Enquest Regulatory News (ENQ)

Results for the year ended 31 December 2017 and 2018 outlook

20 March 2018

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

2017 performance

· Kraken first oil delivered in Q2; full cycle gross project capital expenditure further reduced

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

· Group production averaged 37,405 Boepd in 2017, down 5.9% on 2016

· Revenue of $635.2 million (2016: $849.6 million) and EBITDA of $303.6 million (2016: $477.1 million); lower realised prices, reflecting the favourable impact of commodity hedges in 2016

· Cash generated from operations of $327.0 million (2016: $408.3 million)

· Cash capital expenditure of $367.6 million (2016: $609.2 million)

· Cash* and available bank facilities amounted to $244.4 million at 31 December 2017, with net debt of$1,991.4 million. Excluding Payment in Kind interest, net debt was $1,900.9 million

· Reported post-tax non-cash impairments of $107.2 million

· Net 2P reserves of 210 MMboe at the end of 2017

* Excluding $26.5 million of cash from the ring fenced working capital facility associated with SVT. 

2018 outlook

· Guidance range of c.50,000 to 58,000 Boepd; Kraken gross production has averaged around 38,000 Bopd in the first two months of the year

· Unit opex expected to be c.$24/Boe, including costs associated with planned workovers

· Cash capital expenditure expected to be c.$250 million; includes drilling programmes at Kraken (DC4), PM8/Seligi and Heather

· Kraken full cycle gross project capital expenditure further reduced to c.$2.3 billion, more than 25% lower than originally sanctioned

· The Group has hedged c.7.5 MMbbls of oil at an average price of c.$62/bbl 

EnQuest Chief Executive, Amjad Bseisu, said:

"2017 was a transformational year for EnQuest. The Group delivered the complex Kraken project on schedule and expects full cycle gross capital expenditure to be significantly below budget, while the acquisition of the Magnus oil field and Sullom Voe Oil Terminal is aligned with the Group's asset life extension capabilities and provides further opportunities for synergies and growth.

"Production performance in January and February was strong and the Group expects a material increase in production in 2018. This growth, combined with a focus on cost control and a substantially reduced cash capital expenditure programme, should see the Group generate increased cash flow, enabling it to manage its liquidity and reduce debt.

"Beyond 2018, the Group has significant potential within the existing portfolio, in particular at Magnus and PM8/Seligi, but also with potential future developments at Kraken, positioning EnQuest to deliver long-term sustainable growth."Production and financial information

**EBITDA is calculated on a business performance basis, and is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion, depreciation, foreign exchange movements and the realised gains/loss on foreign currency derivatives related to capital expenditure. *** Including losses of $20.6 million (2016: revenue of $255.8 million) associated with EnQuest's oil price hedges. ****Cash capex is stated net of proceeds received from the disposal of tangible and intangible fixed assets of $nil (2016: $1.5 million). ***** Net (debt)/cash represents cash and cash equivalents less borrowings, stated excluding accrued interest and the net-off of unamortised fees.

Production details

1 Includes net production from Magnus since acquisition on 1 December 2017, averaged over the 12 months to the end of December 2017.

2 Includes net production from Scolty/Crathes since first oil on 21 November 2016, averaged over the 12 months to the end of December 2016.

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

2017 performance summary

The Group's focus during the year was to deliver the Kraken development, complete the acquisition of assets from BP and position the Group for profitable growth as it transitions from a period of heavy investment to one in which the Group can begin to reduce its debt. First oil from the Kraken project, one of the largest developments in the North Sea in the last ten years, was delivered on schedule, with full cycle gross capital expenditure expected to be significantly below budget. EnQuest completed the acquisition of initial interests in Magnus, the Sullom Voe Oil Terminal and associated infrastructure in December.

Production for the year was lower than originally expected at 37,405 Boepd, impacted by Electrical Submersible Pump performance at Alma/Galia and lower contributions from the Scolty/Crathes and Kraken developments.

The Group's focus on cost control and management of commercial agreements resulted in lower operating expenditures of $349.3 million, with unit opex of $25.6/boe. However, lower realised prices, reflecting the forward prices available at the time at which the commodity hedge programme was implemented, combined with lower production reduced EnQuest's revenue, EBITDA and cash generated by operations.

As expected, cash capital expenditure of $367.6 million was materially lower than 2016. The majority of the expenditure was at Kraken, with the remaining spend largely reflecting the settlement of deferred invoices in respect of the Alma/Galia and Scolty/Crathes developments and the Eagle discovery. Excellent drilling performance at Kraken has delivered the first three drill centres ('DC's) significantly ahead of schedule, which, along with lower market rates for the remaining subsea campaign, resulted in a reduction of approximately $100 million in the expected full life gross project capital expenditure estimate.

Liquidity and net debt

EnQuest's lending banks continued their support of the Group and agreed to relax the Company's covenants and to amend the amortisation schedule of its Term Loan and Revolving Credit Facility. EnQuest also agreed an $80 million oil prepayment transaction and execution of a $37.25 million refinancing agreement in relation to its Tanjong Baram project. EnQuest finished the year with net debt of $1,991.4 million, with cash and available bank facilities of$244.4 million, excluding $26.5 million of cash from the ring fenced working capital facility associated with SVT.

Reserves

Net 2P reserves at the end of 2017 were 210 MMboe, (2016: 215 MMboe) representing a reserve life of 17 years. The slight reduction in reserves was driven by some changes in long-term assumptions combined with lower production performance in the North Sea, largely offset by the benefit of the acquisition of an initial 25% equity interest in Magnus and better production performance in Malaysia.

2018 performance and additional outlook details

Production performance in the first two months of 2018 was strong across the portfolio, with Kraken gross average production around 38,000 Bopd in this period. Extreme cold weather in early March resulted in brief shutdowns at a number of the Group's North Sea fields. While Kraken was shut down, the Group has undertaken much of the workscope previously scheduled for the planned shutdown in April and, as a result, this planned shutdown is no longer required. The Group continues to have planned maintenance shutdowns at a number of the Group's fields, including Kraken, in the third quarter. The drilling programmes at Magnus and PM8/Seligi, along with the workover programme at Alma/Galia are expected to deliver production improvements later in the year, with the DC4 programme at Kraken expected to come into production in 2019. The Group expects material net production growth in 2018 to within the guidance range of c.50,000 to 58,000 Boepd.

The Group continues to expect unit operating expenditures of approximately $24/Boe, including the impact of planned workovers at Alma/Galia, while the depletion and depreciation charge is anticipated to be around $22/Boe, reflecting the impact of a full year's contribution from Kraken.

2017 general and administration costs reflect the Group's ongoing efforts to reduce costs across the organisation. 2018 costs are expected to be in the 'single digit' millions.

Cash capital expenditure is still expected to be around $250 million, largely reflecting the drilling programmes at Kraken, Heather and PM8/Seligi. The renegotiation of the drilling rig contract with Transocean, reducing both the contract duration and day rate, has resulted in net cash capital expenditure savings of c.$60 million in 2019. Kraken full cycle gross project capital expenditure is now expected to be c.$2.3 billion, more than 25% lower than originally sanctioned.

EnQuest continues to take prudent measures to improve its liquidity position. In January, EnQuest received $30 million in cash in exchange for agreeing to undertake the management of the physical decommissioning at Thistle and Deveron and being liable to make payments to BP by reference to 3.7% of the gross decommissioning costs of these assets. The Group has an outstanding option, exercisable over a 12 month period, to receive a further $20 million in cash in exchange for making additional payments by reference to 2.4% of the gross decommissioning costs of these fields. In February, the Group completed the $37.25 million refinancing agreement in relation to its Tanjong Baram project, providing approximately $25 million in additional liquidity.

Summary financial review of 2017

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

Total revenue for 2017 was $635.2 million, 25.2% lower than 2016 ($849.6 million). This reduction was largely as a result of lower realised prices, which reflected the forward prices available at the time at which the commodity hedge programme was implemented. The commodity hedge programme resulted in realised losses of $20.6 million in 2017 compared to realised gains of $255.8 million in 2016. As a result, the Group's blended average realised oil price was $52.2/bbl in 2017, compared to $63.8/bbl during 2016. Excluding this hedging impact, the average realised oil price was $53.9/bbl in 2017, 21.8% higher than 2016 ($44.3/bbl), reflecting higher market prices. Revenue is predominantly derived from crude oil sales which totalled $637.0 million for 2017, 10.2% higher than 2016 ($577.8 million). This increase in crude oil revenue reflected a higher market oil price, partially offset by lower production.

Total cost of sales for 2017 was $569.5 million, 12.9% lower than 2016 ($653.5 million). This included depletion expense of $223.1 million (2016: $240.6 million).

Operating expenditures of $349.3 million were 2.3% lower than 2016 ($357.4 million), reflecting the Group's focus on cost control and management of commercial agreements and includes net lease charter payment credits of$19.5 million arising from the non-availability of the Kraken FPSO and the absence of the 2016 loss on operating expense foreign exchange derivatives, partially offset by a full year of operations at Scolty/Crathes, which came onstream in November 2016. The Group's average unit operating cost for 2017 was $25.6/Boe, 4.0% higher than 2016 ($24.6/Boe) primarily as a result of the 5.9% reduction in production.

Realised losses on foreign currency derivatives related to capital expenditure were $4.8 million, down 89.9% compared to 2016 (losses of $47.3 million) reflecting weaker Sterling:US Dollar exchange rates during the year.

At 31 December 2017, the Group had moved to a net underlift position compared to the prior year end net overlift position, resulting in a $20.4 million credit to cost of sales (2016: charge of $2.8 million).

Other net expenses of $17.6 million (2016: income of $51.9 million) primarily comprise net foreign exchange losses, as a result of revaluing Sterling-denominated amounts on the balance sheet following the strengthening of Sterling against the US Dollar. The prior year included foreign exchange gains of $51.9 million.

EBITDA for 2017 was $303.6 million, 36.4% lower than 2016 ($477.1 million) largely as a result of lower realised prices and lower production.

The tax credit for 2017 of $66.0 million (2016: $5.2 million tax credit), excluding exceptional items, is due predominantly to the Ring Fence Expenditure Supplement on UK activities.

Exceptional items resulting in a net post-tax loss of $27.3 million have been disclosed separately for 2017 (2016: profit of $63.7 million). These largely reflect tangible oil and gas non-cash impairments of $107.2 million, primarily arising from some changes in assumptions combined with lower production performance in the North Sea, partially offset by the recognition of accounting for the excess of fair value over consideration of $48.7 million associated with the acquisition of initial interests in assets from BP.

Net debt at 31 December 2017 was $1,991.4 million, an increase of 10.8% compared to 2016 ($1,796.5 million) primarily as a result of the capital expenditure programme for 2017 of $367.6 million (2016: $609.2 million), principally at Kraken. Excluding Payment in Kind interest ('PIK'), net debt was $1,900.9 million (2016: $1,768.8 million).

UK corporate tax losses at the end of the year increased to $3,121.3 million (2016: $2,893.7 million).

Ends

For further information please contact:

EnQuest PLC Tel: +44 (0)20 7925 4900

Amjad Bseisu (Chief Executive)

Jonathan Swinney (Chief Financial Officer)

Ian Wood (Communications & Investor Relations) 

Tulchan Communications Tel: +44 (0)20 7353 4200

Martin Robinson

Martin Pengelley

Presentation to Analysts and 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)330 336 9105

USA: +1 323 794 2093

Confirmation Code: EnQuest

Notes to editors

This announcement has been determined to contain inside information.

ENQUEST

EnQuest is one of the largest UK independent producers in the UK North Sea. EnQuest PLC trades on both the London Stock Exchange and the NASDAQ OMX Stockholm. Its operated assets include Thistle/Deveron, Heather/ Broom, the Dons area, Magnus, the Greater Kittiwake Area, Scolty/Crathes Alma/Galia and Kraken; EnQuest also has an interest in the non-operated Alba producing oil field. At the end of December 2017, EnQuest had interests in 25 UK production licences and was the operator of 23 of these licences.

EnQuest believes that the UKCS represents a significant hydrocarbon basin, which continues to benefit from an extensive installed infrastructure base and skilled labour. EnQuest believes that its assets offer material organic growth opportunities, driven by exploitation of current infrastructure on the UKCS and the development of low risk near field opportunities.

EnQuest is replicating its model in the UKCS by targeting previously underdeveloped assets in a small number of other maturing regions; complementing its operations and utilising its deep skills in the UK North Sea. In which context, EnQuest has interests in Malaysia where its operated assets include the PM8/Seligi Production Sharing Contract and the Tanjong Baram Risk Services Contract.

Forward-looking statements: This announcement may contain certain forward-looking statements with respect to EnQuest's expectation and plans, strategy, management's objectives, future performance, production, reserves, costs, revenues and other trend information. These statements and forecasts involve risk and uncertainty because they relate to events and depend upon circumstances that may occur in the future. There are a number of factors which could cause actual results or developments to differ materially from those expressed or implied by these forward-looking statements and forecasts. The statements have been made with reference to forecast price changes, economic conditions and the current regulatory environment. Nothing in this announcement should be construed as a profit forecast. Past share performance cannot be relied on as a guide to future performance.

Chairman's statement

EnQuest performance overview

EnQuest delivered a number of commendable operational achievements in 2017, combined with another year of strong safety performance. In June, first oil was achieved at the Kraken project, a critical turning point for the Company in delivering improved operating cash flow and marking the start of a material reduction in the Group's capital investment requirements. While the subsequent ramp-up in production took longer than anticipated following initial commissioning and operational efficiency issues, by the end of the year, this large and complex development had produced over 40,000 Bopd (gross). In the first two months of 2018, average gross production was around 38,000 Bopd, and has reached 50,000 Bopd with improving operational efficiency as we continue to optimise performance.

Group production of 37,405 Boepd in 2017 was disappointing, primarily caused by performance issues at Alma/Galia and lower than planned production from both Kraken and Scolty/Crathes.

Despite the challenges presented by the prevailing macro-economic environment, the Group undertook further steps to set the platform to improve the balance sheet. The Group delivered operating and capital expenditures in line with targets, demonstrating the team's focus on cost control and managing commercial agreements. EnQuest also completed a crude oil prepayment transaction and executed a refinancing agreement for its Tanjong Baram project in Malaysia, which combined improve the Group's liquidity by more than $100 million.

The Group continued to pursue its vision and advance its long-term growth plan, agreeing and completing the acquisition of interests in the Magnus oil field and the Sullom Voe Oil Terminal ('SVT') from BP. This innovatively structured transaction required no immediate cash payment from EnQuest and limits the Group's exposure to negative cash flows from Magnus, capitalising on EnQuest's strengths in realising value from maturing oil fields with large volumes in place.

This transaction adds to the material growth potential of EnQuest's asset base. By the end of 2017, EnQuest had a net 2P reserve base of 210 MMboe, which represents average growth of approximately 13% per annum since EnQuest's formation eight years ago and a reserve life of around 17 years.

Industry context

Oil & Gas UK's Economic Report 2017 showed that since 2014 the cost of lifting oil from the North Sea has almost halved, an improvement in unit operating costs highlighted as being greater than the improvements achieved by any other basin. EnQuest's cost conscious approach has been central to its business model since its inception and the Group remains focused on driving innovative and collaborative ways of operating to deliver cost savings across its business. While that quantum of reduction in operating costs cannot be repeated, a focus on improving costs and driving efficiencies is a fundamental requirement in ensuring EnQuest is able to deliver profitable growth over the long term.

The opportunity for long-term growth in the North Sea is clear: The UK Oil & Gas Authority recently announced they expect 11.7 billion barrels of oil and gas to be produced from the UK Continental Shelf ('UKCS') over the period 2016 to 2050, an increase of 2.8 billion barrels of oil and gas from that previously forecast; and the UK Department for Business, Energy & Industrial Strategy forecasts oil and gas will still be supplying around two-thirds of domestic energy demand by 2035, confirming their place as vital sources of energy supply.

EnQuest is supportive of the UK Government's proposals to introduce a mechanism to transfer tax history on the sale and purchase of North Sea oil assets. We welcome the removal of a potential tax barrier to the conclusion of deals. EnQuest has demonstrated the dramatic and positive impact on production, production efficiency and field life which can be achieved when assets move into the right hands. If implemented in the right way, these measures will be another positive step by the Government in supporting the strategy for Maximising Economic Recovery for the UK.

The UKCS remains a compelling basin in which to invest. It has exciting hydrocarbon opportunities, established infrastructure, access to a world-class supply chain and a highly skilled workforce, all supported by a globally competitive fiscal regime. A similar investment proposition continues to prevail in Malaysia, where the Group has a strong partnership with PETRONAS. These opportunities provide EnQuest with long-term potential for growth.

The EnQuest Board

With the Board's focus on succession planning, and after rigorous search processes, I was delighted to welcome three new Non-Executive Directors to the Company since the start of 2017: Carl Hughes joined the Board on 1 January 2017, having previously been an energy and resources audit partner of Deloitte; John Winterman, who has extensive leadership experience in global exploration, business development and asset management, was appointed on7 September 2017; and Laurie Fitch, who has worked in a variety of investment and corporate finance roles, joined us on 8 January 2018. All three bring considerable and varied expertise to the Company and I look forward to working with them.

In July 2017, Dr Philip Nolan stepped down from his role as Non-Executive Director, having joined the Board in 2012.I thank Philip for his valuable contribution to the Company, especially in its development over the past five years.I would also like to thank Neil McCulloch, who stepped down as Chief Operating Officer and Executive Director in December 2017, for his unstinting contribution to EnQuest during a challenging period for both the Company and industry.

EnQuest's people

In 2017, the Group remained focused on positioning the business for the prevailing oil price environment, whilst at the same time ensuring it continued to achieve its operational targets. Management of matters pertaining to the Kraken and Magnus projects required significant amounts of the Board and management's time and attention, while compliance with debt covenants and review of liquidity options also remained a priority. The Group's achievements against these objectives have only been possible due to EnQuest's people. The Board and I would like to express our gratitude to everyone at EnQuest for having continued to work with such energy and dedication to address the challenges presented in recent years, ensuring that EnQuest can move forward, to create further value from opportunities in maturing oil fields.

The Board and I would also like to take this opportunity to thank all those who worked on the acquisition of assets from BP, and extend a particularly warm welcome to our new colleagues and contractor workforce who joined EnQuest as a result.

Strategy and governance

The Directors provide strategic guidance to executive management and take key decisions on the implementation of the Group's strategy. During 2017, the Board reviewed and refined the presentation of the Company's purpose, vision, strategy and business model. In addition, a number of 'tenets' were developed to guide the Company's pursuit of its strategy in accordance with the Group's appetite for risk and within its Risk Management Framework.

Ensuring that the Board works effectively remains a key focus of the Company. 2017 saw the Risk Committee, established in 2016, fully embedded into the governance structure of the Company. The primary purpose of the Risk Committee is to provide a forum for in-depth examination of non-financial risk areas. EnQuest's governance framework also contains several non-Board Committees, which provide advice and support to the Chief Executive, including an Executive Committee, Operations Committee and Investment Committee.

The Board believes that the manner in which it conducts its business is important and it is committed to delivering the highest standards of corporate governance for the benefit of all of its stakeholders. The Board has approved the Company's overall approach to corporate responsibility, which is focused on five main areas. These are Health and Safety, People, Environment, Business Conduct and Community.

The Board receives regular information on the performance of the Company in these areas, and specifically monitors health and safety and environmental reporting at each Board meeting. The Company's Health, Safety, Environment & Assurance ('HSE&A') Policy is reviewed by the Board annually and all incidents, forward-looking indicators and significant HSE&A programmes are discussed by the Board. Specific developments and updates in all areas are brought to the Board's attention when appropriate.

The Group has a Code of Conduct that it requires all personnel to be familiar with as it sets out the behaviour which the organisation expects of its Directors, managers and employees, and of our suppliers, contractors, agents and partners. This year, it has been updated with guidance on preventing the facilitation of tax avoidance.

EnQuest's company values underpin a working environment where people are safe, creative and passionate, with a relentless focus on results. Inductions for all employees transferring from BP were run in September to ensure that all those impacted understood the EnQuest business, how we work and how they can contribute to EnQuest's success. Alongside this, time was invested to understand the culture of our business through an online survey and subsequent focus groups. Following a review of the results from these activities, the Executive Committee is working on identifying the next steps to develop the culture and ensure that EnQuest is an attractive place to work.

Dividend

The Company has not declared or paid any dividends since incorporation and does not plan to pay dividends in the near future. Any future payment of dividends is expected to depend on the earnings and financial condition of the Company meeting the conditions for dividend payments which the Company has agreed with its lenders and such other factors as the Board of Directors of the Company considers appropriate.

2018: A new chapter

In 2018, EnQuest is entering a new phase. Kraken is progressing well, the Magnus integration and drilling programmes are well underway, plans are being developed to enhance performance at our other producing assets, and the period of heavy capital investment is largely behind us. These material advances should result in EnQuest generating positive net cash flow after investment and tax, allowing us to continue to manage our capital structure and liquidity position. Despite the current improvement in the near term oil price environment, we recognise we must maintain our focus on financial discipline, cost efficiencies and managing Group liquidity. Consequently, it is important that we prioritise our resources to those key projects which maximise cash flow to facilitate debt reduction, continuing the Company's progress towards a more sustainable balance sheet and enabling the long-term growth of the business.

Chief Executive's report

EnQuest's priorities and performance in 2017

2017 was a transformational year for EnQuest, positioning the Group for profitable growth and transitioning from a period of heavy capital investment to one in which the Group can begin to reduce its debt. The Group focused on the Kraken development, completion of the asset acquisitions from BP, delivery against our financial and operational targets and the effective management of the Group's financial position.

Operational performance

EnQuest was proud to deliver first oil from Kraken on schedule while significantly reducing full cycle gross capital expenditure. Kraken is one of the largest developments in the North Sea in the last ten years, comprising a phased drilling campaign of 25 wells tied back to a complex new Floating Production, Storage and Offloading ('FPSO') vessel. The drilling performance has been excellent, with the first three programmes completed early and at a lower cost than originally planned. The FPSO has taken longer than expected to commission, leading to lower operational efficiency than planned. A systematic process to resolve these issues has improved uptime and, with the reservoir performing in line with expectations, production increased throughout 2017 and into 2018.

On 1 December 2017, EnQuest completed the acquisition of initial interests in Magnus, SVT and associated infrastructure from BP and assumed operatorship. This large and complex transition was achieved safely and efficiently, delivered on time and on budget, with the integration of these assets into the EnQuest business progressing well.

EnQuest's average production of 37,405 Boepd reflected Electrical Submersible Pump ('ESP') performance issues at Alma/Galia and lower than planned production from both Kraken and Scolty/Crathes. Overall the Group's production performance was disappointing and led to EnQuest reducing its 2017 production guidance in August last year. However, the combination of improving performance at Kraken, planned drilling and workover campaigns at a number of assets and a full year's contribution from Magnus underpins EnQuest's expectation of material production growth in 2018.

Net 2P reserves of 210 MMboe at the end of 2017 represented a 2.4% decrease on the 215 MMboe at the end of 2016. This small decline reflects some changes in long-term assumptions, combined with lower production performance in the North Sea, partially offset by the Magnus acquisition related increase and better performance in Malaysia. When EnQuest was formed in 2010, it had 81 MMboe of reserves. Our ability to exploit, develop, convert and selectively acquire or dispose of reserves has meant that by the end of 2017, EnQuest had produced almost the entirety of this initial reserve base, and still has 2P reserves with a current production life of around 17 years.

Financial performance

The Group's focus on financial discipline resulted in total operating expenditures of $349.3 million, unit opex of $25.6/Boe and cash capital expenditure of $367.6 million. While it is becoming more challenging to deliver the large decreases in operating costs of recent years, the Group will continue to pursue further operating cost reduction initiatives. 

EBITDA of $303.6 million was materially lower than 2016. This reduction was driven by lower realised prices, which reflected the forward prices available at the time at which the commodity hedge programme was implemented, combined with lower production. The commodity hedge programme resulted in realised losses of $20.6 million in 2017 compared to realised gains of $255.8 million in 2016.

EnQuest's ongoing programme of prudent measures to improve liquidity included the completion of an $80 million oil prepayment transaction and execution of a $37.25 million refinancing agreement in relation to its Tanjong Baram project, which completed in February 2018. Combined, this provides over $100 million of additional financial resources. EnQuest continued its close dialogue with its lending banks, agreeing a relaxation of the Company's covenants and amending the amortisation schedule of its Term Loan and Revolving Credit Facility; these changes provided additional flexibility while Kraken continued to increase production rates. EnQuest finished the year with net debt of$1,900.9 million, excluding Payment in Kind interest.

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

EnQuest delivered on its commitment to continual improvement in HSE&A performance, achieving good year-on-year improvement in 2017 with excellent results in many areas and meeting the majority of our performance targets.

In occupational safety, our Lost Time Incident ('LTI') performance remained strong in both Malaysia and the UK, with many assets recording an LTI-free year. We had no reportable hydrocarbon releases during 2017 on our UK operated assets having increased our focus on asset integrity and implemented hydrocarbon prevention plans across our sites. Our drive for operational excellence saw continued focus in the UK on coaching our workforce to identify and understand control of Major Accident Hazards ('MAH'), embedding our life saving rules and transitioning to a new control of work tool which enhances both system and behavioural compliance. In March, members of the Board visited a contractor's emergency response centre to help benchmark and refine EnQuest's own emergency response and crisis management plans.

EnQuest's focus on HSE&A is always a priority. Under our continual improvement programme, activities in 2018 focus further on control of MAH and developing and empowering employees to deliver safe results.

North Sea operations

In December, Faysal Hamza and Bob Davenport took over management of EnQuest's North Sea operations as Interim Head of North Sea and Managing Director, North Sea respectively.

Production in 2017 from the North Sea averaged 28,467 Boepd, down 7.0% compared to 2016. This reduction was driven by lower volumes from Alma/Galia reflecting ESP related well shut-ins, storm-related production outages and natural declines. Production at other assets was also reduced by lower water injection, natural declines and an unscheduled shutdown in December of the third-party operated Forties Pipeline.

Partially offsetting this decline was production from Kraken, a full year of production from Scolty/Crathes, limited by wax in the flowline, and the initial contribution from Magnus. Various production enhancement activities were successfully undertaken during the year, improving performance at a number of fields by year end.

The Kraken development

Following first oil on 23 June 2017, production increased throughout the second half of the year as both production and injection wells performed in line with expectations and the commissioning and operational efficiency issues, encountered during the initial production build up, were addressed. The second processing train, which was brought online during November, assisted in bringing gross production rates to over 40,000 Bopd. All production and water injection wells from the first three drill centres ('DCs') have been brought online and operational efficiency has significantly improved. Whilst production has been constrained, FPSO charter rates have been reduced in accordance with production levels. We continue to work with the operator to maximise production from Kraken.

The combination of excellent delivery of the DC3 drilling programme, lower market rates for the remaining subsea campaign and the renegotiation of the drilling rig contract with Transocean has resulted in significant reductions to the full cycle gross project capital expenditure, which is now expected to be c.$2.3 billion. This is more than 25% lower than originally sanctioned.

Magnus and Sullom Voe Oil Terminal

The acquisition is a good strategic and operational fit for EnQuest, providing opportunities for synergies and growth. We invest safely to realise value from opportunities presented in maturing assets, applying our differential capabilities to deliver high levels of production efficiency, asset life extension and cost control. The transaction is aligned with the UK's strategy of Maximising Economic Recovery by getting the right assets into the right hands. Magnus is a good quality reservoir with large volumes in place, providing opportunities for infill drilling and the revitalisation of wells. BP's confidence in EnQuest taking over operatorship underlines EnQuest's capabilities as an asset life extension expert.

Malaysia operations

Production in 2017 was broadly in line with 2016 at 8,938 Boepd, reflecting good operational uptime across PM8/Seligi and Tanjong Baram and the execution of key work scopes, such as the compression reliability improvement and well interventions at PM8/Seligi. Given the natural decline rates of these mature fields, this performance is testament to the team's capabilities in maximising hydrocarbon recovery in advance of the Group's first drilling campaign in PM8/Seligi, planned for 2018.

2018 performance and outlook

The Group expects material production growth in 2018 to between 50,000 and 58,000 Boepd, largely driven by performance at Kraken and a full year's contribution from Magnus, partially offset by natural declines elsewhere in the portfolio. Production performance in the first two months of 2018 was strong across the portfolio, with Kraken gross production averaging around 38,000 Bopd in this period. Extreme cold weather in early March resulted in brief shutdowns at a number of the Group's North Sea fields. While Kraken was shut down, the Group has undertaken much of the workscope previously scheduled for the planned shutdown in April and, as a result, this planned shutdown is no longer required. The Group continues to have planned maintenance shutdowns at a number of the Group's fields, including Kraken, in the third quarter. During 2018, EnQuest expects to drill three wells at Magnus and two wells at PM8/Seligi which, along with the workover programme at Alma/Galia, should result in an improved production performance later in the year, with the DC4 programme expected to come onstream in 2019, sustaining Kraken production.

Unit opex is expected to be approximately $24/Boe. Cash capital expenditure is expected to be lower than 2017 at approximately $250 million and primarily relates to drilling campaigns at Kraken, Heather and PM8/Seligi.

With production growing, a strong focus on cost control and a substantially reduced cash capital expenditure programme, the Group should generate positive net cash flow which will enable it to start reducing debt.

In January 2018, EnQuest received $30 million in cash in exchange for agreeing to undertake the management of the physical decommissioning at Thistle and Deveron and being liable to make payments to BP by reference to 3.7% of the gross decommissioning costs of these assets.

Future growth opportunities

With Kraken delivering and the Group transitioning from a period of heavy investment, our focus is now turning towards the next stage of EnQuest's development. The Group has significant potential within the existing portfolio, in particular at Magnus, PM8/Seligi and, in the longer term, Kraken. Each of these fields has substantial reserves and resources in place and with EnQuest's proven capabilities in enhancing hydrocarbon recovery from mature and underdeveloped assets, the Group is well placed to deliver long-term sustainable growth.

Operating review

North Sea operations overview

EnQuest delivered some notable achievements during the year, particularly the delivery of first oil from Kraken on schedule and completing the acquisition of initial interests in the Magnus oil field, the Sullom Voe Oil Terminal ('SVT') and associated infrastructure assets from BP.

Kraken is a landmark heavy oil development project, one of the largest developments in the North Sea in the last ten years. The drilling performance has been excellent, with programmes completed early and at a lower cost than originally planned. Although there were some initial issues with a prolonged commissioning of the Floating Production, Storage and Offloading vessel leading to lower operational efficiency, substantial progress has since been made and performance continues to improve.

On 1 December 2017, EnQuest completed the acquisition of assets from BP. Following a period of extensive preparation, the assets and operations were transitioned safely and smoothly to EnQuest and the integration programme is now well underway. Both assets offer excellent opportunities for EnQuest and the wider industry and are in the spirit of Maximising Economic Recovery in the UK Continental Shelf. Magnus is a good operational fit and is close to EnQuest's existing operated assets in the Northern North Sea. It has high quality reservoirs with significant future opportunities. EnQuest is drilling three wells in 2018 to deliver increased volumes. At SVT, approximatelyone-third of the Group's North Sea production flows through the terminal. As such, it has the potential to play an important role in EnQuest's future growth.

The Group's North Sea production declined to 28,467 Boepd, down 7.0% on 2016. Underperformance at Alma/Galia and natural declines elsewhere were partially offset by a full year's contribution from Scolty/Crathes and initial contributions from Kraken and Magnus.

A focus on cost control and commercial agreements resulted in operating costs being in line with the Company's expectations. Such financial discipline is an essential part of the way in which EnQuest does business. Unit operating costs have reduced significantly from historical levels, particularly when the price of oil was above $100/bbl, but the Group recognises the need to continue to work on delivering further cost efficiencies.

Northern North Sea operations

Daily average net production:

- 2017: 15,627 Boepd*

- 2016: 18,885 Boepd

* Includes net production from Magnus since the acquisition on 1 December 2017, averaged over the 12 months to the end of December 2017.

2017 performance summary

Production in 2017 of 15,627 Boepd was 17.3% lower than 2016. This reduction was primarily driven by lower water injection at Heather/Broom and Thistle/Deveron, combined with natural declines at these and the Dons fields. Production efficiency at Heather/Broom and the Dons fields was very good, and the contribution from Magnus also helped mitigate the reduced production.

During the year, work programmes to improve the reliability of water injection on Heather/Broom, Thistle/Deveron and the Dons were successful, delivering improved performance by year end. Water injection was reinstated at the Dons in December 2017 following the replacement of the water injection pipelines. On Thistle, work was undertaken to improve the reliability of water injection and shut off areas of the reservoir in which high volumes of water were being produced. The resulting improved water injection performance significantly increased reservoir pressure. Shutting off some water production from four wells that produced high levels of water increased oil production by around a thousand barrels per day, doubling the target uplift from this work scope. When combined with better plant uptime, these programmes enabled Thistle production rates to finish the year strongly.

Reservoir performance and production were above expectations at Don Southwest, with production improving chemical treatments completed at West Don and Don Southwest.

Average gross production of c.16,000 Boepd from Magnus during the full year 2017 was similar to 2016; a good result during this intensive period of preparation for transition. Upon completion of the acquisition on 1 December 2017, EnQuest became duty holder and operator.

As part of EnQuest's asset life extension strategy, a series of idle well reservoir abandonments were successfully undertaken at Thistle and Heather to reduce integrity risks and provide opportunities for future drilling of infill wells. The abandonment programme on Heather partially abandoned legacy wells which should safeguard sustained high water injection reservoir efficiency. The programme was well executed, delivered ahead of schedule and under budget. This allowed the team to include an additional well within the programme cost estimate. These programmes, co-funded by EnQuest's partners, demonstrate EnQuest's ability to execute low-cost well work and is an important new component of the strategy to extend the lives of these fields, benefiting all stakeholders in these fields.

Asset data and 2018 work programme

Thistle/Deveron

• Working interest at end 2017: 99%

• Decommissioning related costs: 3.7% (as defined below)1

• Fixed steel platform

1 EnQuest is liable for the decommissioning costs associated with investment since it assumed operatorship, with the balance remaining with the former owners. Following the exercise of the Thistle decommissioning option in January 2018, EnQuest will undertake the management of the physical decommissioning of Thistle and Deveron and is liable to make payments to BP by reference to 3.7% of the gross decommissioning costs of Thistle and Deveron. EnQuest has an outstanding option to receive $20 million in cash in exchange for making payments by reference to a further 2.4% of the gross decommissioning costs of the Thistle and Deveron fields.

2018 and beyond

A shutdown is planned in Q3, the timing of which is driven by the third-party shutdown of the Cormorant Alpha pipeline, which is Thistle's oil export route. EnQuest will co-ordinate this shutdown with its own planned programme of maintenance work on Thistle.

The well abandonment programme is continuing in 2018.

The Dons fields

• Working interest at end 2017:

- Don Southwest 60%

- Conrie 60%

- West Don 78.6%

- Ythan 60%

• Decommissioning liabilities: As per working interests

• Floating production unit with subsea wells

2018 and beyond

A shutdown is planned in Q3, the timing of which is driven by the third-party shutdown of the Cormorant Alpha pipeline, which is the Dons' oil export route. EnQuest will co-ordinate this shutdown with its own planned programme of maintenance work on the Dons.

A water injection optimisation programme will be undertaken during 2018.

Heather/Broom

• Working interest at end 2017:

- Heather 100%

- Broom 63%

• Decommissioning liabilities:

- Heather 37.5%

- Broom 63%

• Fixed steel platform

2018 and beyond

Additional drilling is taking place on Heather. The H-67 sidetrack was completed in March following initial spud in January, while further well abandonments will take place later in the year.

A maintenance shutdown is planned in Q2.

Magnus

• Working interest at end 2017: 25%

• Decommissioning related costs: 7.5% (as defined below)1

• Fixed steel platform

1 BP has retained the decommissioning liability in respect of the existing Magnus wells and infrastructure. EnQuest will pay BP additional deferred consideration by reference to 7.5% of BP's actual decommissioning costs on an after-tax basis. The additional consideration payable is capped at the amount of cumulative positive cash flows received by EnQuest from Magnus, SVT and the associated infrastructure assets.

2018 and beyond

The post-acquisition integration programme will continue into 2018, ensuring the team understands the Group's culture, processes and controls, and how the team can contribute to EnQuest's success.

Following an upgrade of the drilling rig, the 2018 drilling programme includes a well intervention plan (logging and potentially also perforations) then two production wells and one injection well set to come onstream during 2018. In early Q1, the first wireline intervention was successfully completed, prior to the spudding of the first new sidetrack well.

New production efficiency enhancement opportunities are also being assessed.

Sullom Voe Oil Terminal

A strategic infrastructure hub

SVT was commissioned in 1978 and receives East of Shetland ('EoS') oil via the Brent Pipeline System, which services Brent, Thistle, Northern Producer, Alwyn and TENCCA, and the Ninian Pipeline System, which services Ninian, Magnus and Heather. Since 1998, the terminal has also provided services to West of Shetland ('WoS') fields, including Schiehallion, Clair and Foinaven. Gas from these three fields is 'sweetened' at SVT before being shipped to Magnus, for Enhanced Oil Recovery and onward export. The terminal also now processes condensate from the Laggan-Tormore development.

Following the safe and efficient transfer of operatorship to EnQuest on 1 December 2017, steady operations have continued.

Building on the work that BP as operator and EnQuest and other owners have undertaken in recent years, EnQuest is targeting cost improvements and exploring terminal life extension opportunities which could benefit wider Northern North Sea and WoS operations.

Central North Sea operations

Daily average net production:

- 2017: 8,131 Boepd

- 2016: 11,718 Boepd*

* Includes net production from Scolty/Crathes since first oil on 21 November 2016, averaged over the 12 months to the end of December 2016.

2017 performance summary

Production in 2017 of 8,131 Boepd was 30.6% lower than 2016. This reduction was primarily driven by lower volumes at Alma/Galia reflecting Electric Submersible Pump ('ESP') related well shut-ins, storm-related production outages and natural declines. Field performance improved in the second half of the year following completion of the optimisation projects for power, produced water and sea water injection.

Good production has been delivered from the Greater Kittiwake Area ('GKA'), with high levels of plant uptime and production efficiency. The GKA work programme was focused on optimising production across the assets, including replacement of the Mallard/Gadwall water injection flowline and the E gas compressor crank shaft. The GKA team delivered a good HSE&A performance and was proud to have delivered 12 years of operations without an LTI.

In line with previous updates, the full year contribution from Scolty/Crathes was limited due to wax in the flowline. These wax issues continue to be managed with chemical and lift gas treatments. Full year production uptime has been very high with the reservoir performing well. The unscheduled shutdown in December of the third-party operated Forties Pipeline resulted in the GKA and Scolty/Crathes fields being shut down for approximately three weeks, during which time opportunistic maintenance work was undertaken.

Asset data and 2018 work programme

Greater Kittiwake Area ('GKA')

• Working interest at end 2017 of 50% in each of:

- Kittiwake

- Grouse

- Mallard

- Gadwall

- Goosander

• Decommissioning liabilities:

- Kittiwake 25%

- Mallard 30.5%

- Grouse, Gadwall and Goosander 50%

• Fixed steel platform

• 100% interest in export pipeline from GKA to Forties Unity platform

2018 and beyond

A maintenance shutdown is scheduled for Q3 2018. The work programme includes the installation of a new gas compressor.

Evaluation of the potential from the Eagle discovery (100% EnQuest) is ongoing, with the licence having been extended in early 2018.

Scolty/Crathes

• Working interest at end 2017 of 50% in each of:

- Scolty

- Crathes

• Decommissioning liabilities: As per working interests

• Tied back to the Kittiwake platform

2018 and beyond

A maintenance shutdown is scheduled for Q3 2018. EnQuest continues to undertake technical work with its partners in developing a permanent solution to debottleneck production in 2019.

Alma/Galia

• Working interest at end 2017:

- 65% in both fields

• Decommissioning liabilities: As per working interest

• Floating Production, Storage and Offloading unit ('FPSO') with subsea wells

2018 and beyond

A well workover campaign is scheduled for the summer of 2018, aiming to increase production levels by replacing three failed ESPs.

Alba (non-operated)

The Alba oil field is operated by Chevron.

• Working interest at end 2017: 8%

• Decommissioning liabilities: As per working interest

• Fixed steel platform

The Kraken development

• Daily average net production:

- 2017: 4,709 Boepd2

- 2016: N/A

2Net production since first oil on 23 June, averaged over the 12 months to the end of December 2017.

2017 performance summary

The Kraken FPSO arrived in the North Sea in early January and was on-station and securely moored by mid-February, with first oil delivered on 23 June 2017. The four wells from the first drill centre ('DC') and the three wells from DC2 produced at initial gross rates above expectations and with stabilised flow rates which confirmed the field development plan. Water injection wells performed in line with expectations.

During the period after first oil, prolonged commissioning of the complex Kraken FPSO vessel led to lower than expected production efficiency and to initial production volumes being lower than expected. EnQuest continued with its plan of bringing wells onstream in a phased manner, in line with good reservoir management practices aimed at maximising long-term productivity and value. The second processing train, which was brought online during November, assisted in bringing gross production rates to over 40,000 Bopd. Since late December, all DC3 wells have been brought online and operational uptime has improved.

Following the excellent delivery of the DC3 drilling programme and lower market rates for the remaining subsea campaign, full cycle gross Kraken project capital expenditure was further reduced during 2017.

Cargo offloads started in September and one was successfully completed in each subsequent month. The quality of the crude has been well received by buyers. By as early as November, a sale of cargo had been contracted at a discount to Brent of less than $5/bbl, this level of pricing being achieved earlier than targeted.

Asset data and 2018 work programme

• Working interest at end 2017: 70.5%.

• Decommissioning liabilities: As per working interest

• Floating Production, Storage and Offloading ('FPSO') unit with subsea wells

2018 and beyond

Average gross production for the first two months of 2018 was around 38,000 Bopd, and has reached the targeted 50,000 Bopd, with improving production efficiency as we continue to optimise performance. The DC4 well campaign, which was not anticipated to impact 2018 production, is expected to commence in the second half of 2018, coming onstream in 2019 to sustain production.

Extreme cold weather in early March resulted in Kraken being shut down. During this period, the Group has undertaken much of the previously planned April shutdown workscope and, as a result, this planned shutdown is no longer required. EnQuest continues to have a summer shutdown planned for one week in September.

In early 2018, EnQuest agreed renegotiated terms with Transocean for the Transocean Leader drilling rig, reducing both the contract duration and the day rates, saving c.$60 million of net cash payments for capital expenditure in 2019. Full cycle gross project capital expenditure has been reduced by approximately $100 million and is now expected to be c.$2.3 billion, more than 25% lower than originally sanctioned.

Malaysian operations

• Daily average net production:

- 2017: 8,937 Boepd (working interest): 5,884 Boepd (entitlement)

- 2016: 9,148 Boepd (working interest): 6,426 Boepd (entitlement)

2017 performance summary

At PM8/Seligi, EnQuest continued to enhance production by investing in low-cost well interventions and facility projects to improve production efficiency, including gas compression package major overhauls, well test improvements with Multi-Phase Flow Meters and process simplifications to improve overall reliability. In addition, robust maintenance and integrity inspection campaigns of platform structures, topsides and subsea pipelines continued to ensure safe operations.

During 2017, the first new drilling projects were defined for execution in 2018, and significant progress was made on rebuilding of static and dynamic reservoir simulation models in support of longer-term field redevelopment. At Tanjong Baram, the focus remained on steady, safe and low-cost operations with high levels of production efficiency and uptime throughout the year.

Asset data and 2018 work programme

PM8/Seligi

• Working interest at end 2017: 50%

• Decommissioning liabilities:

- PM8 50%

- Seligi 50% of partial liability allocated based on ratio of remaining oil reserves and to estimated ultimate recovery

In addition to the main production platform and separate gas compression platform, there are 11 minimum facility satellite platforms tied back to the main platform.

2018 and beyond

EnQuest will commence its first drilling campaign with two PM8/Seligi commitment wells (appraisal and development) to be drilled around the middle of 2018, with first production in Q3. Idle well restoration and surveillance campaigns are planned for Q2 and Q3.

A maintenance shutdown is scheduled in Q3.

Longer term, EnQuest will extend field life through further investment in idle well restoration, facility improvements and upgrades and technical studies supporting development drilling and secondary recovery projects to increase ultimate recovery.

Tanjong Baram

• Working interest at end 2017: 70%

• Decommissioning liabilities: None

2018 and beyond

Maintenance shutdowns are scheduled in Q1 and Q3.

Financial review

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

Financial overview

EnQuest has continued to focus on project execution and financial discipline. The Company delivered first oil from the Kraken development in June 2017 and completed the acquisition of initial interests in the Magnus oil field and Sullom Voe Oil Terminal ('SVT') through an innovatively structured transaction in December. EnQuest also continues to focus on cost control and cash management, and as operating cash flows grow and capital expenditure reduces, this should facilitate reductions in debt. These key milestones, along with the effective management of the Group's liquidity position, continue to ensure that the Company is well placed to deliver value to stakeholders in the medium and long term.

Production on a working interest basis decreased by 5.9% to 37,405 Boepd, compared to 39,751 Boepd in 2016. Lower production at Alma/Galia and natural declines at the Group's other North Sea fields were partially offset by production from Kraken and a full year of production from Scolty/Crathes, which came onstream in November 2016.

Total revenue for 2017 was $635.2 million, 25.2% lower than 2016 ($849.6 million). This was as a result of lower realised oil prices, reflecting the forward prices available at the time at which the commodity hedge programme was implemented, combined with lower production. The commodity hedge programme resulted in realised losses of$20.6 million in 2017 compared to realised gains of $255.8 million in 2016.

The Group's operating expenditures of $349.3 million were 2.3% lower than 2016 ($357.4 million), but unit operating costs increased by 4.0% to $25.6/Boe as a result of lower production.

EBITDA for 2017 was $303.6 million, down 36.4% compared to 2016 ($477.1 million), primarily as a result of lower revenue.

Business performance loss after tax for 2017 was $33.6 million (2016: profit of $121.5 million). After re-measurements and exceptional items, the Group recorded a net loss of $60.8 million (2016: net profit of $185.2 million).

Reflecting the ongoing investments EnQuest has made to develop its assets, notably Kraken, EnQuest's net debt increased from $1,796.5 million at the end of 2016 to $1,991.4 million at 31 December 2017. This includes $90.5 million of interest that has been capitalised to the principal of the facilities pursuant to the terms of the Group's November 2016 refinancing ('PIK').

1 Stated excluding accrued interest and excluding the net-off of unamortised fees (refer to note 19 of the consolidated financial statements).

There are no significant debt maturities until October 2018, when a single amortisation of the RCF of $270 million is due.

As at 31 December 2017, total cash and available facilities totalled $244.4 million, excluding $26.5 million of cash from the ring fenced working capital facility associated with SVT (2016: $330.9 million excluding $nil cash from the ring fenced SVT working capital facility).

UK corporate tax losses at the end of the year increased to $3,121.3 million. In the current environment, no material corporation tax or supplementary corporation tax is expected to be paid on UK operational activities for the foreseeable future. The Group paid cash corporate income tax on the Malaysian assets which will continue throughout the life of the Production Sharing Contract.

Income statement

Production and revenue

Net working interest production of 37,405 Boepd was 5.9% lower than 2016 (39,751 Boepd). This reduction primarily reflects the impact of ESP performance issues at Alma/Galia, natural declines in the Group's assets where there has been no recent drilling, partially offset by the impact of commencement of production at Kraken in June 2017 and a full year of production from Scolty/Crathes, which achieved first oil in November 2016.

On average, market prices for crude oil in 2017 were higher than in 2016. The Group's blended average realised oil price excluding the impacts of hedging was $53.9/bbl for 2017, 21.8% higher than 2016 ($44.3/bbl). Revenue is predominantly derived from crude oil sales and for 2017, crude oil sales totalled $637.0 million, 10.2% higher than 2016 ($577.8 million). The increase in revenue reflected higher market prices for crude oil, partially offset by lower production. Revenue from the sale of condensate and gas was $2.8 million (2016: $3.6 million) while tariffs and other income generated $16.0 million (2016: $12.4 million).

The Group's commodity hedges and other oil derivatives generated $20.6 million of realised losses (2016 income: $255.8 million), including $10.4 million of non-cash amortisation of option premiums (2016: $31.2 million).

Cost of sales

Cost of sales were $569.5 million for the year ended 31 December 2017, 12.9% lower than 2016 ($653.5 million). Operating costs decreased by $8.1 million, reflecting the benefit of a weaker Sterling exchange rate and net lease charter payment credits of $19.5 million arising from the non-availability of the Kraken FPSO, partially offset by a full year of operations at Scolty/Crathes. The Group's average unit operating cost has increased by 4.0% to $25.6/Boe, primarily due to the 5.9% reduction in production volumes.

At 31 December 2017, the Group had moved to a net underlift position compared to the prior year end net overlift position, resulting in a $20.4 million credit to cost of sales (2016: charge of $2.8 million). The Group's change in lifting position and inventory reflected the unwind of the overlift balance that had accrued at 31 December 2016, primarily on Thistle and GKA, partially offset by the unwind of underlift at Alma/Galia and the build up of an overlift at Scolty/Crathes.

Depletion expense of $223.1 million was 7.3% lower than 2016 ($240.6 million), reflecting lower production in 2017. The average unit depletion rate decreased slightly from $16.6/Boe to $16.3/Boe.

Other cost of sales of $12.7 million were higher than 2016 ($5.4 million), principally driven by the impact of higher oil prices on the supplemental payment due on profit oil in Malaysia.

General and administrative expenses

General and administrative expenses were $0.8 million (2016: $10.9 million), reflecting the Group's ongoing efforts to reduce costs across the organisation.

Other income and expenses

Net other expenses of $17.6 million (2016: income of $51.9 million) primarily comprises net foreign exchange losses, which relate to the revaluation of Sterling denominated amounts in the balance sheet following the strengthening of Sterling against the US Dollar, offset by one-off general and administration recovery impacts. The prior year income comprised almost entirely of net foreign exchange gains.

Finance costs

Finance costs of $149.0 million were 21.9% higher than 2016 ($122.2 million). The charges include $137.9 million of bond and loan interest payable (2016: $110.5 million), $13.5 million unwinding of discount on provisions and liabilities, largely in respect of decommissioning (2016: $14.2 million), $2.8 million amortisation of arrangement fees for the bank facilities and bonds (2016: $5.9 million) and other financial expenses of $5.9 million (2016: $10.5 million), primarily commitment and letter of credit fees.

The Group capitalised interest of $42.3 million in 2017 in relation to the interest payable on borrowing costs on its capital development projects, primarily the Kraken development (2016: $55.3 million).

In June 2017, in line with first oil from Kraken, the Group's lease for the FPSO vessel from Armada Kraken PTE Limited ('BUMI') commenced. Finance lease interest of $31.3 million has been recognised within finance costs. In 2016, $36.5 million of finance costs related to the amortisation of put option premium related to the Group's oil hedge portfolio were recognised. No corresponding charge existed in 2017 as no put options had been used to hedge 2017 production.

Finance income

Finance income of $2.2 million (2016: $1.4 million) includes $1.8 million from the unwind of the discount on financial assets (2016: $1.0 million) and $0.4 million of bank interest receivable (2016: $0.3 million).

Taxation 

The tax credit for 2017 of $66.0 million (2016: $5.2 million tax credit), excluding exceptional items, is mainly due to the Ring Fence Expenditure Supplement ('RFES') on UK activities. 

Remeasurement and exceptional items

Revenue included unrealised losses of $7.7 million in respect of the mark to market movement on the Group's commodity contracts (2016: unrealised loss of $51.5 million).

Non-cash impairment charge on the Group's oil and gas assets arising from changes in assumptions combined with lower production performance in the North Sea totalled $172.0 million (2016: reversal of non-cash impairment of $147.9 million).

Other income and expense included the recognition of the accounting for the excess of fair value over consideration of $16.1 million associated with the Thistle decommissioning option and $10.3 million associated with the accounting impact of the acquisition of initial interests in assets from BP and the related discounted purchase option valuation of $22.3 million (see note 29). Other items include a $1.3 million gain from the disposal of Ascent Resources loan notes, a $10.3 million charge arising from a cost recovery settlement in Malaysia, a $6.4 million charge arising from the cancellation of contracts and a $2.8 million provision in relation to restricted cash.

A tax credit of $117.0 million (2016: charge of $37.3 million) has been presented as exceptional, representing the tax impact of the above items, together with a net write-back of $47.2 million of tax losses which had been previously impaired.

Earnings per share

The Group's reported basic loss per share was 5.4 cents (2016: earnings per share of 22.7 cents) and reported diluted loss per share was 5.4 cents (2016: earnings per share of 22.1 cents).

Cash flow and liquidity

Net debt at 31 December 2017 amounted to $1,991.4 million, including PIK of $90.5 million, compared with net debt of $1,796.5 million at 31 December 2016, including PIK of $27.7 million. The Group has remained in compliance with financial covenants under its debt facilities throughout the year and managing ongoing compliance remains a priority. Where necessary or appropriate, the Group has and would seek waivers and/or consents.

The movement in net debt was as follows:

The Group's reported operating cash flows for the year ended 31 December 2017 were $301.8 million, down 20.5% compared to 2016 ($379.5 million). The main driver for this reduction is the reduced contribution from commodity price hedging, where total cash flows received in 2017 were $3.6 million as compared to $198.8 million for 2016. This reduced cash flow was partially offset by the impact of higher market oil prices on revenue and reduced operating and general and administrative expenses.

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

In the North Sea, a total of $252.2 million was spent during the year on the Kraken development, primarily related to drilling and completing 14 wells across Drill Centres ('DC') 2 and 3. Excellent drilling performance resulted in the delivery of the wells ahead of schedule. In early 2018, EnQuest also agreed renegotiated terms for the drilling rig, reducing both the contract duration and day rates. Full cycle gross project capital expenditure is now expected to be c.$2.3 billion. The remaining 2017 cash capital expenditure is primarily the settlement of deferred invoices in respect of the Alma/Galia and Scolty/Crathes developments and the Eagle discovery.

Balance Sheet

The Group's total asset value has increased by $1,112.5 million to $5,038.5 million at 31 December 2017(2016: $3,926.0 million), mainly attributable to the recognition of the $772.0 million Kraken FPSO finance lease asset in property, plant and equipment ('PP&E'). Net current liabilities have increased to $377.9 million as at 31 December 2017 (2016: $45.1 million), primarily driven by the scheduled $270 million RCF amortisation due in October 2018 and the impact of the Kraken FPSO finance lease commitments due within one year.

Property, plant and equipment

PP&E has increased by $885.2 million to $3,848.6 million at 31 December 2017 from $2,963.4 million at31 December 2016 (see note 10).

This increase is explained by the recognition of the Kraken FPSO finance lease in June 2017 of $772.0 million, capital additions to PP&E of $323.6 million, additions of $124.5 million for the acquisition of interests in the Magnus oil field, SVT and associated infrastructure assets (see note 29), a net increase of $66.2 million for changes in estimates for decommissioning and other provisions, including the KUFPEC cost recovery provision, offset by depletion and depreciation charges of $229.2 million and non-cash impairments of $172.0 million.

Intangible oil and gas assets

Intangible oil and gas assets marginally increased to $52.1 million at 31 December 2017 from $50.3 million at31 December 2016 (see note 12).

Trade and other receivables

Trade and other receivables have increased by $25.1 million to $227.8 million at 31 December 2017 compared with $202.7 million at 31 December 2016. The increase relates mainly to the timing of crude oil sales, increased underlift and higher oil prices, partially offset by other working capital movements (see note 15).

Cash and net debt1

The Group had $173.1 million of cash and cash equivalents at 31 December 2017 and $1,991.4 million of net debt, including PIK of $90.5 million (2016: $174.6 million of cash and cash equivalents and $1,796.5 million of net debt, including PIK of $27.7 million). Net debt1 comprises the following liabilities:

· $224.1 million principal outstanding on the £155 million retail bond (2016: $191.3 million) including $14.9 million of interest capitalised as an amount payable in kind ('PIK') in the year;

· $720.8 million principal outstanding on the high yield bond, including capitalised interest (PIK) of $70.8 million pursuant to the Restructuring (2016: $677.5 million and $27.5 million respectively);

· $1,100.0 million carrying value of credit facility, comprising amounts drawn down of $1,095.2 million and PIK interest of $4.8 million (2016: $1,037.5 million comprising amounts drawn down of $1,037.3 million and PIK interest of $0.2 million);

· $25.6 million relating to the SVT Working Capital Facility (2016: $nil);

· $75.5 million relating to the Mercuria Prepayment Facility (2016: $nil);

· $10.0 million outstanding from a trade creditor loan (2016: $40.0 million); and

· $8.5 million principal outstanding on the Tanjong Baram Project Finance Facility (2016: $24.9 million).

 1Net debt excludes accrued interest and the net-off of unamortised fees (see note 19 of the consolidated financial statements).

Provisions

The Group's decommissioning provision increased by $145.4 million to $639.3 million at 31 December 2017(2016: $493.9 million). The movement is explained by additions to Kraken of $63.6 million based on drilling and developments carried out in the period, an increase of $80.9 million due to changes in estimates (including the impact of oil prices and foreign exchange rates) and $11.5 million unwinding of discount, partially offset by reductions of$10.6 million for decommissioning carried out in the period.

Other key movements in provisions during the period include the addition of $66.6 million of outstanding contingent consideration for the acquisition of the Magnus oil field, SVT and associated infrastructure assets from BP completed in December 2017 (see note 29) and $10.3 million for PM8/Seligi cost recovery. This is largely offset by a $77.8 million reduction for changes in estimates and the fair value of cost recovery provisions combined with payments of $9.0 million contingent consideration to Centrica pursuant to the Greater Kittiwake Area acquisition agreement and $5.5 million for the final settlement due to Cairn under the carry agreement (see note 22).

Income tax

The Group had no UK corporation tax or supplementary corporation tax liability at 31 December 2017, which remains unchanged from 31 December 2016. The income tax asset at 31 December 2017 represents UK corporation tax receivable in relation to non-upstream activities and the income tax payable is in relation to the Group's activities in Malaysia (see note 7).

Deferred tax

The Group's net deferred tax asset has increased from $191.7 million at 31 December 2016 to $335.6 million at31 December 2017. The increase is mainly due to the RFES, together with the recognition of $9.7 million of previously derecognised tax losses. Total UK tax losses carried forward at the year end amount to $3,121.3 million(2016: $2,893.7 million) (see note 7).

Trade and other payables

Trade and other payables of $446.1 million at 31 December 2017 are $6.7 million lower than at 31 December 2016 ($452.8 million). $367.3 million are payable within one year (2016: $410.2 million) and $78.8 million are payable after more than one year (2016: $42.6 million). The decrease in current payables mainly reflects the settlement of deferred invoices and an $11.9 million reduction in the overlift position, offset by accruals (see note 23).

Other financial liabilities

Other current financial liabilities have increased by $16.9 million to $61.2 million. The increase primarily relates to mark to market movements on the Group's commodity derivatives following the strengthening of the oil price, waiver fees payable to credit facility lenders due in March 2018 (previously non-current) and the Group's liability to carry PETRONAS Carigali for its share of exploration or appraisal well commitments in relation to the PM8/Seligi asset in Malaysia (previously non-current).

Other non-current financial liabilities of $7.1 million (2016: $19.8 million) relate mainly to the Magnus field liabilities acquired as part of the transaction that completed in December 2017 (see note 20).

Financial risk management

Oil price

The Group is exposed to the impact of changes in Brent crude oil prices on its revenue and profits. EnQuest's policy is to manage the impact of commodity prices to protect against volatility and allow availability of cash flow for reinvestment in capital programmes that are driving business growth.

In November 2017, the Group entered into an 18-month collar structure for the Mercuria Prepayment Facility of$80 million (see note 19). Repayment will be in equal monthly instalments over 18 months, through the delivery of an aggregate of approximately 1.8 mmbbls of oil. EnQuest will receive the average Brent price over each month subject to a floor of $45 per barrel and a cap of approximately $64 per barrel. Losses totalling $5.2 million were included within unrealised revenue in the income statement.

The marking to market of the Group's open contracts as at 31 December 2017 gave rise to a loss of $29.2 million in respect of fixed price swap contracts for 4.15 MMbbls of 2018 production at a weighted average price of $59.1/bbl (2016: loss of $40.5 million in respect of fixed price swap contracts for 5.99 MMbls of 2017 production at a weighted average price of $51.3/bbl).

During 2016, the Group entered into commodity hedging contracts to hedge a portion of its 2017 production against fluctuations in oil prices. This hedging generated cash outflows of $0.9 million (including $2.0 million outflow in respect of the settlement of December 2016 hedges) while revenue and other operating income included a loss of$31.1 million during 2017. These amounts were mostly in respect of the settlement of swaps in respect of 6.0 MMbbls, plus the maturity of certain other commodity derivatives. The Group's marketing and trading activities, which are designed to manage price exposures on certain individual cargos, generated $6.7 million of cash, and contributed $10.6 million to revenue and other operating income.

Foreign exchange

EnQuest's functional currency is US Dollars. Foreign currency risk arises on purchases and the translation of assets and liabilities denominated in currencies other than US Dollars. To mitigate the risks of large fluctuations in the currency markets, the hedging policy agreed by the Board allows for up to 70% of the non-US Dollar portion of the Group's annual capital budget and operating expenditure to be hedged. For specific contracted capital expenditure projects, up to 100% can be hedged.

During 2017, the Group has continued to use an exchange structure to manage risk. The first exchange structure was entered into in 2016 and allowed the counterparty to elect to sell £47.5 million to EnQuest at an exchange rate of $1.4:£1, or purchase 1.3 MMbbls of oil at $58/bbl. This structure expired on 30 June 2017. The second exchange structure allowed the counterparty to elect to sell £66.0 million to EnQuest at an exchange rate of $1.2:£1 or purchase 1.5 MMbbls of oil at $60/bbl. This structure expired on 31 December 2017. As a result of these exchange structures, $4.4 million was recognised within other foreign currency contracts and no costs within other operating income during the year (2016: $9.3 million and $nil respectively).

EnQuest continually reviews its currency exposures and when appropriate looks at opportunities to enter into foreign exchange hedging contracts.

Surplus cash balances are deposited as cash collateral against in-place letters of credit as a way of reducing interest costs. Otherwise cash balances can be invested in short-term bank deposits and AAA-rated liquidity funds, subject to Board-approved limits and with a view to minimising counterparty credit risks.

Going concern

The Group closely monitors and manages its funding position and liquidity risk throughout the year, including monitoring forecast covenant results, to ensure that it has access to sufficient funds to meet forecast cash requirements. Cash forecasts are regularly produced and sensitivities considered for, but not limited to, changes in crude oil prices (adjusted for hedging undertaken by the Group), production rates and project timing and costs. These forecasts and sensitivity analyses allow management to mitigate any liquidity or covenant compliance risks in a timely manner. Management has also continued to take action to implement cost saving programmes to reduce planned operational, general and administrative and capital expenditures in 2017 and 2018. At 31 December 2017, the Group had cash and available bank facilities of $244.4 million, excluding $26.5 million of cash from the ring fenced working capital facility associated with SVT.

The Group's business plan ('Base case'), which underpins this assessment, assumes Kraken production rates are in line with the Group's production guidance. The Base case has been updated for the forward curve and uses an oil price assumption of c.$67/bbl throughout 2018 and c.$63/bbl for the first quarter of 2019. This has been further stressed tested under a plausible downside case ('Downside case') as described in the viability statement. Both cases reflect the bank debt amortisation profile due in the going concern period. The Directors consider the Base case and Downside case to be an appropriate basis on which to make their assessment.

The Group has historically reviewed farm down options and continues to do so. The Base case and Downside case indicate that the Company is covenant compliant and will be able to operate within the headroom of its existing borrowing facilities for 12 months from the date of approval of the Annual Report and Accounts.

Should there be any liquidity shortages or covenant breaches due to events not included in the Base or Downside cases, the Directors believe that a number of mitigating actions, including assets sales or other funding options, can be executed successfully in the necessary timeframe to meet debt repayment obligations as they become due and in order to maintain liquidity.

Nevertheless, there remains the risk that the Group is unable successfully to achieve farm down options, other potential asset sales or other funding options. The risk represents a material uncertainty that may cast doubt upon the Group's ability to continue to apply the going concern basis of accounting.

Notwithstanding the material uncertainty described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group will be able to continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors therefore continue to adopt the going concern basis in preparing the financial statements.

Viability statement

The Directors have assessed the viability of the Group over a three-year period to March 2021. This assessment has taken into account the Group's financial position as at March 2018, the future projections and the Group's principal risks and uncertainties. The Directors' approach to risk management, their assessment of the Group's principal risks and uncertainties, and the actions management are taking to mitigate these risks, are outlined in the Risks and uncertainties section of this statement.

The period of three years is deemed appropriate as it provides a sufficient time horizon to assess the performance of the Kraken project and covers the period within which the Group's Facility will be largely repaid.

Based on the Group's projections, the Directors have a reasonable expectation that the Group will be able to continue in operation and meet its liabilities as they fall due over the period to March 2021.

The Group's business plan process has underpinned this assessment and has been used as the Base case. The business plan process takes account of the Group's principal risks and uncertainties, and has further been stress tested to understand the impact on the Group's liquidity and financial position of reasonably possible changes in these risks and/or business plan assumptions.

The forecasts which underpin this assessment use the same oil price assumption as for the going concern assessment with a longer-term price assumption for the viability period being aligned to a recent forward curve. The Base case reflects significant steps already undertaken to reduce operating and capital expenditure.

For the current assessment, the Directors also draw attention to the specific principal risks and uncertainties (and mitigants) identified below, which, individually or collectively, could have a material impact on the Group's viability during the period of review. In forming this view, it is recognised that such future assessments are subject to a level of uncertainty that increases with time and, therefore, future outcomes cannot be guaranteed or predicted with certainty. The impact of these risks and uncertainties, including their combined impact, has been reviewed by the Directors and the effectiveness and achievability of the potential mitigating actions have been considered.

Oil price volatility

A material decline in oil and gas prices would adversely affect the Group's operations and financial condition. To mitigate oil price volatility, the Directors have hedged c.7.5 million barrels of 2018 production at an average price of c.$62/bbl. As further mitigation, the Directors, in line with Group policy, will continue to pursue hedging at the appropriate time and price.

Kraken production and related asset disposal

All production and injector wells on the first three Drilling Centres ('DC') are onstream and are, in aggregate, operating as per the Field Development Plan ('FDP'). Both production processing trains are also onstream. Kraken gross production averaged around 38,000 Bopd (gross) in the first two months of 2018 and has already delivered the targeted 50,000 Bopd (gross) as planned. The remaining development wells (DC4) will be drilled from Q4 2018 and onstream from Q1 2019, concluding the execution of the FDP. On the basis of this performance, and subject to delivering on the Group's plans to further optimise production and improving plant uptime, EnQuest expects to deliver sustained production rates.

The Group has historically reviewed farm down options and continues to do so.

Access to funding

The Group's Facility contains certain covenants (based on the ratio of indebtedness incurred under the term loan and revolving facility to EBITDA, finance charges to EBITDA, and requirement for liquidity testing). Prolonged low oil prices, cost increases and production delays or outages could further threaten the Group's liquidity and/or ability to comply with relevant covenants.

The Directors recognise the importance of ensuring medium-term liquidity and in particular to protect against potential future declines in the oil price. EnQuest has a committed $1.125 billion Tranche A Term Loan and a further Tranche B $75 million Revolving Credit Facility (collectively the 'Facility'). Across the Facility, $98 million remains available at 31 December 2017.

In addition, the maturity dates of the $721 million high yield bond and the £166 million retail notes (both figures inclusive of the PIK notes), have been amended to April 2022, with an option exercisable by the Group (at its absolute discretion) to extend the maturity date by one year and an automatic further extension of the maturity date to October 2023 if the existing Facility is not fully repaid or refinanced by October 2020.

A further condition to the payment of interest on both the high yield bond and retail notes in cash is based on, amongst other things, the average prevailing oil price (dated Brent future (as published by Platts)) for the six-month period immediately preceding the day which is one month prior to the relevant interest payment date being at least $65/bbl; otherwise interest payable is to be capitalised.

In conducting the viability review, these risks have been taken into account in the stress testing performed on the Base case described above.

Specifically the Base case has been subjected to stress testing by considering the impact of the following plausible downside risks:

· a 10% discount to the oil price forward curve;

· a 5% increase in operating costs except for fixed costs related to the Kraken FPSO; and

· a lower value achieved from the sale of an interest in Kraken.

A scenario has been run illustrating the impact of the above risks on the Base case. This plausible Downside case indicates no mitigating actions need be undertaken for the Group to be viable in the three-year period.

Notwithstanding the principal risks and uncertainties described above, after making enquiries and, assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group will be able to continue in operation and meet its commitments as they fall due over the viability period ending March 2021. Accordingly, the Directors therefore support this viability statement.

Risks and uncertainties

 Management of risks and uncertainties

The Board has articulated EnQuest's vision to be the operator of choice for maturing and underdeveloped hydrocarbon assets. As EnQuest moves from a period of heavy investment to one focused on realising value from existing resources, it will focus on driving improved cash flow and managing its capital structure and liquidity.

EnQuest seeks to balance its risk position between investing in activities that can drive growth with the appropriate returns, including any appropriate market opportunities that may present themselves, and the continuing need to remain financially disciplined. This financial discipline drives cost efficiency and cash flow generation to reduce the Group's debt. In this regard, the Board has developed certain strategic tenets to guide the Company during the current phase of its evolution which link with its strategy and appetite for risk. Broadly, these reflect a focus by the Company on:

· Maintaining discipline across metrics such as financial headroom, leverage ratio and gearing;

· Enhancing diversity within our portfolio of assets, with a focus on underdeveloped producing assets and maturing assets with investment potential; and

· Ensuring the quality of the investment decision-making process.

In pursuit of its strategy, EnQuest has to face and manage a variety of risks. Accordingly, the Board has established a Risk Management Framework to enhance effective risk management within the following Board-approved overarching statement of risk appetite (which has been further refined in light of the Company's strategic tenets):

· We make investments and manage the asset portfolio against agreed key performance indicators consistent with the strategic objectives of enhancing net cash flow, reducing leverage, managing costs and diversifying our asset base;

· We seek to avoid reputational risk by ensuring that our operational processes and practices reduce the potential for error to the greatest extent practicable;

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

· We seek to manage operational risk by means of a variety of controls to prevent or mitigate occurrence; and

· We set clear tolerances for all material operational risks to minimise overall operational losses, with zero tolerance for criminal conduct.

The Board reviews the Company's risk appetite annually in light of changing market conditions and the Company's performance and strategic focus. The Executive Committee periodically reviews and updates the Group Risk Register based on the individual risk registers of the business. The Group Risk Register, along with an assurance mapping exercise and a risk report (focused on the most critical risks and emerging and changing risk profiles), is periodically reviewed by the Board (with senior management), to ensure that key issues are being adequately identified and actively managed. In addition, a sub-Committee of the Board has been established (the Risk Committee) to provide a forum for the Board to review selected individual risk areas in greater depth.

The Board, supported by the Audit Committee, has reviewed the Group's system of risk management and internal control for the period from 1 January 2017 to the date of this report, and is satisfied that it is effective and that the Group complies in this respect with the Financial Reporting Council's 'Guidance on Risk Management, Internal Control and Related Financial and Business Reporting'.

Key business risks

The Group's principal risks are those which could prevent the business from executing its strategy and creating value for shareholders or lead to a significant loss of reputation. The Board has carried out a robust assessment of the principal risks facing the Company, including those that would threaten its business model, future performance, solvency or liquidity.

Cognisant of the Group's 2016 financial restructuring (and consequent strategic focus on reducing the Company's debt and strengthening its balance sheet), the Board is satisfied that the Group's risk management system works effectively in assessing and managing the Group's risk appetite and has supported a robust assessment by the Directors of the principal risks facing the Group.

Set out below are:

· The principal risks and mitigations;

· An estimate of the potential impact and likelihood of occurrence after the mitigation actions, along with how these have changed in the past year; and

· An articulation of the Group's risk appetite for each of these principal risks.

Amongst these, the key risks the Group currently faces are a prolonged low oil price environment and/or a sustained decline in oil prices and materially lower than expected production performance for a prolonged period, particularly at the Kraken field.

KEY PERFORMANCE INDICATORS

(i) Including realised loss of $20.6 million in 2017 associated with EnQuest's oil price hedges (2016: realised gain of $255.8 million, 2015: realised gain of $261.2 million).

(ii) EBITDA is calculated on a business performance basis, and is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion, depreciation, foreign exchange movements and the realised gains/loss on foreign currency derivatives related to capital expenditure.   

(iii) Net of proceeds from disposal of $nil million (2016: $1.5 million, 2015: $75.5 million).

OIL AND GAS RESERVES AND RESOURCES

At 31 December 2017

GROUP STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2017

The attached notes 1 to 30 form part of these Group financial statements.

GROUP BALANCE SHEET

At 31 December 2017

The attached notes 1 to 30 form part of these Group financial statements.

The financial statements were approved by the Board of Directors on 19 March 2018 and signed on its behalf by:

Jonathan Swinney

Chief Financial Officer

GROUP STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2017

The attached notes 1 to 30 form part of these Group financial statements.

GROUP STATEMENT OF CASH FLOWS

For the year ended 31 December 2017

The attached notes 1 to 30 form part of these Group financial statements.

NOTES TO THE GROUP FINANCIAL STATEMENTS

For the year ended 31 December 2017

1. Corporate information

EnQuest PLC ('EnQuest' or 'the Company') is a limited liability Company incorporated and registered in England and is listed on the London Stock Exchange and on the Stockholm NASDAQ OMX.

The principal activities of the Company and its subsidiaries (together the 'Group') is to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner.

The Group's financial statements for the year ended 31 December 2017 were authorised for issue in accordance with a resolution of the Board of Directors on 19 March 2018.

A listing of the Group companies is contained in note 28 to these Group financial statements.

2. Summary of significant accounting policies

New standards and interpretations

The Group has adopted and applied the following standards that are relevant to its operations for the first time for the annual reporting period commencing 1 January 2017:

· Amendments to IAS 12 Income Taxes - Recognition of Deferred Tax Assets for Unrealised Losses;

· Annual Improvements to IFRSs (2014 - 2016 Cycle): IFRS 12 Disclosure of interests in other entities; and

· Disclosure Initiative Amendments - IAS 7 Statement of Cash Flows.

There were no new standards or interpretations effective for the first time for periods beginning on or after 1 January 2017 that had a significant effect on the Group's financial statements, although an amendment to IAS 7 Statement of Cash Flows has resulted in a reconciliation of liabilities disclosed for the first time in note 30.

Standards issued but not yet effective

Standards issued and relevant to the Group, but not yet effective up to the date of issuance of the Group's financial statements, are listed below. This listing is of standards and interpretations issued, which the Group reasonably expects to be applicable at a future date. The Group intends to adopt these standards when they become effective. The Directors do not anticipate that the adoption of these standards will have a material impact on the Group's financial statements in the period of initial application.

IFRS 9 Financial Instruments

In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments which replaces IAS 39 Financial Instruments: Recognition and Measurement and all previous versions of IFRS 9. The standard introduces new requirements for classification and measurement, impairment under the 'expected credit loss' ('ECL') model and hedge accounting. IFRS 9 is effective for annual periods beginning on or after 1 January 2018, with early application permitted. The Group plans to adopt the new standard on the required effective date and will not restate comparative information.

During 2017, the Group has performed an impact assessment for the application of IFRS 9. This assessment is based on currently available information and may be subject to changes arising from further reasonable and supportable information being made available to the Group in 2018 when the Group will adopt IFRS 9. The Group continues to assess its accounting processes, controls and policies on an on-going basis.

Classification and measurement

The Group expects that all financial assets will continue to be measured at amortised cost or fair value and will be measured on the same basis as is currently adopted under IAS 39.

The Group has not designated any financial liabilities at fair value through profit or loss ('FVTPL') and the assessment did not indicate any material impact regarding the classification of financial liabilities. The Group does not currently designate any hedge relationships for hedge accounting.

Impairment

The Group's receivables have a good credit rating, hence the expected credit losses are low (see note 15). There has been no noted change in the credit risk of receivables in the year, therefore the Group does not believe that the new ECL impairment methodology will have a material impact on the valuation of financial assets.

Non-current assets are held with reputable businesses with whom the Group has good working relationships. The scheduled repayment of cash flows have been and continue to be received in line with expectations. There has been no noted change in the credit risk of receivables in the year, therefore the Group does not believe that the new ECL impairment methodology will have a material impact on the valuation of financial assets.

Cash is held with bank and financial institution counterparties, which are rated with an A-/A3 credit rating or better(see note 16). The Group considers that the available cash balances have low credit risk based on the external credit rating of the counterparties.

2. Summary of significant accounting policies (continued)

Standards issued but not yet effective (continued)

IFRS 9 Financial Instruments (continued)

Modification of debt

In July 2017 the IASB confirmed the accounting for modifications of financial liabilities under IFRS 9. When a financial liability measured at amortised cost is modified without this resulting in derecognition, a gain or loss should be recognised in profit or loss. The gain or loss is calculated as the difference between the original contractual cash flows and the modified cash flows discounted at the original effective interest rate. Any fees and costs incurred are amortised over the remaining term of the asset.

During the 2016 refinancing, the modification of the Bonds was not considered to be significant. As a result, the change in contractual cash flows on the Bonds was amortised over the new life of the bonds, rather than taken straight to profit or loss (see note 19). Under IFRS 9, the refinancing is a modification of the debt in which the difference in contractual cash flows should be taken straight to profit or loss. On the implementation of IFRS 9 on 1 January 2018, an adjustment will be taken through opening reserves and through the value of both bonds, High Yield Bond and Retail Bond of $34.0m ($9.2m and $24.8m respectively).

IFRS 15 Revenue from Contracts with Customers

IFRS 15 was issued in May 2014, and amended in April 2016, and establishes a single comprehensive model that will apply to revenue arising from contracts with customers. IFRS 15 will supersede the current revenue recognition guidance including IAS 18 Revenue and related interpretations when it becomes effective, for annual periods beginning on or after 1 January 2018.

The core principle of IFRS 15 is that an entity should recognise revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. The five step model recognises revenue when (or as) a performance obligation is satisfied, i.e. when 'control' of the goods or services underlying the particular performance obligation is transferred to the customer. Extensive new disclosures are required by IFRS 15.

During 2017, the Group has performed an impact assessment for the application of IFRS 15. This assessment is based on currently available information and may be subject to changes arising from further reasonable and supportable information being made available to the Group in 2018 when the Group will adopt IFRS 15. The Group continues to assess its accounting processes, controls and policies on an on-going basis. The Group plans to adopt the new standard on the required effective date using the modified retrospective method.

The Group recognises revenue from the following major sources:

· Sale of crude oil, gas and condensate;

· Tariff revenue for the use of Group infrastructure;

· Production imbalances.

Interest income and dividend income from debt and equity investments were covered by IAS 18. These are now within the scope of IFRS 9.

Sale of crude oil, gas and condensate

The Directors have assessed the sale of crude oil, gas or condensate and determined that these represent a single performance obligation, being the sale of barrels equivalent on collection of a cargo or on delivery of commodity into an infrastructure. Revenue will accordingly be recognised for this performance obligation when control over the corresponding commodity is transferred to the customer. This is in line with the current recognition of revenue under IAS 18. Variable revenue conditions can arise on either party based on the failure to provide commitments detailed within the contract. These variations arise as an event occurs and therefore the transaction price is known at the timing of the performance obligations with no judgement required. Revenue recognition is therefore consistent with current practice.

A Production Sharing Contract (PSC) is in place in Malaysia with Petronas, the custodian for Malaysia's national oil and gas resources. The production is shared in line with the risks and benefits that result from the activity of the PSC and therefore this is a collaborative arrangement. Revenue is recognised on the sale of the crude oil, as per the analysis of sale of crude oil above. This is in line with the current recognition of revenue under IAS 18.

2. Summary of significant accounting policies (continued)

Standards issued but not yet effective (continued)

IFRS 15 Revenue from Contracts with Customers (continued)

Tariff revenue for the use of Group infrastructure

The Directors have assessed the revenue arising from tariffs, which are charged to customers for the use of infrastructure owned by the Group in the North Sea. There is one contract per customer which is for a period of 12 months of less and is based on one performance obligation for the use of Group assets. The use of the assets is not separable as they are all dependent on one another in order to fulfil the contract and no one item of infrastructure can be individually identified. Revenue will accordingly be recognised over the performance of the contract as services are provided for the use of the infrastructure on a throughput basis. Revenue recognition is therefore consistent with current practice under IAS 18.

Production imbalances

Production imbalances arise on fields as oil is lifted per each joint venture party, resulting in a variance in the volume of oil lifted versus the entitlement per owner per their working interest. The change in production imbalances is currently taken through cost of sales (see note 5(b)) at fair value at the date of lifting. All Group fields are operated through a Joint Venture Agreement ('JVA') through which production imbalances are settled. These transactions are settled by the JVA through lifting schedules and are not settled in cash, with the exception of a misbalance at the cessation of contract.

These are collaborative agreements through the JVA and non-monetary exchanges, and therefore do not meet the definition of a customer under IFRS 15. Production imbalances will continue to be recognised through cost of sales, as per the current accounting treatment, with no change on the application of IFRS 15.

IFRS 16 Leases

IFRS 16 Leases, issued in January 2016, sets out the principles for the recognition, measurement, presentation and disclosure of leases for both lessors and lessees. It replaces the previous leases standard IAS 17 Leases and is effective from 1 January 2019.

IFRS 16 introduces a single, on-balance sheet lease accounting model for lessees. A lessee recognises a right-of-use asset representing its right to use the underlying asset and a lease liability representing its obligation to make lease payments. There are recognition exemptions for short-term leases and leases of low-value items. Lessor accounting remains similar to the current standard i.e. lessors continue to classify leases as finance or operating leases.

The Group has completed an initial assessment of the potential impact on its consolidated financial statements, but has not yet completed its detailed assessment. The actual impact of applying IFRS 16 on the financial statements in the period of initial application will depending on future economic condition, including the Group's borrowing rate at1 January 2019, the composition of the Group's lease portfolio at that date, the Group's latest assessment of whether it will exercise any lease renewal options and the extent to which the Group chooses to use practical expedients and recognition exemptions.

As at 31 December 2017, the Group has non-cancellable operating lease commitments of $110 million (see note 24). A preliminary assessment indicates that these arrangements will meet the definition of a lease under IFRS 16, and hence the Group will recognise a right-of-use asset and a corresponding liability in respect of these leases, unless they qualify for low value or short-term leases upon the application of IFRS 16. The new requirement to recognise aright-of-use asset and a related lease liability is expected to have a significant impact on the amounts recognised in the Group's consolidated financial statements and the Directors are currently assessing its potential impact. It is not practicable to provide a reasonable estimate of the financial effect until the Directors complete the review.

The Group plans to apply the practical expedient to grandfather the definition of a lease on transition. This means that it will apply IFRS 16 to all contracts entered into before 1 January 2019 and identified as leases in accordance withIAS 17. Contracts which have not been considered or identified as a lease will continue to be accounted for in line with their historical treatment.

In contrast, for finance leases where the Group is a lessee, as the Group has already recognised an asset and a related finance lease liability for the lease arrangement, and in cases where the Group is a lessor (for both operating and finance leases), the Directors of the Company do not anticipate that the application of IFRS 16 will have a significant impact on the amounts recognised in the Group's consolidated financial statements.

2. Summary of significant accounting policies (continued)

Basis of preparation

The Group financial information has been prepared in accordance with International Financial Reporting Standards ('IFRS') as adopted by the European Union as they apply to the financial statements of the Group for the year ended 31 December 2017 and applied in accordance with the Companies Act 2006. The accounting policies which follow set out those policies which apply in preparing the financial statements for the year ended 31 December 2017.

The Group financial information has been prepared on an historical cost basis, except for the fair value remeasurement of certain financial instruments, including derivatives, as set out in the accounting policies below. The presentation currency of the Group financial information is United States Dollars and all values in the Group financial information are rounded to the nearest thousand ($'000) except where otherwise stated.

The financial statements have been prepared on the going concern basis. Further information relating to the use of the going concern assumption is provided in the 'Going Concern' section of the Financial Review.

Basis of consolidation

Subsidiaries

Subsidiaries are all entities over which the Group has the sole right to exercise control over the operations and govern the financial policies generally accompanying a shareholding of more than half of the voting rights. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing the Group's control. Subsidiaries are fully consolidated from the date on which control is transferred to the Group and are de-consolidated from the date that control ceases.

Intercompany profits, transactions and balances are eliminated on consolidation. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Group.

Joint arrangements

Oil and gas operations are usually conducted by the Group as co-licensees in unincorporated joint operations with other companies. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the consent of the relevant parties sharing control.

Most of the Group's activities are conducted through joint operations, whereby the parties that have joint control of the arrangement have the rights to the assets, and obligations for the liabilities, relating to the arrangement. The Group reports its interests in joint operations using proportionate consolidation - the Group's share of the production, assets, liabilities, income and expenses of the joint operation are combined with the equivalent items in the consolidated financial statements on a line-by-line basis.

Business combinations

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value, and the amount of any controlling interest in the acquiree. For each business combination, the acquirer measures the non-controlling interest in the acquiree either at fair value or at the proportionate share of the acquiree's identifiable net assets. Those petroleum reserves and resources that are able to be reliably valued are recognised in the assessment of fair values on acquisition. Other potential reserves, resources and rights, for which fair values cannot be reliably determined, are not recognised.

Where applicable, the consideration for the acquisition includes any asset or liability resulting from a contingent consideration arrangement, measured at its acquisition-date fair value. Subsequent changes in such fair values are adjusted against the cost of acquisition where they qualify as measurement period adjustments. All other subsequent changes in the fair value of contingent consideration classified as a financial liability are remeasured through profit or loss. If the contingent consideration is not within the scope of IAS 39, it is measured at fair value in accordance with the appropriate IFRS. Contingent consideration that is classified as equity is not remeasured and subsequent settlement is accounted for within equity.

If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, the Group reports provisional amounts for the items for which the accounting is incomplete. Those provisional amounts are adjusted during the measurement period (see below), or additional assets or liabilities are recognised to reflect new information obtained about facts and circumstances that existed as of the acquisition date that, if known, would have affected the amounts recognised as of that date.

The measurement period is the period from the date of acquisition to the date the Group obtains complete information about facts and circumstances that existed as of the acquisition date, and is subject to a maximum of one year.

2. Summary of significant accounting policies (continued)

Goodwill 

Goodwill arising on a business combination is initially measured at cost, being the excess of the cost of the business combination over the net fair value of the identifiable assets, liabilities and contingent liabilities of the entity at the date of acquisition.

If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Group re-assesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognised at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, the gain is recognised in profit or loss.

Following initial recognition, goodwill is stated at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that such carrying value may be impaired.

For the purposes of impairment testing, goodwill acquired is allocated to the cash generating units ('CGU') that are expected to benefit from the synergies of the combination. Each unit or units to which goodwill is allocated represents the lowest level within the Group at which the goodwill is monitored for internal management purposes.

Impairment is determined by assessing the recoverable amount of the cash generating unit to which the goodwill relates. Where the recoverable amount of the CGU is less than the carrying amount of the CGU and related goodwill, an impairment loss is recognised. Impairment losses relating to goodwill cannot be reversed in future periods.

Critical accounting estimates and judgements

The management of the Group has to make estimates and judgements when preparing the financial statements of the Group. Uncertainties in the estimates and judgements could have an impact on the carrying amount of assets and liabilities and the Group's result. The most important estimates and judgements in relation thereto are:

Estimates in oil and gas reserves

The business of the Group is to enhance hydrocarbon recovery and extend the useful lives of mature and underdeveloped assets and associated infrastructure in a profitable and responsible manner. Estimates of oil and gas reserves are used in the calculations for impairment tests and accounting for depletion and decommissioning. Changes in estimates of oil and gas reserves resulting in different future production profiles will affect the discounted cash flows used in impairment testing, the anticipated date of decommissioning and the depletion charges in accordance with the unit of production method.

Estimates in impairment of oil and gas assets, goodwill and the estimate of the cost recovery provision

Determination of whether oil and gas assets or goodwill have suffered any impairment requires an estimation of the fair value less costs to dispose of the CGU to which oil and gas assets and goodwill have been allocated. The calculation requires the entity to estimate the future cash flows expected to arise from the CGU using discounted cash flow models comprising asset-by-asset life of field projections using Level 3 inputs (based on IFRS 13 fair value hierarchy). Key assumptions and estimates in the impairment models relate to: commodity prices that are based on forward curve prices for the first three years and thereafter at $70/bbl inflated at 2.0% per annum from 2022; discount rates derived from the Group's post-tax weighted average cost of capital of 10.0% (2016: 10.0%); commercial reserves and the related cost profiles. As the production and related cash flows can be estimated from EnQuest's experience, management believes that the estimated cash flows expected to be generated over the life of each field is the appropriate basis upon which to assess goodwill and individual assets for impairment.

These same models and assumptions are used in the calculation of the cost recovery provision (see note 22).

Determining the fair value of property, plant and equipment on business combinations

The Group determines the fair value of property, plant and equipment acquired in a business combination based on the discounted cash flows at the time of acquisition from the proven and probable reserves. In assessing the discounted cash flows, the estimated future cash flows attributable to the asset are discounted to their present value using a discount rate that reflects the market assessments of the time value of money and the risks specific to the asset at the time of the acquisition. In calculating the asset fair value the Group will apply a forward curve followed by an oil price assumption representing management's view of the long-term oil price.

2. Summary of significant accounting policies (continued)

Critical accounting estimates and judgements (continued)

Decommissioning provision

Amounts used in recording a provision for decommissioning are estimates based on current legal and constructive requirements and current technology and price levels for the removal of facilities and plugging and abandoning of wells. Due to changes in relation to these items, the future actual cash outflows in relation to decommissioning are likely to differ in practice. To reflect the effects due to changes in legislation, requirements and technology and price levels, the carrying amounts of decommissioning provisions are reviewed on a regular basis.

The effects of changes in estimates do not give rise to prior year adjustments and are dealt with prospectively. While the Group uses its best estimates and judgement, actual results could differ from these estimates.

In estimating decommissioning provisions, the Group applies an annual inflation rate of 2.0% (2016: 2.0%) and an annual discount rate of 2.0% (2016: 2.3%).

Debt restructuring

The Group undertook debt restructuring during 2016 resulting in a substantial modification of the terms of its Revolving Credit Facility ('RCF') (see note 19). Accordingly, extinguishment accounting was applied, resulting in the derecognition of the carrying value of the facility, including any unamortised arrangement fees, and the recognition of a new financial liability for the revised facility at fair value. Costs associated with the renegotiation of the facility were expensed to the income statement as exceptional finance costs (see note 4).

Going concern

The Directors' assessment of going concern concludes that the use of the going concern basis is appropriate and that, notwithstanding the material uncertainty as provided in the 'Going Concern' section of the Financial Review, the Directors have a reasonable expectation that the Group will be able to continue in operation and meet its commitments as they fall due over the going concern period.

The going concern assumption is highly sensitive to economic conditions. The Group closely monitors and manages its funding position and liquidity risk throughout the year, including monitoring forecast covenant results, to ensure it has access to sufficient funds to meet forecast cash requirements. Cash forecasts are regularly produced and sensitivities considered for, but not limited to, changes in crude oil prices (adjusted for hedging undertaken by the Group), production rates and development project timing and costs. These forecasts and sensitivity analyses allow management to mitigate any liquidity or covenant compliance risks in a timely manner. See the Financial Review for further details.

Taxation

The Group's operations are subject to a number of specific tax rules which apply to exploration, development and production. In addition, the tax provision is prepared before the relevant companies have filed their tax returns with the relevant tax authorities and, significantly, before these have been agreed. As a result of these factors, the tax provision process necessarily involves the use of a number of estimates and judgements including those required in calculating the effective tax rate. In considering the tax on exceptional items, the Group applies the appropriate statutory tax rate to each item to calculate the relevant tax charge on exceptional items.

The Group recognises deferred tax assets on unused tax losses where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the likelihood of future taxable profits and the amount of deferred tax that can be recognised.

Foreign currencies

Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which the entity operates (functional currency). The Group financial statements are presented in United States Dollars ($), the currency which the Group has elected to use as its presentation currency.

In the accounts of the Company and its individual subsidiaries, transactions in currencies other than a company's functional currency are recorded at the prevailing rate of exchange on the date of the transaction. At the year end, monetary assets and liabilities denominated in foreign currencies are retranslated at the rates of exchange prevailing at the balance sheet date. Non-monetary assets and liabilities that are measured at historical cost in a foreign currency are translated using the rate of exchange as at the dates of the initial transactions. Non-monetary assets and liabilities measured at fair value in a foreign currency are translated using the rate of exchange at the date the fair value was determined. All foreign exchange gains and losses are taken to profit and loss in the statement of comprehensive income.

2. Summary of significant accounting policies (continued)

Property, plant and equipment

Property, plant and equipment is stated at cost less accumulated depreciation and any impairment in value. Cost comprises the purchase price or construction cost and any costs directly attributable to making that asset capable of operating as intended by management. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

Oil and gas assets are depleted, on a field-by-field basis, using the unit of production method based on entitlement to proven and probable reserves, taking account of estimated future development expenditure relating to those reserves.

Depreciation on other elements of property, plant and equipment is provided on a straight line basis at the following rates:

Office furniture and equipment 5 years

Fixtures and fittings 10 years

Long leasehold land period of lease

Each asset's estimated useful life, residual value and method of depreciation are reviewed and adjusted if appropriate at each financial year end.

No depreciation is charged on assets under construction.

Oil and gas assets

Exploration and appraisal assets

The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Pre-licence costs are expensed in the period in which they are incurred. Expenditure directly associated with exploration, evaluation or appraisal activities is initially capitalised as an intangible asset. Such costs include the costs of acquiring an interest, appraisal well drilling costs, payments to contractors and an appropriate share of directly attributable overheads incurred during the evaluation phase. For such appraisal activity, which may require drilling of further wells, costs continue to be carried as an asset whilst related hydrocarbons are considered capable of commercial development. Such costs are subject to technical, commercial and management review to confirm the continued intent to develop, or otherwise extract value. When this is no longer the case, the costs are written off as exploration and evaluation expenses in the statement of comprehensive income. When exploration licences are relinquished without further development, any previous impairment loss is reversed and the carrying costs are written off through the statement of comprehensive income. When assets are declared part of a commercial development, related costs are transferred to property, plant and equipment. All intangible oil and gas assets are assessed for any impairment prior to transfer and any impairment loss is recognised in the statement of comprehensive income.

Development assets

Expenditure relating to development of assets including the construction, installation and completion of infrastructure facilities such as platforms, pipelines and development wells, is capitalised within property, plant and equipment.

Farm-outs - in the exploration and evaluation phase

The Group does not record any expenditure made by the farmee on its account. In the event of a partial farm out, the Group also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements but redesignates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained. Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest with any excess accounted for by the farmor as a gain on disposal.

Farm-outs - outside the exploration and evaluation phase

In accounting for a farm-out arrangement outside the exploration and evaluation phase, the Group:

· derecognises the proportion of the asset that it has sold to the farmee;

· recognises the consideration received or receivable from the farmee, which represents the cash received and/or the farmee's obligation to fund the capital expenditure in relation to the interest retained by the farmor and/or any deferred consideration;

· recognises a gain or loss on the transaction for the difference between the net disposal proceeds and the carrying amount of the asset disposed of. A gain is only recognised when the value of the consideration can be determined reliably. If not, then the Group accounts for the consideration received as a reduction in the carrying amount of the underlying assets; and

· tests the retained interests for impairment if the terms of the arrangement indicate that the retained interest may be impaired.

The consideration receivable on disposal of an item of property, plant and equipment or an intangible asset is recognised initially at its fair value by the Group. However, if payment for the item is deferred, the consideration received is recognised initially at the cash price equivalent. The difference between the nominal amount of the consideration and the cash price equivalent is recognised as interest revenue. Any part of the consideration that is receivable in the form of cash is treated as a financial asset and is accounted for at amortised cost.

2. Summary of significant accounting policies (continued)

Oil and gas assets (continued)

Carry arrangements

Where amounts are paid on behalf of a carried party these are capitalised. Where there is an obligation to make payments on behalf of a carried party and the timing and amount are uncertain, a provision is recognised. Where the payment is a fixed monetary amount, a financial liability is recognised.

Changes in unit of production factors

Changes in factors which affect unit of production calculations are dealt with prospectively, not by immediate adjustment of prior years' amounts.

Borrowing costs

Borrowing costs directly attributable to the construction of qualifying assets, which are assets that necessarily take a substantial period of time to prepare for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use. All other borrowing costs are recognised as interest payable in the statement of comprehensive income in accordance with the effective interest method.

Impairment of tangible and intangible assets (excluding goodwill)

At each balance sheet date, the Group reviews the carrying amounts of its oil and gas assets to assess whether there is an indication that those assets may be impaired. If any such indication exists, the Group makes an estimate of the asset's recoverable amount. An asset's recoverable amount is the higher of an asset's fair value less costs of disposal and its value in use. In assessing value in use, the estimated future cash flows attributable to the asset are discounted to their present value using a post tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.

If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. An impairment loss is recognised immediately in the statement of comprehensive income.

Where an impairment loss subsequently reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset in prior years.A reversal of an impairment loss is recognised immediately in the statement of comprehensive income.

Non-current assets held for sale

Non-current assets classified as held for sale are measured at the lower of carrying amount and fair value less costs of disposal.

Non-current assets are classified as held for sale if their carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset is available for immediate sale in its present condition. Management must be committed to the sale which should be expected to qualify for recognition as a completed sale within one year from the date of classification.

Financial assets

Financial assets within the scope of IAS 39 are classified as financial assets at fair value through profit or loss, loans and receivables, held-to-maturity investments, available-for-sale financial investments, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. The Group determines the classification of its financial assets at initial recognition.

All assets are recognised initially at fair value plus transaction costs, except in the case of financial assets recorded at fair value through profit or loss.

Purchases or sales of financial assets that require delivery of assets within a timeframe established by regulation or convention in the marketplace (regular way trades) are recognised on the trade date.

The Group's financial assets include cash and short-term deposits, trade and other receivables, loans and other receivables, quoted and unquoted financial instruments and derivative financial instruments.

2. Summary of significant accounting policies (continued)

Financial assets (continued)

Subsequent measurement of financial assets depends on their classification as described below:

Financial assets at fair value through profit or loss ('FVTPL')

Financial assets are classified as at FVTPL when the financial asset is either held for trading or designated as at FVTPL. Financial assets are classified as held for trading if they are acquired for the purpose of selling or repurchasing in the near term. Derivatives are also classified as held for trading unless they are designated as effective hedging instruments as defined by IAS 39.

Financial assets at FVTPL, including commodity and foreign exchange derivatives, are stated at fair value, with any gains or losses arising on remeasurement recognised immediately in the income statement.

Financial assets designated upon initial recognition at FVTPL are designated at their initial recognition date and only if the criteria under IAS 39 are satisfied.

Available-for-sale financial investments

Listed and unlisted shares held by the Group that are traded in an active market are classified as beingavailable-for-sale and are stated at fair value. Gains and losses arising from changes in fair value are recognised in other comprehensive income and accumulated in the available-for-sale reserve with the exception of impairment losses which are recognised directly in profit or loss. Where the investment is disposed of or is determined to be impaired, the cumulative gain or loss previously recognised in the available-for-sale reserve is reclassified to profit or loss.

Loans and receivables

These include trade receivables, loans and other receivables that have fixed or determinable payments that are not quoted in an active market and are measured at amortised cost using the effective interest method, less any impairment. Interest income is recognised by applying the effective interest rate, except for short-term receivables when the recognition of interest would be immaterial.

Impairment of financial assets

The Group assesses, at each reporting date, whether there is any objective evidence that a financial asset is impaired. A financial asset is deemed to be impaired where there is objective evidence of impairment that, as a result of one or more events that have occurred after the initial recognition of the asset, the estimated future cash flows of the investment have been affected.

For listed and unlisted equity investments classified as available-for-sale, a significant or prolonged decline in the fair value of the security below its cost is considered to be objective evidence of impairment. When an available-for-sale financial asset is considered to be impaired, cumulative gains and losses previously recognised in other comprehensive income are reclassified to profit or loss in the period. In respect of equity securities, impairment losses previously recognised in profit or loss are not reversed through profit or loss but through other comprehensive income. Any increase in fair value subsequent to an impairment loss is recognised in other comprehensive income.

For financial assets carried at amortised cost, the amount of the impairment is the difference between the asset's carrying amount and the present value of estimated future cash flows, discounted at the financial asset's original effective interest rate. The carrying amount is reduced through use of an allowance account and the amount of the loss is recognised in profit or loss.

Derivatives

Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently remeasured at their fair value. The method of recognising the resulting gain or loss depends on whether the derivative is designated as a hedging instrument.

The Group categorises derivatives as follows:

Fair value hedge

Changes in the fair value of derivatives that qualify as fair value hedging instruments are recorded in the profit or loss, together with any changes in the fair value of the hedged asset or liability.

Cash flow hedge

The effective portion of changes in the fair value of derivatives that qualify as cash flow hedges are recognised in other comprehensive income. The gain or loss relating to the ineffective portion is recognised immediately in the profit or loss. Amounts accumulated in other comprehensive income are transferred to the profit or loss in the period when the hedged item will affect the profit or loss. When the hedged item no longer meets the requirements for hedge accounting, expires or is sold, any accumulated gain or loss recognised in other comprehensive income is transferred to profit and loss when the forecast transaction which was the subject of the hedge occurs.

Where put options are used as hedging instruments, only the intrinsic value of the option is designated as the hedge, with the change in time value recorded in finance costs within the income statement.

2. Summary of significant accounting policies (continued)

Derivatives

Derivatives that do not qualify for hedge accounting

When derivatives do not qualify for hedge accounting, changes in fair value are recognised immediately in the profit or loss within 'Re-measurements and exceptional items' profit or loss on the face of the income statement. When a derivative reaches maturity, the realised gain or loss is included within the Group's Business performance results with a corresponding reclassification from 'Re-measurements and exceptional items'.

Option premium

Option premium received or paid for commodity derivatives are amortised into Business performance revenue over the period between the inception of the option, and that options expiry date. This results in a corresponding reclassification from 'Re-measurements and exceptional items' revenue.

As noted above, where put options are designated as an effective hedge, the change in time value is recorded in finance costs. As the cost of a put option represents the initial time value of that option, option premium paid for put options which have been designated as effective hedges are amortised in Business performance finance costs, with an offsetting reclassification from 'Re-measurements and exceptional items' finance costs.

Trade receivables

Trade receivables are recognised initially at fair value and subsequently measured at amortised cost less provision for impairment.

Financial liabilities

Financial liabilities within the scope of IAS 39 are classified as financial liabilities at fair value through profit or loss or other financial liabilities at amortised cost. The Group determines the classification of its financial liabilities at initial recognition.

All liabilities are recognised initially at fair value net transaction costs, except in the case of financial liabilities recorded at fair value through profit or loss.

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

Other financial liabilities, including borrowings, are initially measured at fair value, net of transaction costs. Other financial liabilities are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis.

Interest bearing loans and borrowings

Interest bearing loans and borrowings are recognised initially at fair value, net of transaction costs incurred. Transaction costs are amortised over the life of the facility.

Borrowing costs are stated at amortised cost using the effective interest method.

The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or a shorter period to the net carrying amount of the financial liability where appropriate.

Bonds

Bonds are measured on an amortised cost basis.

Derecognition of financial assets and liabilities

Financial assets

A financial asset (or, where applicable, a part of a financial asset) is derecognised where:

· the rights to receive cash flows from the asset have expired;

· the Group retains the right to receive cash flows from the asset, but has assumed an obligation to pay them in full without material delay to a third party under a 'pass-through' arrangement; or

· the Group has transferred its rights to receive cash flows from the asset and either (a) has transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset.

2. Summary of significant accounting policies (continued)

Derecognition of financial assets and liabilities (continued)

Financial liabilities

A financial liability is derecognised when the obligation under the liability is discharged, cancelled or expires.

If an existing financial liability is replaced by another from the same lender, on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability such that the difference in the respective carrying amounts, together with any costs or fees incurred, are recognised in profit or loss. IAS 39 Financial Instruments: Recognition and Measurement regards the terms of exchanged or modified debt as 'substantially different' if the net present value of the cash flows under the new terms (including any fees paid net of fees received) discounted at the original effective interest rate is at least 10.0% different from the discounted present value of the remaining cash flows of the original debt instrument. The Group also considers qualitative factors in assessing whether a modified financial liability is 'substantially different'. Where the modification is substantially different, it accounts for this as an extinguishment of the original liability even though a quantitative analysis may indicate a less than 10.0% cash flow change.

Inventories

Inventories of consumable well supplies are stated at the lower of cost and net realisable value, cost being determined on an average cost basis. Inventories of hydrocarbons are stated at the lower of cost and net realisable value.

Under/over-lift

Under or over-lifted positions of hydrocarbons are valued at market prices prevailing at the balance sheet date. An under-lift of production from a field is included in current receivables and valued at the reporting date spot price or prevailing contract price. An over-lift of production from a field is included in current liabilities and valued at the reporting date spot price or prevailing contract price. Movements in under or over-lifted positions are accounted for through cost of sales.

Cash and cash equivalents

Cash and cash equivalents includes cash at bank, cash in hand, outstanding bank overdrafts and highly liquid interest bearing securities with original maturities of three months or less.

Equity

Share capital

The balance classified as equity share capital includes the total net proceeds (both nominal value and share premium) on issue of registered share capital of the parent Company. Share issue costs associated with the issuance of new equity are treated as a direct reduction of proceeds.

Merger reserve

Merger reserve represents the difference between the market value of shares issued to effect business combinations less the nominal value of shares issued. The merger reserve in the Group financial statements also includes the consolidation adjustments that arise under the application of the pooling of interest method.

Cash flow hedge reserve

For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognised directly as other comprehensive income in the cash flow hedge reserve. Upon settlement of the hedged item, the change in fair value is transferred to profit or loss.

Available-for-sale reserve

Gains and losses (with the exception of impairment losses) arising from changes in available-for-sale financial investments are recognised in the available-for-sale reserve until such time that the investment is disposed of, where it is reclassified to profit or loss.

Share-based payments reserve

Equity-settled share-based payment transactions are measured at the fair value of the services received, and the corresponding increase in equity is recorded directly at the fair value of the services received. The share-based payments reserve includes shares held within the Employee Benefit Trust.

Retained earnings

Retained earnings contain the accumulated results attributable to the shareholders of the parent Company.

Employee Benefit Trust

EnQuest PLC shares held by the Group are deducted from the share-based payments reserve and are recognised at cost. Consideration received for the sale of such shares is also recognised in equity, with any difference between the proceeds from the sale and the original cost being taken to reserves. No gain or loss is recognised in the statement of comprehensive income on the purchase, sale, issue or cancellation of equity shares.

2. Summary of significant accounting policies (continued)

Provisions

Decommissioning

Provision for future decommissioning costs is made in full when the Group has an obligation: to dismantle and remove a facility or an item of plant; to restore the site on which it is located; and when a reasonable estimate of that liability can be made. The amount recognised is the present value of the estimated future expenditure. An amount equivalent to the discounted initial provision for decommissioning costs is capitalised and amortised over the life of the underlying asset on a unit of production basis over proven and probable reserves. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the oil and gas asset.

The unwinding of the discount applied to future decommissioning provisions is included under finance costs in the statement of comprehensive income.

Other

Provisions are recognised when: the Group has a present legal or constructive obligation as a result of past events; it is probable that an outflow of resources will be required to settle the obligation; and a reliable estimate can be made of the amount of the obligation.

Leases

The determination of whether an arrangement is or contains a lease is based on the substance of the arrangement at the inception date. The arrangement is assessed for whether fulfilment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys a right to use the asset or assets, even if that right is not explicitly specified in an arrangement.

Finance leases that transfer substantially all the risks and benefits incidental to ownership of the leased item to the Group, are capitalised at the commencement of the lease at the fair value of the leased asset or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are recognised in finance costs in the income statement.

A leased asset is depreciated over the useful life of the asset. However, if there is no reasonable certainty that the Group will obtain ownership by the end of the lease term, the asset is depreciated over the shorter of the estimated useful life of the asset and the lease term.

Lease charter payment credits, arising from the non-performance of the leased asset, are recognised as an operating expense in the income statement for the period to which they relate.

Operating lease payments are recognised as an operating expense in the income statement on a straight line basis over the lease term.

Revenue and other operating income

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

Oil and gas revenues comprise the Group's share of sales from the processing or sale of hydrocarbons on an entitlement basis, when the significant risks and rewards of ownership have been passed to the buyer.

Tariff revenue is recognised in the period in which the services are provided at the agreed contract rates.

Rental income is accounted for on a straight line basis over the lease terms and is included in revenue in the income statement.

The Group uses various commodity derivative instruments to manage some of the risks arising from fluctuations in commodity prices. Such contracts include options, swaps and futures. Where these derivatives have been designated as cash flow hedges of underlying commodity price exposures, certain gains and losses attributable to these instruments are deferred in other comprehensive income and recognised in the income statement within revenue and other operating income when the underlying hedged transaction crystallises or is no longer expected to occur.

All other commodity derivatives within the scope of IAS 39 are measured at fair value with changes in fair value recognised in the income statement within revenue and other operating income. Unrealised mark to market changes in the remeasurement of derivative contracts are initially included in exceptional items within profit or loss. When the derivative reaches maturity, the gain or loss is realised and recycled to be included within Business performance.

2. Summary of significant accounting policies (continued)

Re-measurements and exceptional items

As permitted by IAS 1 (Revised): Presentation of Financial Statements, certain items are presented separately. The items that the Group separately presents as exceptional on the face of the statement of comprehensive income are those material items of income and expense which, because of the nature or expected infrequency of the events giving rise to them, merit separate presentation to allow shareholders to understand better the elements of financial performance in the year, so as to facilitate comparison with prior periods and to better assess trends in financial performance.

The following items are routinely classified as Remeasurements and exceptional items ('exceptional'):

· Unrealised mark to market changes in the remeasurement of derivative contracts are included in exceptional profit or loss. This includes the recycling of realised amounts from exceptional items into Business performance income when a derivative instrument matures, together with the recycling of option premium amortisation from exceptional to Business performance as set out in the Derivatives policy previously;

· Impairments and write offs/write downs are deemed to be exceptional in nature. This includes impairments of tangible and intangible assets, and write offs/write downs of unsuccessful exploration. Other non-routine write offs/write downs, where deemed material, are also included in this category; and

· The depletion of a fair value uplift to property, plant and equipment that arose from the merger accounting applied at the time of EnQuest's formation.

Employee benefits

Short-term employee benefits

Short-term employee benefits such as salaries, social premiums and holiday pay, are expensed when incurred.

Pension obligations

The Group's pension obligations consist of defined contribution plans. A defined contribution plan is a pension plan under which the Group pays fixed contributions. The Group has no further payment obligations once the contributions have been paid. The amount charged to the statement of comprehensive income in respect of pension costs reflects the contributions payable in the year. Differences between contributions payable during the year and contributions actually paid are shown as either accrued liabilities or prepaid assets in the balance sheet.

Share-based payment transactions

Eligible employees (including Directors) of the Group receive remuneration in the form of share-based payment transactions, whereby employees render services in exchange for shares or rights over shares (equity-settled transactions) of EnQuest PLC.

Equity-settled transactions

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date on which they are granted. Fair value is measured in reference to the scheme rules, as detailed in note 18. In valuingequity-settled transactions, no account is taken of any service or performance conditions, other than conditions linked to the price of the shares of EnQuest PLC (market conditions) or 'non-vesting' conditions, if applicable.

The cost of equity-settled transactions is recognised over the period in which the relevant employees become fully entitled to the award (the vesting period). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group's best estimate of the number of equity instruments that will ultimately vest. The statement of comprehensive income charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

No expense is recognised for awards that do not ultimately vest, except for awards where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance conditions are satisfied. Equity awards cancelled are treated as vesting immediately on the date of cancellation, and any expense not previously recognised for the award at that date is recognised in the statement of comprehensive income.

2. Summary of significant accounting policies (continued)

Taxes

Income taxes

Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities, based on tax rates and laws that are enacted or substantively enacted by the balance sheet date.

Deferred tax is provided in full on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Group financial statements. However, deferred tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred tax is measured on an undiscounted basis using tax rates (and laws) that have been enacted or substantively enacted by the balance sheet date and are expected to apply when the related deferred tax asset is realised or the deferred tax liability is settled. Deferred tax assets are recognised to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilised.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

The carrying amount of deferred income tax assets is reviewed at each balance sheet date. Deferred income tax assets and liabilities are offset only if a legal right exists to offset current tax assets against current tax liabilities, the deferred income taxes relate to the same taxation authority and that authority permits the Group to make a single net payment.

Production taxes

In addition to corporate income taxes, the Group's financial statements also include and disclose production taxes on net income determined from oil and gas production.

Production tax relates to Petroleum Revenue Tax ('PRT') and is accounted for under IAS 12 Income Taxes since it has the characteristics of an income tax as it is imposed under Government authority and the amount payable is based on taxable profits of the relevant fields. Current and deferred PRT is provided on the same basis as described above for income taxes.

Investment allowances

The UK taxation regime provides for a reduction in ring fence supplementary corporation tax where investments in new or existing UK assets qualify for a relief known as investment allowances. Investment allowances are only triggered when production from the field commences. The Group is eligible for a number of investment allowances which will materially reduce the level of future supplementary corporation taxation. Investment allowances are recognised as a reduction in the charge to taxation in the years claimed.

3. Segment information

Management have considered the requirements of IFRS 8: Operating Segments in regard to the determination of operating segments and concluded that the Group has two significant operating segments; the North Sea and Malaysia. Operations are managed by location and all information is presented per geographical segment. The information reported to the Chief Operating Decision Maker does not include an analysis of assets and liabilities and accordingly this information is not presented.

3. Segment information (continued)

Adjustments and eliminations

Finance income and costs and gains and losses on derivatives are not allocated to individual segments as the underlying instruments are managed on a Group basis.

Capital expenditure consists of property, plant and equipment and intangible assets, including assets from the acquisition of subsidiaries.

Inter-segment revenues are eliminated on consolidation. All other adjustments are part of the reconciliations presented further below.

Reconciliation of (loss)/profit:

Revenue from two customers (2016: three customers) each exceed 10% of the Group's consolidated revenue arising from sales of crude oil and amounted respectively to $206.1 million in the North Sea operating segment and $105.2 million in the Malaysia operating segment (2016: $321.0 million and $85.7 million arising in the North Sea operating segment and $89.9 million in Malaysia operating segment).

All of the Group's segment assets (non-current assets excluding financial instruments, deferred tax assets and other financial assets) are located in the United Kingdom except for $119.1 million located in Malaysia (2016: $128.1 million).

4. Re-measurements and exceptional items

(i) Fair value re-measurements include unrealised mark to market movements on derivative contracts and other financial instruments where the Group does not classify them as effective hedges. It also includes the impact of recycling realised gains and losses (including option premia) out of 'Re-measurements and exceptional items' and into 'Business performance' profit or loss. In addition a $1.3 million gain in respect to the disposal of Ascent Resources loan notes was recognised in 2017. Refer to note 2 for further details on the Group's accounting policies for derivatives and 'Re-measurements and exceptional items'.

(ii) Impairments and write offs includes an impairment of tangible oil and gas assets totalling $172.0 million (2016: impairment reversal of $147.9 million), together with a charge of $2.7 million in relation to inventory write downs, a $0.02 million impairment on the investment in Ascent Resources (2016: $0.05 million impairment) and a $0.2 million write back of previously impaired exploration costs (2016: $0.8 million impairment/write off). Further details on the tangible impairment are provided in note 10.

(iii) Other mainly includes a gain in relation to the excess of fair value over cost arising on the acquisition of the Magnus oil field and other interests compromising of the $22.3 million purchase option, $16.1 million Thistle decommissioning option and $10.3 million 25% acquisition value, totalling a gain of $48.7 million (see note 29). Other items include a charge of $10.3 million in relation to the 2014 PM8 cost recovery settlement agreement, a charge of $6.4 million for the cancellation of contracts and a charge of $2.8 million in relation to the provision on restricted cash (see note 16). Other income also includes other items of income and expense which, because of the nature or expected infrequency of the events giving rise to them, merit separate presentation to allow shareholders to understand better the elements of financial performance in the year so as to facilitate comparison with prior periods and to better assess trends in financial performance.

(iv) Other tax exceptional items include $13.2 million for the recognition of previously de-recognised tax losses, together with $34.0 million for the impact on deferred tax of a revision to the balance of non-qualifying expenditure.

4. Re-measurements and exceptional items (continued)

(i) The Group's restructuring was deemed to result in a substantial modification of the terms of the Group's credit facility (see note 19). In accordance with IAS 39, the Group has accounted for this substantial modification as an extinguishment of the liability for the original credit facility and the recognition of a new liability for the revised credit facility. In 2016, this resulted in $15.0 million of unamortised costs associated with the previous credit facility being expensed on extinguishment. The costs of negotiating the modifications to the credit facility, totalling $11.1 million and a $12.0 million restructuring fee, payable to the credit facility lenders by March 2018, were expensed. In 2016, these comprised an aggregate of $38.1 million of debt restructuring costs. 

(ii) The Group had an agreement to hire the Stena Spey drilling vessel. Based on the drilling forecasts for 2016, it was expected that the vessel would not be fully utilised over this period and therefore a provision was recognised for unavoidable contracted costs of $22.9 million. During the year ended 31 December 2016, following changes to the Group's drilling schedule, the contracted days were utilised in full and the provision of $22.9 million was reversed in full.

(iii) During the year ended 31 December 2016, the Group disposed of its interest in the Avalon prospect for cash proceeds of $1.5 million, resulting in a loss on disposal of $16.2 million (see note 12).

(iv) In 2016, other primarily included a $3.4 million reversal of a provision for contingent consideration which was no longer required following the results of the Eagle well drilled during the year and a $1.3 million depreciation of the fair value uplift.

(v) The Finance Act 2016 enacted a change in the supplementary charge tax rate, reducing it from 20% to 10%, and a change to petroleum revenue tax rate, reducing it from 35% to 0%, both effective from 1 January 2016. The Finance Act 2016 also enacted a reduction in the mainstream corporation tax rate reducing it from 18% to 17% with effect from 1 April 2020.The impact of these changes in tax rates in 2016 was a tax charge of $29.5 million.

(vi) At the year ended 31 December 2016, the recovery of deferred tax assets was reviewed which has led to a recognition of previously impaired tax losses totalling $48.8 million. This write back reflects the increase in value of the Group's assets following a partial recovery of oil prices.

5. Revenue and expenses

(a) Revenue and other operating income

* Unrealised gains and losses on oil derivative contracts which are either ineffective for hedge accounting purposes or held for trading are disclosed as exceptional items in the income statement (see note 4).

 (b) Cost of sales