Enquest Regulatory News (ENQ)

Results for the year ended 31 December 2018 and 2019 outlook

48% production growth and debt reduction delivered in 2018

2019 production growth and debt reduction driven by Magnus

 21 March 2019

Unless otherwise stated, all figures are on a Business performance basis and are in US Dollars.

2018 performance

§ Acquisition of additional interests in Magnus and the Sullom Voe Oil Terminal completed in December

§ Group production averaged 55,447 Boepd in 2018, up 48.2% on 2017

§ Revenue of $1,201.0 million (2017: $635.2 million) and EBITDA of $716.3 million (2017: $303.6 million); higher volumes and realised prices, partially offset by the impact of commodity hedges

§ Cash generated from operations of $788.6 million (2017: $327.0 million) reflecting higher EBITDA

§ Cash capital expenditure of $220.2 million (2017: $367.6 million)

§ Cash and available bank facilities amounted to $309.0 million at 31 December 2018, with net debt of$1,774.5 million (2017: $1,991.4 million)

§ Net 2P reserves of 245 MMboe and net 2C resources of 198 MMboe at the end of 2018 (2017: 2P reserves of 210 MMboe; 2C resources of 164 MMboe); growth driven by acquisition of Magnus

2019 performance and outlook

§ Average Group production expected to grow by around 20% to between 63,000 to 70,000 Boepd; production has averaged 67,700 Boepd in the first two months of the year

§ Operating expenditure expected to be approximately $600 million, including additional interest in Magnus

§ Cash capital expenditures expected to be approximately $275 million; includes a combined total of approximately $100 million related to deferred payments from prior periods and phasing of spend from 2018, mainly DC4

§ EnQuest has hedges in place for c.8.0 MMbbls of oil. Approximately 6.5 MMbbls are hedged at an average floor price of c.$66/bbl. In accordance with the Oz Management facility agreement, the Group has a further c.1.5 MMbbls hedged across 2019 with an average floor price of c.$56/bbl

§ Group's credit facility reduced to $730.0 million following early repayment of $55.0 million

§ End 2019 Net debt to EBITDA ratio expected to be approaching 2x; EnQuest's target is between 1x and 2x

EnQuest Chief Executive, Amjad Bseisu, said:

"In 2018, the Group met its financial and operational targets. Production increased by 48%, just above the midpoint of our guidance, which, along with strong cost control, drove a significant improvement in cash generation allowing the Group to reduce net debt.

"FPSO performance has been the main limiting factor in achieving Kraken's full production potential. As such, our clear operational priority is to improve Kraken's FPSO uptime and efficiency. We are working with the FPSO operator on a number of improvement initiatives.

"We are committed to further reducing our debt, and expect our net debt to EBITDA ratio to trend towards 2x this year and intend to operate within our 1-2x target in the future.

"The acquisition of Magnus has added material value to the business through significant production and reserve growth, and the application of our production enhancing capabilities are already improving performance above original expectations.

"In the near term, we remain focused on investing in short-cycle projects which maximise cash flow and allow us to deliver on our plans to reduce our debt. We have opportunities for low-cost material growth in near-field, short-cycle infill and tie-back investments, particularly at Magnus, PM8/Seligi and Kraken.

"Longer term, our capital allocation will balance investment to develop our asset base, returns to shareholders and the acquisition of suitable growth opportunities."

Production and financial information

Notes:

1 Including losses of $93.0 million (2017: losses of $20.6 million) associated with EnQuest's oil price hedges

2 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, inventory revaluation and the realised gains/loss on foreign currency derivatives related to capital expenditure

3 2017 reported earnings per share has been restated for the bonus element of the rights issue

4 Net (debt)/cash represents cash and cash equivalents less borrowings, stated excluding accrued interest and the net-off of unamortised fees

Production details

Notes:

1 Includes net production related to 25% interest in Magnus until 30 November 2018 and 100% interest of Magnus from 1 December 2018, averaged over the 12 months to the end of December 2018

2 Includes net production from the initial 25% interest in Magnus from 1 December 2017, averaged over the 12 months to the end of December 2017

3 Net production since first oil on 23 June, averaged over the 12 months to the end of December 2017

2018 performance summary

During 2018, the Group was focused on meeting its financial and operational targets and facilitating debt reduction. The successful acquisition of Magnus, the Sullom Voe Terminal and related infrastructure assets from BP was a great testament to our people's focus on delivery and excellent team collaboration. The Group's collective efforts delivered a set of assets with a strong strategic fit into the portfolio. EnQuest's cash generation capability has improved through the acquisition of Magnus in particular and the Group is well positioned to meet its debt repayment schedule and capital programme in 2019 and beyond.

In line with the Group's guidance, EnQuest's average production increased by 48.2% to 55,447 Boepd, primarily reflecting the contributions from Kraken and Magnus, a better than expected performance at Heather, Alma/Galia and Scolty/Crathes, partially offset by natural declines.

The combination of significantly higher production, higher realised prices and the Group's focus on cost control resulted in EBITDA and cash generated by operations more than doubling in 2018 compared to 2017, reaching $716.3 million and $788.6 million, respectively.

As expected, cash capital expenditure of $220.2 million was materially lower than 2017. The majority of the expenditure was at Kraken, although the delayed arrival of the Transocean drilling rig resulted in the DC4 drilling programme and associated costs being phased into 2019, with the remaining spend largely reflecting drilling activities at Heather/Broom and PM8/Seligi.

Liquidity and net debt

During the year, EnQuest continued to manage its liquidity position actively and ensuring the Group is able to deploy capital and resources to those key projects which maximise cash flow to facilitate debt reduction.

In January, the Group agreed to receive $30.0 million in cash from BP in exchange for undertaking the management of the physical decommissioning of the Thistle and Deveron fields and making payments by reference to 4.5% of BP's decommissioning costs of these fields when spend commences. Following shareholder approval at the General Meeting held in October, EnQuest received a further $20.0 million in cash in exchange for increasing its total payment obligation of BP's decommissioning costs of the Thistle and Deveron fields by 3.0% to 7.5%.

In February, the Group completed the $37.25 million refinancing agreement in relation to its Tanjong Baram project, providing approximately $25.0 million in additional liquidity.

In September, the Group agreed $175 million of financing with funds managed by Oz Management. The financing is ring-fenced on a 15% interest in the Kraken oil field and will be repaid out of the cash flows associated with the 15% ring-fenced interest over a maximum of five years.

In October, following shareholder approval at the General Meeting, net proceeds of around $128.9 million were raised through a rights issue in which the Group received valid acceptances in respect of 95.5% of the total number of new ordinary shares offered pursuant to the rights issue. $100.0 million of the proceeds were used to fund EnQuest's share of the consideration in relation to acquiring the remaining 75% interest in Magnus and additional interests in the Sullom Voe Terminal and associated infrastructure. The balance will be used to fund a two-well infill drilling programme in 2019.

During the year, the Group's improved cash generation and the Kraken financing agreement facilitated the cancellation and repayment of $340.0 million of the Group's credit facility.

At the end of the year, net debt was reduced by 10.9% to $1,774.5 million, with total cash and available facilities of $309.0 million, including ring-fenced accounts associated with Magnus, the Oz Management facility and other joint venture accounts totalling $107.3 million.

Reserves and resources

Net 2P reserves at the end of 2018 were 245 MMboe (2017: 210 MMboe) and have been audited on a consistent basis with prior years. This represents a reserve life of 13 years. The reserve replacement ratio was 184%, driven by the acquisition of an additional 75% equity interest in Magnus. Net 2C resources at the end of 2018 were 198 MMboe (2017: 164 MMboe) and included an additional 40 MMboe of 2C resources associated with the Magnus acquisition.

2019 performance and additional outlook details

At Magnus, performance has remained strong through the first two months of the year. FPSO performance has continued to limit production performance at Kraken. All DC4 wells are now onstream and, as FPSO maintenance activities are completed, production is expected to significantly improve. We continue to expect to deliver gross production of between 30,000 and 35,000 Bopd from Kraken. Elsewhere across the portfolio, aggregate production has been broadly in line with the Group's expectations.

2019 production is expected to grow by around 20% to between 63,000 and 70,000 Boepd, primarily driven by Magnus. Production from DC4 at Kraken, where all three wells are now onstream, and the anticipated improvement in performance at Scolty/Crathes following the installation of the replacement pipeline scheduled for the third quarter of 2019 are expected to offset natural declines elsewhere across the portfolio.

The successful delivery of the capital programme, which includes drilling at Kraken, Magnus and PM8/Seligi combined with project-related expenditures at Scolty/Crathes and Thistle/Deveron and the Dons, will underpin production during 2019 and beyond.

Debt repayment remains the priority for the Group, and will be enabled through its improved cash-generation capability combined with its focus on cost control and capital discipline. In March, the Group reduced its credit facility by $55.0 million to $730.0 million, ahead of the scheduled amortisation due in April, which now has a balance due of $50.0 million. At the end of 2019, the Group expects overall net debt to EBITDA to be approaching 2x, with the Group intending to operate between 1x and 2x in the future.

Summary financial review of 2018

(all figures quoted are in US Dollars and relate to Business performance unless otherwise stated)

Revenue and other operating income for 2018 was $1,201.0 million, 89.1% higher than 2017 ($635.2 million). This increase reflects the material increase in volumes and higher realised prices, partially offset by realised losses of $93.0 million associated with the Group's commodity hedge programme (2017: losses of $20.6 million), which reflected the timing at which the hedges were entered into and the increase in market prices during the first half of 2018 in particular. The Group's blended average realised oil price was $61.2/bbl in 2018, compared to $52.2/bbl during 2017. Excluding this hedging impact, the average realised oil price was $66.2/bbl in 2018, 22.8% higher than 2017 ($53.9/bbl), reflecting higher market prices. Revenue is predominantly derived from crude oil sales which totalled $1,237.6 million, 94.3% higher than 2017 ($637.0 million), reflecting the material increase in volumes and higher realised prices. Revenue from the sale of condensate and gas was $43.1 million (2017: $2.8 million) as a result of increased gas sales from Magnus, which includes the combination of produced gas sales and the onward sale of third-party gas purchases not required for injection activities, for which the costs are included in other cost of sales.

Total cost of sales for 2018 was $926.0 million, 62.6% higher than 2017 ($569.5 million). This included non-cash depletion expense of $437.1 million, 95.9% higher than 2017 ($223.1 million) as a result of increased production, primarily at Kraken and Magnus.

Operating expenditures of $465.9 million were 33.4% higher than 2017 ($349.3 million), reflecting the full year contribution of Kraken and Magnus, partly offset by the benefit of a weaker Sterling exchange rate. The Group's average unit operating cost for 2018 was $23.0/Boe, 10.2% lower than 2017 ($25.6/Boe) primarily as a result of the material increase in production.

Other cost of sales increased by $35.4 million to $48.1 million compared to 2017 ($12.7 million), principally reflecting the cost of additional Magnus related third-party gas purchases not required for injection activities.

Other net income of $19.1 million (2017: net expense of $17.6 million) primarily comprise net foreign exchange gains as a result of revaluing Sterling-denominated amounts on the balance sheet following the weakening of Sterling against the US Dollar.

EBITDA for 2018 was $716.3 million, 135.9% higher than 2017 ($303.6 million) largely as a result of higher production and higher realised prices increasing Group revenues.

The tax credit for 2018 of $20.9 million (2017: $66.0 million tax credit), excluding exceptional items, is due predominantly to the Ring Fence Expenditure Supplement on UK activities.

Post-tax exceptional items for 2018 were a gain of $49.1 million (2017: losses of $27.3 million). The gain in 2018 primarily reflects the non-cash increase in fair value of $74.3 million recognised under step acquisition accounting on the initial interests in the assets acquired from BP in December 2017 following completion of the acquisition of additional interests in these assets in December 2018. Post-tax non-cash impairments of oil and gas assets of $78.7 million were largely offset by post-tax unrealised gains on commodity contracts of $59.9 million.

Net debt at 31 December 2018 was $1,774.5 million, a decrease of 10.9% compared to 2017 ($1,991.4 million) primarily as a result of the improved cash generating capability of the Group and lower cash capital expenditure programme in 2018 of $220.2 million (2017: $367.6 million), principally at Kraken. Excluding Payment in Kind interest ('PIK'), net debt was $1,642.5 million (2017: $1,900.9 million).

UK corporate tax losses at the end of the year were $3,225.3 million (2017: $3,121.3 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 InvestorsA 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)800 376 7922 or +44 (0) 844 571 8892

International: +44 (0) 207 192 8000

Confirmation Code: EnQuest

Notes to editors

This announcement has been determined to contain inside information.

ENQUEST

EnQuest is an independent production and development company with operations in the UK North Sea and Malaysia. The Group's strategic vision is to be the operator of choice for maturing and underdeveloped hydrocarbon assets by focusing on operational excellence, differential capability, value enhancement and financial discipline.

EnQuest PLC trades on both the London Stock Exchange and the NASDAQ OMX Stockholm. Its UK 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 2018, EnQuest had interests in 18 UK production licences and was the operator of 16 of these licences. EnQuest's interests in Malaysia include the PM8/Seligi Production Sharing Contract and the Tanjong Baram Risk Services Contract, both of which the Group operates.

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

In 2018, EnQuest took a further significant step forward in strengthening the business and adding to its potential. The exercise of the Magnus Option, which received very strong support from our shareholders to acquire the remaining 75% equity interest in Magnus, provided the Group with an immediate and material increase to its 2P reserves, production and cash flow. Magnus performance has been strong since EnQuest assumed operatorship in December 2017 and the application of the Group's differential capabilities saw production increase significantly in late 2018.

While production from Kraken was below our expectations, primarily reflecting FPSO performance and weather-related outages, the strong production performance across the Group elsewhere saw EnQuest meet its production growth target. The Group's improved cash-generating capability and the execution of the Kraken financing agreement enabled the Group to make material repayments on its bank debt. Debt reduction remains a priority for EnQuest.

The Group's net 2P reserves were up approximately 17% after accounting for the increased production in 2018, driven by the additional 75% interest in Magnus. By the end of 2018, EnQuest had a net 2P reserves base of 245 MMboe, which represents average growth of approximately 13% per annum since EnQuest's formation nine years ago and a reserves life of around 13 years.

Industry context

For much of 2018, we saw a steady improvement in the oil price, reflecting a combination of strong growth in global demand coupled with increasing constraints on supply. However, during the fourth quarter, concerns over a weakening demand outlook and expectations of over-supply saw a rapid deterioration in the oil price, which dipped to around $50/bbl in late December. Since then, the price has recovered to within the range of c.$65/bbl and c.$68/bbl. Throughout this period of volatility, we have remained focused on achieving our targets, maintaining and enhancing production while controlling costs and capital expenditure. It is vital we continue to keep this focus through 2019 with ongoing oil price uncertainty.

The Directors believe that the UK Continental Shelf remains an attractive investment proposition. While there may be some disruption to the supply chain from the impacts of the UK's proposed exit from the European Union, the Directors are confident that such issues can be overcome. The industry has worked hard in recent years to reduce its operating and capital costs, facilitating delivery on the UK Government's strategy of Maximising Economic Recovery of the significant hydrocarbons that remain in place. This competitive regulatory structure is further supported by a competitive fiscal regime, an extensive installed infrastructure base, access to a world-leading supply chain and a highly skilled workforce. EnQuest has been successful in replicating its UK operating model in Malaysia, another maturing region with significant hydrocarbons in place, and where the Group has a strong partnership with PETRONAS.

EnQuest's Board

As previously noted in EnQuest's 2017 Annual Report and Accounts, we were extremely pleased to welcome Laurie Fitch to the Board. Laurie joined the Company on 8 January 2018 and became a member of both the Risk and Remuneration Committees. In January 2019, as planned, Laurie succeeded Helmut Langanger as the Chair of the Remuneration Committee. Helmut has chaired the Committee for nine years, developing open and transparent communications with our investors as we have shaped an effective remuneration policy. I would like to take this opportunity to thank Helmut for his valuable leadership over this period. We are pleased he will continue to be a member of the Remuneration Committee to aid Laurie's transition into the role.

As a Board, we remain conscious of the need to have an effective succession plan that ensures the Board has the correct composition of skills and experience to continue its support of the executive management team in executing the Group's strategy. We are therefore very pleased that, subject to shareholder approval at the annual general meeting, Howard Paver will join the Board. Howard is a petroleum engineer by background and has 40 years of oil and gas experience working for Hess, BHP Petroleum, Mobil and Schlumberger in various senior leadership positions. His significant knowledge in production and development, as well as experience of managing complex assets in various parts of the globe, will bring technical and commercial skills to the Board. This is of particular relevance as Helmut Langanger, who has over 40 years of industry experience, will be rotating off the Board in due course.

In 2019, both Helmut and I will have served as Directors of the Company for nine years. With the completion of the Magnus option and following on from the Company's financial restructuring in late 2016, the Company is positioned to pursue its strategic goals and, as is now appropriate, Helmut, as Senior Independent Director, is leading a process to identify a candidate to replace me as Chairman and take the Company forward to the next phase of its development. It is envisaged that after my succession process has completed, Helmut will retire from the Board.

EnQuest's people

In 2018, the Group was focused on meeting its operational and financial targets and maintaining cost and capital discipline in a volatile macro environment. The capital raise, via a rights issue, to facilitate the strategically important acquisition of additional interests in Magnus, the Sullom Voe Terminal and associated infrastructure from BP, and the financing associated with Kraken, all required significant amounts of the Board's and management's time and attention. Additionally, achieving all of these objectives has only ultimately been possible due to EnQuest's people. The Board and I would like to express our gratitude to everyone, both new and old, at EnQuest for their drive, commitment and professionalism in delivering Safe Results, meeting our targets and completing the acquisition of assets from BP to give the Company an even stronger base upon which to build for the future.

Following the results of our culture survey in 2017, the Group's Values were refreshed through a series of group-wide focus groups and workshops. This process has ensured that our Values embody everything the Company stands for and align with the aspirations of our people, acting as a guide in the pursuit of EnQuest's strategy. Through 2019, the refreshed Values will be incorporated into a number of the Group's processes, including those in Human Resources and Health, Safety, Environment and Assurance.

In early 2019, the Board approved the establishment of an Employee Forum to improve engagement and interaction between the workforce and the Board. This supplements the Group's existing employee engagement activities and is in line with the revised Corporate Governance Code published in July 2018.

Strategy and governance

The Directors provide strategic guidance and challenge to executive management and take key decisions on the implementation of the Group's strategy. EnQuest's governance framework also contains several non-Board Committees, which provide advice and support to the Chief Executive, including an Executive Committee, Investment Committee and HSE&A Committee.

The Group welcomes the drive for increased governance and transparency in general, and specifically in relation to climate change. The Board recognises the increasing societal, media and investor focus on climate change and the desire to understand its potential impacts on the oil and gas industry through improved disclosure, utilising mechanisms such as those proposed by the Task Force on Climate-related Financial Disclosures. Through the Risk and Audit Committees, the Board has continued to review the potential risk of climate change on the effective execution of the Group's strategy and has concluded that, on a standalone basis, climate change is not a principal risk but one factor amongst others influencing our assessment of the Group's principal risks, the details of which can be found on pages 20 to 28. The Risk Committee will continue to undertake detailed analyses of specific risk areas to ensure that the potential effects of climate change continue to be identified, considered and assessed appropriately within the Group's Risk Management Framework. Further, the Board, in particular through the work of the Risk Committee, has been active in supporting the continued evolution of the Group's Risk Management Framework to enhance effective risk management within the Board-approved risk appetite of the Company. Through this process, the Risk Committee reviewed all risk areas faced by the Group and identified the causes of risk and their associated impacts and mapped these to the preventative and containment controls used to manage such risks to acceptable levels.

Ensuring that the Board works effectively remains a key focus of the Company. During the year, an external evaluation of the Board was held which recognised the improvements made in the Group's governance since the last external evaluation in 2016. It also identified additional areas for consideration to drive continuous improvement in this area. The most important area discussed related to Board succession planning, which I have already outlined. The Board is committed to delivering the highest standards of corporate governance. Activities are already under way in relation to the changes to the Corporate Governance Code announced in July 2018 and the Board is actively engaged in the implementation of the necessary processes and procedures that will enable continued compliance.

The Board believes that the manner in which the Group conducts its business is important. In the execution of our strategy, we are committed to working responsibly for the benefit of all our 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, 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. Having undertaken a detailed review of the Group's HSE&A processes, the Risk Committee recommended the addition of HSE&A oversight and review within its scope of work to supplement and assist the Board in reviewing such matters.

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, as well as suppliers, contractors, agents and partners.

Dividend

The Company has not declared or paid any dividends since incorporation and does not plan to pay dividends in the immediate future. However, the Board anticipates reviewing the policy when appropriate, the timing of which will be subject to the oil price environment, the capital structure of the Company and its expected future cash flows.

2019: continued focus on delivery and debt reduction

We have made significant progress in 2018, meeting our targets and making substantial repayments of our bank debt. The acquisition of Magnus diversifies our production portfolio and, along with Kraken and PM8/Seligi, provides the Group with material future production opportunities. In 2019, we must continue to focus on delivering on our targets to facilitate the effective management of our liquidity position and capital structure. With the oil price environment remaining volatile, we recognise that we must maintain our focus on financial discipline, cost efficiencies and managing Group liquidity. We will continue to prioritise our resources to those projects which maximise cash flow to facilitate debt reduction, continuing the Company's progress towards a more sustainable balance sheet which will enable the long-term growth of the business.

Chief Executive's report

Overview

During 2018, the Group was focused on meeting its financial and operational targets and facilitating debt reduction. The successful acquisition of Magnus, the Sullom Voe Terminal and related infrastructure assets from BP was a great testament to our people's focus on delivery and excellent team collaboration. The Group's collective efforts delivered a set of assets with a strong strategic fit into the portfolio. EnQuest's cash-generation capability has improved through the acquisition of Magnus in particular and we are well positioned to meet our debt repayment schedule and capital programme in 2019 and beyond.

Operational performance

EnQuest's average production increased by 48.2% to 55,447 Boepd, above the mid-point of the Group's guidance. The increase reflected the contributions from Kraken and Magnus, along with a better than expected performance at Heather, Alma/Galia and Scolty/Crathes, partially offset by natural declines.

Following strong shareholder support for the rights issue undertaken in October, EnQuest completed the acquisition of additional interests in Magnus, the Sullom Voe Terminal and related infrastructure in December. The additional interest in Magnus and the success of plant debottlenecking and well intervention work drove a substantial and better than expected increase in production.

The acquisition of Magnus also drove a material increase in net 2P reserves to 245 MMboe at the end of 2018, up 17% on the 210 MMboe at the end of 2017, and was a key component in the Group achieving a reserves replacement ratio of 184%. While production at Kraken has been below expectations, with FPSO performance the main limiting factor, the Group's reserves position for Kraken remains materially unchanged. Since the Company was formed with around 81 MMboe of 2P reserves, the Group has achieved a compound average reserves growth of 13%, with remaining 2P reserves representing a current production life of around 13 years.

Financial performance

The combination of increased production and higher realised prices drove an improved financial performance in 2018. Both EBITDA and cash generated by operations more than doubled, to $716.3 million and $788.6 million respectively. The Group's ongoing focus on cost control kept operating expenditure to $465.9 million, with unit operating costs reduced to around $23.0/Boe. Capital expenditure was also significantly lower year on year, down $147.4 million to $220.2 million, primarily driven by the reduced programme at Kraken.

EnQuest reviewed a number of potential opportunities to realise value from the Kraken asset. Having reviewed the various options available to the Group, the Board approved the financing arrangement for $175 million, ring-fenced on a 15% interest in the Kraken oil field, with funds managed by Oz Management, as the preferred economic option at the time. We continue to keep a future potential equity farm-down at Kraken under review.

The combination of this financing agreement and strong underlying business performance facilitated accelerated repayments of the Group's credit facility, which reduced by $340.0 million, from $1,125.0 million to $785.0 million, excluding the revolving credit facility. The Group ended the year with net debt of $1,774.5 million, down from $1,991.4 million at the end of 2017 and further debt reduction remains a near-term priority for the Group.

Health, Safety, Environment and Assurance ('HSE&A')

As always, Safe Results is our number one priority and we have had excellent results in many areas, meeting the majority of our performance targets. In Malaysia, we again had zero lost-time incidents ('LTI'), with PM8/Seligi achieving eight years LTI free, and we reduced the number of hydrocarbon release events. This strong performance came against a backdrop of high activity levels offshore. In the UK North Sea, our colleagues on the Kittiwake platform recorded their 13th year without an LTI with many of our other assets also delivering an LTI-free year. However, we saw an increase in the number of hydrocarbon release events and had a high-potential dropped-object incident on Magnus associated with lifting operations. These serve to highlight that we must remain focused on safety at all times and aim for continuous improvement in all that we do.

The main sources of atmospheric emissions from EnQuest assets are derived from combustion plant associated with power generation and flaring. As such, while overall extraction emissions increased in 2018, largely as a result of the addition of Magnus to our portfolio, our improved production performance drove our extraction-related greenhouse gas emissions intensity ratio lower by 17.6%. In Malaysia, the team's focus on minimising emissions resulted in flaring at PM8/Seligi being maintained at around 35% below the annual flare consent from the regulator.

While hydrocarbons are expected to remain a key element of the UK and global energy mix, the Group recognises that it must endeavour to minimise carbon emissions from its operations as far as practicable as it seeks to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner. Our strategy of acquiring assets and extending their economic life facilitates the industry's move from long-term, 'full-cycle' expenditure to lower-carbon energy supply sources while helping to fulfil energy demand requirements during this transition period.

UK North Sea operations

Production from the UK North Sea was materially higher in 2018 than in 2017. This increase was driven by a combination of additional production from Kraken and Magnus and the successful execution of our planned work programmes.

At Magnus, the team successfully undertook plant de-bottlenecking and water injection system improvements. Two new wells were drilled and brought online, with further production improvements driven by successful well intervention activities. Following our two-well drilling campaign in 2018, a further two-well programme will commence in 2019, along with additional intervention and plant improvement activities. Future material infill drilling opportunities continue to be refined and assessed to maximise recovery from the significant remaining resources in place.

Further drilling successes were achieved at Heather, Thistle and Alma/Galia. The H-67 well at Heather delivered above the Group's pre-drill expectations and the Group began its well abandonment campaign at Heather in December following the successful execution of six well abandonments at Thistle. The replacement of three Electric Submersible Pumps at Alma/Galia resulted in production restoration in line with the Group's plans.

At both Alma/Galia and Scolty/Crathes, production was better than expected as a result of improved production efficiency and the successful management of wax deposition, respectively. The successful production optimisation strategy at Scolty/Crathes has resulted in the project achieving payback just over two years after start-up, despite the wax deposition challenges meaning only the Crathes reservoir has delivered production and revenues.

During the year, we sanctioned the Scolty/Crathes pipeline replacement project, to remedy the wax deposition-related production restrictions, and the Dunlin bypass, which will see volumes from Thistle and the Dons exported via the Magnus facility and Ninian Pipeline System to the Sullom Voe Terminal. Both projects help underpin longer-term production from these assets. Elsewhere, the Group continues to assess development options for the Eagle Discovery and at Dons North East.

Production at Kraken was below expectations, reflecting a number of FPSO and weather-related outages throughout the year. Our clear operational priority in 2019 is to improve FPSO uptime and efficiency. We are working with the FPSO operator on a number of improvement initiatives to maximise facility uptime to enable stable production. Reservoir performance has been strong and remains broadly in line with the Group's expectations. We have seen excellent communication between producer and injector wells and our improving management of reservoir voidage following repairs to the water injection system also supported reservoir deliverability.

The delayed arrival of the drilling rig at Drill Centre 4 ('DC4') resulted in drilling commencing later than planned with first production from the wells being rephased accordingly. Drilling at DC4 is nearing completion, with the first two of three wells now onstream. We continue to assess future opportunities at Kraken that have material volumes of oil in place for future development, such as the Western Flank.

At the Sullom Voe Terminal, the Group reduced terminal operating costs by around 25%, to approximately £150.0 million, through the implementation of a number of efficiency initiatives. We also assisted in three ship-to-ship transfers of oil in the Port of Sullom Voe, and the Group continues to explore opportunities to maximise the long-term value of the terminal.

Malaysia operations

Production in 2018 was slightly lower than in 2017, primarily reflecting natural decline at Tanjong Baram. Our focus on asset integrity, which included underwater structural integrity assessments and gas compressor rejuvenation, helped drive continued high levels of production efficiency at PM8/Seligi. The regulator recognised the Group's efforts with an award for the 'Highest Improvement' in relation to offshore self-regulation. Our programme of well interventions continues to be successful in arresting the field's decline, and we successfully concluded EnQuest's first ever drilling campaign at PM8/Seligi, with aggregate production from the two new wells in line with expectations.

EnQuest will continue its asset life extension activities in 2019 through further investment in two new wells, idle well restoration and facility improvements and upgrades. Technical studies to support future development drilling and secondary recovery projects to increase ultimate recovery from the material volumes in place in PM8/Seligi are also under way.

2019 performance and outlook

Following effective reservoir management and well intervention work at Magnus, performance has remained strong through the first two months of the year. FPSO performance has continued to limit production performance at Kraken. All DC4 wells are now onstream and, as FPSO maintenance activities are completed, production is expected to significantly improve. We continue to expect to deliver gross production of between 30,000 and 35,000 Bopd from Kraken. Elsewhere across the portfolio, aggregate production has been broadly in line with the Group's expectations.

2019 production is expected to grow by around 20% to between 63,000 and 70,000 Boepd, primarily driven by Magnus. Production from DC4 at Kraken, where all three wells are now onstream, and the anticipated improvement in performance at Scolty/Crathes following the installation of the replacement pipeline scheduled for the third quarter of 2019 are expected to offset natural declines elsewhere across the portfolio.

The successful delivery of the capital programme, which includes drilling at Kraken, Magnus and PM8/Seligi combined with project-related expenditures at Scolty/Crathes and Thistle/Deveron and the Dons, will underpin production during 2019 and beyond.

Debt repayment remains the priority for the Group, and will be enabled through its improved cash-generation capability combined with our focus on cost control and capital discipline. In March, the Group reduced its credit facility by $55.0 million to $730.0 million, ahead of the scheduled amortisation due in April, which now has a balance due of $50.0 million. At the end of 2019, the Group expects overall net debt to EBITDA to be approaching 2x, with the Group intending to operate between 1x and 2x in the future.

Longer-term development

In the near term, we remain focused on delivering on our plans to reduce our debt. We also have the opportunity for material growth where our portfolio has significant potential for near-field, short-cycle development, particularly at Magnus, PM8/Seligi and Kraken.

After we have reduced our debt to sustainable levels, and dependent on price conditions and company performance, our capital allocation will balance investment to develop our asset base, returns to shareholders and the acquisition of suitable growth opportunities. The application of our proven capabilities in enhancing hydrocarbon recovery from mature and underdeveloped assets means we are well placed to pursue long-term sustainable growth.

Operating review

Northern North Sea operations

Daily average net production:

· 2018: 19,293 Boepd1

· 2017: 15,627 Boepd2

Notes:

1 Includes net production related to 25% interest in Magnus until 30 November 2018 and 100% interest of Magnus from 1 December 2018, averaged over the 12 months to the end of December 2018

2 Includes net production from the initial 25% interest in Magnus since the acquisition on 1 December 2017, averaged over the 12 months to the end of December 2017

2018 performance summary

Production in 2018 of 19,293 Boepd was 23.5% higher than in 2017, primarily reflecting a full year's contribution from Magnus and better than expected performance from the H-67 well at Heather, which came online in March, partially offset by natural declines across the area. Good production and water injection efficiency performance was achieved at Heather/Broom, Thistle and the Dons, with production efficiency at each of these fields above 80%.

Magnus performance has been strong throughout 2018, also achieving production efficiency above 80%. Successful plant de-bottlenecking, completion of the planned maintenance shutdown and additional production following the two well drilling campaign were complemented by successful well intervention activities. Water injection performance has been strong, with high levels of uptime throughout the year, reflecting the Group's analysis of historical power generation reliability and a focus on alleviating downtime issues.

EnQuest continued to pursue a series of partner-funded idle well reservoir abandonments as part of the Group's asset life extension strategy, improving asset integrity and reducing longer-term decommissioning costs. At Thistle, six well abandonments were successfully concluded ahead of schedule and at a lower cost than budgeted, with the team subsequently mobilised to Heather to undertake abandonment work on two wells. In June, the Dunlin bypass export project was sanctioned which, once completed, will see volumes from Thistle and the Dons exported via the Magnus facility and Ninian Pipeline System to the Sullom Voe Terminal.

At the Sullom Voe Terminal, the Group made excellent progress in the optimisation of its planned work programme and identified and implemented a number of cost-saving initiatives. The Group was successful in reducing terminal operating costs by around 25% to approximately £150.0 million through focused supply chain management, efficient project delivery and simplifying and improving utilisation of the resources on site. These savings were achieved while delivering a strong safety performance and high levels of site availability. In line with the Group's aim to maximise the long-term value of the terminal, the Group has worked with the Shetland Islands Council and other stakeholders to deliver three ship-to-ship transfers of crude oil at the terminal.

2019 performance and outlook

Strong production performance at Magnus has continued, with aggregate production elsewhere broadly in line with the Group's plans.

At Magnus, the Group is focused on maintaining and improving production through a combination of drilling two new wells, further well intervention activity and increases in the facility's water injection capacity by returning to service the second of two deaeration towers on the asset and improving pump operations. EnQuest will continue to optimise the volumes and placement of both injected water and gas to maintain production. A three-week shutdown is planned for the second quarter.

The planned two-week maintenance shutdowns at Thistle and the Dons are expected to take place in the summer and have been coordinated with the operator of the existing third-party export route and the timing of the installation of the Dunlin bypass pipeline to minimise downtime during the pipeline's commissioning phase. Drilling of the Dons North East prospect continues to be evaluated.

At Heather/Broom, further well abandonments are expected to be executed during the year along with a scheduled three-week shutdown in the third quarter. Further well intervention and drilling opportunities are being developed.

Central North Sea operations

Daily average net production:

· 2018: 6,353 Boepd

· 2017: 8,131 Boepd

2018 performance summary

Production in 2018 of 6,353 Boepd was 21.9% lower than in 2017. The reduction was primarily driven by the expected performance at both Scolty/Crathes and Alma/Galia, although production at both assets was slightly better than anticipated with production efficiency at both fields above 80%.

At Alma/Galia, three failed Electric Submersible Pumps ('ESP') were successfully replaced during the third quarter, restoring aggregate production in line with plans. Production and water injection efficiency were strong, although partially offset by the end of production from the Galia reservoir following the cessation of the originally installed ESP.

Good management of wax deposition at Scolty/Crathes drove a better than expected performance and the installation of the new pipeline was sanctioned in June. Wax restrictions on production will continue to be managed until the pipeline is operational.

Aggregate production from Kittiwake and Alba was slightly ahead of expectations. Anticipated natural declines were partially mitigated by better than expected production and water injection efficiency. The team at Kittiwake delivered production efficiency of around 80% while also achieving another strong HSE&A performance, reaching 13 years without a lost-time incident.

2019 performance and outlook

Performance to the end of February has been broadly in line with the Group's expectations.

The Scolty/Crathes pipeline is expected to be installed during the third quarter. To facilitate annual maintenance and the required pipeline installation and commissioning activities, a shutdown of approximately six weeks has been planned. Once complete, production levels at Scolty/Crathes are expected to improve significantly. At Kittiwake, production optimisation activities and development options for the Eagle discovery continue to be evaluated. Following an extensive asset integrity campaign across the Greater Kittiwake Area in 2018, a short shutdown is planned during the third quarter.

With Alma/Galia expected to cease production early in the next decade, the focus is on production optimisation and cost control, with preparatory decommissioning plans now under way. A two-week scheduled shutdown is planned for the second quarter.

The Kraken development

Daily average net production:

· 2018: 21,369 Bopd

· 2017: 4,709 Bopd1

Note:

1 Net production since first oil on 23 June, averaged over the 12 months to the end of December 2017

2018 performance summary

Average gross production for 2018 was below expectations. Throughout 2018, production was limited by a number of FPSO system and weather-related outages which required additional maintenance activities to resolve. Following repairs to the water injection system, injection rates were significantly increased to manage reservoir voidage, which in turn supported improved reservoir deliverability. Reservoir performance remains on track with well testing and reservoir modelling showing excellent communication between producer and injector wells. Net lease charter payment credits arising from the non-availability of the Kraken FPSO in 2018 were approximately $45 million, which partially mitigated the loss of revenue associated with lower production performance.

At DC4, the subsea infrastructure was installed in line with plans. Drilling commenced in November after the delayed arrival of the Transocean Leader drilling rig, with first production from the wells being rephased to the end of the first quarter 2019. As a result of improved reservoir understanding, the Group gained approval for developing DC4 with three wells instead of the four originally planned, saving approximately $23 million with no material impact on oil production rates or recovery anticipated.

2019 performance and outlook

FPSO performance has continued to limit production performance at Kraken. All DC4 wells are now onstream and performing in line with expectations. As FPSO maintenance activities are completed, production is expected to significantly improve. We continue to expect to deliver gross production of between 30,000 and 35,000 Bopd from Kraken.

A three-week maintenance shutdown is scheduled for the third quarter.

The Group continues to pursue opportunities for production optimisation through improving facility uptime and reservoir management activities, including well tests, water injection and reservoir voidage. Assessment of additional near-field, low-cost drilling opportunities within the existing producing reservoir and the Western Flank, which combined contain around 115 MMbbls of stock tank oil initially in place, is ongoing.

Malaysia operations

Daily average net production:

· 2018: 8,432 Boepd1

· 2017: 8,938 Boepd1

Note

1 Working interest. 2018 entitlement: 5,631 Boepd; 2017 entitlement: 5,884 Boepd

2018 performance summary

Production in 2018 of 8,432 Boepd was 5.7% lower than in 2017, primarily reflecting natural decline at Tanjong Baram. Production efficiency has remained high at PM8/Seligi, with the planned shutdown activities in September and October successfully concluded ahead of budget and schedule. During the year, the Group undertook a significant low-cost idle well intervention programme at PM8/Seligi. In total, 12 idle wells were returned to service ahead of schedule and below budget, delivering production improvements above the Group's plans. Such programmes have been fundamental to arresting natural declines at the field since EnQuest took on operatorship. The Group also drilled its first new wells in the field, with aggregate production broadly in line with the Group's expectations. Asset integrity activities included underwater structural inspections for a number of assets, gas compressor rejuvenation and improving satellite facility monsoon reliability performance through the upgrade of control and shutdown systems. The installation of multi-phase flow meters at PM8/Seligi platforms B, E and Raya-A and remote well monitoring and testing at the satellite facilities will facilitate improved well optimisation. The team received an award for the 'Highest Improvement' in relation to offshore self-regulation, reflecting the Group's focus on safety and continuous improvement.

At Tanjong Baram, the focus remained on steady, safe and low-cost operations. Third-party export facility outages limited production efficiency and uptime throughout the year.

2019 performance and outlook

Aggregate production from PM8/Seligi and Tanjong Baram has been in line with the Group's expectations for the first two months of 2019, with the Group receiving an award for meeting domestic demand fluctuations for natural gas.

At PM8/Seligi, a two-well drilling campaign is expected to be executed in the third quarter of 2019, with first production from both wells around the end of the quarter. Further subsurface studies will be completed to enable the Group to continue to develop and optimise its future drilling opportunities to further increase recovery from the significant hydrocarbons in place, targeting an increase in production over time.

Further idle well intervention activities are planned throughout the year, with the Group planning to return to service around ten wells in order to mitigate natural decline in the reservoir.

2019 will also benefit from asset rejuvenation activity, including idle piping isolation, pipework maintenance, glycol dehydration unit rejuvenation and a compressor turbine control panel upgrade. A minimal shutdown is planned this year and is aligned with the third-party operated oil export pipeline and terminal maintenance activities to minimise downtime.

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.

At Tanjong Baram, the focus is on maintaining safe operations, with production expected to continue to decline.

Financial review

Financial overview

All figures quoted are in US Dollars and relate to Business performance unless otherwise stated.

The Group made significant progress in 2018, meeting our targets, maintaining financial discipline and making substantial repayments of our bank debt. Significant time and attention were devoted to completing the acquisition of assets from BP and executing the financing agreement for a 15% share of Kraken, which have strengthened the balance sheet and enhanced liquidity.

Production on a working interest basis increased by 48.2% to 55,447 Boepd, compared to 37,405 Boepd in 2017. The full year's contribution from Magnus, including the post-acquisition impact of an additional 75% equity interest in December, increased volumes at Kraken and the strong performance at Heather were partially offset by anticipated lower production at Alma/Galia and Scolty/Crathes, along with natural declines across the portfolio.

Revenue for 2018 was $1,201.0 million, 89.1% higher than in 2017 ($635.2 million) reflecting the material increase in volumes and higher realised prices. The Group's commodity hedge programme resulted in realised losses of $93.0 million in 2018 (2017: losses of $20.6 million) as a result of the timing at which the hedges were entered into and the increase in market prices during the first half of 2018 in particular.

The Group's operating expenditures of $465.9 million were 33.4% higher than in 2017 ($349.3 million) reflecting the full year contribution of the Kraken and Magnus assets. Unit operating costs decreased by 10.2% to $23.0/Boe (2017: $25.6/Boe) as a result of increased production.

EBITDA for 2018 was $716.3 million, up 135.9% compared to 2017 ($303.6 million), primarily as a result of increased revenue.

Note:

1 Realised (gain)/loss on FX derivatives is 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.

EnQuest's net debt decreased by $216.9 million to $1,774.5 million at 31 December 2018 (31 December 2017: $1,991.4 million). This includes $132.0 million of interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing ('Payable in Kind' or 'PIK') (31 December 2017: $90.5 million) (see note 19 for further details). Excluding PIK capitalised in 2018, net debt reduced by $258.4 million.

Notes:

1 Stated excluding accrued interest and accounting adjustment on adoption of IFRS 9 Financial Instruments of $33.4 million, and excluding the net-off of unamortised fees. Includes $117.5 million of PIK (2017: $85.7 million)

2 Stated excluding accrued interest and excluding the net-off of unamortised fees. Includes $14.4 million of PIK (2017: $4.8 million)

During the year, the Group's improved cash generation and the Kraken financing agreement facilitated cancellation and repayment of $340.0 million of the RCF, more than the scheduled amortisation requirement. In March 2019, EnQuest repaid an additional $55.0 million early with further scheduled amortisation reductions under the facility due in April 2019 ($50.0 million) and October 2019 ($100.0 million).

As at 31 December 2018, total cash and available facilities totalled $309.0 million, including ring-fenced accounts associated with Magnus, the Oz Management facility and other joint venture accounts totalling $107.3 million (2017: $270.9 million including ring-fenced accounts associated with Magnus and other joint venture accounts totalling $71.9 million). Undrawn available facilities amounted to $68.4 million at the end of 2018 (2017: $97.8 million).

UK corporate tax losses at the end of the year remained broadly in line with 2017 at $3,225.3 million (2017: $3,121.3 million). The Group generated taxable profits as production from Kraken increased and completed the acquisition of 75% of the Magnus field and associated infrastructure. Both utilised existing tax losses, which were largely offset by additional Ring Fence Expenditure Supplement ('RFES') generated in the period.

In the current environment, no significant corporation tax or supplementary corporation tax is expected to be paid on UK operational activities for the foreseeable future. During 2018, cash tax has been paid on the profits generated from Magnus and associated infrastructure assets prior to the completion of the acquisition of the additional interests. As part of this transaction, the assets were transferred to EnQuest Heather Ltd from EnQuest NNS Ltd, which allows profits generated by these assets to be offset against tax losses. Post-transfer, no taxes are expected to be payable in respect of these assets for the foreseeable future. The Group also 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

Production on a working interest basis increased by 48.2% to 55,447 Boepd, compared to 37,405 Boepd in 2017. The full year's contribution from Magnus, including the post-acquisition impact of an additional 75% equity interest in December, increased volumes at Kraken and the strong performance at Heather were partially offset by anticipated lower production at Alma/Galia and Scolty/Crathes, along with natural declines across the portfolio.

On average, market prices for crude oil in 2018 were higher than in 2017. The Group's blended average realised oil price excluding the impact of hedging was $66.2/bbl, 22.8% higher than in 2017 ($53.9/bbl). Revenue is predominantly derived from crude oil sales which totalled $1,237.6 million, 94.3% higher than in 2017 ($637.0 million), reflecting the material increase in volumes and higher realised prices. Revenue from the sale of condensate and gas was $43.1 million (2017: $2.8 million) as a result of sales of gas from Magnus, which includes the combination of produced gas sales and the onward sale of third-party gas purchases not required for injection activities, for which the costs are included in other cost of sales. Tariffs and other income generated $13.4 million (2017: $16.0 million). The Group's commodity hedges and other oil derivatives generated $93.0 million of realised losses (2017: $20.6 million), including losses of $17.2 million of non-cash amortisation of option premiums (2017: losses of $10.4 million) as a result of the timing at which the hedges were entered into and the increase in market prices during the first half of 2018 in particular. The Group's blended average realised oil price including the impact of hedging was $61.2/bbl in 2018, 17.2% higher than 2017 ($52.2/bbl).

Cost of sales

Note:

1 Calculated on a working interest basis.

Cost of sales were $926.0 million for the year ended 31 December 2018, 62.6% higher than in 2017 ($569.5 million). Operating costs increased by $116.6 million, reflecting the full year contribution of Kraken and Magnus partly offset by the benefit of a weaker Sterling exchange rate. The Group's average unit operating cost decreased by 10.2% to $23.0/Boe as a result of increased production.

Depletion expense of $437.1 million was 95.9% higher than in 2017 ($223.1 million), mainly reflecting the contribution from Kraken and Magnus in 2018. Other cost of sales of $48.1 million were higher than in 2017 ($12.7 million), principally reflecting the cost of additional Magnus related third-party gas purchases not required for injection activities.

General and administrative expenses

General and administrative expenses were $4.0 million (2017: $0.8 million), reflecting the Group's personnel and property costs.

Other income and expenses

Net other income of $19.1 million (2017: net other expenses of $17.6 million) primarily comprises net foreign exchange gains, which relate to the revaluation of Sterling-denominated amounts in the balance sheet following the weakening of Sterling against the Dollar. The prior year expense comprised net foreign exchange losses, offset by one-off general and administration recovery impacts.

Finance costs

Finance costs of $236.1 million were 58.5% higher than in 2017 ($149.0 million). The increase was primarily driven by a $40.8 million reduction in capitalised interest as a result of the Kraken project coming onstream in 2017 (2018: $1.5 million; 2017: $42.3 million), an additional $24.5 million in finance lease interest (2018: $55.8 million; 2017: $31.3 million), $19.7 million additional bond and loan interest charges (2018: $157.7 million; 2017: $137.9 million) and an additional $0.5 million relating to the unwinding of discount on provisions and liabilities, largely in respect of decommissioning (2018: $14.0 million; 2017: $13.5 million). Other finance costs included $8.5 million amortisation of arrangement fees for financing facilities and bonds (2017: $2.8 million) and other financial expenses of $1.7 million (2017: $5.9 million), primarily the cost for surety bonds principally to provide security for decommissioning liabilities.

Finance income

Finance income of $3.4 million (2017: $2.2 million) includes $1.8 million of bank interest receivable (2017: $0.4 million) and $1.5 million from the unwind of the discount on financial assets (2017: $1.8 million).

Taxation

The tax credit for 2018 of $20.9 million (2017: $66.0 million tax credit), excluding exceptional items, is mainly due to the RFES on UK activities.

Earnings per share

The Group's Business performance basic profit per share was 6.4 cents (2017: loss per share of 2.5 cents, restated for bonus element of rights issue) and Business performance diluted profit per share was 6.2 cents (2017: loss per share of 2.5 cents, restated for bonus element of rights issue).

Remeasurement and exceptional items

Revenue included unrealised gains of $97.4 million in respect of the mark to market movement on the Group's commodity contracts (2017: unrealised loss of $7.7 million).

Non-cash impairment charge on the Group's oil and gas assets arising from changes in assumptions combined with change in production profiles in the North Sea totalled $126.0 million (2017: $172.0 million).

Other income and expense included a $1.3 million loss on fair value in relation to the revaluation of the option to purchase the remaining 75% of Magnus and other interests and the fair value uplift of the initial acquisition assets on the accounting step acquisition of $74.3 million. It also includes the reversal of a contingent provision of $5.3 million.

A tax credit of $12.4 million (2017: credit of $117.0 million) has been presented as exceptional, representing the tax impact of the above items.

Earnings per share

The Group's reported basic profit per share was 10.4 cents (2017: loss per share of 4.6 cents, restated for bonus element of rights issue) and reported diluted profit per share was 10.1 cents (2017: loss per share of 4.6 cents, restated for bonus element of rights issue).

Net debt at 31 December 2018 amounted to $1,774.5 million, including PIK of $132.0 million, compared with net debt of $1,991.4 million at 31 December 2017, including PIK of $90.5 million. The Group has remained in compliance with financial covenants under its debt facilities throughout the year. The movement in net debt was as follows:

Note:

1 Stated including $117.5 million of bond PIK (2017: $85.7 million) and $14.4 million of facility PIK (2017: $4.8 million). Capitalised interest on Oz Management facility of $3.5 million (2017: $nil)

The Group's reported operating cash flows for the year ended 31 December 2018 were $794.4 million, up 163.2% compared to 2017 ($301.8 million). The main drivers for this increase were the material increase in volumes and higher realised prices, partly offset by commodity price hedges.

Cash outflow on capital expenditure is set out in the table below:

Cash capital expenditure primarily relates to Kraken activities and well drilling on Heather/Broom and PM8/Seligi.

Balance sheet

The Group's total asset value has increased by $623.4 million to $5,661.9 million at 31 December 2018 (2017: $5,038.5 million), mainly attributable to the acquisition of the remaining 75% of Magnus and associated assets. Net current liabilities have decreased to $301.2 million as at 31 December 2018 (2017: $377.9 million).

Property, plant and equipment ('PP&E')

PP&E has increased by $501.3 million to $4,349.9 million at 31 December 2018 from $3,848.6 million at 31 December 2017 (see note 10). This increase is explained by the capital additions to PP&E of $181.5 million, additions of $745.4 million for the acquisition of the remaining 75% interest in Magnus and additional interests in associated assets, additions of $123.9 million on the uplift of the original 25% acquisition, a net increase of $19.0 million for changes in estimates for decommissioning and other provisions, including the KUFPEC cost recovery provision, offset by depletion and depreciation charges of $442.4 million and non-cash impairments of $126.0 million.

The PP&E capital additions during the period, including capitalised interest, are set out in the table below:

Intangible oil and gas assets

Intangible oil and gas assets marginally decreased to $51.8 million at 31 December 2018 (31 December 2017: $52.1 million).

Trade and other receivables

Trade and other receivables have increased by $48.0 million to $275.8 million at 31 December 2018 compared with $227.8 million at 31 December 2017 (see note 15).

Cash and net debt1

The Group had $240.6 million of cash and cash equivalents at 31 December 2018 and $1,774.5 million of net debt, including PIK and capitalised interest of $135.5 million (2017: $173.1 million of cash and cash equivalents and $1,991.4 million of net debt, including PIK of $90.5 million). Net debt1 comprises the following liabilities:

· $218.9 million principal outstanding on the £155 million retail bond, including interest capitalised as an amount PIK of $21.5 million in the year (2017: $224.1 million and $14.9 million, respectively);

· $746.1 million principal outstanding on the high yield bond, including PIK of $96.1 million in the year (2017: $720.8 million and $70.8 million, respectively);

· $799.4 million carrying value of credit facility, comprising amounts drawn down of $785.0 million and PIK interest of $14.4 million (2017: $1,100.0 million comprising amounts drawn down of $1,095.2 million and PIK interest of $4.8 million);

· $178.5 million carrying value of Oz Management facility, comprising amounts drawn down of $175.0 million and capitalised interest of $3.5 million (2017: $nil);

· $15.7 million relating to the SVT Working Capital Facility (2017: $25.6 million);

· $22.2 million relating to the Mercuria Prepayment Facility (2017: $75.5 million);

· $2.5 million outstanding from a trade creditor loan (2017: $10.0 million); and

· $31.7 million principal outstanding on the Tanjong Baram Project Finance Facility (2017: $8.5 million).

Note:

1 Net debt excludes accrued interest, accounting adjustment on adoption of IFRS 9 Financial Instruments and the net-off of unamortised fees (see note 19).

Provisions

The Group's decommissioning provision increased by $32.4 million to $671.7 million at 31 December 2018 (2017: $639.3 million). The movement is explained by an increase of $29.9 million due to changes in estimates (including the impact of oil prices and foreign exchange rates) and $12.6 million unwinding of discount, partially offset by reductions of $10.0 million for decommissioning carried out in the period.

Other provisions increased by $605.4 million in 2018 to $715.4 million (2017: $110.0 million). Key movements during the period primarily related to the remaining acquisition of 75% of Magnus and additional interests in SVT and associated infrastructure assets from BP. An addition of $625.3 million reflects the discounted amounts expected to be due under the terms of the Magnus vendor loan and long-term profit sharing agreement associated with the 75% interest. In 2018, EnQuest repaid $48.6 million of the outstanding vendor loan associated with the initial 25% interest, and recognised a change in estimate of $12.8 million on the outstanding contingent consideration (see note 29). Other provisions also includes EnQuest's obligation to make payments to BP by reference to 7.5% of BP's decommissioning costs of the Thistle and Deveron fields. $5.3 million of the movement relates to the utilisation of PM8/Seligi cost recovery.

Income tax

The Group had a UK corporation tax or supplementary corporation tax liability at 31 December 2018 of $12.2 million (2017: $nil), primarily reflecting tax payable on Magnus and associated infrastructure assets prior to the completion of the acquisition of additional interests and the transfer of these assets to EnQuest Heather Limited. Following transfer of the assets, no further tax is expected to be payable for the foreseeable future. The remainder of the income tax liability of $3.7 million related to corporate income tax on Malaysian assets (see note 7).

Deferred tax

The Group's net deferred tax asset has decreased from $335.6 million at 31 December 2017 to a net deferred tax asset of $258.9 million at 31 December 2018. The decrease is mainly due to the deferred tax liability generated as part of the business combination accounting for the Magnus acquisition during the period.

Total UK tax losses carried forward at the year end amount to $3,225.3 million (2017: $3,121.3 million) (see note 7).

Trade and other payables

Trade and other payables of $502.0 million at 31 December 2018 are $55.9 million higher than at 31 December 2017 ($446.1 million). $483.8 million are payable within one year (2017: $367.3 million) and $18.2 million are payable after more than one year (2017: $78.8 million). The increase in current payables mainly reflects VAT payments due at year end combined with other working capital movements (see note 23).

Obligations under finance leases

As at 31 December 2018, the Group held a finance lease liability of $709.0 million associated with the Kraken FPSO of which $93.2 million is classified as a current liability.

Other financial liabilities

As at the end of 2018, the Group had no other financial liabilities (2017: $68.3 million). The decrease primarily relates to the cash payment associated with waiver fees due to credit facility lenders and mark to market movements on the Group's commodity derivatives following the weakening of the oil price in late 2018.

Financial risk management

Oil price

The Group is exposed to the impact of changes in both Brent crude oil prices and gas 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 repayment of debt and investment in capital programmes.

During the year ended 31 December 2018, commodity derivatives generated a total gain of $4.4 million, with revenue and other operating income including a realised loss of $93.0 million. The losses were mostly in respect of the settlement of swaps and calls, and the amortisation of premiums on calls.

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.

EnQuest continually reviews its currency exposures and, when appropriate, looks at opportunities to enter into foreign exchange hedging contracts. During the year ended 31 December 2018, losses totalling $0.4 million (2017: gain of $0.4 million) were recognised in the income statement. This included losses totalling $0.6 million realised on contracts maturing during the year (2017: $nil).

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 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 expenditure, general and administrative spend and capital expenditure in 2018 and 2019. At 31 December 2018, the Group had total cash and available facilities of $309.0 million, including ring-fenced accounts associated with Magnus, the Oz Management facility and other joint venture accounts totalling $107.3 million.

The Group's business plan ('Base case'), which underpins this going concern 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.$61.9/bbl throughout 2019 and c.$60.7/bbl for first quarter 2020. This has been further stress 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 Base case and Downside case indicate that the Company is covenant compliant and 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 circumstances arise that differ from the Group's projections, the Directors believe that a number of mitigating actions, including asset 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.

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 can continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors 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 2022. This assessment has taken into account the Group's financial position as at March 2019, 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 on pages 20 to 28. The period of three years is deemed appropriate as it is the time horizon across which management constructs a detailed plan against which business performance is measured and also covers the period within which the Group's term loan and revolving credit facility is expected to be repaid. Based on the Group's projections, the Directors have a reasonable expectation that the Group can continue in operation and meet its liabilities as they fall due over the period to March 2022.

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 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 the current forward curve.

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 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 approximately 6.5 MMbbls of collar options at an average floor price of around $66/bbl in the first half of 2019. In accordance with the Oz Management facility agreement, the Group has a further approximately 1.5 MMbbls hedged across 2019 with an average floor price of around $56/bbl. The Directors, in line with Group policy, will continue to pursue hedging at the appropriate time and price.

· Kraken production

All production and injector wells on Drilling Centres ('DC') DC1, DC2, DC3 and DC4 are onstream. Both production processing trains are also online and production and injection wells are operating in line with expectations in aggregate. On the basis of this performance, and subject to delivering on the Group's plans to further optimise production and improve plant uptime, EnQuest expects to deliver planned production rates.

· Access to funding

The Group's credit facility contains certain covenants (based on the ratio of indebtedness incurred under the term loan and revolving credit facility to EBITDA, finance charges to EBITDA, and a 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 $785 million Tranche A Term Loan and a further Tranche B $75 million revolving credit facility (collectively the 'Facility'). Across the Facility, $68 million remains available at 31 December 2018.

In addition, the maturity dates of the existing $746 million High Yield Bond and the £172 million Retail Notes (both figures inclusive of the PIK notes) is April 2022, with an option exercisable by the Group (at its absolute discretion) to extend 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 Futures benchmark 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 per barrel; 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 10.0% discount to the oil price forward curve;

· a 3.5% decrease in 2019 production and a 5.0% decrease from 2020 onwards;

· a 2.5% increase in operating costs except for fixed costs related to the Kraken FPSO; and

· a 2.5% increase in capital expenditure from 2020 onwards.

A scenario has been run illustrating the impact of the above risks on the Base case. This plausible Downside case indicates that mitigating actions, including asset sales or other funding options, would need to be undertaken for the Group to be viable for in some parts of 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 can continue in operation and meet its commitments as they fall due over the viability period ending March 2022. Accordingly, the Directors therefore support this viability statement.

Risks and uncertainties

Management of risks and uncertainties

Consistent with the Company's purpose (as set out on the inside of the front cover of this report), the Board has articulated EnQuest's strategic vision to be the operator of choice for maturing and underdeveloped hydrocarbon assets. EnQuest is focused on delivering on its targets, driving future growth and managing its capital structure and liquidity.

EnQuest seeks to balance its risk position between investing in activities that can achieve its near-term targets and drive future growth with the appropriate returns, including any appropriate market opportunities that may present themselves, and the continuing need to remain financially disciplined. This combination drives cost efficiency and cash flow generation, facilitating a reduction in the Group's debt. In this regard, the Board has developed certain strategic tenets to guide the Company 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 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:

· 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 embed a risk culture within our organisation corresponding to the risk appetite which is articulated for each of our principal risks;

· We seek to avoid reputational risk by ensuring that our operational and HSE&A processes, policies and practices reduce the potential for error and harm to the greatest extent practicable 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 and controls review exercise and a risk report (focused on identifying and mitigating the most critical and emerging risks through a systematic analysis of the Company's business, its industry and the global risk environment), is periodically reviewed by the Board (with senior management), to ensure that key issues are being adequately identified and actively managed. In addition, the Group's Risk Committee (a sub-Committee of the Board) provides a forum for the Board to review selected individual risk areas in greater depth.

As part of its strategic, business planning and risk processes, the Group considers how a number of macro-economic themes may influence its principal risks. These are factors which influence long-term supply and demand trends and/or about which the Company should be cognisant in developing its strategy. They include, for example, developments in technology, demographics, climate change and how markets and the regulatory environment may respond, and the decommissioning of infrastructure in the UK North Sea and other mature basins. These themes are relevant to the Group's assessments across a number of its principal risks. The Group will continue to monitor these themes and the relevant developing policy environment at an international and national level and will adapt its strategy accordingly. For example, EnQuest remains conscious of the potential for a number of aspects of climate change to amplify certain principal risks over time (e.g. in relation to access to capital markets - see 'Financial' risk on page 24 - and oil price - see 'Oil and gas prices' risk on page 26). The Group is also conscious that as an operator of mature producing assets with limited appetite for exploration, it has limited exposure to investments which do not deliver near-term returns and is therefore in a position to adapt and calibrate its exposure to new investments according to developments in relevant markets.

As part of its evolution of the Group's Risk Management Framework, the Risk Committee has refreshed its views on all risk areas faced by the Group (categorising these into a 'Risk Library' of 18 overarching risks). For each risk area, the Committee reviewed 'Risk Bowties' that identified risk causes and impacts and mapped these to preventative and containment controls used to manage the risks to acceptable levels.

The Board, supported by the Audit and Risk Committees, has reviewed the Group's system of risk management and internal control for the period from 1 January 2018 to the date of this report and carried out a robust assessment of the Company's emerging and principal risks, the procedures in place to identify and mitigate principal and emerging risks and confirms 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 (identified from the 'Risk Library') 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 purpose and strategy, 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 on the following pages 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 sustained decline in oil prices (see 'Oil and gas prices' risk on page 26), a lack of growth opportunities (see 'Production' risk on page 22 and 'Subsurface risk and reserves replacement' on page 23) and materially lower than expected production performance for a prolonged period, particularly at the Kraken field (see 'Production' risk on page 22).

Stefan Ricketts

Company Secretary

The Strategic Report was approved by the Board and signed on its behalf by the Company Secretary on 20 March 2019.

KEY PERFORMANCE INDICATORS

1 Lost time incident frequency represents the number of incidents per million exposure hours worked (based on 12 hours for offshore and 8 hours for onshore)

2 Including realised loss of $93.0 million in 2018 associated with EnQuest's oil price hedges (2017: realised loss of $20.6 million; 2016: realised gain of $255.8 million)

3 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, inventory revaluation and the realised gains/loss on foreign currency derivatives related to capital expenditure

4 Net of proceeds from disposal of $nil million (2017: $nil million; 2016: $1.5 million)

OIL AND GAS RESERVES AND RESOURCES

At 31 December 2018

Group Statement of Comprehensive Income

For the year ended 31 December 2018

* Restated following rights issue

The attached notes 1 to 29 form part of these Group financial statements.

Group Balance Sheet

At 31 December 2018

The attached notes 1 to 29 form part of these Group financial statements.

The financial statements were approved by the Board of Directors on 20 March 2019 and signed on its behalf by:

Jonathan Swinney

Chief Financial Officer

Group Statement of Changes in Equity

For the year ended 31 December 2018

The attached notes 1 to 29 form part of these Group financial statements.

Group Statement of Cash Flows

For the year ended 31 December 2018

The attached notes 1 to 29 form part of these Group financial statements.

Notes to the Group Financial Statements

For the year ended 31 December 2018

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 2018 were authorised for issue in accordance with a resolution of the Board of Directors on 20 March 2019.

A listing of the Group companies is contained in note 27 to these Group financial statements.

2. Summary of significant accounting policies

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 2018 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 2018.

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.

New standards and interpretations

The Group applied IFRS 15 Revenue from Contracts with Customers and IFRS 9 Financial Instruments from 1 January 2018. The nature and effect of the changes as a result of adoption of these new accounting standards are described below. Other new standards are also effective from 1 January 2018 but they do not have a material effect on the Group's financial statements. The Group has not early adopted any standards, interpretations or amendments that have been issued but are not yet effective.

IFRS 15 Revenue from Contracts with Customers

IFRS 15 establishes a comprehensive framework for determining whether, how much and when revenue is recognised. It replaces IAS 18 Revenue, IAS 11 Construction Contracts and related interpretations. The five-step model applies to revenue arising from contracts with customers and requires revenue to be recognised at an amount that reflects the consideration to which an entity expects to be entitled in exchange for transferring goods or services to a customer. Determining the timing of the transfer of control, at a point in time or over time, requires judgement.

The Group adopted IFRS 15 using the full retrospective method of adoption as per the new IFRS 15 accounting policies and the Group has assessed that there is no impact on the financial statements.

IFRS 9 Financial Instruments

IFRS 9 Financial Instruments replaces IAS 39 Financial Instruments: Recognition and Measurement, bringing together the accounting aspects for financial instruments: classification and measurement, impairment under the expected credit loss ('ECL') model and hedge accounting.

When adopting IFRS 9, the Group has applied transition relief and opted not to restate prior periods. Differences arising from the adoption of IFRS 9 are recognised in retained earnings. The total impact on the Group's retained earnings as at 1 January 2018 is $38.1 million. The effect of adopting IFRS 9 is as follows:

Impact on the statement of financial position (increase/(decrease)):

The table shows the adjustment recognised for each relevant line item. Line items that were not affected by the changes have not been included. The adjustments are recognised in the opening balance sheet on 1 January 2018.

In October 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 ('EIR'). Any fees and costs incurred are amortised over the remaining term of the asset.

At the end of 2016 the Group's bonds were refinanced, for which the modification was not considered to be significant under IAS 39. 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. 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. The cash flows were reassessed and, on 1 January 2018 on the adoption of IFRS 9, an adjustment for $38.1 million was taken through opening reserves and through the amortised value of the bonds ($15.4 million increase to high yield bonds and a $22.7 million increase to retail bonds).

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 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 requires lessees and lessors to make more extensive disclosures than under IAS 17.

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. Lessees will be required to recognise separately the interest expense on the lease liability and the depreciation expense on the right-of-use asset. There are recognition exemptions for short-term leases and leases of low-value items. Lessor accounting remains similar to the current accounting under IAS 17 i.e. lessors continue to classify leases as finance or operating leases.

During 2018, the Group has performed an impact assessment for the application of IFRS 16. This assessment is based on currently available information and will be subject to changes arising from further reasonable and supportable information being made available to the Group in 2019, including the Group's borrowing rate at 1 January 2019 when the Group will adopt IFRS 16. The Group continues to assess its accounting processes, controls and policies on an ongoing basis.

The Group will adopt the new standard on the required effective date using the modified retrospective method. The Group will apply the practical expedient to grandfather the definition of a lease on transition. It will therefore 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. The Group will also elect to use the exemptions proposed by the standard on lease contracts for which the lease terms ends within 12 months as of the date of initial application and lease contracts for which the underlying asset is of low value.

The Group has identified leases which will be recognised as finance leases under IFRS 16. On the implementation of IFRS 16 on 1 January 2019, the Group expects to recognise right-of-use assets and corresponding lease liabilities of approximately $82 million. The preliminary estimated impact on the Group's 2019 consolidated statement of comprehensive income results in a decrease in to net profit of approximately $2 million; a result of the replacement of operating lease payments previously accounted under IAS 17 by increased depreciation and finance charges under IFRS 16. EBITDA is estimated to increase by approximately $7 million. The estimated 2019 consolidated financial statements impact is computed based on the information available to date and the actual impact of IFRS 16 on the Group's 2019 consolidated financial statements may differ from the estimates provided above.

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 (see below). 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 IFRS 9, 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.

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 reassesses 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 CGU 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 the IFRS 13 fair value hierarchy). Key assumptions and estimates in the impairment models relate to: commodity prices that are based on internal view of forward curve prices for the first three years and thereafter at $75/bbl inflated at 2.0% per annum from 2023; discount rates derived from the Group's post-tax weighted average cost of capital of 10.0% (2017: 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.

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, 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% (2017: 2.0%) and an annual discount rate of 2.0% (2017: 2.0%).

Going concern

The Directors' assessment of going concern concludes that the use of the going concern basis is appropriate and that 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 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's 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.

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 Five years

Fixtures and fittings Ten 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.

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 its 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 instruments (policy applicable from 1 January 2018)

Financial assets and financial liabilities are recognised when the Group becomes a party to the contractual provisions of the financial instrument.

Financial assets are derecognised when the contractual rights to the cash flows from the financial asset expire, or when the financial asset and substantially all the risks and rewards are transferred. A financial liability is derecognised when it is extinguished, discharged, cancelled or expires. When 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 the derecognition of the original liability and the recognition of a new liability. The difference in the respective carrying amounts is recognised in the statement of profit or loss.

Financial assets and financial liabilities are offset and the net amount is reported in the consolidated statement of financial position if there is a currently enforceable legal right to offset the recognised amounts and there is an intention to settle on a net basis.

Financial assets

Initial recognition and initial measurement

Financial assets are classified, at initial recognition, as amortised cost, fair value through other comprehensive income ('FVOCI'), or fair value through profit or loss ('FVPL').

The classification of financial assets at initial recognition depends on the financial asset's contractual cash flow characteristics and the Group's business model for managing them. With the exception of trade receivables that do not contain a significant financing component or for which the Group has applied the practical expedient, the Group initially measures a financial asset at its fair value plus transaction costs (in the case of a financial asset not at fair value through profit or loss). Trade receivables that do not contain a significant financing component or for which the Group has applied the practical expedient are measured at the transaction price determined under IFRS 15.

Subsequent measurement

Financial assets at amortised cost

This category is the most relevant to the Group. The Group measures financial assets at amortised cost if both of the following conditions are met:

· The financial asset is held within a business model with the objective to hold financial assets in order to collect contractual cash flows; and

· The contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

Financial assets at amortised cost are subsequently measured using the effective interest rate method and are subject to impairment. Gains and losses are recognised in profit or loss when the asset is derecognised, modified or impaired.

Financial assets at fair value through other comprehensive income (debt instruments)

The Group measures debt instruments at fair value through OCI if both of the following conditions are met:

· The financial asset is held within a business model with the objective of both holding to collect contractual cash flows and selling; and

· The contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

For debt instruments at FVOCI, interest income, foreign exchange revaluation and impairment losses or reversals are recognised in the statement of profit or loss and computed in the same manner as for financial assets measured at amortised cost. The remaining fair value changes are recognised in OCI. Upon derecognition, the cumulative fair value change recognised in OCI is recycled to profit or loss.

Financial assets at fair value through profit or loss

Financial assets at fair value through profit or loss include financial assets held for trading, financial assets designated upon initial recognition at fair value through profit or loss, or financial assets mandatorily required to be measured at fair value. Financial assets are classified as held for trading if they are acquired for the purpose of selling or repurchasing in the near term. All financial assets not classified as measured at amortised cost or FVOCI as described above are measured at FVPL.

Derivatives, including separated embedded derivatives, are also classified as held for trading unless they are designated as effective hedging instruments. Financial assets with cash flows that are not solely payments of principal and interest are classified and measured at fair value through profit or loss, irrespective of the business model. Notwithstanding the criteria for debt instruments to be classified at amortised cost or at FVOCI, as described above, debt instruments may be designated at FVPL on initial recognition if doing so eliminates, or significantly reduces, an accounting mismatch.

Financial assets at FVPL are carried in the statement of financial position at fair value with net changes in fair value recognised in the statement of profit or loss.

This category includes derivative instruments and listed equity investments which the Group had not irrevocably elected to classify at FVOCI.

Financial assets with embedded derivatives are considered in their entirety when determining whether their cash flows are solely payment of principal and interest.

Impairment of financial assets

IFRS 9's impairment requirements use more forward-looking information to recognise expected credit losses - the ECL model. This replaces IAS 39's 'incurred loss model'.

The Group recognises an allowance for ECLs for all debt instruments not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Group expects to receive, discounted at an approximation of the original effective interest rate. The expected cash flows will include cash flows from the sale of collateral held or other credit enhancements that are integral to the contractual terms.

ECLs are recognised in two stages. For credit exposures for which there has not been a significant increase in credit risk since initial recognition, ECLs are provided for credit losses that result from default events that are possible within the next 12 months (a '12-month ECL'). For those credit exposures for which there has been a significant increase in credit risk since initial recognition, a loss allowance is required for credit losses expected over the remaining life of the exposure, irrespective of the timing of the default (a 'lifetime ECL').

For trade receivables and contract assets, the Group applies a simplified approach in calculating ECLs. Therefore, the Group does not track changes in credit risk, but instead recognises a loss allowance based on lifetime ECLs at each reporting date. The Group has established a provision matrix that is based on its historical credit loss experience, adjusted for forward-looking factors specific to the debtors and the economic environment.

For debt instruments at FVOCI, the Group applies the low credit risk simplification. At every reporting date, the Group evaluates whether the debt instrument is considered to have low credit risk using all reasonable and supportable information that is available without undue cost or effort. In making that evaluation, the Group reassesses the internal credit rating of the debt instrument. In addition, the Group considers that there has been a significant increase in credit risk when contractual payments are more than 30 days past due.

It is the Group's policy to measure ECLs on such instruments on a 12-month basis.

Financial liabilities

Initial recognition and initial measurement

Financial liabilities are classified, at initial recognition, as financial liabilities at FVPL, loans and borrowings, payables, or as derivatives designated as hedging instruments in an effective hedge, as appropriate.

All financial liabilities are recognised initially at fair value and, in the case of loans and borrowings and payables, net of directly attributable transaction costs.

The Group's financial liabilities include loans and borrowings, trade and other payables, quoted and unquoted financial liabilities, and derivative financial instruments.

Subsequent measurement

Financial liabilities at fair value through profit or loss

Financial liabilities at FVPL include financial liabilities held for trading and financial liabilities designated upon initial recognition as at fair value through profit or loss.

Financial liabilities are classified as held for trading if they are incurred for the purpose of repurchasing in the near term. This category also includes derivative financial instruments entered into by the Group that are not designated as hedging instruments in hedge relationships as defined by IFRS 9. Separated embedded derivatives are also classified as held for trading unless they are designated as effective hedging instruments. Gains or losses on liabilities held for trading are recognised in the statement of profit or loss.

The Group uses derivative financial instruments, such as forward currency contracts, interest rate swaps and commodity contracts, to address its foreign currency risks, interest rate risks and commodity price risks, respectively. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as financial assets when the fair value is positive and as financial liabilities when the fair value is negative. Any changes in fair value are recognised immediately in the profit or loss within 'Remeasurements 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 'Remeasurements and exceptional items'.

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 option's expiry date. This results in a corresponding reclassification from 'Remeasurements and exceptional items' revenue.

The Group has not designated any derivative financial instruments as hedging instruments for the periods contained within these financial statements.

Loans and borrowings

This is the category most relevant to the Group and includes the measurement of the bonds. After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortised cost using the EIR method. Gains and losses are recognised in profit or loss when the liabilities are derecognised as well as through the EIR amortisation process. This category generally applies to interest-bearing loans and borrowings.

Amortised cost is calculated by taking into account any discount or premium on acquisition and fees or costs that are an integral part of the EIR. The EIR amortisation is included as finance costs in the statement of profit or loss.

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.

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.

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.

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.

Group as a lessee

A lease is classified at the inception date as a finance lease or an operating lease. A lease that transfers substantially all the risks and rewards incidental to ownership to the Group is classified as a finance lease.

Finance leases 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.

An operating lease is a lease other than a finance lease. Operating lease payments are recognised as an operating expense in the income statement on a straight-line basis over the lease term.

Group as a lessor

Leases in which the Group does not transfer substantially all the risks and rewards of ownership of an asset are classified as operating leases. Rental income arising is accounted for on a straight-line basis over the lease terms and is included in revenue in the statement of profit or loss due to its operating nature. Initial direct costs incurred in negotiating and arranging an operating lease are added to the carrying amount of the leased asset and recognised over the lease term on the same basis as rental income. Contingent rents are recognised as revenue in the period in which they are earned.

Revenue from contracts with customers

Revenue from contracts with customers is recognised when control of the goods or services are transferred to the customer at an amount that reflects the consideration to which the Group expects to be entitled to in exchange for those goods or services. The Group has concluded that it is the principal in its revenue arrangements because it typically controls the goods or services before transferring them to the customer.

Sale of crude oil, gas and condensate

The sale of crude oil, gas or condensate represents a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue is accordingly recognised for this performance obligation when control over the corresponding commodity is transferred to the customer. 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. The normal credit term is 30 to 90 days upon collection or delivery.

Tariff revenue for the use of Group infrastructure

Tariffs are charged to customers for the use of infrastructure owned by the Group. There is one contract per customer which is for a period of 12 months or 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 interdependent in order to fulfil the contract and no one item of infrastructure can be individually isolated. Revenue is recognised over the performance of the contract as services are provided for the use of the infrastructure at the agreed contracted rates on a throughput basis.

Other income

Other income is recognised to the extent that it is probable economic benefits will flow to the Group and the revenue can be reliably measured.

Production imbalances and under/over-lift

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. All Group fields are operated through a Joint Venture Agreement ('JVA') through which production imbalances are settled. Settlement occurs through agreed lifting schedules and are not settled in cash, with the exception of a misbalance at the cessation of contract. As collaborative agreements and non-monetary exchanges, the transactions do not meet the definition of a customer under IFRS 15 and are recognised through cost of sales.

The under or over-lifted positions of hydrocarbons arising from production imbalances 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.

Remeasurements 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 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;

· 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; and

· Other exceptional items that arise from time to time as reviewed by management and disclosed as exceptionals in the notes to the financial statements, such as the acquisition accounting of Magnus and other interests in 2017 and 2018.

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.

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') within the UK 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 allowance

The UK taxation regime provides for a reduction in ring fence supplementary corporation tax where investment in new or existing UK assets qualify for a relief known as investment allowance. Investment allowance must be activated by commercial production from the same field before it can be claimed. The Group has both unactivated and activated investment allowance which could reduce future supplementary corporation taxation. The Group's policy is that investment allowance is 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.

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 profit/(loss):

Revenue from two customers relating to the North Sea operating segment each exceed 10% of the Group's consolidated revenue arising from sales of crude oil, with the total amount of $580.5 million (2017: two customers; $206.1 million arising in the North Sea operating segment and $105.2 million in the 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 $111.7 million located in Malaysia (2017: $119.1 million).

4. Remeasurements and exceptional items

(i) Fair value remeasurements 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 recycled realised gains and losses (including option premia) out of 'Remeasurements and exceptional items' and into 'Business performance' profit or loss. Refer to note 2 for further details on the Group's accounting policies for derivatives and 'Remeasurements and exceptional items'. In addition, this includes the fair value remeasurement of contingent consideration on the Magnus vendor loan of $9.7 million (2017: includes $1.3 million gain in respect of the disposal of the Ascent Resources loan notes)

(ii) Impairments and write offs includes an impairment of tangible oil and gas assets totalling $126.0 million (2017: impairment of $172.0 million). 2017 includes a charge of $2.7 million in relation to exceptional inventory write downs. Further details on the tangible impairment are provided in note 10

(iii) Other includes a $1.3 million loss in relation to the revaluation of the option to purchase the Magnus oil field and other interests and $74.3 million in relation to the step acquisition uplift of the original 25% equity acquired in 2017 (see note 29) (2017: $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). Other movements mainly relate to the derecognition of contingent consideration on future exploration of $5.3 million (see note 22) (2017: 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). 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) In 2017, other tax exceptional items included $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

5. Revenue and expenses

(a) Revenue

The Group generates revenue through the sale of crude oil, gas and condensate, and the provision of infrastructure to its customers for tariff income. Other sources of revenue include amounts related to derivative contracts and rental income from operating leases.

The nature and effect of initially applying IFRS 15 on the Group's financial statements are disclosed in note 2.

(i) 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)

Disaggregation of revenue from contracts with customers

Revenue derived from the sale of crude oil, gas and condensate is recognised as goods transferred at a point in time when control is gained by the customer on collection or delivery. The sale of oil is subject to market prices. The Group manages this risk through the use of commodity derivative contracts. Revenue derived from tariff revenue is recognised as the service is provided over time.

Contract balances

The following table provides information about receivables from contracts with customers. There are no contract assets or contract liabilities.

Trade receivables are non-interest-bearing and are generally on terms of 30 to 90 days post control gained by the customer. In 2018 and 2017, no provision was recognised for expected credit losses on trade receivables.

(b) Cost of sales

(i) The realised loss on foreign exchange derivative contracts was $0.6 million for contracts related to operating expenditure (2017: loss of $4.8 million related to capital expenditure)

(ii) Unrealised gains and losses on foreign exchange derivative contracts which are held for trading are disclosed as exceptional in the income statement (see note 4)

(c) General and administration expenses

(d) Other income