EnQuest PLC Preliminary Results

CHAIRMAN'S STATEMENT
 

EnQuest in 2016
When I became Chairman of EnQuest in September 2016, I said that EnQuest's priority was to deliver a business and a balance sheet which were robust in the prevailing oil price environment.  In November 2016, EnQuest was pleased to announce the successful completion of a financial restructuring designed to deliver such a robust balance sheet.  This was a comprehensive package of measures which, combined with an extensive and ongoing cost saving programme, put EnQuest's business on a strong footing, well placed to deliver the Kraken development and to deliver value to shareholders in the medium term. 

I also said that I was pleased to become Chairman of a company with an asset base which has material growth potential and with such a strong team of people.  In 2016, our people again performed well in a challenging environment, with EnQuest delivering production up 9% on 2015, whilst at the same time significantly further reducing costs, with unit operating costs down 17% on the prior year. 

With the combined effect of increased production and acquisition related increases, EnQuest ended 2016 with a net 2P reserve base of 215 MMboe, ahead of the 203 MMboe position at the end of 2015. This represents an average of 15% growth per annum since EnQuest's formation seven years ago and a current reserve life of 17 years.

Industry context
EnQuest's low cost capabilities have always been central to its business model.  The macro environment since 2014 has acted as a catalyst for the North Sea oil and gas industry, galvanising companies into new, innovative and collaborative ways of operating.  EnQuest has been at the forefront of these advances and initiatives and these more cost efficient operating methodologies are being institutionalised.  These are lasting structural changes and are essential to the optimisation of hydrocarbon extraction from the North Sea and beyond.

EnQuest supports the UK Government's strategy for 'Maximising Economic Recovery ('MER') for the UK and works closely with the Oil & Gas Authority ('OGA') to achieve this.  In Q4 2016, EnQuest brought the Scolty/Crathes development onstream; the only offshore oil Field Development Plan to have been approved in the UKCS in 2015.  Realisation of the potential from these smaller fields was enabled by cost efficiency, technology application and solid execution. EnQuest looks forward to adding further value to these MER (UK) initiatives through applying its differential capabilities to optimise the recovery of oil from the UKCS.

EnQuest welcomes the current programme to simplify and make more competitive the UK upstream tax regime, including reductions in the headline level of oil and gas tax rate, as set out in HMT's 'Driving Investment' document. These are essential to creating certainty and to driving the still substantial investment needed in the UKCS.  EnQuest believes that there is no longer a case for additional petroleum tax levies, such as the supplementary charge on UK upstream oil and gas activities. Such taxes mitigate against the realisation of MER (UK).     

Reasons for the 2016 financial restructuring
The decline in oil prices since 2014 and the cost of the Alma/Galia development project have had a significant negative impact on the Group's revenues, liquidity and available cash resources. 

In response to the decline in oil prices, the Group set a number of strategic priorities, including delivering on execution, streamlining operations and strengthening the Group's balance sheet. The Group focused on delivering a strong operational performance and also took a number of additional measures to address the impact of the decline in oil prices and the Group's cash flow constraints.  These included; negotiating the relaxation of certain financial covenants in the revolving credit facility ('RCF') and the retail notes; engaging in commodity hedging activities; divesting non-core international assets; reducing operating costs; reducing capital expenditure on the Kraken development; improving future cash flows through the development of Kraken and Scolty/Crathes; and deferring certain trade creditor obligations.

These measures were significant steps in maintaining the Group's viability in the prevailing environment. However, a longer term solution was needed to strengthen the Group's liquidity position, to reduce the burden of the Group's cash debt service obligations and to enable the Group to continue pursuing its business strategy, particularly, bringing Kraken to first oil.

This led to the financial restructuring in Q4 2016, the key features of which were amendments to the RCF and to both the high yield and retail bonds, the renewal of surety bond facilities and a placing and open offer, to raise £82 million.  On 21 November, the Board was pleased to announce that the restructuring had been successfully completed and was effective.

The EnQuest Board
On 8 September 2016, EnQuest announced that after over six years in the role, Dr James ('Jim') Buckee was retiring as Chairman of the Company and that I was to become EnQuest's new Chairman, both with immediate effect. The Board and I reiterate our thanks to Jim for his important contribution to the Company since its inception.  During his tenure, EnQuest grew reserves from 80.5 MMboe at the start, to 203 MMboe at the end of 2015. For my part, I was indeed pleased to become Chairman at such an important time in the Company's development and I was warmly welcomed into my new role by EnQuest's Chief Executive, Amjad Bseisu, and the rest of the Board.

On 15 December 2016, EnQuest announced the appointment of Carl Hughes as a Non-Executive Director and that Neil McCulloch was being appointed as Chief Operating Officer ('COO') and was to join the Board as an Executive Director at the 2017 AGM.   The appointment of Carl Hughes as a Non-Executive Director of the EnQuest Board was effective on 1 January 2017.  Carl was previously a vice chairman and senior audit partner at Deloitte, based in London; he was also global leader of Deloitte's energy and resources practice.   Prior to his promotion to COO, Neil was EnQuest's President, North Sea.  Neil's previous responsibilities for EnQuest's North Sea operations expanded to include production from Kraken and EnQuest's operations in Malaysia.   I am delighted to welcome Carl to EnQuest and I look forward to working with him as a member of the Board.  I am also pleased to congratulate Neil, both on his appointment to the role of COO and on being invited to join the Board.

In March 2016, as part of the planned rotation of the Board, Clare Spottiswoode retired from the Board.  I would like to repeat the Board's gratitude to Clare for her valuable contributions during her tenure with EnQuest. In conjunction with an independent search firm, the process of building on our rotation plans continues.

Our people
The Directors assess and evolve EnQuest's strategy as appropriate, taking key decisions on its implementation. 

In 2016, the strategic focus was again on positioning the business for the prevailing oil price environment, whilst also ensuring it continued to achieve its operational targets. Delivery against these objectives has only been possible due to EnQuest's people.  The Board and I would like to express our gratitude to everyone at EnQuest for having worked so diligently and innovatively to address the challenges presented by the oil price environment. 

In particular, we are grateful to the EnQuest leadership team for their energy and dedication in navigating into place the complicated restructuring and capital raise.  We are pleased that these arrangements have put EnQuest in the position where it can continue doing what it is known for and what it does so well, creating value from opportunities in maturing oil fields.

Following the capital restructuring, the Board also worked with the management team on the proposed EnQuest acquisition of interests in the Magnus oil field and the Sullom Voe Terminal.  Again, this transaction is a significant demonstration of the stamina and ingenuity of our people - your Company is led by a high quality team.

Governance
The Board believes that the manner in which it conducts its business is important and it is committed to working to the highest standards of corporate governance for the benefit of all of its stakeholders. Ensuring that the Board works effectively remains a key areas of focus. EnQuest's values underpin a working environment where people are safe, creative and passionate, with a relentless focus on results.

2016 saw the inception of a new Committee of the Board, the Risk Committee. The primary purpose of the Risk Committee is to provide a forum for in-depth examination of non-financial risk areas (financial risk being within the scope of the Audit Committee). Over the course of the year, the Committee has reviewed a number of areas such as asset integrity, subsurface risks and morale.

EnQuest's corporate responsibility is focused on five main areas. These are, first and foremost, Health and Safety,  People, Environment, Business Conduct and Community. The Board has approved EnQuest's overall approach to Corporate Responsibility and specific developments and updates in each are brought to the Board's attention when appropriate. The Board receives regular information on EnQuest's performance in these areas, and specifically monitors health and safety and environmental reporting at each Board meeting. EnQuest's 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.

Culture is an area of increased focus given the impacts of the current oil price environment and the growth in operations, as both the Alma/Galia and Kraken projects add scale to EnQuest's business. Furthermore, EnQuest is now working to complete its acquisition of operating interests in the Magnus field and the Sullum Voe Terminal, transitioning to take over operatorship and absorbing significant additional numbers of personnel into the business. It is therefore important to set the right tone and to foster among the workforce high morale, common values and a focus on efficient and ethical achievement. Furthermore, EnQuest took considerable care to ensure that the processes adopted during a rationalisation of the workforce in Aberdeen were, and were seen to be, fair and understanding.

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 will depend on the earnings and financial condition of the Company and on such other factors as the Board of Directors of the Company considers appropriate at the time.

A return to sustainable growth
In January 2017, with a view to continuing to build its growth options, EnQuest announced the acquisition of interests in the Magnus oil field and the Sullom Voe Terminal ('SVT'), for both of which EnQuest is set to become operator, subject to the necessary approvals.  The acquisition has an innovative structure, recognising EnQuest's current balance sheet constraints.  The vendor, BP, endorsed EnQuest's capabilities, highlighting that EnQuest is a natural operator of mature assets in the North Sea, well placed to improve production and to prolong the life of such assets in the UKCS. 

With Magnus and SVT being added to the portfolio and with the 2016 restructuring implemented, EnQuest is positioned with the right assets and the right team for the next phase of its growth.  EnQuest has the high efficiency and low cost capabilities required for this environment; it has restructured its operations and its ways of doing business such that even modest increases in oil prices can have a significant positive impact on future cash flows and growth. 

In 2017, EnQuest's top operational priority is safely bringing the Kraken development onstream on schedule.  As EnQuest begins to move beyond an extended period of heavy capital investment, its strategic priorities continue to be to increase production by delivering on operational and development execution, whilst also continuing to reduce the operating cost base.  This combination of financial and operational discipline will result in increasing cash flows and in the deleveraging of the balance sheet, which continue to be the high priorities in the near term.

CHIEF EXECUTIVE'S REPORT

EnQuest's performance, business model and strategy in 2016
2016 was another challenging year for EnQuest, with continuing pressure from the oil price environment.  Accordingly, EnQuest has delivered further reductions in operating and capital expenditure and continued to streamline operations. EnQuest's low cost operating structure and low cost approach to operatorship are integral to its way of doing business, whilst always retaining safe operations as the number one priority.  It was a year characterised by both operational and financial achievements, with the successful financial restructuring being essential for the strength of the balance sheet.
 

The average production of 39,751 Boepd in 2016 included good performances at Heather/Broom and at PM8/Seligi, and a promising start from Scolty/Crathes, following early delivery of first oil.  A first full year of production from Alma/Galia increased UKCS production over the prior year, despite productivity from Alma/Galia being negatively impacted by well performance. Overall production was also affected by extended shutdowns. The Kraken development finished 2016 under budget and on course for first oil in Q2 2017, with the drilling programme ahead of schedule.

To help protect its capital investment programme, EnQuest had entered into a substantial hedging programme for 2016; this contributed $255.8 million to EBITDA of $477.1 million in 2016.  Cost control and efficient management of operations drove further material cost reductions; average 2016 full year unit opex was $24.6/bbl, compared to $29.7/bbl in 2015 and $42.1/bbl in 2014.  2016 cash capex was $609.2 million, down 19% on 2015; this final 2016 capex total was well down on the original estimate of between $700 million and $750 million, reflecting ongoing reduction initiatives throughout the year, including deferral of payments for Kraken and Scolty/Crathes.  

Even though EnQuest had been successful in making significant reductions to its cost base, the Company also needed to restructure its financial position.  In October 2016, EnQuest announced proposed amendments to the revolving credit facility and to both the retail notes and the high yield notes, as well as a placing and open offer. In November 2016, EnQuest successfully completed the restructuring.  This provided EnQuest with a stable and sustainable capital structure, reduced cash debt service obligations and enhanced liquidity. The revolving credit facility was restructured into a $1,125 million term loan facility and a $75 million revolving credit facility.  The terms of the high yield bonds and retail bonds were amended, with extended maturities and interest to be paid in kind rather than in cash when oil prices are below $65/bbl in the six month period prior to determination.  The placing and open offer also raised gross aggregate proceeds of £82 million.  The restructuring was key for EnQuest and significantly improved its liquidity position.  EnQuest finished the year with net debt of $1,796.5 million, as at 31 December 2016.

End 2016 net 2P reserves of 215 MMboe represented a 6% increase on the 203 MMboe at the end of 2015. This reflected the impact of EnQuest producing 13 MMboe of hydrocarbons in 2016 and the acquisition of an additional 10.5% interest in the Kraken development from First Oil at the start of 2016.  There were also upward revisions to reserve estimates at the Thistle and Heather hubs, both due to improved predicted performance of infill wells based on reservoir simulation model outputs and decreases at Alma/Galia due to the levels of well performance.  By the end of 2016, EnQuest had therefore converted into flowing barrels the equivalent 84% of the 81 MMboe of reserves with which it began its business with in 2010.

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

EnQuest maintained its commitment to the delivery of continual improvement in HSE&A performance in 2016, with excellent results in many areas, but with some areas requiring fresh actions to be undertaken.

EnQuest's Lost Time Injury ('LTI') performance remained strong: the Kittiwake, Northern Producer and EnQuest Producer assets in the North Sea all recorded an LTI free year. EnQuest's Malaysian operations recorded zero LTIs and were pleased to achieve a Total Recordable Incident Frequency ('TRIF') for the year which was better than targeted.

In the UK, a comprehensive HSE&A audit programme was completed, with findings being part of the 2017 continual improvement programme. This underlines EnQuest's focus on improvement through the detection and resolution of issues.

EnQuest's focus on HSE&A continues to be a priority.

North Sea

In 2016, EnQuest produced an average of 30,603 Boepd in the North Sea, an 11.3% increase on the previous year and a generally good performance with high levels of production efficiency.  2016 production benefitted from the drilling programme in H2 2015 and from the new Scolty/Crathes development, brought onstream ahead of schedule and under budget.  Production was negatively impacted by third party shutdowns for maintenance, which were delayed and took longer than anticipated, also by the well performance issues at Alma/Galia, and reliability issues with its electrical submersible pumps ('ESP's).   EnQuest monitors its projects to ensure that lessons learned from past projects, such as Alma/Galia, are used as inputs to the structuring of new ones; hence at sanction, most of the Kraken development was structured using lump-sum fixed price contracts, with remuneration for the vessel provider being determined by delivery and functionality key performance indicators.

Heather/Broom performance was one of the highlights of the year, with production of 5,948 Boepd, up 28.1% on the prior year.  This was due to increased plant and water injection reliability and the continuing benefits of the 2015 wells workover programme.  Driven partly by this increased production, but also by the ongoing cost reduction programme, Heather/Broom significantly reduced its unit operating costs.   

Kraken

In 2016, the Kraken development progressed well, finishing the year ahead of budget and on schedule for first oil in Q2 2017. The conversion programme for the Kraken FPSO vessel continued and on 23 November, the FPSO left Singapore, en route to the North Sea.  Drilling for the project was ahead of schedule on drill centres 2 and 3 ('DC-2' and 'DC-3'), following completion of well activities at drill centre 1 ('DC-1').

Earlier in the year, the subsea installation programme was completed, with all three drill centres fully connected to the submerged turret production ('STP') buoy for hook up to the FPSO and the last mooring pile and wire/chains installed.

The drilling programme made excellent progress in 2016, with the results from the producer and injector wells which were drilled and completed meeting pre-drill expectations. This good progress on drilling and also on the execution of the subsea programme were key factors in the $375 million of additional Kraken gross project capex savings announced in 2016, reducing gross capex to c.$2.5 billion. 

Malaysia
Total production of 9,148 Boepd in Malaysia was slightly ahead of the prior year.  Production of 7,960 Boepd from PM8/Seligi was slightly lower than the prior year's 8,689 Boepd, as a result of additional maintenance shutdown days in 2016, as well as reduced volumes of gas and condensate, which are ad hoc in their nature.  Adjusting for these, underlying production at PM8/Seligi increased year on year, a substantial achievement for a mature field with wells which have natural decline rates.  Especially in a year with no drilling, this is a testament to the success of the programme of well intervention and topsides work and high levels of production efficiency. 

Financial performance KPIs

In 2016, EnQuest generated EBITDA of $477.1 million compared with $474.2 million in 2015; the negative impact of lower oil prices, being mitigated by hedging income of $255.8 million and also by the significant action taken on costs.

Cost reduction measures led to EnQuest's average unit production and transportation cost being reduced again, down to $24.6/bbl  compared to $29.7/bbl in 2015.

As at 31 December 2016, EnQuest had total net debt of $1,796.5million.

2017 year to date

The Kraken FPSO arrived in the North Sea in early January, having completed its journey from Singapore within the scheduled number of days.  The vessel was berthed in Rotterdam for post voyage inspection and final preparations prior to sailing. The FPSO then sailed to the Kraken field once good weather conditions were anticipated for the hook up of the STP buoy mooring system to the FPSO.  This was completed and a full rotation test performed so that by mid-February the vessel was on station and securely moored.  Work is continuing in the turret area, as is topsides commissioning work.  Following completion of the turret area work subsea commissioning will commence.  Handover of FPSO systems from commissioning to operations continues.

In January 2017, EnQuest was pleased to announce an agreement to acquire from BP an initial 25% interest in the Magnus oil field representing c.16 MMboe of additional net 2P reserves (gross reserves of 63 MMboe) with net production of c.4,200 Boepd in 2016 (gross production c.16,600 Boepd) as well as a 3.0% interest in the Sullom Voe oil terminal and supply facility ('SVT') and additional interests in related North Sea pipeline infrastructure.  EnQuest already had interests of 3.0% in SVT.  EnQuest is to become the operator of these assets.  The transaction is subject to certain regulatory, government authority, counterparty and partner consents. The consideration for these interests is $85 million, subject to working capital and other adjustments, which will be funded by deferred consideration payable from the cash flow of the assets being acquired. There are no requirements for cash from EnQuest, other than as generated from these assets.

The transaction capitalises on EnQuest's strengths in realising value from the management of maturing oil fields, as underlined by BP's confidence in proposing a change of operatorship to EnQuest.  Magnus is a good quality reservoir; it has large volumes in place, with potential for infill drilling and for the revitalisation of wells, and scope for field life extension. Magnus is a producing asset that will materially increase EnQuest's reserve base.  There is long term  potential in Magnus and there would be a significant increase in cash flow at higher oil prices.  Operationally and financially SVT is an important asset to EnQuest and taking over operatorship gives significant influence over its long term future.  EnQuest is a natural strategic partner to BP for maturing assets and this innovative structure represents a natural evolution of EnQuest's business.  EnQuest believes the innovative transaction net cash flow sharing structure can also become a template for transferring maturing assets from other majors to efficient operators such as EnQuest.  Since this proposed acquisition was announced, the process of transitioning operatorship of these assets and securing the necessary regulatory, government, counterparty and partner consents has begun and continues.

2017 and beyond

In the continuing challenging oil price environment and building upon its successes in 2016, EnQuest is focused on its differential capabilities, low cost approach to operatorship, and financial discipline.  The agreement with BP to acquire interests in, and operatorship of, Magnus and SVT is confirmation of the effectiveness of EnQuest's capabilities and its potential to add value for both EnQuest and for other business partners.   

The Kraken project remains under budget and on track for delivery of first oil in Q2 2017.
 

EnQuest remains on course to achieve average production in the range of 45,000 Boepd to 51,000 Boepd for 2017.   This is based on six operated producing hubs in the UK and the PM8/Seligi hub in Malaysia, with the level of 2017 production being dependent upon the timing of first oil from Kraken. A full year contribution from Kraken in 2018 should substantially increase production again that year. 
 

Six million barrels have been hedged for 2017, at an average of c.$51/bbl.
 

EnQuest remains on course to reduce average unit opex further in 2017, in the range of $21/bbl to $25/bbl including Kraken production.  EnQuest continues to seek cost reductions across the supply chain.
 

Cash capital expenditure will reduce in 2017 and is expected to be in the range of $375 million to $425 million, the majority of which is being invested in the Kraken development.

Following delivery of first oil from Kraken, EnQuest looks forward to beginning the process of deleveraging the balance sheet to levels which are sustainable over the longer term.  EnQuest's combination of integrated technical capabilities and high levels of production efficiency and cost control, ideally positions us to realise production potential from the assets we own.

OPERATING REVIEW

THE KRAKEN DEVELOPMENT

Kraken

Working interest at end 2016: 70.5%.* 

Decommissioning liabilities: As per working interest
Floating Production Storage and Offloading unit with subsea wells
 

* With economic effect from 1 January 2016, EnQuest acquired an additional 10.5% interest in the Kraken development, from First Oil plc, bringing EnQuest's total interest to 70.5%.

2016

In 2016, the Kraken development progressed well, finishing the year ahead of budget and on schedule for first oil in Q2 2017.

In October 2016, following mechanical completion, shore based commissioning activities onboard the Kraken Floating Production, Storage and Offloading vessel ('FPSO') were completed at the quayside in Singapore. The vessel was then moved to deep water anchorage to undertake further commissioning work, following which, on 23 November, the FPSO sailed away en route to the North Sea.  By this stage, drilling for the project was progressing to plan on drill centres 2 and 3 ('DC-2' and 'DC-3'), following completion of well activities at drill centre 1 ('DC-1').

Earlier in the year, the subsea installation programme had been completed, with all three drill centres fully connected to the submerged turret production ('STP') buoy for hook up to the FPSO and the last mooring pile and wire/chains installed.

The drilling programme made excellent progress in 2016 and this efficient execution was a key factor in the project capital expenditure reductions announced. The results from the producer and injector wells drilled and completed met  pre-drill expectations. At year end, four producers and five water injectors had been completed since drilling commenced on the project.

2017 and beyond 

The Kraken FPSO arrived in the North Sea in early January, having completed its journey from Singapore within the scheduled number of days.  The vessel was berthed in Rotterdam for post voyage inspection and final preparations prior to sailing.  The FPSO then sailed to the Kraken field once good weather conditions were anticipated for the hook up of the STP buoy mooring system to the FPSO.  This was completed and a full rotation test performed so that by mid-February the vessel was on station and securely moored.  The risers and umbilicals have now been successfully pulled in.  Work is continuing in the turret area, as is topsides commissioning work.  Following completion of the turret area work, subsea commissioning will commence.  Handover of FPSO systems from commissioning to operations continues.

All drilling is now complete on DC-1 and DC-2 and the rig next moves to DC-3. At start up 13 wells will be available comprising 7 producers and 6 injectors. As with all developments of this scale, wells will be brought onstream in a phased manner in line with good reservoir management practices. Drilling performance to date has significantly de-risked delivery of the project to and beyond first oil.  

The project continues to be under budget and on schedule for first oil in Q2 2017.

NORTH SEA OPERATIONS

In the North Sea in 2016, EnQuest focused on streamlining operations, delivering on execution and on strengthening the balance sheet.  It was an intensely busy year and the team has much to be proud of.  Successes included continued excellent drilling performance and high aggregate production efficiency.  EnQuest portfolio in the North Sea is assessed to again have exceeded the Oil and Gas Authority's stated target of 80% production efficiency.

The strength of the drilling performance helped EnQuest to deliver first oil from Scolty/Crathes ahead of schedule and under budget and facilitated the inclusion in the programme of the successful drilling of the Eagle discovery. 

Scolty/Crathes represented a particular achievement; this was the only offshore pure oil Field Development Plan ('FDP') approved in the UK North Sea in 2015 and first oil was achieved approximately a year after the FDP was approved and the project was sanctioned.  With the support of EnQuest's partner, the collaboration of our own team with our contractors and sub-contractors, the timely delivery of this 'small pools' project was enabled through cost efficiency and the application of technology, sustaining the wider Greater Kittiwake Area ('GKA') and infrastructure.  It is an excellent example of Maximising Economic Recovery ('MER') in practice.

With unit capital costs under $20/bbl, Scolty/Crathes also demonstrates in practice the capital discipline that is essential at this stage in EnQuest's evolution, focused on a limited capital expenditure programme and on cash flow generating activities.

EnQuest reached its highest level of production in 2016, but below initial targets.  Production was affected by longer  than forecast third party shutdowns and also by disappointing productivity from Alma/Galia.  

The cost reduction programme to streamline operations continued in 2016, helping to drive Group unit opex to the mid $20s per barrel, down almost 50% on the levels of early 2014.  This was delivered by many initiatives and innovations across the operations and supply chain, including further reductions in service unit rates, supplier forums, open book contracts, and additional incentivised contract structures linking payment to performance.  Payment compliance audits were used to ensure that contract terms were rigidly and correctly enforced.  Centralising the procurement team has taken advantage of lower global costs.

In 2016 in the UK, an HSE&A audit programme was completed, with findings being part of the 2017 continual improvement programme. This underlines EnQuest's focus on improvement through the detection and resolution of HSE&A issues.

Magnus and Sullom Voe
In January 2017, EnQuest was delighted to announce the proposed acquisition of interests in the Magnus oil field in the northern North Sea and in the Sullom Voe Terminal ('SVT') on Shetland, from BP.

Magnus has well understood reservoirs with significant high quality subsurface data including 4D seismic. EnQuest sees upside potential in Magnus' resource base and has the necessary skills to realise the latent value therein. There are currently three mature drilling targets with the potential to be onstream in 2018. Two of these wells will expand the existing Water Alternating Gas ('WAG') scheme. Beyond this, there are significant further opportunities, including further expansion of WAG, which EnQuest expects to be realised in the future. EnQuest's proven ability to reliably drill low cost wells will be instrumental in commercialising Magnus' remaining resource potential.

EnQuest materially reduced its unit operating costs between 2014 and 2016, whilst also delivering high levels of operating efficiency.   EnQuest anticipates being able to apply the same approach to Magnus, significantly reducing unit operating costs and increasing operating efficiency.  EnQuest also expects economies of scale from combining with its existing operations, including savings in logistics, contracts and overhead, creating further efficiencies across EnQuest's 'Northern North Sea' portfolio.

Building on the work that BP as operator and EnQuest and other owners have done in recent years, EnQuest expects to be able to improve efficiency and costs and extend the life of the Sullom Voe oil terminal.  In so doing, this will extend the lives of EnQuest's Northern North Sea oil fields.  Such operating improvements will have a wider effect and benefit adjacent fields and infrastructure, helping to rejuvenate northern North Sea operations generally. This would also be a further demonstration of EnQuest's commitment to the region and of its capabilities.

Thistle/Deveron

Working interest at end 2016: 99%
Decommissioning liabilities: Original liabilities remain with former owner*
Fixed steel platform
Daily average net production:
2016: 7,533 Boepd
2015: 8,930 Boepd
* Under the terms of EnQuest's proposed acquisition of interest in the Magnus oil field and the Sullom Voe Terminal, EnQuest has an option to receive $50 million in cash in exchange for undertaking the management of the physical decommissioning for Thistle and Deveron and making payments by reference to 6% of the gross decommissioning costs of the Thistle and Deveron fields. 

2016

Across 2016, average production from Thistle/Deveron was 7,533 Boepd. 

2016 reflected the benefit of the 2015 drilling programme; the planned Southern Fault Block P2 sidetrack was however halted at the start of the year due to slot recovery issues.  In Q1 2016, one of the Thistle power generation turbines was overhauled and other maintenance and integrity projects continued throughout the year.  Further production enhancing field life extension work was scheduled for the middle of 2016, during a Thistle production shutdown planned to coincide with a third party shutdown of the Brent Pipeline System ('BPS').  However, the BPS shutdown was delayed to the end of the year, thereby delaying Thistle production enhancements. The BPS shutdown itself proved to be considerably longer than expected, resulting directly in four weeks of lost production. Bad weather in late December then also affected production start up by a further week. In December, Thistle started and successfully commissioned new process plant and associated controls. Water injection remained offline during this period to support essential electrical maintenance and to address flexible flowline integrity. 

2017 and beyond

On both Thistle and Heather there is a programme to abandon redundant well stock, co-funded by EnQuest's partners. This will both reduce risk and present opportunities in the future to drill further infill wells when circumstances allow.  The related Thistle programme of partial well abandonments will continue throughout 2017, starting with the abandonment of well A05/25, which commenced in January 2017. The phased approach to decommissioning utilises EnQuest's ability to execute low cost well work for the benefit of all Thistle stakeholders and is an important new component of Thistle's life extension strategy.   

The BPS operator is planning a further shutdown in 2017, currently expected to result in a Thistle shutdown in Q3.

The Don fields

Working interest at end 2016:
- Don Southwest 60%
- Conrie 60%
- West Don 78.6% *
- Ythan 60%
Decommissioning liabilities: As per working interests
Floating production unit with subsea wells
Daily average net production:
2016: 5,404 Boepd
2015: 7,690 Boepd

* Following the default of First Oil plc in Febuary 2016, a process was initiated which resulted in the transfer to EnQuest of 15.15% of First Oil's working interest in the West Don field. The transfer was completed on 2 August 2016, increasing EnQuest's stake from its previous 63.45%.

2016

Across 2016, average production from the Don fields was 5,404 Boepd. 

2016 reservoir performance for the Don wells was above expectations, particularly with the benefit of the Ythan production well, drilled last year.  However, the delay and extension of the third party BPS shutdown also affected the Don fields, with planned Dons production enhancement projects considerably delayed and with an extended 32 day Dons shutdown at the end of H2 2016.  The 2016 Dons work programme included chemical treatment programmes and routine maintenance throughout the year.  The start of gas import benefitted production in the first half of the year, increasing plant efficiency and reducing production costs.  A water injection line failure on Don Southwest reduced production with a temporary repair being successfully completed in November. 

2017 and beyond

The planned BPS shutdown will impact the Dons similarly to Thistle, with a Don fields shutdown expected in Q3.

Heather/Broom

Working interest at end 2016:
 - Heather 100%
 - Broom 63%
Decommissioning liabilities:
- Heather 37.5%
- Broom 63%
Fixed steel platform
Daily average net production:
2016: 5,948 Boepd
2015: 4,643 Boepd

2016

Across 2016, average production from Heather/Broom was 5,948 Boepd.

The strong production performance resulted from a combination of work to increase water injection reliability and increased injectivity from the wells drilled and worked over in 2015. The Heather Alpha platform also had outstanding reliability with no unplanned outages.  Maintenance and integrity projects continued as normal.

2017 and beyond

Following on from the Thistle well programme, the drill crew will move to Heather in the second half of 2017 to start a similar programme of well decommissioning. Removing legacy wells will safeguard current sustained high water  injection efficiency.  EnQuest is pleased to have gained decommissioning partner funding for this important life extension work.

A Heather hub shutdown for routine inspection and maintenance is expected Q3 2017.

Greater Kittiwake Area ('GKA')

At end 2016, working interest 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
Daily average net production:
2016: 2,988 Boepd
2015: 3,981 Boepd

2016

Across 2016, average production from GKA was 2,988 Boepd.

Production at the start of the year benefitted from continuing improvements in production efficiency, strong

performance of the recently sidetracked Gadwall well, and from chemical treatments on Goosander conducted in 2015. The work programme at the start of the year focused on operational upgrades and on offshore construction on the Kittiwake platform in readiness for the tie-back of the Scolty/Crathes fields. H2 2016 included the planned three week shutdown, which included preparation for Scolty/Crathes delivering production on 21 November. GKA encountered gas compressor issues which resulted in Grouse being shut in for part of H2 2016, before being brought back online after the compressor was reinstated.  In Q2 2016, EnQuest undertook the drilling of the nearby Eagle exploration well, which was confirmed as a discovery. 

2017 and beyond

The work programme in GKA for 2017 will be focused on optimising production across the assets and concluding the minimal scope of work remaining from the Scolty/Crathes project: the replacement of the associated gas compressor ('A-Gas').  Grouse would also be offline during the gas system shutdown. No drilling is planned on GKA in 2017. Evaluation of the potential from the Eagle discovery is ongoing.

A chemical treatment (scale squeeze) is planned in the summer of 2017 for the Mallard well to coincide with the

planned three week GKA shutdown in Q3 2017.

Scolty/Crathes

At end 2016, working interest 50% in each of:
- Scolty
- Crathes
Decommissioning liabilities: As per working interests
Tied back to the Kittiwake platform
Daily average net production:
2016: 719 Boepd
Data is based on the net production since first oil from Scolty/Crathes on 21 November 2016, as averaged over the full year.

2016

In 2016, the Scolty/Crathes development progressed ahead of schedule and under budget, with excellent drilling performance on both wells.   On 21 November 2016, EnQuest delivered first oil from Scolty/Crathes, which had previously been anticipated by the end of H1 2017.  Early production has been consistent with pre-drill modelling and field development plan assumptions; average production in 2016 from 21 November to 31 December was 6,422 Boepd.

2017 and beyond

The 2017 programme for Scolty and Crathes will be focused on optimising production across the two fields, as part of this process the Scolty well is currently shut in. Production will be affected by the same outages as are planned for GKA in 2017.

Alma/Galia

Working interest at end 2016:
- 65% in both fields
Decommissioning liabilities: As per working interest
Floating, Production Storage and Offloading unit ('FPSO') with subsea wells
Daily average net production
2016:  6,740 Boepd
2015: 1,083 Boepd^*
* Net production since first oil on 27 October 2015, averaged over the twelve months to the end of December 2015

2016

Across 2016, average production from Alma/Galia was 6,740 Boepd, following delivery of first oil in October 2015.

By Q2 2016, six production wells were onstream. After analysis of the initial results, a production performance enhancment work programme was established.  The K2 (AP5) well cleaned up naturally after a number of weeks of production resulting in significantly better performance.  K1 (AP4) required a chemical treatment which was successful and the workover of the K3Z (AP1) well further increased production.  Well K6 was not completed due to mechanical issues and was replaced by well K7 (AP6) which came onstream late in Q4. K7 (AP6) overall productivity has been broadly as anticipated.

Productivity from Alma/Galia has been negatively impacted by well performance including ESP reliability. In October 2016, the EnQuest Producer was brought onto permanent power with the boiler and steam turbines online.

2017 and beyond
In 2017, the final phase of the power optimisation and the produced and sea water injection optimisation projects will be completed on the EnQuest Producer.  Discussions are ongoing with the ESP supplier, on rectification plans to address the pump reliability issues.  An unscheduled shutdown took place in January/February as a result of damage from severe winter storms; Alma/Galia performed well after being brought back onstream. A two week maintenance shutdown is scheduled for Q2 2017.

Alba (non-operated) The Alba oil field is operated by Chevron. 

Working interest at end of 2016: 8%
Decommissioning liabilities: As per working interest
Fixed steel platform
Daily average net production:
2016: 1,271  Boepd
2015: 1,178  Boepd

2016

Across 2016, average production from Alba was 1,271 Boepd.

 
2017 and beyond

A maintenance shutdown is planned in Q3.

Proposed acquisition of interests in the Magnus oil field and in the Sullom Voe Terminal.

On 24 January 2017, EnQuest PLC announced an agreement to acquire from BP an initial 25% interest in the Magnus oil field representing c.16 MMboe of additional net 2P reserves (gross reserves of 63  MMboe) with net production of c.4,200 Boepd in 2016 (gross production c.16,600 Boepd) as well as a 3.0% interest in the Sullom Voe oil terminal and supply facility ('SVT'), 9.0% of Northern Leg Gas Pipeline ('NLGP'), and 3.8% of Ninian Pipeline System ('NPS').  Prior to this transaction, EnQuest had existing interests of 3.0% in SVT, 5.9% in NLGP and 2.7% in NPS. 

EnQuest is to become the operator of these assets and the transaction is subject to certain regulatory, government authority, counterparty and partner consents.  The transition for the change in operatorship is anticipated to take between 6 and 12 months from the date of the announcement.

Magnus
Magnus is a maturing asset with significant remaining potential.

Facilities

The Magnus platform is located in Block 211/12A and is the most northerly installation in the UKCS, its closest neighbours are Northern Producer (c.12 miles) and Thistle (c.19 miles).  Magnus started operations in 1983. It has integrated production/drilling/accommodation facilities.  Since 2010, its levels of operating efficiency have been low (30%-70%).   
 

Reservoir and wells

The majority of hydrocarbons in place sit within the high quality Upper Jurassic turbidite Magnus Sandstone Member ('MSM'). Significant other resources sit in the Lower Kimmeridge Clay Formation ('LKCF'). Overall the Magnus field  has 2.0 billion boe hydrocarbons initially in place ('HCIIP'), with an 54% Recovery Factor ('RF'). Over 100 well penetrations have been drilled in over 30 years, there are 28 platform slots and five subsea wells. It has 14 active gas-lifted producers and 10 injectors. Water Alternating Gas('WAG') enhanced oil recovery ('EOR') started in 2002 within the MSM. It has been monitored using 4D seismic surveys, the most recent of which was in 2013.

Sullom Voe Terminal ('SVT')
A strategic infrastructure hub. 

SVT was commissioned in 1978 and receives East of Shetland ('EoS') oil via two pipelines: the Brent Pipeline System ('BPS') which services Brent, Thistle, Northern Producer, Alwyn and TENCCA; and the Ninian Pipeline System ('NPS') which services Ninian, Magnus and Heather.  EoS oil is stabilised, stored and offloaded to tankers. The peak EoS processing rate was 1.5 million bpd in 1985; the current rate is c.130,000 bpd.
 

Since 1998, the terminal has also provided services to West of Shetland ('WoS') fields.  Schiehallion crude was tankered to SVT and  used tanks and jetties.  An additional oil pipeline from Clair was commissioned in 2005. Clair oil does not require stabilisation, but uses tanks and jetties.  Gas from Foinaven, Schiehallion and Clair is 'sweetened' at SVT before being shipped to Magnus, for EOR and onward export.   The terminal has recently started to process condensate from Total's Laggan-Tormore development.   

MALAYSIAN OPERATIONS

PM8/Seligi

Working interest at end 2016: 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
Daily average net production:
2016:  7,960 Boepd (working interest): 5,594 Boepd (entitlement)
2015:  8,689 Boepd (working interest): 5,958 Boepd (entitlement)

2016

Across 2016, average production from PM8/Seligi was 7,960 Boepd.

Overall 2016 field performance was strong. Average annual production volumes were reduced by 21 days of maintenance shutdowns, compared to 3.5 shutdown days in 2015, and by lower gas sales, (325 Boepd), due to lower demand.  

A total of 17 idle well strings were re-activated during 2016, adding an additional c.5,000 Boepd of gross production. This included two add-perforation jobs in November which added over c.1,000 Boepd of gross production. As a result of the successful idle well activation programme and improvements to plant stability at Seligi-A platform, the field achieved very strong levels of oil production. 

2017 and beyond

EnQuest will continue to enhance production by investing in low cost well interventions and facility projects to improve production efficiency, including gas compression control system upgrades to improve reliability. In addition, robust maintenance and integrity inspection campaigns of platform structures, topsides, and subsea pipelines will continue to ensure safe operations. This includes a planned annual maintenance shutdown in Q3 2017.

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. During 2017, the first new drilling projects will be defined for execution in 2018, and significant progress will be made on rebuilding of static and dynamic reservoir simulation models in support of longer term field redevelopment.

Tanjong Baram

Working interest at end 2016: 70%
Decommissioning liabilities: None
Daily average net production:
2016:  1,188 Boepd (working interest): 832 Boepd (entitlement)
2015:  373 Boepd (working interest): 261 Boepd (entitlement)
2015 data reflects net production from first production in June 2015 averaged over the 12 months to end December 2015.
 

2016

Across 2016, average production from Tanjong Baram was 1,188 Boepd.

Tanjong Baram operational efficiency and uptime remained high throughout the year.

2017 and beyond

Focus remains on steady, safe and low cost operations in 2017. In addition, three options aimed at reviving well A1 are under technical review; the review will be completed in H1 2017.

RISKS AND UNCERTAINTIES

Management of risks and uncertainties

The Board has articulated EnQuest's strategy to deliver value by targeting maturing assets and underdeveloped oil fields. EnQuest has prioritised its strategic focus to deliver on execution targets, streamline operations and strengthen its balance sheet. As EnQuest moves from a period of heavy investment to one focused on realising value from existing resources and capabilities, it will strictly maintain financial discipline and focus on driving cash flow. 

In pursuit of this 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 overarching statement of risk appetite approved by the Board:

·      We aim to deliver consistently above median investment performance

·      We will manage the investment portfolio against agreed key performance indicators consistent with the strategic objectives of enhancing net revenues and strengthening the balance sheet

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

·      We seek to embed a risk culture within our organisation corresponding to the appetite for risk 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

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

We seek to balance our risk position between investing in activities that may drive growth and the continuing need to remain a financially disciplined and low-cost, cash flow generating operator as the Group reduces its debt and appropriate market opportunities present themselves. In this regard the Board has commenced a process to develop certain specific principles to guide the Company during the current phase of its evolution which tie together the Company's thinking on strategy and risk. Broadly, these would reflect a focus by the Company on:

·      Adding value to assets which are already in production and within geographical parameters

·      Adhering to specific disciplines in capital allocation decisions and management of capital structure

·      Management of portfolio concentration risks

·      Ensuring target setting for personnel aligns appropriately with the Company's strategy and risk appetite

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 its members. 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, upon the advice of the Audit Committee, has reviewed the Group's system of risk management and internal control for the period from 1 January 2016 to the date of this report, and is satisfied that they are 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 financial restructuring (and consequent strategic focus on deleveraging 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 (together with an estimate of the potential impact and likelihood of occurrence after the mitigation actions and 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 (see "Oil Price" risk) and any material delay to achieving first oil and/or materially lower than expected production performance at the Kraken field (see "Project execution" and "Production" risks).

FINANCIAL REVIEW

Financial Overview

Following the significant decline in oil prices from late 2014, EnQuest has focused on delivering on execution targets, streamlining operations and strengthening the balance sheet. During 2016, the Company delivered its highest annual production since the Company started in 2010, brought the Scolty/Crathes development to first oil ahead of schedule and under budget, reduced its operating costs further and completed a comprehensive financial restructuring. This restructuring, which included amendments to the credit facility and bonds, as well as a placing and open offer, puts EnQuest in a stronger position to deliver the Kraken development in Q2 2017 and ensures that the Company is well placed to deliver value to shareholders in the medium term.

Production, on a working interest basis, increased by 9% to 39,751 Boepd, compared to 36,567 in 2015. This reflects a full year of production from Alma/Galia and Tanjong Baram, initial production from Scolty/Crathes, increased production from Heather/Broom, partially offset by the impact of longer shutdowns at other fields, mainly due to maintenance on third party infrastructure.

Reflecting EnQuest's drive to streamline operations, together with the increase in production volumes, unit operating costs reduced by 17% to $24.6 per barrel. 

EBITDA for the year ended 31 December 2016 was $477.1 million, compared with $474.2 million in 2015. Although increased production and lower operating costs have driven a higher EBITDA, this was partially offset by the impact of lower oil prices in 2016. The Group manages its exposure to oil prices by entering into commodity hedging contracts. This hedge portfolio contributed $255.8 million to EBITDA in 2016 (2015: $261.2 million).

Profit after tax, on a business performance basis, was $121.5 million, compared with $127.8 million in 2015. After re-measurements and exceptional items, the Group recorded a net profit of $185.2 million, compared with a loss of $759.5 million in 2015.

Reflecting the ongoing investments EnQuest has made to develop its assets, notably Kraken, EnQuest's net debt has increased from $1.55 billion at the end of 2015 to $1.80 billion at 31 December 2016.

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

As at 31 December 2016, total cash and undrawn facilities totalled $330.9 million.

As a result of the continued capital investment, UK corporate tax losses at the end of the year increased to approximately $2.9 billion. In the current environment, no material corporation tax or supplementary corporation tax is expected to be paid on UK operational activities.  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

Production, on a working interest basis, increased by 9% to 39,751 Boepd, compared to 36,567 in 2015. This included a full year of production from Alma/Galia and Tanjong Baram, contributing 6,740 Boepd and 1,188 Boepd, respectively (2015: 1,083 Boepd and 373 Boepd, respectively). Productivity at Alma/Galia, which achieved first oil in October 2015, has been negatively impacted by well performance this year. Heather/Broom demonstrated strong production performance, contributing 5,948 Boepd (2015: 4,643 Boepd), resulting from increased water injection reliability and the continuing benefits of the 2015 wells workover programme. Scolty/Crathes, which achieved first oil in November 2016, has made a promising start, contributing 719 Boepd to annual production. Production at other fields was adversely affected by longer shutdowns than in 2015, including the impact of maintenance carried out on third party infrastructure taking longer than anticipated. 

On average, oil prices in 2016 were lower than in 2015. The Group's blended average realised price per barrel of oil sold excluding hedging was $44.3 for the year ended 31 December 2016, compared to $50.9 during 2015.  Revenue is predominantly derived from crude oil sales and for the year ended 31 December 2016 crude oil sales totalled $577.8 million compared with $634.3 million in 2015.  The decrease in revenue was due to the lower oil price, offset partially by higher production. Revenue from the sale of condensate and gas was $3.6 million (2015: $1.9 million) and tariffs and other income generated $12.4 million (2015: $9.2 million). 

The Group's commodity hedges and other oil derivatives generated $255.8 million of realised income (2015: $261.2 million).  This includes $31.2 million of non-cash amortisation of option premiums and $2.5 million of hedge accounting gains deferred from 2015 (2015: $111.6 million of non-cash amortisation of option premiums). The Group's average realised oil price after hedging was $63.8 per barrel in 2016 compared with $72.0 per barrel in 2015.

Revenue and other operating income also includes an unrealised loss of $51.5 million recognised within exceptional items in respect of the unrealised mark to market loss on the Group's commodity contracts (2015: unrealised gain of $1.9 million). This relates mainly to swap contracts in place at 31 December 2016 hedging 2017 production, where 6 MMbbls were hedged at an average fixed price of $51 per bbl.

Cost of sales

Cost of sales, on a business performance basis, was as follows:

Business performance cost of sales was $653.5 million for the year ended 31 December 2016 compared with $733.4 million for 2015. Although production has increased year-on-year, operating costs decreased by $23.9 million, reflecting EnQuest's ongoing cost saving initiatives and the benefit of a weaker sterling exchange rate, partially offset by an increase in realised losses on foreign currency derivatives of $25.8 million. On a per barrel basis, the Group's average operating cost per barrel has decreased by 17% to $24.6 per barrel, reflecting the cost reductions and foreign exchange benefits above, together with the impact of 9% higher production.

Cost of sales include realised losses on foreign currency derivatives related to capital expenditure of $47.3 million, reflecting the significant devaluation of sterling against the US dollar since June 2016 (2015: loss of $9.4 million).

The Group's overlift position decreased significantly during the year, primarily reflecting the unwind of the balances that had accrued at 31 December 2015 on Thistle and GKA. The impact of this movement on the change in lifting position recognised in cost of sales was offset by the impact higher oil prices on the valuation of the position at 31 December 2016 compared to 31 December 2015, resulting in an overall $2.8 million expense in 2016 (2015: $28.5 million).

Depletion expense of $240.6 million was $58.3 million lower than the prior year, reflecting the impact of impairments recognised for the year ended 31 December 2015 on the average depletion rate, which decreased from $22.4 per barrel to $16.6 per barrel, partially offset by the impact of increased production.

Other cost of sales, which principally include the supplemental payment due on profit oil in Malaysia, decreased by $9.9 million, reflecting the impact of lower oil prices on the supplemental payment.

General and administrative expenses

General and administrative expenses were $10.9 million during the year ended 31 December 2016, compared with $14.4 million reported in 2015. The decrease reflects the benefit of the devaluation of sterling against the US dollar on UK costs and the recovery of overheads. 

Other income and expenses

Other income of $51.9 million almost entirely comprises net foreign exchange gains, which relate primarily to the revaluation of sterling denominated amounts in the balance sheet following the devaluation of sterling against the US dollar.

Taxation 

The tax credit for the year ended 31 December 2016 of $5.2 million (2015: $129.3 million tax credit), excluding exceptional items, is primarily due to Ring Fence Expenditure Supplement on UK activities and the tax effect on foreign exchange gains.

Finance costs

Finance costs of $122.2 million include $110.5 million of bond and loan interest payable (2015: $80.2 million), $14.1 million unwinding of discount on provisions and liabilities (2015: $22.3 million), $36.5 million relating to the amortisation of premium on options designated as hedges of production (2015: $70.0 million), $5.9 amortisation of arrangement fees for the bank facilities and bonds (2015: $7.3 million) and other financial expenses of $10.5 million (2015: $11.0 million), primarily commitment and letter of credit fees.  The Group capitalised interest of $55.3 million in relation to the interest payable on borrowing costs on its capital development projects, primarily the Kraken development (2015: $14.4 million).

Finance income

Finance income of $1.4 million includes $0.3 million of bank interest receivable and $1.0 million unwinding of the discounts on financial assets (2015: $0.3 million and $0.6 million, respectively).

Exceptional items

Exceptional items resulting in a net profit of $101.0 million before tax have been disclosed separately for the year ended 31 December 2016. These mainly include a net reversal of impairments of $147.9 million following the recovery of oil prices since last year, unrealised losses on commodity and foreign currency derivative contracts of $22.0 million, a $16.2 million loss on disposal of the Avalon asset, a $22.9 million credit arising from the derecognition of an onerous contract provision for the Stena Spey drilling vessel, reflecting the contracted days having been utilised in full, and a $3.4 million credit arising from the derecognition of a provision for contingent consideration in relation to the Eagle prospect, no longer expected to be payable. Exceptional items also include a $38.1 million loss on extinguishment of the Group's credit facility as a result of the debt restructuring completed 21 November 2016, comprising the write-off of unamortised costs at the date of restructuring of $15.0 million, plus the expensing of costs associated with the restructuring of the facility of $23.1 million.

A tax charge of $37.3 million has been presented as exceptional, comprising a tax charge of $56.6 million relating to the tax impact of the above exceptional items and a tax credit of $19.3 million related to the recognition of UK tax losses previously written off, offset by the decrease in the supplementary charge on UK oil and gas production to 10%, with effect from 1 January 2016, and the decrease in Petroleum Revenue Tax (PRT) to 0%, with effect from 1 January 2016.

Earnings per share

The Group's reported basic earnings per share was 22.7 cents for the year ended 31 December 2016 compared with loss per share of 98.0 cents for the year ended 31 December 2015.  The Group's reported diluted earnings per share was 22.1 cents for the year ended 31 December 2016 compared with diluted loss per share of 98.0 cents for the year ended 31 December 2015. 

Cash flow and liquidity

The Group's net cash flow from operating activities for the year ended 31 December 2016 was $379.5 million compared with $244.6 million for the same period last year. In part, this is due to the increased production and lower operating expenditure. Cash generated from operations also includes an inflow of $198.8 million from commodity hedging and outflow of $66.9 million from foreign exchange hedging (2015: inflow of $68.6 million and inflow of $3.2 million, respectively).

Net debt at 31 December 2016 amounted to $1,796.5 million compared with net debt of $1,548.0 million at 31 December 2015. The movement in net debt was as follows:

(1)   Cash capex is stated net of proceeds from disposals of $1.5 million

(2)   Pursuant to the Restructuring, effective 21 November 2016, $27.5 million of accrued, unpaid interest was capitalised and added to the principal of the high yield bond and $0.2 million of accrued, unpaid interest was capitalised to the principal of the credit facility as an amount payable in kind ('PIK Amount') (refer note 19 of the consolidated financial statements).

It is anticipated that the underlying effective tax rate for 2017 will be below the UK statutory tax rate of 40%, excluding one-off exceptional tax items, due to UK tax reliefs and profits charged to tax at a lower rate in Malaysia.  In the current environment and with the investment in the North Sea, the Group does not expect a material cash outflow for UK corporation tax on operational activities. This is due to the benefits from tax deductible first year capital allowances in the UK, available investment allowances and accumulated tax losses which are largely attributable to the Group's capital investment programme to date.

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

A total of $428.8 million was spent during 2016 on the Kraken development, where the subsea installation programme has now been completed and excellent progress was made on the drilling programme. Other significant projects undertaken during the year included the completion of the Scolty/Crathes development, drilling of the K7 (AP6) well and workover of the K3Z (AP1) well at Alma/Galia and drilling the Eagle exploration well.

On 21 November 2016, the Company concluded a comprehensive financial restructuring comprising: amendments to the credit facility, high yield bond and retail bond; renewal of surety bond facilities; and a placing and open offer (the 'Restructuring'). The Restructuring significantly improved EnQuest's liquidity position and included the following measures:

·      the placing and open offer resulted in the issue of, in aggregate, 356,738,114 new ordinary shares at an issue price of 23 pence per share and generated gross cash proceeds of $101.6 million;

·      $176.3 million available for drawdown under the credit facility, as at the restructuring date, with maturity extended to October 2021, the amortisation profile amended and certain financial covenants relaxed; 

·      accrued, unpaid interest on the high yield bond as at the restructuring date of $27.5 million was capitalised and added to the principal amount of the bond; 

·      future interest payments due on the both retail and high yield bonds will only be payable in cash where 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 per barrel; otherwise interest payable is capitalised to principal, repayable at maturity; and

·      option exercisable by the Company to extend the maturity date of the high yield bond and retail bond from April 2022 to April 2023 with a further automatic extension of the maturity date to October 2023 if the credit facility is not fully repaid or refinanced by October 2020.

EnQuest has assessed that the Restructuring has resulted in a substantial modification of the terms of its credit facility.  Accordingly, extinguishment accounting has been applied, resulting in the derecognition of the carrying value of the facility, including unamortised arrangement fees of $15.0 million, and the recognition of a new financial liability for the revised facility at fair value. Costs of $23.1 associated with the renegotiation of the facility have been expensed to the income statement as exceptional finance costs.

The impact of the Restructuring on the high yield bond and retail bond has been assessed as not being substantial, resulting in $5.9 million of costs associated with the renegotiation of the bonds being deducted from the carrying values of the bond liabilities in the balance sheet. These costs, along with previous unamortised arrangement fees, will be amortised to the income statement over the revised term of the bonds.

The Group has remained in compliance with financial covenants under its debt facilities throughout the period and managing ongoing compliance remains a priority.

Balance Sheet

The Group's total asset value has increased by $148.7 million to $3,926.0 million at 31 December 2016 (2015: $3,777.3 million).

Property, plant and equipment

Property, plant and equipment ('PP&E') has increased to $2,963.4 million at 31 December 2016 from $2,436.7 million at 31 December 2015.

The increase of $526.7 million is composed of additions to PP&E of $632.5 million, acquisitions of $40.7 million in respect of additional interests in the Kraken and West Don fields acquired from First Oil, an additional $26 million in respect primarily of the Kraken contingent carry recognised during the year, a decrease of $74.8 million for net changes in estimates for decommissioning, the KUFPEC cost recovery provision and other provisions, offset by depletion and depreciation charges of $245.8 million.  In addition, the recovery of the oil price since last year, together with the positive impact on the Group's North Sea cost base of the weakening of the GBP/USD rate, has led to a net reversal of $147.9 million of impairments booked in the prior year.

Intangible oil and gas assets

Intangible oil and gas assets increased to $50.3 million at 31 December 2016 from $46.5 million at 31 December 2015.  The increase of $3.8 million comprises additions of $18.8 million, disposals of $17.6 million relating to the Avalon discovery, which was sold for $1.5 million, an increase of $3.6 million for change in decommissioning provision and write-offs, impairments and other movements of $2.0 million. Additions mainly relate to the Eagle exploration well, drilled on a 100% working interest basis in the Greater Kittiwake Area. The Eagle well has been confirmed as a discovery and further assessment of the results are underway.

Trade and other receivables

Trade and other receivables have decreased by $149.2 million to $202.7 million at 31 December 2016 compared with $351.9 million at 31 December 2015.  The decrease relates mainly to capital expenditure related prepayments, which are capitalised based on the timing of work performed, a decrease in trade receivables due to the timing of crude oil sales and other working capital movements.

Cash and net debt

The Group had $174.6 million of cash and cash equivalents at 31 December 2016 and $1,796.5 million of net debt (2015: $269.0 million and $1,548.0 million, respectively). Net debt* comprises the following liabilities:

·      $191.3 million principal outstanding on the £155 million retail bond;

·      $677.5 million principal outstanding on the high yield bond, including capitalised interest of $27.5 million pursuant to the Restructuring;

·      $1,037.5 million carrying value of credit facility, comprising amounts drawn down of $1,037.3 and interest of $0.2 million capitalised as an amount payable in kind ('PIK Amount');

·      $40.0 million loan facility drawn down from a trade creditor during the year; and

·      $24.9 million principal outstanding on the Tanjong Baram project finance facility.

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

Provisions

The Group's decommissioning provision decreased by $12.9 million to $493.9 million at 31 December 2016 (2015: $506.8 million).  The movement is explained by additions of $49.8 million for Kraken, Scolty/Crathes and Eagle based on drilling and development carried out during the period, $15.2 million arising from the acquisition of additional interests in the Kraken and West Don fields, reductions of $6.4 million for decommissioning carried out during the year and $82.2 million due to changes in estimates, including the impact of the devaluation of sterling against the US dollar, partially offset by $10.7 million unwinding of discount.

A liability of $26.6 million was provided for at 30 June 2016 following an independent reserves determination to assess the contingent consideration payable for Kraken, with a corresponding addition recorded in PP&E. Following payments made during the second half of the year, $5.5 million remained outstanding at 31 December 2016.

An onerous contract provision of $22.9 million for the Stena Spey drilling vessel was derecognised during the period, as the contracted days were utilised fully.

Income tax

The Group had no UK corporation tax or supplementary corporation tax liability at 31 December 2016, which remains unchanged from 31 December 2015. The income tax asset at 31 December 2016 represents UK corporation tax receivable in relation to non-upstream activities and the income tax payable is in relation to the activity in Malaysia.

Deferred tax

The Group's net deferred tax asset has increased from $79.3 million at 31 December 2015 to $191.7 million at 31 December 2016. This movement includes the re-recognition of deferred tax assets totalling $48.8 million, following the improvement in the forecast profitability of the Group, a reduction in deferred tax assets of $29.5 million due to the reduction in the statutory PRT rate and the reduction in supplementary charge on UK oil and gas production, a reduction in deferred tax liability on realised hedges of $134.1 million and an increase in deferred tax liabilities of $73.8 million due to write back of previously impaired assets. Total UK tax losses carried forward at the year-end amount to approximately $2,893.7 million. 

Trade and other payables

Trade and other payables have decreased to $452.8 million at 31 December 2016, of which $42.6 million are payable after more than one year (2015: $543.5 million, all payable within one year). The decrease mainly reflects the settlement of invoices for capital expenditure at Kraken and Scolty/Crathes, for which payment was previously deferred in accordance with supplier agreements. Remaining deferred amounts at 31 December 2016 of $176.8 million are contractually due for settlement in instalments over 2017 and 2018.

Other financial liabilities

Other current financial liabilities have increased by $35.1 million to $44.3 million.  The increase relates primarily to mark-to-market movements on commodity derivatives hedging 2017 production.

Other non-current financial liabilities of $19.7 million (2015: $7.7 million) relate mainly to waiver fees payable to credit facility lenders and also to 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.

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. 

During 2015 the Group entered into commodity hedging contracts to hedge a portion of its 2016 production against fluctuations in oil prices. This included bought put options over 8 MMbbls with an average strike price of $68 per barrel and oil swap contracts to sell 2 MMbbls at an average fixed price of $67 per barrel. These contracts, to which hedge accounting was applied, matured over the course of 2016 and realised $237.2 million of revenue and operating income. A gain of $2.5 million generated in 2015, which had been deferred in the cash flow hedge reserve at 31 December 2015 to match the timing of the underlying production being hedged, was also recognised as realised revenue and operating income in 2016.

At 31 December 2016, the Group's commodity derivative contracts included swap contracts to sell 6 MMbbls at an average fixed price of $51 per barrel, maturing through 2017. The Group has elected not to apply hedge accounting to these contracts, which had a negative fair value and generated an unrealised mark to market loss of $40.5 million, recognised in revenue and other operating income.

Outside of its core hedge portfolio, during 2016 the Group also entered into call options, swaps contracts and futures, accounted for at fair value through profit or loss, which generated $7.6 million of revenue and other operating income.

Finance costs of $5.4 million have been recognised, representing the movement in the time value of put options which have been designated as effective hedges of production.

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.  The Group has hedged its exposures to Sterling, Norwegian Kroner and the Euro in line with this policy.

For the year ended 31 December 2016, the Group's foreign currency hedging portfolio realised a loss of $66.9 million, recognised within cost of sales, of which $19.6 million related to hedges of operating expenditure and $47.3 million related to hedges of capital expenditure. The loss arose principally in relation to contracts to purchase sterling, which devalued significantly against the dollar from June 2016 onwards. Changes in the fair value of these contracts also resulted in an unrealised credit of $7.8 million to cost of sales.

At 31 December 2016, the Group had foreign exchange forward contracts in place over NOK37.1 million at a fixed rate of NOK7.82/$.  These contracts had a negative net fair value of $0.5 million at 31 December 2016 and expire during the first half of 2017.

In the first half of 2016, the Group entered into a chooser structure covering the first half of 2017. The counterparty can choose to sell £47.5 million to EnQuest at an exchange rate of $1.4:£1.0 or purchase 1,320,000 barrels of oil at $58/bbl. The contract had a negative fair value of $9.3 million at 31 December 2016. Subsequent to year-end, the Group entered into a similar chooser contract covering the second half of 2017 where the counterparty can choose to sell £66.0 million to EnQuest at an exchange rate of $1.2:£1.0 or purchase 1,500,000 barrels of oil at $60 per barrel.

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 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.

On 21 November 2016, EnQuest announced a restructuring which comprised the implementation of the RCF Amendments, the Note Amendments, the renewal of the Surety Bond Facilities and the completion of a Placing and Open Offer (collectively 'the Restructuring').

The completion of the Restructuring provides the Group with a more stable and sustainable capital structure, reduced cash debt service obligations and greater liquidity. These will all contribute to ensuring that the Group is in a stronger position to pursue its strategy of targeting mature and marginal oil assets and its focus on cost efficiency during a prolonged period of low oil prices. In particular, the Restructuring enables the Group to complete the Kraken project. 

Following the significant decline in oil prices from late 2014, management has continued to take action to implement cost saving programmes to reduce planned operational expenditure, general and administrative spend and capital expenditure in 2017 and 2018.

At year end, the Group had available cash and bank facilities of $330.9 million and headroom on its related financial covenants under the RCF Amendments. The Group's forecasts and projections take into account the actions described in the preceding paragraph, and reflect the assumption that the Group's major projects remain on track.

This going concern assessment is prepared on the basis that the Facility providers continue to provide access to funding for the duration of the period under review. The Group's business plan (base case) which underpins this assessment assumes Kraken first oil in Q2 2017 and uses an oil price assumption of $55/bbl throughout 2017, and $60/bbl in the first quarter of 2018 and this has been further stressed tested under a plausible downside case (downside case) as described in the Viability statement. The Directors consider the base case and downside case to be an appropriate basis on which to make their assessment.

The base case and downside case indicate that the Company 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 potential covenant breaches the Directors are confident that such breaches would be avoided or remedied either by either executing other funding options or asset sales (mitigating actions) or obtaining waivers and/or consents from the Facility providers in order to ensure that the Facility remains available. The Directors believe that the mitigating actions would be achievable in the necessary timeframe or, if required, that the waivers and/or consents would be forthcoming.

The Directors therefore continue to adopt the going concern basis in preparing the financial statements.

Viability assessment

The Directors have assessed the viability of the Group over a three-year period to March 2020.  This assessment has taken into account the Group's financial position as at March 2017, the future projections and the 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 announcement. 

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 due to be partly repaid or refinanced.

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 2020. 

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

This also assumes that the Facility providers will continue to provide access to sufficient funding for the duration of the three year period under review.  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 statement being aligned to the current forward curve. The base case reflects significant steps already underway to reduce operating and capital expenditure in light of continuing lower oil prices. The position is consistent with the statement made at the time of the restructuring that if oil prices were to stay at the levels at that time of approximately $50 per barrel or if oil prices were to decline, it is highly likely that the Company would be unable to return any value to its shareholders.

The Directors draw attention to the specific risks and uncertainties 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
To mitigate oil price volatility, the Directors hedged 6 MMbbls of 2017 production at an average price of $51 per barrel.   As further mitigation the Directors, in line with Group policy, will continue to pursue hedging at the appropriate time and price.

·      Project execution

The Group's planned capital expenditure during the three year period covered by the viability assessment principally relates to the remaining expenditure to first oil on the Kraken development (which remains on track) and the future phases of the drilling programme on Kraken.  Much of this expenditure has been contracted under fixed price lump sum contracts, therefore there is limited risk that this capital expenditure could exceed that projected and/or that commissioning of projects, in particular Kraken, could occur later than projected. 

The Directors and management team monitor project progress against key milestones and ensure timely intervention as appropriate. 

·      Access to funding

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 diversified funding structure and, following the Restructuring, it has a committed $1.125 billion Tranche A Term Loan and a further Tranche B $75 million Revolving Credit Facility.  Repayment of the Facility commences in April 2018 with the final repayment due in October 2021. In addition, the maturity dates of the $650 million High Yield Bond and the £155 million Retail Notes have been amended to April 2022, with an option exercisable by the Company (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 RCF is not fully repaid or refinanced by October 2020. A further condition to the payment of interest 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. 

Should there be any potential covenant breaches, the Directors are confident that such breaches would be avoided or remedied by either executing other funding options or asset sales (mitigating actions) or obtaining waivers and/or consents from the Facility providers in order to ensure that the Facility remains available.

The Directors believe that the mitigating actions would be achievable in the necessary timeframe or, if required, that the waivers and/or consents would be forthcoming.

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% reduction in production (excluding Kraken as this is already risked in the base case); and

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

A scenario has been run illustrating the impact of the above risks on the base case.  This plausible downside case indicates the need for mitigating actions to be undertaken for the Group to be viable in the three year period.

In light of this, the Directors are also pursuing a number of mitigations to improve medium term liquidity. These options include but are not limited to:

·      asset sales; and

·      other funding options.

The Directors believe that there are a number of options available to them and that only a small number of the potential assets sales or funding options would need successfully to be executed in order for the Group to remain viable for the three year period.

The Group would also seek to modify or temporarily waive existing covenants and loan amortisation should the need arise. The lenders continue to be supportive as demonstrated by the recent Restructuring.  There is also regular dialogue with lenders to ensure that they remain informed of progress on the key projects and operations and the projections underpinning the liquidity position.

Having reviewed the Group's financial position as at March 2017, the future projections, the principal risks and uncertainties and the mitigating actions, 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 2020 and therefore support this viability statement. 

KEY PERFORMANCE INDICATORS

1    Including revenue of $255.8 million in 2016 associated with EnQuest's oil price hedges (2015: $261.2 million, 2014: $31.7 million).

2    EBITDA is calculated on a business performance basis, and is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion, depreciation,  foreign exchange movements and the realised gains/loss on foreign currency derivatives related to capital expenditure.  EBITDA for prior periods has been restated on a comparable basis by adding back realised gain/(loss) on foreign currency derivatives related to capital expenditure (2015: loss of $9.4 million, 2014: gain of $28.9 million).     

3    Net of proceeds from disposal of $1.5 million (2015: $75.5 million, 2014: $2.2 million).

OIL AND GAS RESERVES AND RESOURCES

At 31 December 2016