilised during the year (9,058) -
Unwinding of discount 1,017 279
Foreign exchange (128) -
At 31 December 2016 59,757 19,767
Additions on acquisition 38,420 6,742
Disposed during the year (3,561) -
Change in fair value 627 (340)
Utilised during the year (27,209) -
Unwinding of discount 1,832 163
Foreign exchange 26 -
At 31 December 2017 69,892 26,332
Comprised of:
Financial carry - 7,211
Accrued waiver fee - 12,000
KUFPEC receivable 7,065 -
BUMI receivable 24,407 -
Decommissioning of Magnus and other interests option - 4,214
Thistle decommissioning option 16,120 -
Purchase option 22,300
Other - 2,907
Total 69,892 26,332
Classified as:
Current 61,701 19,211
Non-current 8,191 7,121
69,892 26,332
20. Other financial assets and financial liabilities (continued)
(f) Other receivables and liabilities (continued)
Other receivables
As part of the 2012 farm-out to the Kuwait Foreign Petroleum Exploration Company ('KUFPEC') of 35% of the Alma/Galia development, KUFPEC agreed to pay EnQuest a total of $23.3 million over a 36 month period after Alma/Galia is deemed to be fully operational. $7.1 million was received during the year ended 31 December 2017
and the remaining receivable, discounted to present value, had a carrying value of $7.1 million at 31 December 2017 (2016: $14.0 million). Unwinding of discount of $0.2 million is included within finance income for the year ended
31 December 2017 (2016: $0.4 million).
In August 2016, EnQuest agreed with Armada Kraken PTE Ltd ('BUMI') that BUMI would refund $65 million (EnQuest's share being $45.8 million) of a $100.0 million lease prepayment made in 2014 for the FPSO for the Kraken field. This refund is receivable during 2018 and onwards. Included within other receivables at 31 December 2017 is an amount of $24.4 million representing the discounted value of EnQuest's share of these repayments
(2016: $43.5 million). A total of $20.1 million was collected during the period. Unwinding of discount of $1.6 million is included within finance costs in the twelve months ended 31 December 2017.
As part of the Magnus and other interests acquisition (see note 29), EnQuest entered into an option to undertake the decommissioning of Thistle. The financial asset of $16.1 million represents the difference between the $50 million cash that BP would transfer to EnQuest upon exercise of the option, and the net present value of the estimate cash outflow to settle the liability assumed.
In addition, the Group has an option to acquire the remaining 75% of the Magnus oil field and BP's interest in the associated infrastructure for a value of $300 million. This option lapses in January 2019. In line with IAS 39, a discounted value of $22.3 million has been attributed to this option (see note 29).
Other receivables at 31 December 2016 also included $2.3 million representing the fair value of a convertible loan note from Ascent. This loan note was sold during the first half of 2017, realising a gain of $1.3 million.
Other liabilities
As part of the agreement to acquire an interest in the PM8/Seligi assets in Malaysia, the Group agreed to carry Petronas Carigali for its share of exploration or appraisal well commitments. The discounted value of $7.2 million has been disclosed as a financial liability (2016: $7.4 million). Unwinding of the discount of $0.2 million is included within finance expense for the year ended 31 December 2017 (2016: $0.3 million).
In addition, included in other liabilities is an accrued 'waiver fee' of $12.0 million payable to the Credit Facility lenders in relation to the restructuring of the facility in November 2016 (see note 19). The amount is payable by March 2018.
As part of the Magnus and other interests acquisition (see note 29), EnQuest agreed to pay additional consideration in relation to the management of the physical decommissioning costs of Thistle and Deveron. The financial liability of $4.2 million relates to the amount due to BP by reference to 7.5% of BP's actual decommissioning costs on an after tax basis.
21. Fair value measurement
The following table provides the fair value measurement hierarchy of the Group's assets and liabilities:
31 December 2017 Quoted prices in active Significant observable Significant unobservable
Total markets inputs inputs
(Level 1) (Level 2) (Level 3)
$'000 $'000 $'000 $'000
Assets measured at fair
value:
Derivative financial
assets
Interest rate swap(ii) 36 - 36 -
Other financial assets
Available-for-sale
financial investments:
Quoted equity shares 152 152 - -
Thistle decommissioning
option 16,120 - - 16,120
Purchase option 22,300 - - 22,300
Liabilities measured at
fair value:
Derivative financial
liabilities
Commodity derivative
contracts(i) 41,996 - 41,996 -
Other financial liability
Decommissioning of Magnus
and other interests
option 4,214 - - 4,214
Liabilities for which fair
values are disclosed (see
notes 19 and 24)
Interest bearing loans and
borrowings 1,219,675 - - 1,219,675
Obligations under finance
leases 797,933 - - 797,933
Sterling retail bond 161,595 161,595 - -
High yield bond 519,896 - 519,896 -
(i) Valued using readily available information in the public markets and quotations provided by brokers and price index developers.
(ii) Valued by the counterparties, with the valuations reviewed internally and corroborated with market data.
31 December 2016 Quoted prices in active Significant observable Significant unobservable
Total markets inputs inputs
(Level 1) (Level 2) (Level 3)
$'000 $'000 $'000 $'000
Assets measured at fair
value:
Derivative financial
assets
Commodity derivative
contracts(i) 2,973 - 2,973 -
Interest rate swap(ii) 41 - 41 -
Other financial assets
Available-for-sale
financial investments:
Quoted equity shares 171 171 - -
Loans and receivables
Other receivables(i) 2,270 - 2,270 -
Liabilities measured at
fair value:
Derivative financial
liabilities
Commodity derivative
contracts(i) 34,548 - 34,548 -
Foreign currency
derivative contracts(ii) 9,726 - 9,726 -
Liabilities for which
fair values are disclosed
(see notes 19 and 24)
Interest bearing loans
and borrowings 1,102,366 - - 1,102,366
Obligations under finance - - - -
leases
Sterling retail bond 138,727 138,727 - -
High yield bond 491,405 - 491,405 -
Fair value hierarchy
All financial instruments for which fair value is recognised or disclosed are categorised within the fair value hierarchy, based on the lowest level input that is significant to the fair value measurement as a whole, as follows:
Level 1: Quoted (unadjusted) market prices in active markets for identical assets or liabilities;
Level 2: Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable;
Level 3: Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable.
For assets and liabilities that are recognised at fair value on a recurring basis, the Group determines whether transfers have occurred between levels in the hierarchy by re-assessing categorisation (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the period (2016: no transfers).
For recurring and non-recurring fair value measurements categorised within Level 3 of the fair value hierarchy, the Group uses the valuation processes to decide its valuation policies and procedures and analyse changes in fair value measurements from period to period. Level 3 financial instruments consist of interest bearing loans and borrowings (see note 19) and contingent consideration (see note 24), which are valued in accordance with the Group's accounting policies.
22. Provisions
Decommissioning Cost recovery Contingent Surplus lease
provision Carry provision provision Consideration provision Total
$'000 $'000 $'000 $'000 $'000 $'000
At 1 January 2016 506,770 - 127,121 26,269 26,417 686,577
Additions during
the year 44,454 - - - - 44,454
Acquisitions 15,153 - - - - 15,153
Changes in
estimates (76,855) 26,591 (40,389) (4,056) (22,604) (117,313)
Unwinding of
discount 10,724 - 2,797 367 9 13,897
Utilisation (6,355) (21,100) - - (421) (27,876)
Foreign exchange - - - - (585) (585)
At 31 December
2016 493,891 5,491 89,529 22,580 2,816 614,307
Additions during
the year 63,613 - 10,329 3,131 - 77,073
Acquisitions (see
note 29) - - - 66,623 - 66,623
Changes in
estimates 80,881 - (77,785) - 194 3,290
Change in fair
value - - - (423) - (423)
Unwinding of
discount 11,471 - 1,838 255 17 13,581
Utilisation (10,605) (5,491) - (9,000) (394) (25,490)
Foreign exchange - - - - 253 253
At 31 December
2017 639,251 - 23,911 83,166 2,886 749,214
Classified as
Current 11,138 - 5,178 26,512 387 43,215
Non-current 628,113 - 18,733 56,654 2,499 705,999
639,251 - 23,911 83,166 2,886 749,214
Decommissioning provision
The Group makes full provision for the future costs of decommissioning its production facilities and pipelines on a discounted basis. With respect to the Heather field, the decommissioning provision is based on the Group's contractual obligation of 37.5% of the decommissioning liability rather than the Group's equity interest in the field.
The Group's total provision represents the present value of decommissioning costs which are expected to be incurred up to 2033 assuming no further development of the Group's assets. The liability is discounted at a rate of 2.0%
(2016: 2.3%). The unwinding of the discount is classified as a finance cost (see note 6).
Acquisitions during the year ended 31 December 2016 reflect amounts associated with the additional interests in the Kraken and West Don fields acquired during the year which were $7.5 million and $7.6 million, respectively (see note 29).
These provisions have been created based on internal and third-party estimates. Assumptions based on the current economic environment have been made which management believe are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required, which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning liabilities is likely to depend on the dates when the fields cease to be economically viable. This in turn depends on future oil prices, which are inherently uncertain.
The Group enters into surety bonds principally to provide security for its decommissioning obligations. The surety
bond facilities which expired in December 2017 were renewed for 12 months, subject to on-going compliance with
the terms of the Group's borrowings. At 31 December 2017, the Group held surety bonds totalling $129.6 million (2016: $118.5 million).
Carry provision
Consideration for the acquisition of 40% of the Kraken field from Cairn (previously Nautical) and First Oil PLC ('First Oil') in 2012 was through development carries. The 'contingent' carry is dependent upon a reserves determination which took place in Q2 2016. During 2017, $5.5 million of the carry had been paid, with no remaining liability recognised on the balance sheet as at 31 December 2017 (2016: $21.1 million paid and $5.5 million remaining).
22. Provisions (continued)
Cost recovery provision
As part of the KUFPEC farm-in agreement, a cost recovery protection mechanism was agreed with KUFPEC to enable KUFPEC to recoup its investment to the date of first production. If on 1 January 2017, KUFPEC's costs to first production had not been recovered or deemed to have been recovered, EnQuest would pay KUFPEC an additional 20% share of net revenue. This additional revenue is to be paid until the capital costs to first production have been recovered.
A provision has been made for the expected payments that the Group will make to KUFPEC. The assumptions made in arriving at the projected cash payments are consistent with the assumptions used in the Group's 2017 year end impairment test, and the resulting cash flows were included in the determination of the recoverable value of the project. In establishing when KUFPEC has recovered its capital cost to first oil, the farm-in agreement requires the use of the higher of the actual oil price, or $90/bbl real, inflated at 2.0% per annum from 2012. These cash flows have been discounted at a rate of 2.0% (2016: 2.3%).
During 2017, the Group entered into discussions with Petronas in relation to the prior period PM8 cost recovery at the PM8 concession. A provision has been made for the expected payments that the Group will make as part of the settlement agreement. The provision is expected to be paid in two parts during 2018 and 2019, as disclosed within current and non-current provisions. At 31 December 2017, the provision was $10.3 million.
Contingent consideration
As part of the purchase agreement with the previous owner of the GKA assets, a contingent consideration was agreed based on Scolty/Crathes field development plan ('FDP') approval and 'first oil'. EnQuest paid $3.0 million in November 2015, following FDP approval in October 2015 and $9.0 million during 2017. $8.0 million is due on the later of one year after first oil or 30 January 2018. In addition, further payments will become due if the oil price rises above $75/bbl on a linear basis up to $100/bbl, with a cap on total payments of $20.0 million. The cash flows have been discounted using a 2.0% discount rate (2016: 3.0%). An option model has been used to value the element of the consideration that is contingent on the oil price and has resulted in a credit to the income statement of $0.4 million for the year ended
31 December 2017 (2016: $0.7 million). The carrying value of the Scolty/Crathes contingent consideration at
31 December 2017 is $8.1 million (31 December 2016: $17.3 million).
In addition, there is consideration due subject to future exploration success which, having been reassessed for the year ended 31 December 2017, continues to be held at $5.3 million.
On 1 December 2017 the acquisition of the Magnus oil field and other interests (see note 29) was funded through a vendor loan from BP, recognised as contingent consideration at a fair value of $66.6 million. The loan is repayable solely out of the cash flows which are achieved above operating cash flows from the Transaction assets and is secured over the interests in the Transaction assets. The loan accrues interest at a rate of 5.0% per annum on the base consideration. The fair value has been estimated by calculating the present value of the future expected cash flows, based on a discount rate of 10.0% and assumed repayment of around 3 years.
Surplus lease provision
In June 2015, the Group entered a 20-year lease in respect of the Group's office building in Aberdeen, with part of the building subsequently being sub-let with a rent-free incentive. A provision has been recognised for the unavoidable costs in relation to the sub-let space. The provision has been discounted using a 2.0% (2016: 2.3%) discount rate.
At 31 December 2017, the provision was $2.9 million (2016: $2.8 million).
23. Trade and other payables
2017 2016
$'000 $'000
Current
Trade payables 144,584 232,277
Accrued expenses 271,686 183,753
Over-lift position 23,173 35,058
Joint venture creditors 1,632 456
Other payables 5,014 1,304
--------- ---------
446,089 452,848
========= =========
Classified as:
Current 367,312 410,261
Non-current 78,777 42,587
--------- ---------
446,089 452,848
========= =========
Trade payables are normally non-interest bearing and settled on terms of between 10 and 30 days. The Group has arrangements with various suppliers to defer payment of a proportion of its capital spend. The majority of these deferred payments fall due in 2018 and the balance is expected to be fully settled in 2019.
Certain trade and other payables will be settled in currencies other than the reporting currency of the Group, mainly in Sterling.
Accrued expenses include accruals for capital and operating expenditure in relation to the oil and gas assets.
The carrying value of the Group's trade and other payables as stated above is considered to be a reasonable approximation to their fair value largely due to the short-term maturities.
24. Commitments and contingencies
Commitments
(i) Operating lease commitments - lessee
The Group has financial commitments in respect of non-cancellable operating leases for office premises. These leases have remaining non-cancellable lease terms of between one and 20 years. The future minimum rental commitments under these non-cancellable leases are as follows:
2017 2016
$'000 $'000
Due in less than one year 7,177 4,296
Due in more than one year but not more than five years 27,286 17,412
Due in more than five years 75,536 62,990
109,999 84,698
Lease payments recognised as an operating lease expense during the year amounted to $5.3 million
(2016: $4.8 million).
Under the Dons Northern Producer Agreement, a minimum notice period of 12 months exists whereby the Group expects the minimum commitment under this agreement to be approximately $7.1 million (2016: $9.4 million).
(ii) Operating lease commitments - lessor
The Group sub-leases part of its Aberdeen office. The future minimum rental commitments under these
non-cancellable leases are as follows:
2017 2016
$'000 $'000
Due in less than one year 1,638 202
Due in more than one year but not more than five years 7,141 5,877
Due in more than five years 4,686 5,869
13,465 11,948
Sub-lease rent recognised during the year amounted to $1.3 million (2016: $1.6 million).
24. Commitments and contingencies (continued)
(iii) Finance lease commitments
The Group had the following obligations under finance leases as at the balance sheet date:
2017 2017 2016 2016
Minimum payments Present value of payments Minimum payments Present value of payments
$'000 $'000 $'000 $'000
Due in less than one year 173,846 118,009 - -
Due in more than one year
but not more than five
years 460,960 289,949 - -
Due in more than five years 456,374 389,975 - -
1,091,180 797,933 - -
Less future financing
charges 293,247 - - -
797,933 797,933 - -
Finance leases with an effective borrowing rate of 8.12% were entered into during the year (see note 10).
On 20 December 2013, the Group entered into a bareboat charter with BUMI for the lease of an FPSO vessel for the Kraken field. BUMI constructed the vessel and the Group made an initial prepayment of $100.0 million during 2014.
In August 2016, it was agreed that $65.0 million of this prepayment would be refunded (see note 20(f)).
In June 2017, the Group's lease of the FPSO commenced. The lease has been assessed as a finance lease, and a $772.0 million lease liability and lease asset were recognised in June 2017. The liability was calculated based on the present value of the minimum lease payments at inception of the lease. The lease liability is carried at $797.9 million as at 31 December 2017, of which $118.0 million is classified as a current liability. Finance lease interest of
$31.3 million has been recognised within finance costs.
(iv) Capital commitments
At 31 December 2017, the Group had capital commitments excluding the above lease commitments amounting to $33.8 million (2016: $267.3 million).
Contingencies
The Group becomes involved from time to time in various claims and lawsuits arising in the ordinary course of its business. Other than as discussed below, the Company is not, nor has been during the past 12 months, involved in any governmental, legal or arbitration proceedings which, either individually or in the aggregate, have had, or are expected to have, a material adverse effect on the Company's and/or the Group's financial position or profitability, nor, so far as the Company is aware, are any such proceedings pending or threatened.
The Group is currently engaged in a dispute with KUFPEC, the Group's field partner in respect of Alma/Galia. KUFPEC has commenced a court action in the High Court of Justice claiming an alleged breach of one of the Group's warranties provided under the Alma/Galia Farm-in Agreement and seeking damages of $91.0 million (the maximum breach of warranty claim permitted under the Alma/Galia Farm-in Agreement), together with interest. The court proceedings are on-going and the Directors believe that a considerable period will elapse before a final decision is reached by the courts.
The Directors consider the merits of the claim to be poor and the Group is defending itself vigorously. The Group has not made any provisions in respect of this claim as the Directors believe the claim is unlikely to be successful; and in any event the Directors believe the chances of an outcome exposing the Group to material damages are remote. There can, however, be no assurances that this claim will not ultimately be successful, or that the Group would not otherwise seek to enter into a settlement or compromise in respect of this claim, or that in the event of any such circumstances the Group would not incur costs and expenses in excess of its estimates.
The Group is also currently engaged in discussions with EMAS, one of the Group's contractors on Kraken who performed the installation of a buoy and mooring system, in relation to the payment of approximately $15.0 million of variation claims which EMAS claims is due as a result of soil conditions at the work site being materially different from those reasonably expected to be encountered based on soil data previously provided. The Group is confident that such variation claims are not valid and that accordingly such amount is not due and payable by the Group under the terms of the contract with EMAS. The parties are currently in discussions pursuant to the dispute resolution process under the contract.
There are a number of contractual matters not agreed between the Group and BUMI relating to the charter of the FPSO on the Kraken field. The Group considers that these matters will not adversely impact its payment obligations in relation to the charter.
25. Related party transactions
The Group financial statements include the financial statements of EnQuest PLC and its subsidiaries. A list of the Group's principal subsidiaries is contained in note 28 to these Group financial statements.
Balances and transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note.
All sales to and purchases from related parties are made at normal market prices and the pricing policies and terms
of these transactions are approved by the Group's management. With the exception of the transactions disclosed below, there have been no transactions with related parties who are not members of the Group during the year ended 31 December 2017 (2016: none).
Share subscription
In 2016, subscription for new ordinary shares pursuant to the placing and open offer (see note 17) at the issue price of GBP0.23 per share:
-- Double A Limited ('Double A'), a company beneficially owned by the extended family of Amjad Bseisu, took up its entitlement in the open offer, subscribing for 31,735,702 shares;
-- Directors and key management personnel took up their entitlement in the open offer, subscribing for 423,540 new ordinary shares;
-- Key management personnel participated in the placing, subscribing for 412,608 new ordinary shares; and
-- Close family members of Amjad Bseisu and their associated undertakings participated in the placing, subscribing for 2,940,304 shares.
Commission related to the placing
Double A made a commitment to subscribe for up to 91,224,079 new Ordinary shares under the placing (subject to clawback to satisfy valid applications under the open offer). In consideration of Double A's commitment, the Company agreed to pay Double A commission equal to 1% of the product of (i) the number of new ordinary shares which are subsequently clawed back following completion of the open offer and (ii) the issue price (the 'Commission'). The Commission is consistent with those paid in respect of other participants in the placing. The Commission of $0.2 million due to Double A was outstanding as at 31 December 2016 and settled subsequently during 2017.
Office sublease
During the year ended 31 December 2017, the Group recognised $0.1 million of rental income in respect of an office sublease arrangement with Levendi Investment Management, a company where 72% of the issued share capital is held by Amjad Bseisu (2016: $0.1 million rental income from AA Capital Analysts Limited, a company whose majority controlling shareholder is Double A Limited).
Contracted services
During the year ended 31 December 2017, the Group obtained contracting services from Influit UK Production Solutions for a value of US$0.04m. Amjad Bseisu has an indirect interest in Influit UK Production Solutions.
Compensation of key management personnel
The following table details remuneration of key management personnel of the Group. Key management personnel comprise of Executive and Non-Executive Directors of the Company and other senior personnel. This includes the Executive Committee for the year ended 31 December 2017.
2017 2016
$'000 $'000
Short-term employee benefits 5,057 5,002
Share-based payments 1,305 3,770
Post-employment pension benefits 55 33
6,417 8,805
26. Risk management and financial instruments
Risk management objectives and policies
The Group's principal financial assets and liabilities comprise trade and other receivables, cash and short-term deposits, interest bearing loans, borrowings and finance leases, derivative financial instruments and trade and other payables. The main purpose of these financial instruments is to manage short-term cash flow and raise finance for the Group's capital expenditure programme.
The Group's activities expose it to various financial risks particularly associated with fluctuations in oil price, foreign currency risk, liquidity risk and credit risk. Management reviews and agrees policies for managing each of these risks, which are summarised below. Also presented below is a sensitivity analysis to indicate sensitivity to changes in market variables on the Group's financial instruments and to show the impact on profit and shareholders' equity, where applicable. The sensitivity has been prepared for periods ended 31 December 2017 and 2016, using the amounts of debt and other financial assets and liabilities held at those reporting dates.
Commodity price risk - oil prices
The Group is exposed to the impact of changes in Brent oil prices on its revenues and profits generated from sales of crude oil.
The Group's policy is to have the ability to hedge oil prices up to a maximum of 75% of the next 12 months production on a rolling annual basis, up to 60% in the following 12 month period and 50% in the subsequent 12 month period.
Details of the commodity derivative contracts entered into during and on hand at the end of 2017 are disclosed in
note 20.
The following table summarises the impact on the Group's pre-tax profit and total equity of a reasonably possible change in the Brent oil price, on the fair value of derivative financial instruments (primarily fixed price swaps over a total of 5.5 million barrels as at 31 December 2017), with all other variables held constant. As the derivatives on hand at 31 December 2017 have not been designated as hedges, there is no impact on equity.
Pre-tax profit Total equity
+$10/Bbl -$10/Bbl +$10/Bbl -$10/Bbl
increase decrease increase decrease
$'000 $'000 $'000 $'000
31 December 2017 (68,350) 48,320 - -
31 December 2016 (58,000) 60,000 - -
26. Risk management and financial instruments (continued)
Foreign currency risk
The Group is exposed to foreign current risk arising from movements in currency exchange rates. Such exposure arises from sales or purchases in currencies other than the Group's functional currency (US Dollars) and the bond which is denominated in Sterling. To mitigate the risks of large fluctuations in the currency markets, the hedging policy agreed by the Board allows for up to 70% of the non-US Dollar portion of the Group's annual capital budget and operating expenditure to be hedged. For specific contracted capital expenditure projects, up to 100% can be hedged. Approximately 2% (2016: 1%) of the Group's sales and 83% (2016: 81%) of costs (including capital expenditure) are denominated in currencies other than the functional currency.
At 31 December 2016, the Group had a forward foreign currency contract in place for NOK37.1 with a strike price of NOK8.61/GBP1 which matured in Q1 2017 as a result of the exchange structure entered into in June 2016 (see note 20). As at 31 December 2017, all exchange structures have matured (see note 20).
The Group also enters into foreign currency swap contracts from time to time to manage short-term exposures.
The following table summarises the sensitivity to a reasonably possible change in the US Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact in equity is the same as the impact on profit before tax. The Group's exposure to foreign currency changes for all other currencies is not material:
Pre-tax profit
Year ended Year ended
31 December 2017 31 December 2016
Change in US Dollar rate $'000 $'000
+10% (43,100) (48,250)
-10% 43,100 48,250
Credit risk
Credit risk is managed on a Group basis. Credit risk in financial instruments arises from cash and cash equivalents and derivative financial instruments where the Group's exposure arises from default of the counterparty, with a maximum exposure equal to the carrying amount of these instruments (see maturity table within liquidity risks in note 26). For banks and financial institutions, only those rated with an A-/A3 credit rating or better are accepted. Cash balances can be invested in short-term bank deposits and AAA-rated liquidity funds, subject to Board approved limits and with a view to minimising counterparty credit risks.
In addition, there are credit risks of commercial counterparties including exposures in respect of outstanding receivables. The Group trades only with recognised international oil and gas operators and at 31 December 2017 there were $23.6 million of trade receivables past due (2016: $5.6 million), $1.7 million of joint venture receivables past due (2016: $8.6 million) and $nil (2016: $nil) of other receivables past due but not impaired. Subsequent to year end, $1.5 million of these outstanding balances have been collected (2016: $10.9 million). Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary.
2017 2016
Ageing of past due but not impaired receivables $'000 $'000
Less than 30 days 1,726 6,101
30-60 days - -
60-90 days 253 -
90-120 days - 656
120+ days 23,301 7,473
25,280 14,230
At 31 December 2017, the Group had four customers accounting for 84% of outstanding trade receivables
(2016: three customers, 90%) and three joint venture partners accounting for 97% of joint venture receivables
(2016: five joint venture partners, 90%).
26. Risk management and financial instruments (continued)
Liquidity risk
The Group monitors its risk to a shortage of funds by reviewing its cash flow requirements on a regular basis relative to its existing bank facilities and the maturity profile of its borrowings. Specifically the Group's policy is to ensure that sufficient liquidity or committed facilities exist within the Group to meet its operational funding requirements and to ensure the Group can service its debt and adhere to its financial covenants.
On 21 November 2016, the Company concluded a comprehensive financial restructuring comprising: amendments to the credit facility, high yield bond and retail bond; renewal of surety bond facilities; and a placing and open offer (the 'Restructuring'). The terms of the Restructuring are set out further in notes 17 and 19. The Restructuring was designed to provide the Group with a stable and sustainable capital structure, reduced cash debt service obligations and greater liquidity. In particular, the Restructuring is expected to enable the Group to complete the Kraken and Scolty/Crathes developments. At 31 December 2017, $97.8 million (2016: $156.3 million) was available for draw down under the Group's Credit Facility (see note 19).
The following tables detail the maturity profiles of the Group's non-derivative financial liabilities including projected interest thereon. The amounts in these tables are different from the balance sheet as the table is prepared on a contractual undiscounted cash flow basis and include future interest payments.
Year ended 31 December 2017 On demand Up to 1 year 1 to 2 years 2 to 5 years Over 5 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Loans and borrowings - 424,886 347,603 667,975 - 1,440,464
Bonds(1) - 66,141 66,141 1,112,842 - 1,245,124
Obligations under finance leases - 118,009 64,142 225,807 389,975 797,933
Trade and other payables - 364,472 157,554 - - 522,026
Other financial liabilities - 7,211 - - - 7,211
- 980,719 635,440 2,006,624 389,975 4,012,758
Year ended 31 December 2016 On demand Up to 1 year 1 to 2 years 2 to 5 years Over 5 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Loans and borrowings - 122,590 260,017 960,880 - 1,343,487
Bonds(1) - 56,069 60,812 182,435 901,377 1,200,693
Trade and other payables 258,828 136,564 45,378 - - 440,770
Other financial liabilities - - 7,641 - - 7,641
258,828 315,223 373,848 1,143,315 901,377 2,992,591
(1) Maturity analysis profile for the Group's bonds includes semi-annual coupon interest. This interest is only payable in cash if the average dated Brent oil price is equal to or greater than $65/bbl for the six months preceding the coupon payment date (see note 19).
26. Risk management and financial instruments (continued)
The following tables detail the Group's expected maturity of payables and receivables for its derivative financial instruments. The amounts in these tables are different from the balance sheet as the table is prepared on a contractual undiscounted cash flow basis. When the amount receivable or payable is not fixed, the amount disclosed has been determined by reference to a projected forward curve at the reporting date.
Year ended 31 December 2017 On demand Less than 3 months 3 to 12 months 1 to 2 years Over
2 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Commodity derivative contracts (4,991) (29,616) (10,850) (1,531) - (46,988)
Chooser contract (1,035) - - - - (1,035)
Interest rate swaps - (13) (19) - - (32)
(6,026) (29,629) (10,869) (1,531) - (48,055)
Year ended 31 December 2016 On demand Less than 3 months 3 to 12 months 1 to 2 years Over
2 years Total
$'000 $'000 $'000 $'000 $'000 $'000
Commodity derivative contracts 146 (10,626) (27,419) - - (37,899)
Foreign exchange forward contracts - (4,741) - - - (4,741)
Foreign exchange forward contracts - 4,308 - - - 4,308
Chooser contract - (3,711) (3,711) - - (7,422)
Interest rate swaps - 1 3 2 - 6
146 (14,769) (31,127) 2 - (45,748)
Capital management
The capital structure of the Group consists of debt, which includes the borrowings disclosed in note 19, cash and cash equivalents and equity attributable to the equity holders of the parent, comprising issued capital, reserves and retained earnings as in the Group Statement of Changes in Equity.
The primary objective of the Group's capital management is to optimise the return on investment, by managing its capital structure to achieve capital efficiency whilst also maintaining flexibility. The Group regularly monitors the capital requirements of the business over the short, medium and long-term, in order to enable it to foresee when additional capital will be required. On 21 November 2016, the Group completed a comprehensive package of financial restructuring measures (see notes 17 and 19 for further details).
The Group has approval from the Board to hedge foreign exchange risk on up to 70% of the non US Dollar portion of the Group's annual capital budget and operating expenditure. For specific contracted capex projects, up to 100% can be hedged. In addition, there is approval from the Board to hedge up to 75% of annual production in year 1, 60% in year 2 and 50% in year 3. This is designed to reduce the risk of adverse movements in exchange rates and prices eroding the return on the Group's projects and operations.
The Board regularly reassesses the existing dividend policy to ensure that shareholder value is maximised. Any future payment of dividends is expected to depend on the earnings and financial condition of the Company and such other factors as the Board considers appropriate.
26. Risk management and financial instruments (continued)
The Group monitors capital using the gearing ratio and return on shareholders' equity as follows:
2017 2016
$'000 $'000
Loans, borrowings and bond (i) (A) 2,164,550 1,971,106
Cash and short-term deposits (173,128) (174,634)
Net debt/(cash) (B) 1,991,422 1,796,472
Equity attributable to EnQuest PLC shareholders (C) 760,866 818,852
Profit/(loss) for the year attributable to EnQuest PLC shareholders (D) (60,830) 185,212
Profit/(loss) for the year attributable to EnQuest PLC shareholders excluding exceptionals
(E) (33,554) 121,510
Gross gearing ratio (A/C) 2.8 2.4
Net gearing ratio (B/C) 2.6 2.2
Shareholders' return on investment (D/C) (8%) 23%
Shareholders' return on investment excluding exceptionals (E/C) (4%) 15%
(i) Principal amounts drawn, excludes netting off of fees (see note 19)
27. Post balance sheet events
On 31 January 2018, following the acquisition of the initial 25% interest in the Magnus oil field (see note 29), EnQuest agreed with BP to undertake the management of the physical decommissioning activities for Thistle and Deveron. EnQuest will receive $30 million in cash in exchange for undertaking the management of the physical decommissioning and making payments by reference to 3.7% of the gross decommissioning costs of the Thistle and Deveron fields when spend commences, subject to a cap of GBP57 million. EnQuest will also have an option, exercisable over a 12 month period, to receive a further $20 million in cash in exchange for making additional payments by reference to 2.4% of the gross decommissioning costs of these fields, subject to a cap of GBP42 million.
28. Subsidiaries
At 31 December 2017, EnQuest PLC had investments in the following subsidiaries:
Name of company Principal activity Country of incorporation Proportion of nominal value
of issued shares controlled
by the Group
Intermediate holding company
and provision of Group
manpower and
contracting/procurement
EnQuest Britain Limited services England 100%
Exploration, extraction and
EnQuest Heather Limited(i) production of hydrocarbons England 100%
Extraction and production of
EnQuest Thistle Limited(i) hydrocarbons England 100%
Stratic UK (Holdings)
Limited(i) Intermediate holding company England 100%
Grove Energy Limited(1) Intermediate holding company Canada 100%
Exploration, extraction and
EnQuest ENS Limited(i) production of hydrocarbons England 100%
Exploration, extraction and
EnQuest UKCS Limited(i) production of hydrocarbons England 100%
Exploration, extraction and
EnQuest Norge AS(i)2 production of hydrocarbons Norway 100%
EnQuest Heather Leasing
Limited(i) Leasing England 100%
Exploration, extraction and
EQ Petroleum Sabah Limited(i) production of hydrocarbons England 100%
EnQuest Dons Leasing
Limited(i) Dormant England 100%
Exploration, extraction and
EnQuest Energy Limited(i) production of hydrocarbons England 100%
Exploration, extraction and
EnQuest Production Limited(i) production of hydrocarbons England 100%
EnQuest Global Limited Intermediate holding company England 100%
Exploration, extraction and
EnQuest NWO Limited(i) production of hydrocarbons England 100%
EQ Petroleum Production Exploration, extraction and
Malaysia Limited(i) production of hydrocarbons England 100%
Construction, ownership and
NSIP (GKA) Limited(3) operation of an oil pipeline Scotland 100%
Provision of Group manpower
and contracting/procurement
EnQuest Global Services services for the
Limited(i)4 International business Jersey 100%
EnQuest Marketing and Trading Marketing and trading of
Limited crude oil England 100%
NorthWestOctober Limited(i) Dormant England 100%
EnQuest UK Limited(i) Dormant England 100%
EnQuest Petroleum Developments Exploration, extraction and
Malaysia SDN. BHD(i)5 production of hydrocarbons Malaysia 100%
EnQuest NNS Holdings Limited Intermediate holding company England 100%
Exploration, extraction and
EnQuest NNS Limited production of hydrocarbons England 100%
(i) Held by subsidiary undertaking
The Group has three branches outside the UK (all held by subsidiary undertakings): EnQuest Global Services Limited (Dubai); EnQuest Petroleum Production Malaysia Limited (Malaysia); and EQ Petroleum Sabah Limited (Malaysia).
Registered office addresses:
(1) Suite 2200, 1055 West Hastings Street, Vancouver, British Columbia, V6E 2E9
(2) Fabrikkveien 9, Stavanger, 4033, Norway
(3) Annan House, Palmerston Road, Aberdeen, Scotland, AB11 5QP, United Kingdom
(4) Ground Floor, Colomberie House, St Helier, JE4 0RX, Jersey
(5) c/o TMF, 10th Floor, Menara Hap Seng, No 1 & 3, Jalan P. Ramlee 50250 Kuala Lumpur, Malaysia
29. Business combinations
Acquisition of Magnus and other interests
On 1 December 2017, EnQuest completed the acquisition from BP plc of an initial 25% interest in the Magnus oil field ('Magnus') as well as a 3.0% interest in the Sullom Voe Oil terminal and supply facility ('SVT'), 9.0% of Northern Leg Gas Pipeline ('NLGP'), and 3.8% of Ninian Pipeline System ('NPS') (collectively the 'Transaction assets').
The transaction is in keeping with EnQuest's strategy of maximising value from late life assets with significant remaining resource potential. The required regulatory, government authority, counterparty and partner consents have been obtained for the transaction.
The transaction is an acquisition of an interest in a joint operation under IFRS 11 and, as the activity constitutes a business as defined in IFRS 3 Business Combination, the acquisition has been accounted for as a business combination. The consolidated financial statements include the fair values of the identifiable assets and liabilities as at the date of acquisition, and the results of the Transaction assets for the one month period from the acquisition date.
The fair value of the identifiable assets and liabilities of the Transaction assets as at the date of acquisition were:
Fair value recognised
on acquisition
$'000
Assets
Property, plant and equipment (see note 10) 124,542
Purchase option(iii) 22,300
Financial asset(i) 16,120
Inventory 14,884
177,846
Liabilities
Trade and other payables (see note 23) (8,459)
Financial liabilities(ii) (4,214)
Deferred tax liability (see note 7) (49,816)
(62,489)
Total identifiable net assets at fair value 115,357
Excess of fair value over cost arising on acquisition:
Purchase option(iii) (22,300)
Thistle decommissioning option(i) (16,120)
25% acquisition value (10,314)
Total excess of fair value over cost arising on acquisition(iv) (48,734)
Purchase consideration through vendor loan 66,623
(i) The financial asset relates to the Thistle decommissioning option, and represents the difference between the $50 million cash that BP would transfer to EnQuest upon exercise of the option, and the net present value of the estimated cash outflow to settle the liability assumed.
(ii) The financial liability relates to the amount due to BP by reference to 7.5% of BP's actual decommissioning costs on an
after-tax basis. The additional consideration EnQuest may pay is capped at the amount of cumulative positive cash flows received by EnQuest from the Transaction assets.
(iii) The financial asset relates to the purchase option to acquire the remaining 75% of Magnus oil field and BP's interest in the associated infrastructure for a value of $300 million.
(iv) The initial accounting for the acquisition of the Transaction assets has only been provisionally determined at the end of the reporting period. At the date of finalisation of these financial statements, the necessary market valuations and other calculations had not been finalised and they have therefore only been provisionally determined based on the directors' best estimates. Thus, the fair value of the net asset may be subsequently adjusted, with a corresponding adjustment to goodwill prior to 1 December 2018 (one year after the transaction).
29. Business combinations (continued)
In addition to the above identifiable assets and liabilities, under the terms of the agreement, the Group has an option
to acquire the remaining 75% of the Magnus oil field and BP's interest in the associated infrastructure for a value of $300 million. This option lapses in January 2019. In line with IAS 39, a discounted value of $22.3 million has been attributed to this option and recorded within other financial assets (see note 20).
EnQuest also has the option to receive $50 million from BP in exchange for undertaking the management of the physical decommissioning activities for Thistle and Deveron and making payments by reference to 6.0% of the gross decommissioning costs of Thistle and Deveron fields (see note 20). In January 2018, the Group exercised part of the option (see note 27).
The excess of fair value of the net assets acquired over the purchase consideration has arisen primarily due to BP's strategic decision to partner with EnQuest to extend the life of existing mature assets and from the Group's ability to maximise the value from the late life assets with significant remaining resource potential. The gain has been immediately recognised through exceptionals in the statement of comprehensive income.
At the date of acquisition, the fair value of the net assets was $115.4 million. At 31 December 2017, none of the trade receivables have been impaired.
Fair value of consideration
The consideration payable has been satisfied via a vendor loan from BP. The loan is repayable solely out of the cash flows which are achieved above operating cash flows from the Transaction assets and is secured over the interests in the Transaction assets. The loan accrues interest at a rate of 5.0% per annum on the base consideration. The base consideration was $85 million, which was adjusted for interim period and working capital adjustments since the economic date of 1 January 2017, resulting contingent consideration of $66.6 million. The present value of the contingent consideration was calculated from the future expected cash flows, at a discount rate of 10.0% and assumed repayment of around 3 years. This is recognised within contingent consideration within provisions
(see note 22).
From the date of acquisition, the Transaction assets have contributed $14.0 million of revenue and $2.1 million to the profit before tax from continuing operations of the Group. If the combination had taken place at the beginning of the year, revenue from continuing operations would have been $73.9 million and the profit before tax from continuing operations would have been $25.9 million. In determining these amounts, management has assumed that the fair value adjustments, determined provisionally, that arose on the date of acquisition would have been the same if the acquisition had occurred on 1 January 2017.
All transaction costs were paid by BP as part of the deal agreement.
Information on prior year acquisitions
The net assets acquired during the year ended 31 December 2016 were recognised as follows:
15.15% interest 10.5% interest
in West Don in Kraken Total
$'000 $'000 $'000
Property, plant and equipment (see note 10) 7,096 33,599 40,695
Prepayments and accrued income - 10,500 10,500
Under-lift position 3,271 - 3,271
Deferred tax asset (see note 7) 268 - 268
Accrued expenses (538) (31,581) (32,119)
Provision for decommissioning (see note 22) (7,633) (7,520) (15,153)
Net identifiable assets 2,464 4,998 7,462
In February 2016, the Group acquired an additional 10.5% interest in the Kraken development asset from First Oil for nominal consideration, resulting in a revised working interest of 70.5% in this joint arrangement. The amounts recognised in respect of the identifiable assets acquired and liabilities assumed are set out in the table above.
In August 2016, the Group acquired an additional 15.15% interest in the West Don producing field from First Oil, resulting in a revised working interest of 78.6% in this joint arrangement. The amounts recognised in respect of the identifiable assets acquired and liabilities assumed are set out in the table above. The consideration of $2.5 million, which was satisfied through a reduction of receivable balances, equalled the fair value of identifiable assets acquired and liabilities assumed and therefore no goodwill arose on the acquisition.
30. Cash flow information
Cash generated from operations
Year ended Year ended 31 December
31 December
2017 2016
Notes $'000 $'000
Profit/(loss) before tax (243,773) 217,244
Depreciation 5(c) 4,500 3,930
Depletion 5(b) 224,698 241,879
Exploration costs impaired/(reversed) and written off 5(d) (193) 776
Net impairment (reversal)/charge to oil and gas assets 4 171,971 (147,871)
Write down of inventory 4 (2,682) -
Write down of asset 4 2,808 -
Loss on disposal of intangible oil and gas assets 4 - 16,178
Excess of fair value over consideration 4 (48,734) -
Gain on disposal of loan notes 5(d) (1,263) -
Impairment (reversal)/charge to investments 4 19 (48)
Share-based payment charge 5(f) 2,849 8,452
Shares purchased on behalf of Employee Benefit Trust 17 (1,763) -
Change in deferred consideration 5(d) - (4,056)
Change in surplus lease provision 22 (200) (23,025)
Change in decommissioning provision 5(d) - (1,627)
Change in other provisions 22 10,161 -
Hedge accounting deferral 20 - (2,456)
Amortisation of option premiums 20 (10,445) (31,210)
Unrealised (gain)/loss on financial instruments 5(a)(b) (2,010) 53,088
Unrealised exchange loss/(gain) 5(e) 23,910 (51,867)
Net finance (income)/expense 6 147,079 127,835
Operating profit before working capital changes 276,932 407,222
Decrease/(increase) in trade and other receivables (13,611) 26,579
(Increase)/decrease in inventories 2,039 (7,356)
(Decrease)/increase in trade and other payables 61,674 (18,198)
Cash generated from operations 327,034 408,247
Changes in liabilities arising from financing activities
Year ended 31 December 2017(1) Loans and borrowings Bonds Finance leases Total
(see note 19) (see note 19) (see note 24)
$'000 $'000 $'000 $'000
At 1 January 2017 (1,102,366) (868,740) - (1,971,106)
Cash flows (112,001) - - (112,001)
Additions - - (771,975) (771,975)
Foreign exchange adjustments (552) (18,828) - (19,380)
Capitalised PIK - (58,242) - (58,242)
Unwind of finance discount - - (31,273) (31,273)
Other non-cash movements (4,756) 935 5,315 1,494
(1,219,675) (944,875) (797,933) (2,962,483)
(i) First year adoption of IAS 7 amendment, therefore comparative information is not required.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR GGUWAWUPRGBB
(END) Dow Jones Newswires
March 20, 2018 03:00 ET (07:00 GMT)
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