Final Results

RNS Number : 1905D

EnQuest PLC

26 March 2014

 



ENQUEST PLC, 26 March 2014.  Results for the year ended 31 December 2013*.
Production up 6%, significant reserves increase of 66 MMboe, and strong cash flow

Highlights

§  Production averaged 24,222 Boepd, up 6.2%, a good performance due to a successful 2013 drilling programme

§  Net 2P reserves of 194.8 MMboe, up 66.2 MMboe, reserves replacement ratio of over 850%

§  Revenue of $961.2 million, EBITDA^** of $621.3 million, reflecting good underlying operational performance

§  $984.3 million of cash capital expenditure was invested for the future growth of the business.

§  Production guidance for the full year 2014 is for an increase to between 25,000 Boepd and 30,000 Boepd, excluding production from uncompleted transactions.

§  Alma/Galia production start-up anticipated in H2 2014

§  Kraken progressing to plan, FPSO vessel is expected to arrive in the conversion yard on schedule in Q2 2014

§  The Cairngorm appraisal well has recently reached its target, with indications of hydrocarbons in a relatively good quality basement reservoir

§  Awarded licence in Don North East Field area in early 2014

* Unless otherwise stated, all figures are before exceptional items and depletion of fair value uplift and are in US dollars.

	2013		2012	Change %
Production (Boepd)		24,222	22,802	6.2
Revenue ($m)		961.2	889.5	8.1
Realised oil price $/bbl		109.7	111.6	(1.7)
Gross profit ($m)		428.9	441.3	(2.8)
Profit before tax & net finance costs ($m)		374.8	405.1	(7.5)
EBITDA ** ($m)		621.3	634.6	(2.1)
Cash generated from operations ($m)		562.7	593.9	(5.3)
Reported basic earnings per share (cents)		24.4	46.2	-
Net (debt)/cash *** ($m)		(381.1)	89.9	-

** EBITDA is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion (adjusted for depletion of fair value uplift), depreciation, impairment, write-off of intangible oil and gas assets and foreign exchange movements.  This foreign exchange adjustment for 2013 is a change to the definition used previously and the prior year EBITDA figure has been restated accordingly.   *** Net (debt)/cash represents cash and cash equivalents less borrowings as at the reported cash flow statement date of 31 December.

EnQuest CEO Amjad Bseisu said:

"EnQuest has delivered another good year of growth in production and a significant increase in reserves, supported by strong cash flow.  Production growth of over 6% represents an excellent operational and reservoir performance from our existing assets, particularly in the second half.

Companies like EnQuest are the future of the UK North Sea.  Having strong and technically focused operations gives us the ability to maximise hydrocarbon recovery.  Our objectives are fully aligned with the goals and the recommendations of the recent Wood Review. Our business model is sustainable and is set to deliver a material increase in cash flow from operations over the coming years."

Summary and 2014 Outlook

2013 was another good year of delivery and progress for EnQuest.  We continue to demonstrate that by targeting maturing assets and undeveloped oil fields, we can create value and deliver sustainable growth. 

In 2014, EnQuest will continue to invest in its current producing assets, bring Alma/Galia onstream, integrate the Greater Kittiwake Area ('GKA') acquisition and make substantial investments in the Kraken development, with Kraken scheduled to come onstream by 2017.  We are therefore on course for having six producing operated hubs in the UK and for achieving our objective of annual net production from the UK North Sea of around 50,000 Boepd.  Beyond that, we are creating further new potential from our UK asset portfolio and making low cost investments in international opportunities, securing EnQuest's growth for the longer term. 

§  Production guidance: Average production guidance for the full year 2014 is an increase to between 25,000 Boepd and 30,000 Boepd, this excludes production from Didon in Tunisia, as the acquisition has not completed.
 

§  Drilling programme: EnQuest plans to deliver over 15 wells in 2014.  The drilling programme includes a new production well on Don Southwest, a workover of a production well on GKA, an ongoing intervention programme on Thistle, three production wells and one injection well on Alma/Galia and the recommencement of drilling on Heather for the first time since 2006, with two sidetracks and two workovers.  Two production wells are also planned for the non-operated Alba.
 

§  Exploration and appraisal: The 2014 exploration and appraisal drilling programme includes wells on Cairngorm, a Kraken satellite and Avalon in the UK.  Internationally, in H2 2014, a non-operated well is being matured for drilling in the Sabah area, offshore Malaysia.

§  Assessment of the results of the Cairngorm appraisal well is underway; preliminary analysis indicates a 173ft hydrocarbon column was encountered, with evidence of good reservoir properties in the fractured granite.  With the results of the previous well and seismic, the overall indications in the structure are now of a total hydrocarbon column of 797ft.  Further evaluation is ongoing.

§  Development opportunities:  Scolty/Crathes: Following the acquisition of the GKA assets and the planned drilling of Avalon, options for a proposed Scolty/Crathes development will be assessed. Don North East: Within the first twelve months of the licence, it is intended to submit a field development plan ('FDP') in relation to Area 24, to include at least one production well.

§  Capital and operating expenditure: In 2014, capital expenditure on current projects is expected to be approximately $1 billion with approximately $400 million being invested in the Kraken development and approximately $200 million in Alma/Galia.  Production and transportation costs for 2014 are expected to be in the range $415 million to $435 million, including c.$60 million for GKA and c.$25 million for Alma/Galia. 

§  Tax: The effective tax rate for 2014 is expected to be approximately 60%, based on current oil prices; with continuing investment in the North Sea no material cash tax is expected to be paid on UK operational activities before 2020.

By Production and Development Asset

Thistle/Deveron

§  In 2014, capital investment is continuing in the Thistle life extension project; ongoing activities include; a control systems upgrade and significant simplification of processes, jacket integrity improvements and topsides structural integrity improvements.

Don fields

§  Production optimising projects continue on the Don fields, with a new production well planned to be drilled in H1 2014 in Don Southwest.  

§  In Q1 2014, EnQuest applied for and was offered an 'out of round' licence ('Don NE') in the Don North East area for blocks 211/18e and 211/19c, including the Area 23 and Area 24 discovered oil accumulations and an undrilled extension to the Don NE field. 

Heather/Broom

§  Following the completion of the rig reactivation project, rig operations commenced in Q1 2014 with a workover of the H56 well, due onstream in H1 2014, to be followed by the sidetrack of H44 as a new injection well in the B2 block. The 2014 programme also includes a sidetrack of H48 and a workover of the crestal E-Block producer H47.

§  The Heather life extension project includes a three year infill drilling campaign; there are nine wells in the initial programme, targeting 12 MMboe reserves which are included in net 2P reserves. 

Alma/Galia

§  Drilling and completion operations continue ahead of production start-up.  The field is set to generate a material increase to EnQuest's net production, with initial net peak production of c.13,000 Boepd. Production start-up is anticipated in H2 2014.

Kraken

§  In Q2 2014 the vessel to be converted to the Kraken FPSO will arrive at the shipyard in Singapore for the conversion scope to commence. Further appraisal drilling will be undertaken on a satellite to the west of the Kraken field in Q3 2014 to assess the upside potential of the field.  Contracts for over 60% of the project have now been signed.

Greater Kittiwake Area

§  Following completion of the acquisition in Q1 2014, EnQuest has taken over as operator, an early workover programme is planned in 2014 and an assessment of exploration opportunities in the area.  EnQuest has a working interest of 50% in GKA, with an overall decommissioning liability of approximately 25%.

Further business development in Q1 2014

Norwegian North Sea

§  In January 2014, EnQuest was offered and accepted two licences in the Norwegian 2013 Awards in Pre-defined Areas ('APA') licensing round, both located in the Norwegian Sea.  EnQuest was offered production licence 758 ('Rosslyng'), with EnQuest as the operator and having a 35% interest.  EnQuest was also offered licence 760 ('Chinook'), with Total as the operator, both Total and EnQuest having a 50% interest each. In both cases, the work commitments in the initial two year period entail 3D seismic licensing and reprocessing.

Review of 2013

Financial

§  Strong levels of cash generation continued, with EBITDA of $621.3 million and cash generated from operations of $562.7 million.  Net debt was $381.1 million at the end of 2013, after cash outflow of $984.3 million on capital expenditure.  Cash generated from operations is slightly lower than the prior year mainly due to costs associated with the new financing facilities put in place in 2013.

§  Tax losses increased to $1,087 million at the end of 2013, reflecting the investment programme.

§  2013 revenue of $961.2 million was 8.1% higher than in 2012, mainly due to the increase in production, partly offset by the decrease in the realised average price per barrel of oil sold.  There was a slight increase in revenue for 2013 due to an overlift of $2.6 million in 2013, compared to an underlift of $24.4 million in 2012.

§  Profit from operations before tax and net finance costs was $374.8 million, a 7.5% decrease over 2012.  This reflects the $84.1 million increase in the cost of sales, partly due to a $27.2 million change in the lifting position and also to an increase in transportation costs.  Production and transportation costs increased due to increased production volumes, including those from the Alba acquisition, but primarily due to an increase in costs per barrel at the Sullom Voe terminal.  Unit production costs of $27.2 per barrel were flat compared to the $27.4 per barrel equivalent costs incurred in 2012. 

§  Profit after tax of $193.1 million was 25.6% lower than 2012 due to a higher effective tax rate as a result of higher tax benefits in 2012.

§  In 2013, $984.3 million of cash capital expenditure was invested for the future growth of the business; $460.5m was invested on the Alma/Galia development and $171.5m on the Kraken development, with approximately $295m invested on the existing producing fields.

§  In 2013, EnQuest put in place a new credit facility for up to $1.7 billion and issued retail bonds totalling £155 million.

Production, Development & Reserves

	Net daily average 2013	Net daily average 2012
	(Boepd)	(Boepd)
Thistle/Deveron	7,925	8,058
The Don Fields	11,014	10,992
Heather/Broom	4,339	3,752
Alba	944*	-
Total	24,222	22,802

*Net production since the completion of the acquisition at the end of March 2013, averaged over all of 2013.

Thistle/Deveron

§  Production at Thistle/Deveron achieved a net 7,925 Boepd in 2013, with a particularly strong performance in the second half of the year, with peak rates over 16,000 Boepd. 

§  In H2 2013, production benefitted from strong performance from a new production well which came onstream at the start of August.  Thistle's new D turbine and fully rebuilt B turbine are resulting in significantly improved power supply stability. Despite a two week scheduled platform shut down for maintenance in October 2013, production in the second half of 2013 was almost double the levels in the first half.   

Don fields

§  Production at the Don fields achieved a net 11,014 Boepd in 2013, ahead of the 10,992 Boepd produced in 2012. 

§  Production benefitted from the West Don W6/W4 producer/injector pair, following the tie in of the W6 injector  well in Q1 2013.  The Don South West Area 6 producer, S12Z, was completed and brought onstream in June 2013, followed by Area 6 injector, S13, in August.  Operational performance highlights in H2 2013 included a record water injection rate of 58,000 bwpd.

Heather/Broom

§ Production at Heather/Broom achieved a net 4,339 Boepd in 2013, up 15.6% on 2012, reflecting good well performance at Broom and improved operating efficiency at both Heather and Broom.  An improvement in Heather operating uptimes was achieved partly as a result of extensive work on the gas lift compression system.  The Heather rig reactivation project was successfully completed in H2 2013, with commissioning in early 2014.

Alma/Galia

§  In February 2013, EnQuest announced that it had approved an increase in the scope and specification of the Alma/Galia project with the objective of extending the field life, optimising operating costs and enabling a second phase.  The extension of the field life increased gross 2P reserves to 34MMboe.

§  The EnQuest Producer is now at a yard on the Tyne to undertake finishing yard scope and onshore commissioning.

§  By the end of 2013, subsea infrastructure was in place including trees, pipelines, umbilicals and manifolds.  Risers and mooring systems were pre-installed awaiting arrival of the EnQuest Producer FPSO.  The first electrical submersible pump ('ESP') was successfully installed on Alma on Well K2, followed by the installation of the second ESP, in well K3.

Kraken

§  In H1 2013, an appraisal well confirmed a second accumulation of oil north of Kraken. In H2 2013, the Kraken Field Development Plan ('FDP') was approved by the Department of Energy and Climate Change ('DECC') and sanctioned by EnQuest and its partners.  At the time of project sanction, the major supplier arrangements were already in place, including those for the FPSO vessel. First production is anticipated in 2016/2017, with gross peak production of over 50,000 Boepd. Following the project's sanction, EnQuest has added over 60 MMboe to its net 2P reserves.

Reserves

§  Audited net 2P reserves at the start of 2014 were 194.8 MMboe, a 51.6% increase on the start of 2013; reflecting a reserves replacement ratio of over 850% and a reserve life of over 20 years.  Net 2P reserves include 7 MMboe that will be consumed as lease fuel on the Kraken and Alma/Galia FPSOs.

Ends

For further information please contact:

EnQuest PLC                                                                                                                                                               

Tel: [phone]

Amjad Bseisu (Chief Executive)

Jonathan Swinney (Chief Financial Officer) 

Michael Waring (Head of Communications & Investor Relations)                                                                   

Tulchan Communications                                                                                            

Tel: [phone]

Martin Robinson           

David Allchurch

Martin Pengelley

Presentation to Analysts and Investors

A presentation to analysts and investors will be held at 09:30 today. The presentation and Q&A will also be accessible via an audio webcast - available from the investor relations section of the EnQuest website at www.enquest.com.   A conference call facility will also be available at 09:30 on the following numbers:

United Kingdom: [phone]     

United States of America: [phone]

Notes to editors

EnQuest is the largest UK independent producer in the UK North Sea.  EnQuest PLC trades on both the London Stock Exchange and the NASDAQ OMX Stockholm.  It is a constituent of the FTSE 250 index.  Its operated assets include the Thistle, Deveron, Heather, Broom, West Don, Don Southwest, Conrie, Kittiwake, Mallard, Gadwall, Goosander and Grouse producing fields and the Alma/Galia and Kraken developments; EnQuest also has an interest in the non-operated Alba producing oil field.  EnQuest had 31 UK production licences at the start of 2014. This increases to 37 production licences with the inclusion of the assets from the acquisition of the Greater Kittiwake Area which completed in Q1 2013 and the Don North East area licence which was offered 'out of round' to EnQuest in Q1 2014; these licences cover 47 blocks or part blocks in the UKCS, 30 of the licences are operated by EnQuest. 

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

EnQuest has begun replicating its existing model in the UKCS by targeting previously underdeveloped assets in a small number of other maturing regions; complementing our operations and utilising our deep skills in the UK North Sea.  In which context, EnQuest also has interests in two blocks offshore Sabah, in Malaysia and an interest in the Northwest October concession in Egypt.

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

STRATEGIC REPORT

CHAIRMAN'S STATEMENT

EnQuest's performance

EnQuest is delivering sustainable growth.  Over our first four years to the start of 2014, we have grown our original net 2P reserve base by almost 150%, representing a replacement ratio of approximately 450% and EnQuest now has a reserve life of over 20 years.  In the first four years, EnQuest generated c.$2.1 billion in cash flow from operations, and has invested c.$2.3 billion in the future growth of the business.   I believe that, in risk-adjusted terms, EnQuest is positioned at the most value creating part of the exploration and production lifecycle.  EnQuest's momentum is strong, the Board and I are more excited by our prospects today than at any time since EnQuest's inception.

Industry context

In 2013, oil prices remained strong and stable, for the third year in succession.  This was a healthy backdrop for continuing investment and new opportunities in the energy industry.  However, there have been cost increases which have directly contributed to the cancellation of some substantial development projects in the industry.  This competitive environment underlines the scale of EnQuest's achievement in successfully delivering the sanction of the Kraken development. 

In 2013, EnQuest put a new credit facility in place, for up to $1.7 billion.  As a company of substantial size, with high levels of cash generated from operations, EnQuest has good access to capital and has a strong balance sheet, providing capacity to acquire new assets.  Sellers of oil field assets need buyers who not only have the required funding, but who have the necessary technical and operational capabilities, essential for the subsequent safe and effective management of the assets.  EnQuest has all of these capabilities. Generally, the flow of assets available to EnQuest for possible acquisition has increased, facilitating potential new acquisition projects, such as EnQuest's recent acquisition of the Greater Kittiwake Area ('GKA') assets.

We believe companies like EnQuest are the future of the UK North Sea.  It is only by combining our skills and expertise with fiscal incentives that we can commit to significant new investments.  In 2013, EnQuest benefited from aspects of the UK North Sea fiscal regime designed to encourage investment.  The Thistle platform utilised a 'brownfield' allowance and the Kraken development secured two 'heavy oil' allowances. EnQuest continues to engage with the UK Government, seeking to optimise the fiscal structure of the UK North Sea. 

EnQuest also engages with the Scottish Government and welcomes statements that, in the event of there being an independent Scotland, the Scottish Government plans a stable and predictable fiscal and regulatory regime.  EnQuest believes that in order to maximise the extraction of hydrocarbons, there is a fundamental requirement for a stable fiscal regime that incentivises investment.

EnQuest welcomes the recommendations of the 2013/2014 Wood review of oil and gas activity on the UK Continental Shelf and its regulation.  Sir Ian Wood's strategy 'Maximising Economic Recovery for the UK', proposes more rigorous stewardship of the UK's remaining oil and gas resources through greater collaboration between operators and strong tripartite co-operation between the UK Department of Energy & Climate Change ('DECC'), HM Treasury and the oil and gas industry.  EnQuest believes that in some important respects the current system is out of date and no longer 'fit for purpose'.  It provides existing operators little incentive to accommodate third parties through their infrastructure and, without action, UK North Sea oil production will decline prematurely.  If the Wood recommendations are implemented they should help to prolong the life of the North Sea and to maximise hydrocarbon extraction from this still rich maturing basin.

EnQuest Board

There were no changes to the composition of the Board during 2013.  The Directors collaborate in assessing and evolving EnQuest's strategy and in key decisions on implementation; in 2013 these included the sanctioning of the Kraken development, the Kittiwake acquisition and EnQuest's initiatives outside the UK North Sea.

Although there were no changes to the Board itself in 2013, in October, EnQuest PLC announced the appointment of Stefan Ricketts as Company Secretary.  This change followed Paul Waters stepping down as Company Secretary.  Paul has been with EnQuest since its inception, the Board thanks him for his contribution and welcomes Stefan to his new role.

EnQuest's results are a reflection of the quality of all of our people and on behalf of the Board, I would like to thank my EnQuest colleagues for their continued hard work, commitment to our values, and successful pursuit of the Company's development plans.  

Governance

The Company recognises the importance of having high standards in all areas of governance, this includes the area of human rights.  In line with the recent expansion of our overseas activities, we are refining our approach to these areas to ensure that the Company's policies are robust for international as well as local operations. Our values will remain consistent with our existing Code of Conduct and will comply with all applicable laws.

In 2013 we further embedded and extended our anti-corruption programme, by launching a Group-wide training programme for all employees. By the end of the year the great majority of our employees had completed the training, which is being extended to all new joiners.

Dividend

The Company has not declared or paid any dividends since incorporation in January 2010 and does not have current intentions to pay dividends in the near future.  Any future payment of dividends is expected to depend on the earnings and financial condition of the Company and on such other factors as the Board of Directors of the Company considers appropriate.

Delivering sustainable growth

2013 was another good year of delivery and progress for EnQuest.  We continue to demonstrate that by targeting maturing assets and undeveloped oil fields, we can create value and deliver sustainable growth.  In 2014, EnQuest will continue to invest in its current producing assets, bring Alma/Galia onstream, integrate the Greater Kittiwake Area acquisition and make substantial investments in the Kraken development, which is scheduled to come onstream by 2017.  We are therefore on course for having six producing operated hubs in the UK and for achieving our objective of annual net production from the UK North Sea of around 50,000 Boepd.  Beyond that, we are creating further new potential from our UK asset portfolio and making low cost investments in international opportunities, securing EnQuest's growth for the longer term. 

STRATEGIC REPORT

CHIEF EXECUTIVE'S REPORT

EnQuest's strategy and business model; a good performance in 2013

In 2013, following the sanction of the large Kraken field in November, EnQuest increased its net 2P reserve base by 51.6% to 194.8 MMboe, reflecting a reserve replacement ratio of over 850% for 2013 and strongly reinforcing the sustainability of EnQuest's growth model.  Existing assets continue to perform well, we produced an average of 24,222 Boepd in 2013, an increase of 6%.  This was around the middle of the guidance range we indicated at the start of the year, even though first production from Alma/Galia was rescheduled into 2014.

In 2013, we produced 8.7 million barrels of oil from our existing reserves.  We also added 74.9 million barrels of oil to 2P reserves; this was achieved through the sanction of the Kraken development, the extension of the planned Alma/Galia field life, selective asset acquisitions, such as our stake in the producing Alba field, and from upward revisions to our existing fields. 

In 2013, cash flow generated from operations was $562.7 million and EBITDA was $621.3 million.  We invested $984.3 million of cash on capital expenditure for the future growth of the business.

In 2013, we agreed the acquisition of a 50% interest in the Greater Kittiwake Area, giving us an opportunity to extend its field life and also to enhance reserves by facilitating a proposed development of the Scolty and Crathes discoveries. This fits well with our objectives of managing maturing fields, exploiting nearby discoveries and near field exploration opportunities.  EnQuest also announced its first acquisition of an international producing asset, giving us an operating platform in Tunisia with short term infill drilling opportunities and a low cost entry point into potentially substantial development opportunities at the Zarat and Elyssa fields.

EnQuest is well positioned for sustainable growth and is successfully implementing its strategy to deliver that growth.

Operations and developments

Health, safety, environment and assurance ('HSE&A')

EnQuest will always maintain the highest level of vigilance with regard to HSE&A, we should acknowledge some significant achievements in 2013. The transfer of duty holdership (direct management of production platforms) to EnQuest from an outsourced contractor was conducted safely and effectively; a natural evolution of our integrated approach to operations management, giving us increased direct control over our assets.

In 2013, EnQuest's 2013 lost time injury frequency rate ('LTIF') of 1.4 compared favourably with the latest available industry average of 1.9.  Also encouraging was that at the end of 2013 our safety critical backlog (a measure of outstanding safety maintenance items) was almost zero.

We will not be complacent, we have put in place a new series of challenging HSE&A objectives for 2014 by way of continuous improvement planning.  We continue to exhibit leadership in demonstrating safety that comes before production and operations.

Operations

In 2013, EnQuest delivered good production growth of 6%.   We produced oil from the Thistle field at volumes not achieved since the mid-1990s, demonstrating EnQuest's ability to rejuvenate maturing fields and to extend their field lives.  New drilling at the successful Don fields enabled them to maintain their position as EnQuest's highest volume producing hub.  

EnQuest delivered nine wells in 2013, including the successful Thistle and Dons drilling programmes.  Uptime performance was strong and  in the top quartile of UK operators as assessed by the UK Production Efficiency Taskforce, utilising DECC data, despite the relative maturity of EnQuest's assets.   The Heather/Broom hub also made a strong contribution to production, reflecting good well performance at Broom and improved operating efficiency at the Heather platform.   In 2014, Heather returns to drilling for the first time in eight years, following its recommencement of rig operations at the end of 2013. 

Developments

Kraken

In November 2013, EnQuest delivered the sanction of the Kraken development in the UK North Sea; the largest single oil investment sanctioned in the UK last year.  EnQuest originally acquired its interests in Kraken after a series of appraisal wells had proven both the presence of oil and also that its flow characteristics were good.  Prior to sanction, EnQuest had a good understanding of the reservoir, had completed a full front end engineering design ('FEED') process and had the major supplier arrangements already in place, including those for the floating, production, storage and offloading vessel ('FPSO'). 

EnQuest is the operator of the project.  The Kraken development uses conventional technology and is anticipated to produce over 30,000 Boepd net to EnQuest at its peak rate; we expect it to come onstream by 2017, creating EnQuest's sixth operated producing hub.  With its long field life in excess of 25 years, Kraken further increases the sustainability of EnQuest's growth.  Comprehensive additional information on the Kraken project was published at EnQuest's capital markets day for investors in Q4 2013, these materials are available on EnQuest's website.

Alma/Galia

In late 2012, EnQuest confirmed the sanction of the Alma/Galia development, now with a gross 34 MMboe. By the end of 2013, the Alma/Galia subsea infrastructure had been put in place, drilling and completion operations were well underway and the 'EnQuest Producer' FPSO vessel had been moved to the Tyne in Newcastle, to undertake finishing yard scope and onshore commissioning.

In H2 2013, as an assessment of the remaining work concluded that additional time was needed for the project, the anticipated date of first production was rescheduled into 2014.  Additional information on the Alma/Galia project was provided to investors at EnQuest's capital markets day in Q4 2013, including details in relation to health and safety, progress in the field, also revised capex and opex, with EnQuest's net capex cost for the first phase at c.$45 per bbl.  EnQuest now expects production to start in H2 2014.  Alma/Galia will significantly increase EnQuest's production when it comes onstream, with an initial net peak production of c.13,000 Boepd. 

Acquisitions and disposals

UK North Sea

In January 2013, EnQuest agreed the acquisition of an 8% interest in the Alba oil field, including 5.9 MMboe of net 2P reserves, as at the economic date of 1 January 2012.  Alba also brings EnQuest additional experience relevant to the development and operation of the Kraken field.  The transaction completed in March 2013.

In H1 2013, EnQuest negotiated the farm out of a total of 55% of its previous 100% interest in the Cairngorm basement oil discovery.  EnQuest received a promoted carry on the Cairngorm appraisal well, this transaction completed in August 2013 and an appraisal well is currently being drilled.

In August 2013, EnQuest announced it had farmed into a 50% interest in the Avalon prospect.  This is located close to the Scolty and Crathes discoveries, in each of which EnQuest has a 40% interest.  An EnQuest operated exploration well is to be drilled on Avalon in 2014.

In Q4 2013, EnQuest announced an agreement to acquire 50% of the Greater Kittiwake Area assets, along with a 100% interest in the Kittiwake to Forties oil export pipeline.  This gives EnQuest increased production and additional net 2P reserves of 4.7 MMboe, as at the economic date of 1 January 2013.   We see significant potential to improve production both through infill drilling and through exploring further prospects in the area.  With Scolty, Crathes and Avalon all nearby and the possibility of a tie-back to Kittiwake, this acquisition creates the potential for a substantial new EnQuest hub and for an extension to the field life of GKA. 

International

In Q4 2012, EnQuest announced its first measured steps outside of the UK North Sea, replicating its existing model by targeting previously underdeveloped assets in what will be a small number of other maturing regions.  In 2012, EnQuest entered Malaysia with an initial investment of only US$3 million, to acquire Nio Petroleum (Sabah) Limited and thereby a 42.5% interest in Blocks SB307 and SB308, offshore Sabah, Malaysia.  In 2014, a well  is being matured for drilling offshore Sabah, Malaysia. 

In January 2014, EnQuest was offered and accepted two licences in the Norwegian 2013 Awards in Pre-defined Areas ('APA') licensing round, both located in the Norwegian Sea.  EnQuest was offered production licence 758 ('Rosslyng'), with EnQuest as the operator and having a 35% interest.  EnQuest was also offered licence 760 ('Chinook'), with Total as the operator, both Total and EnQuest having a 50% interest each. In both cases, the work commitments in the initial two year period entail 3D seismic licensing and reprocessing.

In Q2 2013, EnQuest agreed its first acquisition of international producing assets, acquiring 70% and operatorship of the Didon oil field in Tunisia; including 2 MMboe of net 2P producing oil reserves in Didon, along with over 40 MMboe of net contingent resources in the Zarat field.  With an initial consideration of US$23 million on completion, this represents another low cost entry point into a new region, with the potential for a development of the Zarat field and possibly also the nearby Elyssa field. Completion of this transaction is expected in H2 2014.  

Building on this first move into North Africa, EnQuest has also made a small investment in a 50% interest in the North West October appraisal block in Egypt, with the possibility of a future development opportunity; the consideration is refundable if a development does not proceed. 

Financial performance

In 2013, EnQuest generated strong EBITDA of $621.3 million.  EnQuest is in a strong financial position, having recently put in place a new credit facility, for up to $1.7 billion; providing capacity both for our current projects and for new opportunities.  2013 year end net debt of $381.1 million, compares to a $89.9 million net cash position at the end of 2012 and reflects EnQuest's increased investment programme. 

In total, unit operating costs of $35.5 per barrel were on target; reflecting a good operational performance and good control of direct costs, although transportation costs were up due mainly to an increase in the costs per barrel at the Sullom Voe oil terminal in the Shetland Islands.  Within the total, unit production costs of $27.2 per barrel were flat compared to the $27.4 per barrel equivalent costs incurred in 2012.

2014 so far

In Q1 2014, EnQuest was offered an 'out of round' licence ('Don NE') in the Don North East area for blocks 211/18e and 211/19c, including the Area 23 and Area 24 discovered oil accumulations and an undrilled extension to the Don NE field, in the same area as Don Southwest and West Don. This is a natural fit for EnQuest, providing new production opportunities and utilising existing infrastructure in the Don fields.

The Cairngorm appraisal well has recently reached its target, with indications of hydrocarbons in a relatively good quality basement reservoir.

Outlook for the rest of 2014 and beyond

Production performance has been good in 2014 so far, despite severe winter weather conditions.  Average production for the full year 2014 is anticipated to be between 25,000 Boepd and 30,000 Boepd, excluding production from uncompleted transactions.  EnQuest plans to deliver over 15 wells in 2014. 

The drilling programme includes a new production well on Don Southwest, a production well  workover on GKA, an ongoing intervention programme on Thistle, three production wells and one injection well on Alma/Galia and the recommencement of drilling on Heather for the first time since 2006, with two sidetracks and two workovers.  Also, two production wells are planned for the non-operated Alba field.

The 2014 exploration and appraisal well drilling programme includes Cairngorm, Kraken and Avalon in the UK. Internationally, in H2 2014, a non-operated well is being matured for drilling in the Sabah area, offshore Malaysia.

The drilling on Alma/Galia and the completion work on the EnQuest Producer will be followed by the anticipated start-up of production in the second half of 2014, revitalising the first field to produce oil in the UK North Sea, almost 40 years after it initially came onstream.  We are now moving ahead on the Kraken development, with the FPSO vessel for Kraken due to arrive in the yard in Q2 2014, for the commencement of its conversion programme.

With production from Alma/Galia due to start this year and Kraken scheduled to produce first oil by 2017, EnQuest's already sanctioned development projects are set to deliver a material increase in production to around 50,000 Boepd. 

STRATEGIC REPORT

OPERATING REVIEW

2013: High operational uptimes and high production efficiency

In 2013, EnQuest delivered nine wells with well workovers and new production and water injection wells, growing production by 6.2% to 24,222 Boepd (2012: 22,802 Boepd); a performance underpinned by high operational uptimes, high production efficiency and strong reservoir performance.   This was achieved whilst ensuring that safe results, no harm to people and respect for the environment remained our top priorities.

In EnQuest's first four years, revisions to reserve estimates have increased our net 2P reserves by 25.4 MMboe, reflecting the benefits of our infill drilling programme and our increased reservoir knowledge.  These upgrades to reserve estimates are a direct result of EnQuest's operational work programmes and an important source of value creation; in the four years since our inception, 9.6 MMboe has been produced by Thistle and we have increased Thistle's net 2P reserves by almost twice that level, by 19.0 MMboe. 

In 2013, a series of operational performance efficiency measures were started under an 'Operations Excellence' programme, leveraging the potential of EnQuest's in-house focused organisational structure.  These included a focus on maximising production through loss management programmes and improved standardised reporting methods.  New controls were also put in place to maximise our ability to avoid major accident hazards; a new major accident prevention model was developed, a new asset integrity review board was established, along with a new incident review system.  Waste minimisation initiatives were also launched to maximise cost efficiencies, these included a project to improve the efficiency of the way in which supplier contracts are managed.  

An integral part of EnQuest is its values; collaboration, empowerment, agility, creativity, passion, respect and focus.  This common set of values unifies the EnQuest organisation.  The importance of 'empowerment' was underlined in 2013; more key jobs were brought in-house and became direct EnQuest staff positions, forums were established for information sharing and exchange of ideas and learning.  All of which helped to drive production efficiency at our three operated producing hubs. 

Close collaboration amongst the workforce was required for the successful transfer of duty holdership that took place in March 2013. Duty holdership is a core competency for EnQuest.  The increased control secured by taking over as duty holder is helping to improve operational, production and cost efficiency.

EnQuest's capability is continuing to grow across all its functions, we are again pleased to have been able to increase quality, strength and depth across the organisation.

Thistle/Deveron

Working interest at end 2013: 99%
Decommissioning liabilities: remain with former owner
Fixed steel platform
Daily average net production:
2013: 7,925 Boepd
2012: 8,058 Boepd

2013

Production at Thistle/Deveron achieved a net 7,925 Boepd in 2013, with a particularly strong performance in the second half of the year, with peak spot rates over 16,000 Boepd and having finished 2013 at a daily average above 10,000 Boepd. 

Q1 2013 was negatively impacted by shut downs of the third party Brent pipeline. Q1 2013 production was also affected by higher than normal levels of water injection downtime; this was in turn due to power source reliability issues, caused by outages of the B turbine whilst the new D turbine was being commissioned. 

In H2 2013, production benefited from strong performance from a new production well which came onstream at the start of August.  Thistle's new D turbine and fully rebuilt B turbine are now providing better performance levels, resulting in improved power supply stability. Despite a two week scheduled platform shutdown for maintenance in October 2013, production in the second half of 2013 was almost double the levels in the first half.   

2014 and beyond

In 2014, capital investment is continuing in the Thistle life extension project, ongoing activities include a control systems upgrade and significant simplification of processes, jacket integrity improvements and topsides structural integrity improvements.

Looking further ahead, there are presently 18 producing wells and seven water injection wells in Thistle/Deveron; these will be increased in number during 2016/17.

The Don fields

Working interest at end 2013:
- Don Southwest, 60%
- Conrie, 60%
- West Don, 63.45%
- Don North East, 60%: Q1 2014 'out of round' licence
Decommissioning liabilities: as per working liabilities
Floating production unit with subsea wells
Daily average net production:
2013: 11,014 Boepd
2012: 10,992 Boepd

2013

Production at the Don fields achieved a net 11,014 Boepd in 2013, ahead of the 10,992 Boepd in 2012. 

In Q1 2013, the Don fields were also negatively affected by the third party Brent pipeline shutdowns, however production benefitted from the West Don W6/W4 producer/injector pair, following the tie in of the W6 injector  well in Q1 2013.  The Don Southwest Area 6 producer, S12z, was completed and brought onstream in June 2013, followed by Area 6 injector, S13, in August.  Operational performance highlights in H2 2013 included a record water injection rate of 58,000 bwpd.

2014

Production optimising projects are still continuing on the Don fields, despite the fact that the drilling programme on EnQuest's existing Don fields is coming to an end and production is therefore in natural decline.  This natural decline will reduce 2014 production over 2013, although a new production well is planned to be drilled in H1 2014 in Don Southwest Area 22 (TJ). A maintenance shutdown is planned Q3 2014. 

Additionally, in Q1 2014, EnQuest accepted an 'out of round' licence ('Don NE') in the Don North East area for blocks 211/18e and 211/19c, including Area 23 and Area 24 and an undrilled extension to the Don NE field.  Within the first 12 months of the licence, it is intended to submit a field development plan ('FDP') in relation to Area 24, to include at least one production well.  This will provide further opportunities to enhance Dons area production.

Heather/Broom

Working interest at end 2013:
 - Heather, 100%
 - Broom, 63%
Decommissioning liabilities:
- Heather, 37.5%
- Broom, 63%
Fixed steel platform
Daily average net production:
2013: 4,339 Boepd
2012: 3,752 Boepd

2013

Production at Heather/Broom achieved a net 4,339 Boepd in 2013, up 15.6% on 2012.  Heather has continued to deliver strong year on year production growth, reflecting good well performance at Broom and improved operating efficiency at Heather.  An improvement in Heather operating uptimes was achieved partly as a result of extensive work on the gas lift compression system.  The Heather rig reactivation project was successfully completed in Q4 2013, with operations starting in early 2014.

2014

Following the completion of the rig reactivation project, rig operations in Q1 2014 commenced with a workover of the H56 well, due onstream in H1 2014, to be followed by the sidetrack of H44 as a new injection well in the B2 block. The 2014 programme also includes a sidetrack of H48 and a workover of the crestal E-Block producer H47.

The Heather life extension project includes a three year infill drilling campaign, to be split into two phases, whilst sharing the rig crew with Thistle, also a complementary facilities upgrade.  There are nine wells in the initial programme, targeting 12 MMboe of reserves which are included in net 2P reserves.

Alma/Galia

Working interest at end 2013:
- 65% in both fields
Decommissioning liabilities:
- 65% in both fields
Floating, production storage and offloading unit with subsea wells
First oil expected in H2 2014
- Net peak production to be in excess of 13,000 Boepd

2013

In February 2013 EnQuest announced that it had approved an increase in the scope and specification of the Alma/Galia project with the objective of extending the field life, optimising operating costs and enabling a second phase.  The extension of the field life increased gross 2P reserves to 34MMboe.

During 2013, the scope of the work on the FPSO expanded, including additional work on the existing marine and process systems.  The FPSO was moved to the Tyne for finishing and commissioning work.

By the end of 2013, subsea infrastructure was in place including subsea trees, manifolds, pipelines and umbilicals. Risers and mooring systems were pre-installed, awaiting arrival of the FPSO.  Two wells were completed in 2013, with the first electrical submersible pump ('ESP') successfully installed on Alma on well K2, followed by the installation of the second ESP, in well K3.

2014

Drilling and completion operations continue, with production anticipated in H2 2014.

Kraken

Working interest at end 2013: 60%
Decommissioning liabilities: 60%
Floating Production Storage and Offloading unit with subsea wells
First oil expected by 2017
- Net peak production to be in excess of 30,000 Boepd

2013

The Kraken Field Development Plan ('FDP') was approved by the Department of Energy and Climate Change ('DECC') in H2 2013.  First production is anticipated by 2017, with gross peak production of over 50,000 Boepd. The field layout of the development will consist of 25 wells, tied back to an FPSO. Following the project's sanction, EnQuest has added over 60 MMboe to its net 2P reserves.

Net capital cost to first oil is expected to be approximately $1.4 billion with a gross capital cost to first oil approximately $1.8 billion. EnQuest's net capital costs equate to c.$27 per bbl, including the carry. Gross capital costs of the project are estimated to be approximately $3.2bn. At the time of project sanction, the major supplier arrangements were already in place, including those for the FPSO vessel.

2014

In Q2 2014, the vessel will arrive at the shipyard in Singapore for the conversion scope to commence. Further appraisal drilling shall be undertaken to the west of the Kraken field in H2 2014 to assess the area known as the 'Western Feature'.

In H2 2014, EnQuest expects to commence installation of the subsea structures at the first drill centre, where the initial wells for the development will be drilled. Delivery of the hydraulic submersible pumps ('HSP') used to provide the artificial lift will commence in Q3 2014. Detailed engineering, procurement and manufacture for all equipment relating to wells, subsea infrastructure and the FPSO will continue throughout 2014.

Greater Kittiwake Area

Acquisition completed in Q1 2014
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

Post acquisition programme in 2014
EnQuest has taken over as the operator.  The initial focus will be on integrating GKA into EnQuest and on an early workover programme planned in 2014.  Next steps will include progressing the proposed field development plan submission for the nearby Scolty/Crathes discoveries, with the potential for a tie-back to GKA and exploration of nearby prospects.

Alba (non-operated)

EnQuest's acquisition of its interest in Alba completed at the end of March 2013
Working interest at end of 2013: 8%
Decommissioning liabilities: 8%
Fixed steel platform
2013: 922* Boepd
2012: -

(*) Net production since the completion of the acquisition at the end of March 2013, averaged over the nine months to the end of December.

The Alba oil field is operated by Chevron.  In 2013, two wells were drilled and completed. 

In 2014, planned operations include the drilling of two production wells, also the acquisition of new 4D seismic survey, a key input for maturing future drilling targets. 

Cairngorm

Assessment of the results of the Cairngorm appraisal well is  underway; preliminary analysis indicates a 173ft hydrocarbon column was encountered, with evidence of good reservoir properties in the fractured granite.  With the results of the previous well and seismic, the overall indications in the structure are now of a total hydrocarbon column of 797ft.  Further evaluation is ongoing.

Avalon

Following EnQuest's 2013 farm in to a 50% interest in Avalon, close to Scolty/Crathes, an appraisal well will be drilled in 2014.  EnQuest is the operator of this well.

risks and uncertainties

Management of risks and uncertainties

The Board has articulated EnQuest's strategy to deliver shareholder value by:

exploiting its hydrocarbon reserves;

commercialising and developing discoveries;

converting its contingent resources into reserves; and

pursuing selective acquisitions.

In pursuit of this strategy, EnQuest has to face and manage a variety of risks. As a result, the Board has established a risk management framework, embedding the principles of effective risk management throughout the business.  A Risk and Review Committee was established during 2013 to review significant prospective commitments and advise the Chief Executive on risks therein.

The Group risk register is reviewed by the Executive Committee every month.   Similarly, at each Board meeting the Board reviews and discusses the risk register with senior management to ensure that risks are being appropriately identified and actively managed.

Key business risks

The Group's principal risks could lead to a significant loss of reputation or could prevent the business from executing its strategy and creating value for shareholders.

Set out below are the principal risks and the 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.

Risk		Mitigation
Health, safety and environment (HSE) Oil and gas development, production and exploration activities are complex and HSE risks cover many areas including major accident hazards, personal health and safety, compliance with regulatory requirements and potential environmental harm. Potential impact - Medium (2012 Medium) Likelihood - Low (2012 Low) There has been no material change in the potential impact or likelihood.		The Group maintains, in conjunction with its core contractors, a comprehensive programme of health, safety, environmental, asset integrity and assurance activities and has implemented a continuous improvement programme, promoting a culture of transparency in relation to HSE matters. The Group has established a Corporate HSE committee which meets quarterly. HSE performance is discussed at each board meeting. In addition, the Group has a positive, transparent relationship with the UK Health and Safety Executive. In March 2013, EnQuest took on the role of duty holder for the Group's operated fields in the North Sea.  This has enabled the implementation of EnQuest HSE principles and values across its sites and has improved focus on HSE improvement activities.  As a result, the Group has also strengthened its operating, auditing and integrity management capability accordingly.
Production The Group's production is critical to its success and is subject to a variety of risks including subsurface uncertainties, operating in a difficult environment with mature equipment and potential for significant unexpected shutdowns and unplanned expenditure to occur and where remediation may be dependent on suitable weather conditions offshore. Lower than expected reservoir performance may have a material impact on the Group's results. The Group's delivery infrastructure on the UKCS is dependent on the Sullom Voe Terminal. Potential impact - High (2012 High) Likelihood - Low (2012 Low) There has been no material change in the potential impact or likelihood.		The Group's programme of asset integrity and assurance activities provides leading indicators of significant potential issues which may result in unplanned shutdowns or which may in other respects have the potential to undermine asset availability and uptime. The Group continually assesses the condition of its assets and operates extensive maintenance and inspection procedures designed to minimise the risk of unplanned shutdowns and expenditure. The Group monitors both leading and lagging KPIs in relation to its maintenance activities and liaises closely with its downstream operators to minimise pipeline and terminal production impacts. Life of asset production profiles are audited by independent reserves auditors. The Group also undertakes regular internal peer reviews. The Group's forecasts of production are risked to reflect appropriate production risks. The Sullom Voe Terminal has a good safety record and its safety and operational performance levels are regularly monitored and challenged by the Group and other terminal owners and users to ensure that operational integrity is maintained.

Project execution The Group's success will be dependent upon bringing new developments, such as Alma/Galia and Kraken, to production on budget and on schedule. To be successful, the Group must ensure that project implementation is both timely and on budget. Failure to do so may have a material negative impact on the Group's performance. Potential impact - High (2012 High) Likelihood - Medium (2012 Low) The likelihood of occurrence of an event impacting project execution will have increased to an extent by virtue of the commencement of the capital works on Kraken.  However, it should be noted that project execution risk on Alma/Galia is diminishing as the project works, particularly the FPSO, are coming to an end.		The Group has project teams which are responsible for the planning and execution of such new projects with a dedicated team for each development. The Group has detailed controls, systems and monitoring processes in place to ensure that deadlines are met, costs are controlled and that design concepts and Field Development Plans are adhered to and implemented. These are modified when the circumstances require, but only through a controlled management of change process and with the necessary internal and external authorisation and communication.  The Group also engages third party assurance experts to review, challenge and, where appropriate,  make recommendations to improve the processes for project management, cost control and governance of major projects.  EnQuest ensures that responsibility for delivering time-critical supplier obligations and lead times are fully understood, acknowledged and proactively managed by the most senior levels within supplier organisations. The Alma/Galia development is progressing towards first production in H2 2014.  In 2013, EnQuest announced it had approved additional project scope with the objectives of extending the field life, optimising operating costs and enabling a potential second phase development.  The work required to implement these aims continues on the EnQuest Producer FPSO with the vessel at a finishing yard in the UK for final integration and commissioning prior to sailaway.  The offshore drilling and completion campaign continues with all Alma wells now drilled through the reservoir and two of the six electrical submersible pump completions run.  The piled mooring system and the majority of the subsea construction was completed in 2013 with only final mooring hook-up and riser pull-in to be completed post arrival of the FPSO. The Kraken development was sanctioned by DECC and EnQuest's partners in November 2013. First oil production is scheduled by 2017. The development involves the drilling of 25 new subsea horizontal wells which will be connected to an FPSO. Prior to sanction, EnQuest identified and optimised the development plan using EnQuest's pre-investment assurance processes. Six appraisal wells have been drilled in the area, new seismic data was completed, considerable subsurface modelling was undertaken and FEED studies (front end engineering and design) were carried out for the FPSO and subsea integrated equipment. In order to reduce project cost risk, more than 60% of the capital expenditure has been defined by actual tendering and placing of contracts. The FPSO will involve conversion of an existing tanker which will be under a leased contracting arrangement for a fixed price.
Reserve replacement Failure to develop its contingent and prospective resources or secure new licences and/or asset acquisitions and realise their expected value. Potential impact - High (2012 High) Likelihood - Low (2012 Low) There has been no material change in the potential impact or likelihood.		The Group puts a strong emphasis on subsurface analysis and employs industry leading professionals. The Group continues to recruit in a variety of technical positions which enables it to manage existing assets and evaluate the acquisition of new assets and licences. All analysis is subject to internal and, where appropriate, external peer review. All reserves are currently externally audited by a Competent Person.  In addition, EnQuest has an active business development team both in the UK and internationally developing a range of opportunities.
Financial Inability to fund appraisal and development work programmes. Potential impact - High (2012 High) Likelihood - Medium (2012 Medium) There has been no material change in the potential impact or likelihood.		During the year, the Group has refinanced its revolving credit facility with a new larger facility and has issued a retail bond, both of which can be used to fund its development activities.  This funding is supported by operating cash inflow from the Group's producing assets.  The Group reviews its cash flow requirements on an ongoing basis to ensure it has suitable resources for its needs.

Human resources The Group's success is dependent upon its ability to attract and retain key personnel and develop organisational capability to deliver strategic growth. Potential impact - Medium (2012 Medium) Likelihood - Low (2012 Low) There has been no material change in the potential impact or likelihood.		The Group has established a competent employee base to execute its principal activities. In addition to this, the Group regularly monitors the employment market to provide remuneration packages, bonus plans and long term share-based incentive plans that incentivise performance and longer-term commitment to the Group. EnQuest is undertaking a number of human resource initiatives to enable the Group to meet its growth aspirations. These initiatives are part of the overall People and Organisation strategy and have specific themes relating to Organisation, People, Performance and Culture.  It is a Board-level priority that the Executive and senior management have the right mix of skills and experience.  There continues to be a significant level of resourcing activity and recruitment, selection strategies and processes have been enhanced to ensure that our workforce is competent.  EnQuest's experienced HR department will continue to ensure that key capabilities are in place as the Group grows both in the UKCS and internationally. The Group also maintains market-competitive contracts with key suppliers to support the execution of work where the necessary skills do not exist within the Group's employee base. The focus on Executive and senior management retention, succession planning and development remains an important priority for the Board and an increasing emphasis will be placed on this as the Group grows.
Reputation The reputational and commercial exposures to a major offshore incident are significant. Potential impact - High (2012 High) Likelihood - Low (2012 Low) There has been no material change in the potential impact or likelihood.		Operational activities are conducted in accordance with approved policies, standards and procedures. Interface agreements are agreed with all core contractors. The Group undertakes regular audit activities to provide assurance on compliance with established policies, standards and procedures.
Oil price A material decline in oil and gas prices may adversely affect the Group's results of operations and financial condition. Potential impact - High (2012 High) Likelihood - Low (2012 Low) There has been no material change in the potential impact or likelihood.		The Group monitors oil price sensitivity relative to its capital commitments and has a policy which allows hedging of up to 75% of its production. In order to develop its resources, the Group needs to be able to fund substantial levels of investment. The Group will therefore regularly review and implement suitable policies to hedge against the possible negative funding impacts of changes in oil prices. The Group is establishing an in-house trading and marketing function to enable it to enhance its ability to mitigate the exposure to volatility in oil prices.
Political and fiscal Changes in the regulatory or fiscal environment affecting the Group's ability to deliver its strategy. Potential impact - High (2012 Medium) Likelihood - Medium (2012 Low) The increase in likelihood and impact reflects the possibility of a change in the regulatory and  fiscal regimes following the referendum on Scottish independence in 2014.		It is difficult for the Group to predict the timing or severity of such changes. However, through Oil & Gas UK and other industry associations the Group does engage with government and other appropriate organisations in order to ensure the Group is kept abreast of expected potential changes and takes an active role in making appropriate representations. At a more operational level, the Group has procedures to identify impending changes in relevant regulations to ensure legislative compliance. In respect of the referendum on Scottish independence, senior management liaises with Scottish politicians and others to ensure that third parties are aware of EnQuest's trading and investment activities and the importance of the oil industry in general to the local and national economies.
Joint venture partners Failure by joint venture parties to fund their obligations. Dependence on other parties where the Group is not the operator. Potential impact - Medium (2012 Medium) Likelihood - Medium (2012 Medium) There has been no material change in the potential impact or likelihood.		The Group operates regular cash call and billing arrangements with its co-venturers to mitigate the Group's credit exposure at any one point in time and keeps in regular dialogue with each of these parties to ensure payment. Risk of default is mitigated by joint operating agreements allowing the Group to take over any defaulting party's share in an operated asset. The Group generally prefers to be the operator. The Group maintains regular dialogue with its partners to ensure alignment of interests and to maximise the value of joint venture assets.
Competition The Group operates in a competitive environment across many areas including the acquisition of oil and gas assets, the marketing of oil and gas, the procurement of oil and gas services and access to human resources. Potential impact - Medium (2012 Medium) Likelihood - Low (2012 Low) There has been no material change in the potential impact or likelihood.		The Group has a strong balance sheet which puts it in a favourable position to be able to compete effectively and move quickly when looking to acquire assets. The Group also has strong technical and business development capabilities to ensure it is well positioned to identify potential acquisition opportunities. The Group has good relations with oil and gas service providers and constantly keeps the market under review. Human resources are key to the Group's success and programmes referred to above are in place to ensure it can attract and retain key personnel.

Acquisitions The Group has been active in acquiring new assets.  These have been producing, development and exploration assets most of which have been operated assets, although Alba is not operated by EnQuest. The businesses of all of these assets are similar to the Group's existing activities, but there are additional risks associated with acquisitions such as the difficulty in valuing assets, assumptions on oil price, funding, resourcing new activities and integration within existing operations. Potential impact - Medium (2012 Low) Likelihood - Low (2012 Low) The potential impact is higher due to  acquisitions completed and pending, including Tunisia.		For all acquisitions, the Group performs extensive due diligence prior to announcing and subsequently completing the acquisition using suitably qualified in-house staff or third party specialists.  In all cases, the Group seeks to mitigate risk in sale and purchase agreements by including suitable representations and warranties in the event of issues arising post completion.  When evaluating acquisitions, a risk register is prepared and a risk review committee reviews commercial, technical and other business risks together with mitigation and how risks can be managed by the business on an ongoing basis. EnQuest looks to minimise valuation risk on larger transactions by structuring purchase consideration to include a deferred consideration element contingent upon a future event such as the sanctioning of a future development.  In the case of oil prices, the Group evaluates the value of potential targets at a range of oil prices to ensure that project economics are sufficiently robust. Once a potential acquisition reaches an advanced stage, the Group develops a takeover plan to determine how the target business can be integrated into the Group.  For operated assets, this will involve identifying key personnel to take on critical positions within the target and a plan to embed EnQuest policies and procedures into the newly acquired activity. Initial funding and funding of subsequent investments are modelled within the Group's internal planning models to ensure satisfactory funds can be made available without adverse effects on the existing funding requirements of the Group or its cost of capital.
International business Whilst the majority of the Group's activities and assets are in the UK, the international business is becoming more material.  The Group's international business is subject to the same risks as the UK business (e.g. HSE, production and project execution); however, there are additional risks that the Group faces including security of staff and assets, political, foreign exchange and currency control, taxation, legal and regulatory, cultural and language barriers and corruption. Potential impact - Medium (2012 Low)Likelihood - Low (2012 Low) The potential impact is higher as the international business is growing.		Prior to entering into a new country, EnQuest evaluates the host country to assess whether there is an adequate and established legal and political framework in place to protect and safeguard first its expatriate and local staff and, second, any investment within the country in question. When evaluating international business risks, a risk register is prepared and a risk review committee reviews commercial, technical and other business risks together with mitigation and how risks can be managed by the business on an ongoing basis. EnQuest looks to employ suitably qualified host country staff and work with good quality local advisers to ensure it complies within national legislation, business practices and cultural norms whilst at all times ensuring that staff, contractors and advisers comply with EnQuest's business principles, including those on fraud and corruption. Where appropriate, the risks may be mitigated by entering a joint venture with partners with local knowledge and experience. After country entry, EnQuest maintains a dialogue with local and regional government, particularly with those responsible for oil, energy and fiscal matters, and may obtain support from appropriate risk consultancies.  When there is a significant change in the risk to people or assets within a country, the Group takes appropriate action to safeguard people and assets.

STRATEGIC REPORT

FINANCIAL REVIEW

Financial Overview

The Group's financial performance in 2013 reflects solid operational performance set against a backdrop of significant capital investment in growth projects throughout the year.

In the year ended 31 December 2013, the Brent crude oil price averaged $108.7 per barrel compared to $111.7 per barrel for 2012.  Total production volumes were 6% higher for the year ended 31 December 2013 which resulted in revenue of $961.2 million compared with $889.5 million in 2012.

	Business performance
	2013	2012
	$ million	$ million
Profit from operations before tax and finance income/(costs)	374.8	405.1
Depletion and depreciation	224.0	208.0
Intangible impairments and write-offs	2.0	13.1
Net foreign exchange losses	20.5	8.4
EBITDA	621.3	634.6

EBITDA for the year ended 31 December 2013 was $621.3 million compared with $634.6 million in 2012.  The lower EBITDA is mainly due to higher tariff and transportation costs and G&A costs offset by higher revenues. EBITDA has been adjusted to exclude foreign exchange losses.  The increase in foreign exchange losses is principally due to exchange rate fluctuations of which $10.9 million relates to the retail bond.

The Group entered 2013 with $89.9 million of net cash.  In October 2013, the Group established a fully underwritten new multi-currency revolving credit facility of up to $1.2 billion plus a $500 million accordion feature.  At the year end, $1.2 billion had been committed with the additional $500 million being available depending on oil reserves, including increases resulting from acquisitions.  The new facility replaces the $900 million facility entered into in March 2012.  In Q1 2013, EnQuest successfully raised £145 million from the issue of a retail bond with a 5.5% coupon and maturity in 2022. EnQuest raised a further £10 million in Q4.  These funds together with strong ongoing operating cash flows from the existing portfolio of assets have been used to fund the capital investment programme. The closing net debt position was $381.1 million at 31 December 2013 and was comprised of the following:

	Net debt/(cash)
	2013	2012
	$ million	$ million
Bond1	254.5	-
Multi-currency revolving credit facility1	199.4	34.6
Cash and cash equivalents	(72.8)	(124.5)
	381.1	(89.9)

^{1 Stated excluding accrued interest and net of unamortised fees.}

Through these facilities, EnQuest has diversified its funding base and has provided capacity for current projects and for new opportunities.  EnQuest continues to review opportunities for further diversification of its funding base.

Income Statement

Production and revenue

Production levels, on a working interest basis, for the year ended 31 December 2013 averaged 24,222 Boepd compared with 22,802 Boepd in 2012.  The increase is mainly due to additional production from Heather and Broom as well as the Alba field (acquired late March 2013), offset by marginally lower production from Thistle.

Heather and Broom production was significantly higher than 2012 due to high levels of production efficiency and the absence of a planned shutdown in 2013. Thistle production was lower due to lack of water injection in Q1 and equipment outages (pump and separator) in the first half of the year, offset by a strong performance in the second half of the year from the new A60 well and additional perforations on the A57 well.  Production volume in the Dons fields was higher than 2012 as a result of additional wells drilled in late 2012 and 2013. The increase was offset by lower production due to a higher than anticipated level of water injection outages compared with 2012. There was also a natural well decline from existing well stock. 

The Group's blended average realised price per barrel of oil sold was $109.7 for the year ended 31 December 2013, slightly below the $111.6 per barrel received for 2012.  This is consistent with average oil prices for 2012 and 2013.  Revenue is predominantly derived from crude oil sales and for the year ended 31 December 2013 crude oil sales totalled $953.8 million compared with $879.3 million in 2012.  The increase in revenue is due to higher production and an over-lift of $2.6 million compared with an under-lift of $24.4 million in 2012.

Operating costs

Cost of sales comprises cost of operations, tariff and transportation expenses, change in lifting position, inventory movement and depletion of oil and gas assets.  Cost of sales for the Group (pre-exceptionals and depletion of fair value adjustments) were as follows:

		Reported	Reported
		year ended 31 December	year ended 31 December
		2013	2012
		$ million	$ million
Cost of sales		532.3	448.2
		$	$
Unit operating cost, adjusted for over/under-lift and inventory movements (per barrel):
-Production costs		27.2	27.4
-Transportation costs		8.3	4.9
-Operating costs		35.5	32.3
-Depletion of oil and gas properties		24.6	24.7
		60.1	57.0

Cost of sales pre-exceptionals and depletion of fair value adjustments was $532.3 million for the year ended 31 December 2013 compared with $448.2 million in 2012.  The increase of $84.1 million is due to a change in lifting position from an under-lift in 2012 to an over-lift in 2013 which amounts to $27.0 million. There also has been a significant increase in transportation costs partly due to increased volumes, but mainly due to an increase in costs per barrel at the Sullom Voe Terminal and, to a lesser extent, the Brent pipeline. The purchase of the 8% interest in Alba in Q1 2013 also contributed to the increase in cost of sales.

The Group's operating costs comprise production costs and tariff and transportation costs which were $313.9 million for the year ended 31 December 2013 compared with $269.5 million in 2012.  Transportation costs increased from $40.8 million to $73.5 million for the year ended 31 December 2013 mainly due to significantly higher unit costs per barrel at the Sullom Voe Terminal.  Production costs increased by $11.7 million to $240.4 million for the year ended 31 December 2013.  The main increase was due to the Alba asset acquired in Q1 2013.  In the other producing assets, higher costs in Thistle due to additional power generation, diesel and well intervention costs were offset by lower costs in the Dons and Heather hubs which in 2012 included the costs of planned shutdowns.

The increase in the Group's average unit production and transportation cost of $3.2 per barrel for the year ended 31 December 2013 compared with 2012 is almost entirely due to the increase in transportation tariff rate for access to the Sullom Voe Terminal and Brent pipelines.

The Group's depletion expense per barrel for the year is broadly consistent with the previous year with a decrease of $0.1 per barrel.  The minor decrease is primarily due to the lower DD&A rate for the Heather and Broom hub due to its impairment in 2012 and a lower rate for the new Alba field offset by a higher rate in the Dons hub due to higher planned capex.

The Group's change in lifting position was $2.6 million expense for the year ended 31 December 2013, compared with income of $24.4 million in 2012.  The net over-lift during 2013 has arisen mainly due to a December lifting at Alba which offset an under-lift in the operated assets.

Exploration and evaluation expenses

Exploration and evaluation expenses were $8.6 million in the year ended 31 December 2013, compared with $23.2 million reported in the previous year.  The expenses in 2013 primarily relate to the costs of Norway, including overheads and expenses relating to obtaining new licenses which were awarded in January 2014, and the UK 28^th Licensing Round to take place in April 2014. Costs were significantly higher in 2012 due to the cost of an unsuccessful exploration well and a number of licence relinquishments.

General and administrative expenses

General and administrative expenses were $25.0 million in the year ended 31 December 2013 compared with $6.7 million reported in the previous year.  The main reasons for the increase are due to increased business development spend and a higher G&A recovery from partners in 2012.

Other expenses

Other expenses is comprised of net foreign exchange losses of $20.5 million in the year ended 31 December 2013.

Taxation 

The tax charge for the year of $146.6 million, excluding exceptional items, represents an effective tax rate of 43% compared with 33% in the previous year.  The increase in the Group's effective tax rate for the year is due primarily to a reduction in the level of tax benefits available from leasing arrangements, partly offset by an increase in the ring fence expenditure supplement.

Exceptional items and depletion of fair value uplift

Exceptional losses totalling $8.8 million before tax have been disclosed separately in the year ended 31 December 2013 mainly relating to additional depletion costs resulting from the fair value uplift of the Dons oil and gas assets on acquisition at IPO and are reported as a fair value adjustment.

Finance costs

Finance costs of $46.6 million include $13.3 million of bond and loan interest payable, $12.6 million unwinding of discount on decommissioning provisions, a non-cash unrealised loss of $7.7 million mainly on the mark-to-market valuation of the Group's 2014 oil hedges which are deemed ineffective for hedge accounting purposes.  Other financial expenses of $14.2 million are primarily commitment and letter of credit fees as well as arrangement fee amortisation relating to the bank facilities.  The Group capitalised $1.2 million for the year ended 31 December 2013 in relation to the interest payable on borrowing costs on its capital development projects.

Finance income

Finance income of $11.5 million includes $0.4 million of bank interest receivable, a non-cash unrealised gain of $9.5 million primarily on the mark-to-market of the Group's foreign exchange hedges which are deemed ineffective for hedge accounting purposes and $1.4 million unwinding of discount on the financial asset created in 2012 as part of the consideration for the farm out of the Alma/Galia development to KUFPEC.

Earnings per share

The Group's reported basic earnings per share were 24.4 cents for the year ended 31 December 2013 compared with 46.2 cents in 2012.  The decrease of 21.8 cents is attributable to lower profit before tax and a higher effective income tax rate in the current year compared with 2012.  The Group's reported basic earnings per share excluding exceptional items were 24.8 cents for the year ended 31 December 2013 compared with 33.1 cents in 2012.  The decrease of 8.3 cents is mainly attributable to the higher effective income tax rate in the year ended 31 December 2013 compared with the prior year.

Cash flow and liquidity

The Group's reported cash generated from operations in 2013 was $562.7 million compared with $593.9 million in 2012.  The reported cash flow from operations per issued Ordinary share was 72.3 cents per share compared with 75.7 cents per share in 2012.   The reduction in cash generated is mainly due to the purchase of christmas tree stock not allocated to a specific field.  Movements in trade receivables and payables are in line with normal business.

During the year ended 31 December 2013, $1.2 million was received in relation to an exploration refund for EnQuest Norge AS's activities in Norway. In addition, $11.3 million was paid during the year ended 31 December 2013 in relation to EnQuest Group's UK tax liabilities for non-operational activities and Petroleum Revenue Tax. 

It is anticipated that the underlying effective tax rate for 2014 will be approximately 55%, excluding one-off exceptional tax items. With continuing investment in the North Sea, the Group does not expect a material cash outflow for UK corporation tax on operational activities before 2020.  This is due to the projected level of capital expenditure, which benefits from tax deductible first year capital allowances in the UK, 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:

	2013	2012
	$ million	$ million
Expenditure on producing oil and gas assets	294.5	323.9
Development expenditure	632.0	381.1
Exploration and evaluation capital expenditure	36.6	128.4
Other capital expenditure	21.2	8.9
	984.3	842.3

Significant projects were undertaken during the year, including:

·      the Alma/Galia development including the FPSO and further drilling of the production wells;

·      the Kraken development including drilling the head target well, FPSO FEED costs and project management activities;

·      the Thistle life extension programme;

·      the Thistle drilling programme including the A60 well and A59 well work-over;

·      the Dons drilling programme with the DS producer and the OB injector;

·      the Heather/Broom return to drilling programme and additional living quarters.

Net debt at 31 December 2013 amounted to $381.1 million compared with net cash of $89.9 million in 2012.

In Q1 2013, EnQuest successfully raised £145 million from the issue of a retail bond, with a 5.5% coupon and a 2022 maturity.  A further £10 million was raised in Q4 2013.

Balance Sheet

The Group's total asset value has increased by $1,005.7 million to $3,550.5 million at 31 December 2013 (2012: $2,544.8 million).

Property, plant and equipment

Property, plant and equipment (PP&E) has increased to $2,871.2 million at 31 December 2013 from $1,816.6 million at 31 December 2012.  The increase of $1,054.6 million is mainly due to oil and gas asset capital additions of $840.7 million.  The main spend relates to Kraken ($157.8 million) and Alma/Galia ($437.2 million).  There was also a $52.5 million addition in relation to the Alba acquisition, $415.3 million of carry relating mainly to Kraken ($240 million firm carry and $80 million contingent carry) and the unwinding of the remaining Alma/Galia cost carry ($95.3 million).  Depletion and depreciation charges of $232.6 million were incurred.

The oil and gas asset capital additions, including carry arrangements, during the year are set out in the table below:

	2013
	$ million
Dons hub	69.1
Thistle hub	108.6
Heather and Broom hub	56.6
Alma/Galia	532.5
Kraken	477.8
Alba	62.5
Other	1.4
	1,308.5

Intangible oil and gas assets

Intangible oil and gas assets increased by $33.4 million to $130.9 million at 31 December 2013.  The increase is mainly due to pre-development costs at Scolty/Crathes, the Malaysian asset, an appraisal well at Cairngorm and acquisition of interests in Avalon and Egypt.

Investments

The Group holds an investment of 160,903,958 new ordinary shares in Ascent Resources plc which is valued at $2.4 million based on the quoted bid price as at 31 December 2013.

Inventory

Inventory increased by $31.5 million primarily due to the purchase of christmas trees not allocated to a specific field.

Trade and other receivables

Trade and other receivables have increased by $27.5 million to $267.2 million at 31 December 2013 compared with $239.7 million in 2012.  Joint venture and trade receivables remain consistent with the prior year and in line with continued significant capital expenditure on Alma/Galia and Kraken.  Prepayments and accrued income decreased primarily due to facility fees for the old facility being fully amortised during 2013.  Other receivables have increased due to an increase in the under-lift position and miscellaneous receivables awaiting invoicing.

Cash and bank

The Group had $72.8 million of cash and cash equivalents at 31 December 2013 and $225.8 million was drawn down on the $1.7 billion multi-currency revolving credit facility.  Of the facility, at 31 December 2013 $1.2 billion had been committed and further amounts will be available depending on oil reserves, including increases resulting from acquisitions.

Provisions

The Group's decommissioning provision decreased by $4.6 million to $228.4 million at 31 December 2013 (2012: $233.0 million).  During the year, the Group commissioned third party experts to complete the detailed triennial study to review decommissioning cost estimates for the operated producing hubs.  The outcome of the study confirmed previous cost estimates in many areas, but reduced cost estimates in other areas due to scope of works required or method, time and cost of decommission.  Those reductions in estimates were partly offset by the acquisition of the Alba asset and additional drilling on Alma/Galia together with $12.6 million due to the unwinding of the discount.

The Group acquired 40% of the Kraken field from Nautical Petroleum plc and First Oil plc in 2012 through payment of the development costs (other than operator costs) incurred from 1 January 2012 in respect of the development programme for the Kraken discovery which would otherwise have been payable by those partners.

 A provision has been recognised for the contingent carry (additional consideration) which is dependent on a reserves determination.  The reserves determination would be triggered by the carried parties based on drilling work or, if later, the date on which the firm carry expires.  The contingent carry is pro-rated between 100-166 million barrels of 2P reserves.  The field development plan which was approved in November 2013, stated 137 million barrels. This would give rise to a contingent carry of approximately $80 million which is included as a provision.  The carry is estimated to be paid 12 months after the firm consideration has expired in late 2014 or early 2015.

Income tax

The Group had no corporation tax or supplementary corporation tax liability at 31 December 2013 compared with $3.8 million at 31 December 2012.  The decrease of $3.8 million is due to the submission of research and development expenditure claims, prior year tax adjustments and balances arising on acquisition. The Group had a $4m petroleum revenue tax (PRT) liability at 31 December 2013 compared to no liability at 31 December 2012. The increase is due to the acquisition of Alba, a PRT paying field.  The income tax asset at 31 December 2013 represents the expected refund on exploration activities undertaken in Norway.

Deferred tax liability

The Group's deferred tax liability (net of deferred tax assets) has increased by $137.2 million to $746.3 million at 31 December 2013 from $609.1 million in 2012.  The increase is mainly due to the capital expenditure programme undertaken by the Group during the year which provides the Group with 100% first year capital allowance claims as well as an increase in ring fence taxation losses carried forward and the acquisition of the companies holding an 8% interest in the Alba field.  Total losses carried forward at the year end amount to approximately $1,088 million. 

Trade and other payables

Trade and other payables have increased to $363.3 million at 31 December 2013 from $329.7 million at 31 December 2012.  The increase of $33.6 million is due to an increase in trade payables in line with increased activity in the year.

Other financial liabilities

Other financial liabilities have increased by $153.2 million. The main reason for the increase relates to the Kraken firm carry of $164.2 million.

Financial Risk Management

The Group is exposed to the impact of changes in Brent crude oil prices on its revenue and profits.  EnQuest's policy is to have the ability to hedge oil prices up to a maximum of 75% of the next 12 months production on a rolling annual basis, up to 60% in the following 12 month period, and 50% in the subsequent 12 month period.  Between November 2012 and February 2013, put and call options covering 4.6 million barrels of oil production in 2013 were entered into partially to hedge the exposure to fluctuations in the Brent oil price.  The 2013 oil price hedge contracts consisted of put spreads at $95-$100 per barrel and $70-$75 per barrel and calls at an average of $121.6 per barrel, all executed at nil cost. 

In August and September 2013, some commodity hedging contracts were entered into partially to hedge the exposure to fluctuations in the Brent oil price during 2014.  A total of 3.6 million barrels of puts (300,000 barrels per month) were bought at a price of $106 per barrel and 7.2 million barrels of calls were sold at a price of $106 per barrel, which are only triggered if the monthly average price of Brent exceeds a fixed price for the given month (ranging from $119 to $124 per barrel).  Since the year end the Company has swapped an additional 1 million barrels in Q2 at prices of approximately $109 per barrel.

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 50% of non-US Dollar denominated operating expenditure and 70% of non-US Dollar capital expenditure to be hedged.  During the first half of 2013, the Group entered into a series of forward contracts and structured products to hedge a portion of its Sterling, Euro and Norwegian Krone exposure throughout 2013 and 2014.  In 2013, a total of £223 million was hedged at an average rate of $1.51:£1.  The structured products have an average strike price of $1.46:£1.  If the spot rate at expiry is above $1.64:£1 then there is no trade and the Group funds its Sterling requirement through the spot market or drawing Sterling on the bank facility.  Between $1.64:£1 and $1.33:£1, EnQuest trades at the lower of $1.46:£1 and the spot rate, and below $1.33:£1, EnQuest trades a higher volume of currency at $1.46:£1.  This structure has also been used for hedging a total of £182 million of Sterling exposure in 2014.

The same structure has also been used to hedge the Group's Norwegian Krone (NOK) exposure which arises as part of the Kraken development project.  In 2013, a total of NOK255 million was hedged and in 2014 NOK367 million has been hedged.

In 2013, EnQuest exchanged a total of €74 million for $96 million mainly done by placing forward contracts, however €11 million was placed on the same structured basis as the Sterling and Norwegian Krone arrangements described above.  EnQuest will continue to look 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.

KEY PERFORMANCE INDICATORS

	2013	2012
Lost Time Incident Frequency (LTIF)	1.36	2.00
2P reserves (MMboe)	194.76	128.52
Business performance data:
Production (Boepd)	24,222	22,802
Revenue ($ million)	961.2	889.5
Realised oil price per barrel ($)	109.7	111.6
Opex per barrel (production and transportation costs) ($)	35.5	32.3
Gross profit excluding exceptional items ($ million)	428.9	441.3
Cash capex on property, plant and equipment oil and gas assets($ million)	984.3	842.2
Reported data:
Cash generated from operations ($ million)	562.7	593.9
Net (debt)/cash ($ million)	(381.1)	89.9
Profit before tax ($ million)	330.9	403.4
Basic earnings per share (cents)	24.4	46.2
EBITDA	621.3	634.6

EnQuest PLC

Abridged Group Income Statement

For the year ended 31 December 2013

		2013			2012
	Business Performance US$'000	Exceptional items and depletion of fair value uplift US$'000	Total for period US$'000	Business Performance US$'000	Exceptional items and depletion of fair value uplift US$'000	Total for period US$'000
Revenue	961,199	-	961,199	889,510	-	889,510
Cost of sales	(532,259)	(8,509)	(540,768)	(448,186)	(10,251)	(458,437)
Gross profit/(loss)	428,940	(8,509)	420,431	441,324	(10,251)	431,073
Exploration and evaluation expenses	(8,641)	-	(8,641)	(23,157)	-	(23,157)
Impairment on available for sale assets	-	(312)	(312)	-	(4,417)	(4,417)
Impairment of oil and gas assets	-	-	-	-	(143,882)	(143,882)
Gain on disposal of property, plant and equipment	-	-	-	-	175,929	175,929
General and administration expenses	(25,024)	-	(25,024)	(6,650)	-	(6,650)
Other (expenses)/income, net	(20,452)	-	(20,452)	(6,445)	-	(6,445)
Profit/(loss) from operations before tax and finance income/(costs)	374,823	(8,821)	366,002	405,072	17,379	422,451
EBITDA*	621,300	-	621,300	634,626	-	634,626

Notes:

* EBITDA is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion (note10 adjusted for depletion of fair value uplift ), depreciation (note 10), impairment (note 12) write off of intangible oil and gas assets (note12) and foreign exchange movements (note 5(f)).  This foreign exchange adjustment for 2013 is a change to the definition used previously and the prior year EBITDA figure has been restated accordingly.   EBITDA is not a measure of financial performance under IFRS.

EnQuest PLC

OIL AND GAS RESERVES AND RESOURCES

At 31 December 2013

	UKCS		Other Regions	Total
	MMboe	MMboe	MMboe	MMboe
Proven and Probable Reserves (notes 1, 2, 3 & 6)
At 1 January 2013		128.52	-	128.52
Revisions of previous estimates		2.43	-	2.43
Discoveries, extensions and additions (note 7)		67.04	-	67.04
Acquisitions and disposals (note 8)		5.46	-	5.46
Production:
Export meter	(8.83)
Volume adjustments (note 5)	0.14
		(8.69)	-	(8.69)
Proven and Probable Reserves at 31 December 2013		194.76	-	194.76
Contingent Resources (notes 1, 2 & 4)
At 1 January 2013		157.75	4.40	162.15
Revisions of previous estimates		0.48	-	0.48
Discoveries, extensions and additions		31.44	-	31.44
Acquisitions (note 8)		0.37	-	0.37
Disposals		(2.09)	-	(2.09)
Promoted to reserves (note 7)		(70.95)	-	(70.95)
Contingent Resources at 31 December 2013		117.00	4.40	121.40

Notes:

(1)   Reserves and resources are quoted on a working interest basis.

(2)   Proven and Probable Reserves and Contingent Resources have been assessed by the Group's internal reservoir engineers, utilising geological, geophysical, engineering and financial data. 

(3)   The Group's Proven and Probable Reserves are based on the report audited by a recognised Competent Person in accordance with the definitions set out under the 2007 Petroleum Resources Management System and supporting guidelines issued by the Society of Petroleum Engineers.

(4)   Contingent Resources relate to technically recoverable hydrocarbons for which commerciality has not yet been determined and are stated on a best technical case or '2C' basis.

(5)   Correction of export to sales volumes.

(6)   All volumes are presented pre SVT value adjustment.

(7)   Contingent Resources previously allocated to Kraken have been classified as reserves as a result of ongoing development planning and consequent equity increase.  Kraken project sanction was achieved in November 2013.  Contingent Resources allocated to Alma/Galia have been classified as reserves as a result of development drilling and ongoing subsurface evaluation.

(8)   8% equity was acquired in Alba on 22/2/2013.

(9)   The above proven and probable reserves include 7 MMboe that will be consumed as lease fuel on the Kraken and Alma FPSOs.

ENQUEST PLC

GROUP STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2013

			2013		2012
	Notes	Business performance	Exceptional items and depletion of fair value uplift (note 4)	Reported  in year	Business performance	Exceptional items and depletion of fair value uplift (note 4)	Reported  in year
		US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Revenue	5(a)	961,199	-	961,199	889,510	-	889,510
Cost of sales	5(b)	(532,259)	(8,509)	(540,768)	(448,186)	(10,251)	(458,437)
Gross profit/(loss)		428,940	(8,509)	420,431	441,324	(10,251)	431,073
Exploration and evaluation expenses Impairment of investments Impairment of oil and gas assets Gain on disposal of property, plant and equipment	5(c) 4 4 4	(8,641) - - -	- (312) - -	(8,641) (312) - -	(23,157) - - -	- (4,417) (143,882) 175,929	(23,157) (4,417) (143,882) 175,929
General and administration expenses	5(d)	(25,024)	-	(25,024)	(6,650)	-	(6,650)
Other income	5(e)	-	-	-	2,000	-	2,000
Other expenses	5(f)	(20,452)	-	(20,452)	(8,445)	-	(8,445)
Profit/(loss) from operations before tax and finance income/(costs)		374,823	(8,821)	366,002	405,072	17,379	422,451
Finance costs	6	(46,554)	-	(46,554)	(21,211)	-	(21,211)
Finance income	6	11,487	-	11,487	2,161	-	2,161
Profit/(loss) before tax		339,756	(8,821)	330,935	386,022	17,379	403,401
Income tax	7	(146,607)	5,276	(141,331)	(126,357)	85,174	(41,183)
Profit/(loss) for the year attributable to owners of the parent		193,149	(3,545)	189,604	259,665	102,553	362,218
Other comprehensive income for the year, after tax:
Cash flow hedges: may be reclassified subsequently to profit or loss (net of tax) Available for sale financial assets	21 14			46 398			2,554 -
Total comprehensive income for the year, attributable to owners of the parent				190,048			364,772
Earnings per share	8	US$		US$	US$		US$
Basic		0.248		0.244	0.331		0.462
Diluted		0.243		0.238	0.326		0.454

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

ENQUEST PLC 

GROUP BALANCE SHEET

At 31 December 2013

	Notes	2013	2012
ASSETS		US$'000	US$'000
Non-current assets
Property, plant and equipment	10	2,871,229	1,816,591
Goodwill	11	107,760	107,760
Intangible oil and gas assets	12	130,874	97,506
Investments	14	2,403	2,317
Deferred tax assets	7	14,731	23,143
Other financial assets	21	21,928	19,447
		3,148,925	2,066,764
Current assets
Inventories	15	46,814	15,301
Trade and other receivables	16	267,180	239,722
Current tax receivable		6,275	2,007
Cash and cash equivalents	17	72,809	124,522
Other financial assets	21	8,455	96,472
		401,533	478,024
TOTAL ASSETS		3,550,458	2,544,788
EQUITY AND LIABILITIES
Equity
Share capital	18	113,433	113,433
Merger reserve		662,855	662,855
Cash flow hedge reserve		-	(46)
Available-for-sale reserve		398	-
Share-based payment reserve		(10,280)	(11,072)
Retained earnings		718,303	528,699
TOTAL EQUITY		1,484,709	1,293,869
Non-current liabilities
Borrowings	20	199,396	34,600
Bond	20	254,500	-
Obligations under finance leases	25	72	107
Provisions	23	308,426	232,952
Other financial liabilities	21	839	-
Deferred tax liabilities	7	760,993	632,230
		1,524,226	899,889
Current liabilities
Bond	20	4,291	-
Trade and other payables	24	363,310	329,666
Obligations under finance leases	25	35	34
Other financial liabilities	21	169,891	17,570
Current tax payable		3,996	3,760
		541,523	351,030
TOTAL LIABILITIES		2,065,749	1,250,919
TOTAL EQUITY AND LIABILITIES		3,550,458	2,544,788

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

The financial statements on pages 85 to 121 were approved by the Board of Directors on 25 March 2014 and signed on its behalf by Jonathan Swinney, Chief Financial Officer

ENQUEST PLC

GROUP STATEMENT OF CHANGES IN EQUITY

At 31 December 2013

	Share capital	Merger reserve	Cash flow hedge reserve	Available-for-sale reserve	Share-based payments reserve	Retained earnings	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
At 1 January 2012	113,433	662,855	(2,600)	-	(5,961)	166,481	934,208
Profit for the year	-	-	-	-	-	362,218	362,218
Other comprehensive income	-	-	2,554	-	-	-	2,554
Total comprehensive income for the year	-	-	2,554	-	-	362,218	364,772
Share-based payment charge	-	-	-	-	5,163	-	5,163
Shares purchased on behalf of Employee Benefit Trust	-	-	-	-	(10,274)	-	(10,274)
At 31 December 2012	113,433	662,855	(46)	-	(11,072)	528,699	1,293,869
Profit for the year	-	-	-	-	-	189,604	189,604
Other comprehensive income	-	-	46	398	-	-	444
Total comprehensive income for the year	-	-	46	398	-	189,604	190,048
Share-based payment charge	-	-	-	-	8,193	-	8,193
Shares purchased on behalf of Employee Benefit Trust	-	-	-	-	(7,401)	-	(7,401)
At 31 December 2013	113,433	662,855	-	398	(10,280)	718,303	1,484,709

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

 
ENQUEST PLC

GROUP STATEMENT OF CASH FLOWS

For the year ended 31 December 2013

			2013	2012
	Notes		US$'000	US$'000
CASH FLOW FROM OPERATING ACTIVITIES
Profit before tax			330,935	403,401
Depreciation	5(d)		6,914	1,483
Depletion	5(b)		225,654	216,780
Exploration costs impaired and written off	5(c)		1,966	23,157
Impairment of oil and gas assets	4		-	143,882
Gain on disposal of property, plant and equipment	4		-	(175,929)
Impairment on available-for-sale investments	4		312	4,417
Share-based payment charge	5(g)		8,193	5,163
Unwinding of discount on decommissioning provisions	6		12,588	10,148
Unrealised exchange losses	5(f)		20,452	8,445
Net finance costs	6		22,479	8,902
Operating profit before working capital changes			629,493	649,849
Increase in trade and other receivables			(30,828)	(105,088)
Increase in inventories			(30,849)	(3,459)
(Decrease)/increase in trade and other payables			(5,126)	52,610
Cash generated from operations			562,690	593,912
Decommissioning spend			-	(13,618)
Income taxes paid			(11,278)	(790)
Net cash flows from operating activities			551,412	579,504
INVESTING ACTIVITIES
Purchase of property, plant and equipment			(950,326)	(838,399)
Purchase of intangible oil and gas assets			(36,593)	(128,403)
Proceeds from farm out			2,648	124,587
Interest received			583	787
Net cash flows used in investing activities			(983,688)	(841,428)
FINANCING ACTIVITIES
Proceeds from bank facilities			182,731	34,692
Proceeds from bond issue			246,345	-
Shares purchased by Employee Benefit Trust			(7,401)	(10,274)
Repayment of obligations under finance leases			(35)	(89)
Interest paid			(9,025)	(632)
Other finance costs paid			(35,712)	(14,065)
Net cash flows from financing activities			376,903	9,632
NET DECREASE IN CASH AND CASH EQUIVALENTS			(55,373)	(252,292)
Net foreign exchange on cash and cash equivalents			3,660	(2,093)
Cash and cash equivalents at 1 January			124,522	378,907
CASH AND CASH EQUIVALENTS AT 31 DECEMBER			72,809	124,522

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

ENQUEST PLC

NOTES TO THE GROUP FINANCIAL STATEMENTS

For the year ended 31 December 2013

1.         Notes to the consolidated financial statements

The financial information for the year ended 31 December 2013 and 2012 contained in this document does not constitute statutory accounts as defined in section 435 of the Companies Act 2006. The financial information for the years ended 31 December 2013 and 2012 have been extracted from the consolidated financial statements of EnQuest plc for the year ended 31 December 2013 which have been approved by the directors on 25 March 2014 and will be delivered to the Registrar of Companies in due course. The auditor's report on those financial statements was unqualified and did not contain a statement under section 498 of the Companies Act 2006.

2.         Significant accounting policies

The accounting policies adopted are consistent with those of the previous financial year except for the adoption of new and amended standards.

The Group has adopted IFRS 13 "Fair Value Measurement" and Amendments to IAS 1 "Presentation of items of other comprehensive income".  Adoption of these revised standards did not have any effect on the financial performance or position of the Group.

3.         Segment information

Management have considered the requirements of IFRS 8, in regard to the determination of operating segments, and concluded that the Group has only one significant operating segment, being the exploration for, and the extraction and production of, hydrocarbons.

All revenue is generated from sales to customers in the United Kingdom.  Details of the Group's revenue components are provided in note 5(a).  All crude oil revenue is received from two customers; Shell International Trading and Shipping Company Limited is the major customer and revenue receivable amounted to US$901,936,000 or 95% of total revenue (excluding oil hedge gains and losses) in the year ended 31 December 2013 (2012: US$879,307,000 or 99% of total revenue).

All non-current assets of the Group are located in the United Kingdom except for US$13,414,000 (2012: US$7,136,000) located in Malaysia and US$5,526,000 (2012: nil) located in Egypt. 

4.         Exceptional items and depletion of fair value uplift

	2013	2012
	US$'000	US$'000
Recognised in arriving at profit/(loss) from operations before tax and finance income/(costs):
Impairment of  available for sale investments (note 14)	312	4,417
Impairment of oil and gas assets	-	143,882
Gain on disposal of property, plant and equipment	-	(175,929)
Depletion of fair value uplift	8,509	10,251
	8,821	(17,379)
Tax	(5,276)	(85,174)
	3,545	(102,553)

Impairment of available for sale investments

As consideration for the disposal of the held for sale Petisovci asset, the Group received an investment in Ascent.  The accounting valuation of this shareholding at 30 June 2013 resulted in a non-cash impairment of US$312,000 (2012: US$4,417,000).  During the second half of the year the share price increased resulting in a reversal of part of the impairment loss.  This is recognised in the available-for-sale reserve of US$398,000.

Impairment of oil and gas assets

As part of the annual impairment review process, no impairment triggers were highlighted therefore no impairment was required for the year ended 31 December 2013. In the year ended 31 December 2012 the Heather and Broom hub was impaired by US$143,882,000 (refer to note 10).

Gain on disposal of property, plant and equipment

On 12 October 2012, the Company entered into an agreement to farm out 35% of the Alma/Galia development to KUFPEC UK Limited (KUFPEC) with an effective date of 1 January 2012.  The gain on disposal represents the difference between the total consideration received and the derecognition of 35% of the costs of development at the date of the agreement.

Depletion of fair value uplift

Additional depletion arising from the fair value uplift of Petrofac Energy Developments Limited's (PEDL) oil and gas assets on acquisition of US$8,509,000 (2012: US$10,251,000) is included within cost of sales in the statement of comprehensive income.

Tax

In addition to the tax impact of the exceptional items, in the prior year the tax exceptional amount includes the impact of the 2012 enactment of a restriction on relief of costs incurred in respect of the decommissioning of UK oil and gas assets to 50%.  This increased the tax charge in the year ended 31 December 2012 by US$14,279,000, of which US$10,389,000 was reflected as an exceptional item as it relates to the restriction on the opening decommissioning liability.

5.         Revenue and expenses

(a)       Revenue

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Revenue from crude oil sales	953,752	879,307
Gain on realisation of financial instruments	-	53
Revenue from condensate sales	-	(137)
Tariff revenue	7,445	10,189
Other operating revenue	2	98
	961,199	889,510

(b)       Cost of sales

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Cost of operations	240,439	228,670
Tariff and transportation expenses	73,452	40,806
Change in lifting position	2,649	(24,360)
Inventory movement (note 15)	(1,426)	(3,459)
Depletion of oil and gas assets (note 10)	225,654	216,780
	540,768	458,437

 (c)      Exploration and evaluation expenses

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Unsuccessful exploration expenditure written off (note 12)	704	6,514
Impairment charge (note 12)	1,262	6,583
Pre-licence costs expensed	6,675	10,060
	8,641	23,157

 (d)      General and administration expenses

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Staff costs (note 5(g))	108,226	76,861
Depreciation (note 10)	6,914	1,483
Other general and administration costs	21,450	17,570
Recharge of costs to operations and joint venture partners	(111,566)	(89,264)
	25,024	6,650

 (e)      Other income

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Other income	-	2,000

 (f)       Other expenses

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Net foreign exchange losses	20,452	8,445

 (g)      Staff costs

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Wages and salaries	44,790	30,069
Social security costs	5,128	4,054
Defined contribution pension costs	3,267	3,155
Expense of share-based payments (note 19)	8,193	5,163
Other staff costs	3,645	2,682
Total employee costs	65,023	45,123
Contractor costs	43,203	31,738
	108,226	76,861

The average number of persons employed by the Group during the year was 245 (2012: 173).

Details of remuneration, pension entitlement and incentive arrangements for each Director are set out in the Remuneration Report on pages 56 to 74.

(h)        Auditors' remuneration

The following amounts were payable by the Group to its auditors Ernst & Young LLP during the year: 

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Fees payable to the Group's auditors for the audit of the Group's annual accounts	336	188
Fees payable to the Group's auditors and its associates for other services: The audit of the Group's subsidiaries Audit related assurance services (interim review) Tax advisory services (i) Other assurance services Corporate finance services	272 73 318 43 -	207 67  745 5 148
	706	1,172
	1,042	1,360

(i)   Costs of US$345,600 relating to tax advice on asset and corporate acquisitions were capitalised in the year ended 31 December 2012.  No costs were capitalised in the current year.  

6.         Finance costs/income

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Finance costs:
Loan interest payable	2,954	668
Bond interest payable	10,360	-
Unwinding of discount on decommissioning provisions (note 23)	12,588	10,148
Cash flow hedge re-price premium	-	335
Fair value loss on financial instruments at fair value through profit or loss (note 21)	7,724	2,147
Finance charges payable under finance leases	2	3
Other financial expenses	14,167	8,307
	47,795	21,608
Less: amounts included in the cost of qualifying assets	(1,241)	(397)
	46,554	21,211
Finance income:
Bank interest receivable	429	686
Fair value gain on financial instruments at fair value through profit or loss (note 21)	9,457	871
Unwinding of financial asset (note 21)	1,447	479
Other financial income	154	125
	11,487	2,161

Fair value gains and losses on financial instruments at fair value though profit or loss relate to foreign exchange forward and commodity forward contracts that did not qualify for hedge accounting.

7.         Income tax

(a)        Income tax

The major components of income tax expense are as follows:

	Year ended 31 December	Year ended 31 December
	2013	2012
Group statement of comprehensive income	US$'000	US$'000
Current income tax
Current income tax charge	14,462	6,867
Adjustments in respect of current income tax of previous years	(2,075)	(362)
Overseas income tax
Current income tax charge	(3,379)	(2,007)
Adjustments in respect of current income tax of previous years	703	(842)
Total current income tax	9,711	3,656
Deferred income tax
Relating to origination and reversal of temporary differences	133,314	50,724
Adjustments in respect of changes in tax rates	409	10,785
Adjustments in respect of deferred income tax of previous years	(2,112)	(23,593)
Overseas income tax
Relating to origination and reversal of temporary differences	9	(389)
Total deferred income tax	131,620	37,527
Income tax expense reported in statement of comprehensive income	141,331	41,183

 (b)       Reconciliation of total income tax charge

A reconciliation between the income tax charge and the product of accounting profit multiplied by the UK statutory tax rate is as follows:

	Year ended 31 December	Year ended 31 December
	2013	2012
	US$'000	US$'000
Profit before tax	330,935	403,401
Statutory rate of corporation tax in the UK of 62% (2012: 62%)	205,179	250,109
Supplementary corporation tax non-deductible expenditure	15,250	6,552
Non-deductible expenditure	508	3,310
Deductible lease expenditure	(38,097)	(76,951)
Non-taxable gain on sale of assets	-	(109,076)
Petroleum revenue tax (net of income tax benefit)	21,948	19,081
North Sea tax reliefs	(55,034)	(29,894)
Tax in respect of non-ring fence trade	(5,184)	(10,837)
Deferred tax rate decrease	409	396
North Sea oil and gas decommissioning rate restriction	2,824	14,279
Adjustments in respect of prior years	(3,482)	(24,797)
Overseas tax rate differences	(2,171)	(464)
Other differences	(819)	(525)
At the effective income tax rate of 43% (2012: 10%)	141,331	41,183

 (c)       Deferred income tax

Deferred income tax relates to the following:

	Group balance sheet					Group profit and loss account
	2013	2012				2013		2012
	US$'000	US$'000				US$'000		US$'000
Deferred tax liability
Accelerated capital allowances	1,456,498	1,050,189				387,107		274,703
Deferred PRT	151,825	99,955				47,910		53,610
	1,608,323	1,150,144
Deferred tax asset
Losses	(647,228)	(359,406)				(287,822)		(253,847)
Decommissioning liability	(114,113)	(116,476)				16,057		(4,108)
Other temporary differences	(100,720)	(65,175)				(31,632)		(32,831)
	(862,061)	(541,057)
Deferred tax expense						131,620		37,527
Deferred tax liabilities, net	746,262	609,087
Reflected in balance sheet as follows:
Deferred tax assets	(14,731)	(23,143)
Deferred tax liabilities	760,993	632,230
Deferred tax liabilities, net	746,262	609,087
Reconciliation of deferred tax liabilities, net						2013		2012
						US$'000		US$'000
At 1 January 2013					(609,087)			(577,393)
Tax expense during the period recognised in  profit or loss					(131,620)			(37,527)
Tax expense during the period recognised in  OCI					(75)			(4,167)
Deferred taxes acquired					(5,480)			10,000
At 31 December 2013					(746,262)			(609,087)

 (d) Tax losses

Deferred income tax assets are recognised for the carry-forward of unused tax losses and unused tax credits to the extent that it is probable that taxable profits will be available against which the unused tax losses/credits can be utilised.

The Group has unused UK mainstream corporation tax losses of US$2,481,000 (2012: US$2,662,000) for which no deferred tax asset has been recognised at the balance sheet date due to the uncertainty of recovery of these losses. 

The Group has unused overseas tax losses in Canada of approximately CAD$14,880,000 (2012: CAD$17,106,000) and in Holland of €1,180,000 (2012: €1,070,000) for which no deferred tax asset has been recognised at the balance sheet date.  The tax losses in Canada have expiry periods of between 7 and 20 years, none of which expire in 2014. Tax losses in Holland can be carried forward for a period of up to nine years and are likely to expire in 2014.

(e) Change in legislation

Finance Act 2013 enacted a change in the mainstream corporation tax rate, reducing it from 23% to 21% with effect from 1 April 2014 and 20% with effect from 1 April 2015. The impact of the change in tax rate was an increase in the tax charge of US$409,000.

Finance Act 2012 enacted a restriction on costs incurred in respect of decommissioning to 50%, compared to the North Sea ring fence rate of 62% on or after 21 March 2012.  The impact of the decommissioning relief restriction in 2012 was an increase in the tax charge of US$14,279,000, of which US$10,389,000 related to the revaluation of the opening decommissioning balances. A change in the tax rate for non-ring fence companies was also enacted in the Finance Act 2012, reducing the corporation tax rate from 25% to 23% with effect from 1 April 2013. The impact of the change in tax rate was an increase in the tax charge of US$396,000.

(f) Factors affecting future tax charges

As at 31 December 2013, the Group is eligible for Field Allowances in the UK on Conrie, Alma, Galia, Thistle, Deveron, Kraken and Kraken North which will reduce the Ring Fence profits chargeable to Supplementary Charge. Field Allowances are only granted when DECC approves a field development plan and are triggered when production commences.

8.         Earnings per share

The calculation of earnings per share is based on the profit after tax and on the weighted average number of Ordinary shares in issue during the period.

Basic and diluted earnings per share are calculated as follows:

		Profit after tax		Weighted average number of shares		Earnings per share
		Year ended 31 December		Year ended 31 December		Year ended 31 December
	2013		2012	2013	2012	2013	2012
		US$'000	US$'000	Million	Million	US$	US$
Basic		189,604	362,218	778.2	784.1	0.244	0.462
Dilutive potential of Ordinary shares granted under share-based incentive schemes		-	-	18.1	13.3	(0.006)	(0.008)
Diluted		189,604	362,218	796.3	797.4	0.238	0.454
Adjusted (excluding exceptional items)		193,149	259,665	778.2	784.1	0.248	0.331
Diluted (excluding exceptional items)		193,149	259,665	796.3	797.4	0.243	0.326

9.         Dividends paid and proposed

The Company paid no dividends during the year ended 31 December 2013 (2012: nil).At 31 December 2013 there are no proposed dividends (2012: nil).

10.    Property, plant and equipment

	Land and buildings	Oil and gas assets	Office furniture and equipment	Total
	US$'000	US$'000	US$'000	US$'000
Cost:
At 1 January 2012	-	1,982,250	12,490	1,994,740
Additions	-	829,463	8,859	838,322
Farm in to West Don	-	29,752	-	29,752
Farm out	-	(143,054)	-	(143,054)
Cost carry	-	86,698	-	86,698
Reclassified from intangible assets (note 12)	-	31,221	-	31,221
Change in decommissioning provision	-	62,239	-	62,239
At 31 December 2012	-	2,878,569	21,349	2,899,918
Additions	17,272	840,665	6,491	864,428
Acquired	-	52,541	-	52,541
Cost carry	-	415,300	-	415,300
Reclassified to intangible assets (note 12)	-	(448)	-	(448)
Change in decommissioning provision	-	(44,615)	-	(44,615)
At 31 December 2013	17,272	4,142,012	27,840	4,187,124
Depletion and depreciation:
At 1 January 2012	-	715,222	5,960	721,182
Impairment charge for the year	-	143,882	-	143,882
Charge for the year	-	216,780	1,483	218,263
At 31 December 2012	-	1,075,884	7,443	1,083,327
Charge for the year	-	225,654	6,914	232,568
At 31 December 2013	-	1,301,538	14,357	1,315,895
Net carrying amount:
At 31 December 2013	17,272	2,840,474	13,483	2,871,229
At 31 December 2012	-	1,802,685	13,906	1,816,591
At 1 January 2012	-	1,267,028	6,530	1,273,558

During the year ended 31 December 2013, the Group acquired a non-operated interest in the producing oil field Alba, in the UK Continental Shelf, which has been accounted for as an asset acquisition.  US$52,541,000 is included within 'Acquired' costs.

In November 2013, the Kraken field received Field Development Plan (FDP) approval which triggered the deferred consideration of US$45,000,000 due to Canamens Limited.  In addition, US$5,000,000 in respect of the Group's interest in Kraken and a further £7,000,000 (US$11,592,000) in respect of back-in payments associated with the sole risk drilling undertaken by the previous operator of the Kraken appraisal well and exploration sidetrack became payable. These amounts are included within 'Additions'.

The consideration payable to Nautical Petroleum plc and First Oil plc for 40% of the Kraken field in 2012 were development carries, split between a US$240,000,000 'firm' carry (payable on FDP approval) and a 'contingent' carry (payable up to US$144,000,000 subject to reserves determination).  US$320,000,000 has been included within 'Cost carry' above.  The remaining US$164,176,000 balance of the 'firm' carry and US$80,000,000 of the 'contingent' carry have been provided within financial liabilities (note 21) and provisions (note 23) respectively as at 31 December 2013.

Under the 2012 farm out agreement with KUFPEC for a 35% share of the Alma/Galia development.  KUFPEC were required to carry the Company for US$182,000,000.  This amount was initially recognised as an 'other receivable' (note 21) and then transferred to PP&E as the carry was exhausted.  During the year KUFPEC carried the company for US$98,300,000 (2012: US$86,698,000) under this carry arrangement.  The cost of the 35% share of assets disposed in 2012 was US$143,054,000.

There has been no impairment in the year ended 31 December 2013.  In the prior year the Heather and Broom hub was impaired by US$143,882,000 following a delay in phasing of production to allow drilling of the West Fault Block well at Thistle in 2013 and an increase in capital expenditure associated with the field life extension programme.  Refer to note 11 in respect of key assumptions used in value in use calculations.

At 31 December 2012, due to the recognition of proven and probable reserves for the Kraken field, US$61,994,000 of costs in relation to Kraken were reclassed from intangible to P,P&E.  Also during 2012, prior year pre-development costs in relation to Crawford and Porter (US$30,773,000) were transferred to intangible assets as a result of a decision to review development options.

The net book value at 31 December 2013 includes US$1,581,847,000 (2012: US$599,620,000) of pre-development assets and development assets under construction which are not being depreciated. Also US$10,142,000 of land and US$7,130,000 (2012: nil) of costs relating to the construction of the Group's new head office have not been depreciated.

The amount of borrowing costs capitalised during the year ended 31 December 2013 was US$1,241,000 and relate to the Alma/Galia and Kraken development projects as well as the construction of the new office building (2012: US$397,000). The weighted average rate used to determine the amount of borrowing costs eligible for capitalisation is 0.95% (2012: 0.84%).

The net book value of property, plant and equipment held under finance leases and hire purchase contracts at 31 December 2013 was US$141,000 (2012: US$141,000) of oil and gas assets. The net book value of US$10,695,000 (2012: nil) for land is held under a long lease. 

11.       Goodwill

A summary of goodwill is presented below:

	2013	2012
	US$'000	US$'000
At 1 January and 31 December	107,760	107,760

The balance represents goodwill acquired on the acquisition of Stratic and PEDL in 2010.  Goodwill acquired through business combinations has been allocated to a single cash-generating unit (CGU), the UKCS, being the Group's only significant operating segment and therefore the lowest level that goodwill is reviewed by the Board.

Impairment testing of goodwill

In assessing whether goodwill has been impaired, the carrying amount of the CGU, including goodwill, is compared with its recoverable amount. In certain circumstances IAS 36 allows the use of the most recent detailed calculations of the recoverable amount performed in an earlier period as the basis for the current year's goodwill impairment test.  The most recent detailed calculation of the recoverable amount was performed in 2012 and this has been used as the basis for the tests in the current year as the criteria of IAS 36 has been met. 

The recoverable amount of the CGU in 2012 was determined on a value in use basis using a discounted cash flow model comprising asset-by-asset life of field projections. The pre-tax discount rate used is derived from the Group's post-tax weighted average cost of capital. Risks specific to assets within the CGU are reflected within the cash flow forecasts.

Key assumptions used in value in use calculations

The key assumptions required for the calculation of value in use of the CGU are:

·      oil prices

·      production volumes

·      discount rates

Oil prices are based on forward price curves for the first five years before reverting to the Group's long term pricing assumptions. For the purposes of calculating value in use in the 2012 test, management applied an oil price assumption of US$107.60 per barrel in 2013, US$102.00 per barrel in 2014, US$97.80 per barrel in 2015, US$94.30 per barrel in 2016, US$91.70 per barrel in 2017 thereafter US$90 inflated at 2% per annum from 2013. 

Production volumes are based on life of field production profiles for each asset within the CGU. The production volumes used in the value in use calculations were taken from the report prepared by the Group's independent reserve assessment experts.

The discount rate reflects management's estimate of the Group's weighted average cost of capital (WACC). The

WACC takes into account both debt and equity. The cost of equity is derived from the expected return on investment by the Group's investors. The cost of debt is based on its interest-bearing borrowings. Segment risk is incorporated by applying a beta factor based on publicly available market data. The pre-tax discount rate applied to the Group's pre-tax cash flow projections in 2012 was 20.4%.

Sensitivity to changes in assumptions

The key assumptions to which the calculation of the value in use is most sensitive are oil price and production volumes. No sensitivities need to be included as there is not a reasonably possible change that could result in an impairment.

12.       Intangible oil and gas assets

		US$'000
Cost
At 1 January 2012		125,704
Additions		77,120
Acquisition of interests in licences		39,103
Write-off of relinquished licences previously impaired		(4,754)
Unsuccessful exploration expenditure written off		(6,514)
Reclassified to property, plant and equipment (note 10)		(31,221)
Reclassified from asset held for sale (note 13)		1,254
At 31 December 2012		200,692
Additions		30,852
Farm out		(2,648)
Acquisition of interests in licences		6,837
Write-off of relinquished licences previously impaired		(6,553)
Unsuccessful exploration expenditure written off		(704)
Change in decommissioning provision		(155)
Reclassified from property, plant and equipment (note 10)		448
At 31 December 2013		228,769
Provision for impairment
At 1 January 2012		(101,357)
Impairment charge for the year		(6,583)
Write-off of relinquished licences previously impaired		4,754
At 31 December 2012		(103,186)
Impairment charge for the year		(1,262)
Write-off of relinquished licences previously impaired		6,553
At 31 December 2013		(97,895)
Net carrying amount:
At 31 December 2013		130,874
At 31 December 2012		97,506
At 1 January 2012		24,347

Included within 'Acquisition of interests in licences' in 2013 is US$1,310,000 relating to a farm-in to a 50% non-operated interest in exploration licence P2006 Block 21/6b (Avalon) completed during the year. Also included is the Group's 50% interest in the North West October block in Egypt, acquired in December from Arabian Oil Company Limited (AOC), which is refundable by AOC in the event that first oil is not achieved by September 2014.

Included within 'Acquisition of interests in licences' in 2012 was the US$36,103,000 initial payment made for the acquisition of 20% of Kraken from Canamens Limited. On 31 December 2012, the costs associated with Kraken were reclassified to property, plant and equipment due to the recognition of 2P reserves.  In addition, costs of US$3,000,000 to acquire an interest in two exploration licences in Malaysia are included within 'Acquisition of interests in licences'.

In August 2013, an agreement was completed whereby KUFPEC UK Limited (KUFPEC) and Spike Exploration UK Ltd (Spike) are to take 25% and 30% working interests respectively in the Cairngorm discovery (blocks 16/2b and 16/3d).  KUFPEC and Spike have agreed to pay a premium by way of a promoted carry on the Cairngorm appraisal well and to pay their equity share of back costs of US$2,648,000 which are disclosed within 'Farm out' costs.

During the year ended 31 December 2013, US$6,553,000 of costs relating to relinquished licences previously impaired were written off (2012: US$4,754,000).

The impairment charge for the year ended 31 December 2013 includes costs in relation to the Peik licence which is in the process of being relinquished. During the year ended 31 December 2012 the impairment charge includes the costs of the Tryfan exploration well which proved to be uncommercial.

13.       Assets held for sale

		US$'000
At 1 January 2012		1,254
Reclassified to intangible fixed assets (note 12)		(1,254)
At 31 December 2013 and 31 December 2012		-

During 2011, the FQuad Dutch assets were reclassified as held for sale as they were subject to a swap arrangement whereby these were to be transferred to Sterling Resources Limited for a 50% share in the Cairngorm licence Block 16/3d.  This arrangement was finalised in December 2012 and therefore the costs were reclassified to intangible fixed assets.

14.       Investments

			US$'000
Cost
At 1 January 2012, 31 December 2012 and 31 December 2013			19,231
Provision for impairment
At 1 January 2012			(12,497)
Impairment charge for the year			(4,417)
At 31 December 2012			(16,914)
Impairment charge for the year			(312)
Reversal of impairment loss			398
At 31 December 2013			(16,828)
Net carrying amount:
At 31 December 2013			2,403
At 31 December 2012			2,317
At 1 January 2012			6,734

The investment relates to 160,903,958 new ordinary shares in Ascent acquired in 2011.  The accounting valuation of the Group's shareholding (based on the quoted share price of Ascent) resulted in an additional non-cash impairment of US$312,000 in the six months to 30 June 2013 (year ended 31 December 2012: US$4,417,000).  Since June 2013, the quoted share price has increased, resulting in a reversal of part of the impairment loss of US$398,000.  This has been recognised in the Available-for-sale reserve.  

15.       Inventories

	2013	2012
	US$'000	US$'000
Crude oil	16,273	15,301
Diesel	1,179	-
Materials	29,362	-
	46,814	15,301

16.       Trade and other receivables

	2013	2012
	US$'000	US$'000
Trade receivables	93,252	94,818
Joint venture receivables	116,341	100,918
Underlift position	17,248	9,242
VAT receivable	16,751	14,751
Other receivables	15,055	652
	258,647	220,381
Prepayments and accrued income	8,533	19,341
	267,180	239,722

Trade receivables are non-interest bearing and are generally on 15 to 30 day terms.

Trade receivables are reported net of any provisions for impairment. As at 31 December 2013 no impairment provision for trade receivables was necessary (2012: nil).

Joint venture receivables relate to billings to joint venture partners and were not impaired. At 31 December 2012 the amount included as due from KUFPEC in respect of the carry was US$53,261,000.

As at 31 December 2013 and 31 December 2012 no other receivables were determined to be impaired. 

The carrying value of the Group's trade, joint venture and other receivables as stated above is considered to be a reasonable approximation to their fair value largely due to their short-term maturities.

17.       Cash and cash equivalents

The carrying value of the Group's cash and cash equivalents is considered to be a reasonable approximation to their fair value due to their short-term maturities.  Included within the cash balance at 31 December 2013 is restricted cash of nil (2012: US$14,880,000) relating to cash held under Performance Guarantee Agreements with suppliers.

18.       Share capital

The share capital of the Company as at 31 December was as follows:

	2013	2012
Authorised, issued and fully paid	US$'000	US$'000
802,660,757 (2012: 802,660,757) Ordinary shares of £0.05 each	61,249	61,249
Share premium	52,184	52,184
	113,433	113,433

The share capital comprises only one class of Ordinary share. Each Ordinary share carries an equal voting right and right to a dividend.

There were no new issues of shares during 2013 or 2012.

At 31 December 2013 there were 25,510,520 shares held by the Employee Benefit Trust (2012: 22,966,471), the increase is due to the purchase of shares to satisfy awards made under the Company's share-based incentive schemes net of shares used during the year.

19.       Share-based payment plans

On 18 March 2010, the Directors of the Company approved three share schemes for the benefit of Directors and employees, being a Deferred Bonus Share Plan, a Restricted Share Plan and a Performance Share Plan.  A Sharesave Plan was approved in 2012.  The grant values for all schemes are based on the average share price from the three days preceding the date of grant.

Deferred Bonus Share Plan (DBSP)

Selected employees are eligible to participate under this scheme. Participants may be invited to elect or, in some cases, be required, to receive a proportion of any bonus in Ordinary shares of EnQuest (invested awards).  Following such award, EnQuest will generally grant the participant an additional award over a number of shares bearing a specified ratio to the number of his or her invested shares (matching shares). The awards granted in 2013, 2012 and 2011 will vest 33% on the first anniversary of the date of grant, a further 33% after year two and the final 34% on the third anniversary of the date of grant.  The awards granted in 2010 will vest 25% on the second anniversary of the date of grant, a further 25% after year three and the final 50% on the fourth anniversary of the date of grant. The invested awards are fully recognised as an expense in the period to which the bonuses relate. The costs relating to the matching shares are recognised over the vesting period and the fair values of the equity-settled matching shares granted to employees are based on quoted market prices adjusted for the trued up percentage vesting rate of the plan.

Details of the fair values and assumed vesting rates of the DBSP scheme are shown below:

	Weighted average fair value per share	Trued up vesting rate
2013 awards 2012 awards 2011 awards 2010 awards	127p 124p 137p 101p	99% 95% 78% 58%

The following shows the movement in the number of share awards held under the DBSP scheme outstanding:

	2013 Number*	2012 Number*
Outstanding at 1 January Granted during the year Exercised during the year Forfeited during the year	1,018,357 848,922 (359,077) (24,201)	526,080 783,410 (230,743) (60,390)
Outstanding at 31 December	1,484,001	1,018,357

* Includes invested and matching shares.

There were no share awards exercisable at either 31 December 2013 or 2012.

The weighted average contractual life for the share awards outstanding as at 31 December 2013 was 1.0 years (2012: 1.1 years).

The charge recognised in the 2013 statement of comprehensive income in relation to matching share awards amounted to US$1,058,000 (2012: US$701,000).

Restricted Share Plan (RSP)

Under the Restricted Share Plan scheme, employees are granted shares in EnQuest over a discretionary vesting period at the direction of the Remuneration Committee of the Board of Directors of EnQuest, which may or may not be subject to the satisfaction of performance conditions. Awards made in 2010, 2011, 2012 and 2013 under the RSP will vest over periods between one and four years. At present there are no performance conditions applying to this scheme nor is there currently any intention to introduce them in the future. The fair value of the awards granted under the plan at various grant dates during the year are based on quoted market prices adjusted for an assumed vesting rate over the relevant vesting period. 

Details of the fair values and assumed vesting rate of the RSP scheme are shown below:

	Weighted average fair value per share	Trued up vesting rate
2013 awards 2012 awards 2011 awards 2010 awards	127p 122p 119p 103p	98% 85% 92% 92%

The following table shows the movement in the number of share awards held under the RSP scheme outstanding:

	2013 Number	2012 Number
Outstanding at 1 January Granted during the year Exercised during the year Forfeited during the year	8,158,207 1,567,800 (1,055,827) (290,462)	8,305,132 686,000 (738,753) (94,172)
Outstanding at 31 December	8,379,718	8,158,207
Exercisable at 31 December	2,191,424	1,312,156

The weighted average contractual life for the share awards outstanding as at 31 December 2013 was 1.0 years (2012: 1.2 years).

The charge recognised in the year ended 31 December 2013 amounted to US$3,007,000 (2012: US$2,572,000).

Performance Share Plan (PSP)

Under the Performance Share Plan, the shares vest subject to performance conditions. The PSP share awards granted in 2011, 2012 and 2013 had three sets of performance conditions associated with them. One third of the award relates to Total Shareholder Return (TSR) against a comparator group of 36 oil and gas companies listed on the FTSE 350, AIM Top 100 and Stockholm NASDAQ OMX; one third relates to production growth per share; and one third relates to reserves growth per share, over the three year performance period.  Awards will vest on the third anniversary.

The fair value of the awards granted under the plan at various grant dates during the year are based on quoted market prices adjusted for an assumed vesting rate over the relevant vesting period. 

Details of the fair values and assumed vesting rate of the PSP scheme are shown below:

	Weighted average fair value per share	Trued up vesting rate
2013 awards 2012 awards 2011 awards	127p 124p 137p	97% 94% 96%

The following table shows the movement in the number of share awards held under the PSP scheme outstanding:

	2013 Number	2012 Number
Outstanding at 1 January Granted during the year Forfeited during the year	4,602,639 3,936,000 (239,613)	1,668,522 3,021,117 (87,000)
Outstanding at 31 December	8,299,026	4,602,639

There were no share awards exercisable at either 31 December 2013 or 2012.

The weighted average contractual life for the share awards outstanding as at 31 December 2013 was 1.5 years (2012: 1.9 years).

The charge recognised in the year ended 31 December 2013 amounted to US$4,066,000 (2012: US$1,802,000).

Sharesave Plan

The Group operates an approved savings related share option scheme.  The Plan is based on eligible employees being granted options and their agreement to opening a sharesave account with a nominated savings carrier and to save over a specified period, either three or five years.  The right to exercise the option is at the employee's discretion at the end of the period previously chosen, for a period of six months.

Details of the fair values and assumed vesting rates of the Sharesave Plan are shown below:

	Weighted average fair value per share	Trued up vesting rate
2013 awards 2012 awards	20p 20p	100% 83%

The following shows the movement in the number of share options held under the Sharesave Plan outstanding:

	2013 Number	2012 Number
Outstanding at 1 January Granted during the year Forfeited during the year	697,380       464,460     (75,720)	- 746,880       (49,500)
Outstanding at 31 December	1,086,120	697,380

There were no share options exercisable at either 31 December 2013 or 2012.

The weighted average contractual life for the share options outstanding as at 31 December 2013 was 2.5 years (2012: 2.9 years).

The charge recognised in the 2013 statement of comprehensive income amounted to US$62,000 (2012: US$88,000).

The Company has recognised a total charge of US$8,193,000 (2012: US$5,163,000) in the statement of comprehensive income during the year, relating to the above employee share-based schemes.

20.       Loans and borrowings

Revolving credit facility

At 31 December 2012 the Group had a US$900,000,000 multi-currency revolving credit facility agreement with Lloyds TSB Bank, Bank of America Merrill Lynch, Barclays, BNP Paribas, Crédit Agricole CIB, NICB Bank and Royal Bank of Scotland comprising a committed amount of US$525,000,000 with an additional US$375,000,000 available primarily for investment opportunities with the lenders' consent.

On 30 October 2013 the Group established a new six year US$1,700,000,000 multi-currency credit facility, comprising of a committed amount of US$1,200,000,000 with a further US$500,000,000 available through an accordion structure.

Interest on the revolving credit facility is payable at US LIBOR plus a margin of 2.50% to 3.75%, dependent on specified covenant ratios.  A facility non-utilisation commitment fee is payable at 40% of the interest margin.

At 31 December 2013, US$225,809,000 was drawn down under the Group's facility agreement (2012: US$34,600,000) and LoC utilisation was US$181,543,000 (2012: US$123,750,000).  Unamortised facility fees of US$26,413,000 have been netted off against the draw downs in the balance sheet.

The Group considers there to be no material difference between the fair values of the interest bearing loans and borrowings and the carrying amounts in the balance sheet.

Bond

In February 2013, the Group issued a 5.5% Sterling Retail Bond through the Order book for Retail Bonds (ORB) of the London Stock Exchange. The original bond raised £145,000,000 with an additional £10,245,000 issued in November 2013.

The bond pays a coupon of 5.5% payable bi-annually in February and August and matures in 2022.

The bond had a fair value of US$263,498,446 but is carried at its amortised cost of US$258,791,000.  The fair value has been determined by reference to the price available from the market on which the bond is traded.

21.       Other financial assets and financial liabilities

	2013	2012
	US$'000	US$'000
Financial instruments at fair value through other comprehensive income
Current liabilities
Cash flow hedges:
Forward foreign currency contracts	-	121
Financial instruments at fair value through profit or loss
Current assets
Derivatives not designated as hedges:
Commodity forward contracts	-	1,170
Forward foreign currency contracts	8,455	-
	8,455	1,170
Non-current assets
Derivatives not designated as hedges:
Forward foreign currency contracts	702	-
Current liabilities
Derivatives not designated as hedges:
Commodity forward contracts	5,084	299
Forward foreign currency contracts	631	-
	5,715	299
Non-current liabilities
Derivatives not designated as hedges:
Forward foreign currency contracts	839	-
Loans and receivables
Current assets
Other receivable	-	95,302
Non-current assets Other receivable	21,226	19,447
Other financial liabilities at amortised cost
Current liabilities
Other liability	164,176	17,150
Total current assets	8,455	96,472
Total non-current assets	21,928	19,447
Total assets	30,383	115,919
Total current liabilities	169,891	17,570
Total non-current liabilities	839	-
Total liabilities	170,730	17,570

Commodity forward contracts

In August and September 2013, the Group entered into five options in order to hedge the exposure to changes in future cash flows from the sale of oil production for approximately 3,600,000 barrels of oil in 2014.  These instruments were deemed to be ineffective for hedge accounting purposes and are therefore designated as 'At fair value through profit and loss' (FVTPL).  These contracts had a fair value of US$5,084,000 (loss).  Losses of US$5,084,000 were taken into profit and loss during the year and are included within other finance expenses.

In November 2012, the Group entered into three separate put and call options in order to hedge the exposure to changes in future cash flows from the sale of oil production for approximately 1,000,000 barrels of oil in the first quarter of 2013.  These instruments were deemed to be ineffective for hedging purposes and are therefore designated 'As at fair value through profit and loss' (FVTPL).  The derivative instruments had a net asset fair value of nil (2012: US$871,000).  The gains of US$871,000 at 31 December 2012 were reversed during the current year and have been taken to the income statement where US$1,170,000 is included within other finance costs and US$299,000 is included within other finance income.  

During 2013, additional put and call options hedging oil production for approximately 3,600,000 barrels of oil in 2013 were entered into but had expired by 31 December 2013.  Therefore there is no fair value or profit and loss account impact during the year.

Forward foreign currency contracts

During the year ended 31 December 2013, the Group entered into various forward currency contracts, namely Sterling, Euro and Norwegian Krone.  These contracts do not qualify for hedge accounting.  At 31 December 2013 these had a net fair value of US$7,688,000 (asset).  The gains of US$7,688,000 were recognised in profit and loss, US$9,158,000 shown within other finance income and US$1,470,000 shown within other finance expenses.  These contracts are due to expire during 2014 and 2015.

Also during the year various forward foreign currency contracts, namely Sterling and Euro, were entered into.  However, these had expired by 31 December 2013 and therefore have no fair value or impact on the income statement.

At 31 December 2012 three foreign currency contracts were held with a net fair value of US$121,000 (liability); these had fully unwound by 31 December 2013.  During 2013, the unrealised loss of US$46,000 net of deferred tax of US$75,000 was reversed through other comprehensive income.  There was no impact in profit or loss during the year in respect of these contracts (2012: nil).

Other receivable

As part of the farm out to KUFPEC of 35% of the Alma/Galia development, KUFPEC agreed to carry EnQuest up to a cap of US$182,000,000 and agreed to pay EnQuest a total of US$23,292,000 after production commences over a period of 36 months, the fair value of which was US$19,300,000.  Receivables were recognised for both of these at 31 December 2012.  At 31 December 2013, the carry element has fully unwound and during the year ended 31 December 2013, US$95,300,000 was capitalised within property, plant and equipment. The unwinding of discount on the other receivable of US$1,447,000 is included within finance income for the year ended 31 December 2013 (2012: US$479,000).

Other liability

Under the KUFPEC agreement a 'balancing payment' was also agreed whereby should the cost of development exceed US$1,055,000,000 then EnQuest would be required to pay 17.5% of costs up to a cap on the cost of development of US$1,153,000,000.  At 31 December 2012, as costs were expected to exceed the cap, a liability of US$17,150,000 was recognised.  This was subsequently settled during the year ended 31 December 2013.

The consideration for the acquisition of 40% of the Kraken field from Nautical and First Oil in 2012 was through development carries.  These were split into a 'firm' carry and a 'contingent' carry dependent upon reserves determination.  A financial liability is recognised at 31 December 2013 for the remainder of the 'firm' carry amounting to US$164,176,000.  This is expected to expire at the end of 2014 or early 2015.  The 'contingent' carry has been accounted for as a provision (note 23).

		Other liability	Other receivable
		US$'000	US$'000
At 1 January 2012		-	-
Additions during the year		17,150	114,602
Unwinding of discount		-	479
At 31 December 2012		17,150	115,081
Additions during the year		240,000	-
Utilised during the year		(92,974)	(95,302)
Unwinding of discount		-	1,447
At 31 December 2013		164,176	21,226

22.      Fair value measurement

The following table provides the fair value measurement hierarchy of the Group's assets and liabilities:

	Date of valuation	Total US$'000	Quoted prices in active markets (Level 1) US$'000	Significant observable inputs (Level 2) US$'000	Significant unobservable inputs (Level 3) US$'000
Assets measured at fair value:
Derivative financial assets
Forward foreign currency contracts	31 December 2013	9,158	-	9,158	-
Other financial assets
Available-for-sale financial investments
Quoted equity shares	31 December 2013	2,404	2,404	-	-
Liabilities measured at fair value:
Derivative financial liabilities
Forward foreign currency contracts	31 December 2013	1,470	-	1,470	-
Commodity forward contracts	31 December 2013	5,084	-	5,084	-
Other liability
Liabilities for which fair values are disclosed (notes 20 and 25)
Interest bearing loans and borrowings	31 December 2013	199,396	-	199,396	-
Obligations under finance leases	31 December 2013	107	-	107	-
Sterling retail bond	31 December 2013	263,498	-	263,498	-

There have been no transfers between Level 1 and Level 2 during the period.

The forward foreign currency and the commodity forward contracts were valued externally by the respective banks.

23.       Provisions

	Decommissioning provision	Carry provision	Total
	US$'000	US$'000	US$'000
At 1 January 2012	181,237	-	181,237
Additions during the year	37,609	-	37,609
Farm in to West Don	14,569	-	14,569
Farm out of Alma/Galia development	(7,054)	-	(7,054)
Changes in estimates	10,061	-	10,061
Unwinding of discount	10,148	-	10,148
Utilisation	(13,618)	-	(13,618)
At 31 December 2012	232,952	-	232,952
Additions during the year	3,941	80,000	83,941
Acquisition	27,341	-	27,341
Changes in estimates	(48,711)	-	(48,711)
Unwinding of discount	12,588	-	12,588
Utilisation	315	-	315
At 31 December 2013	228,426	80,000	308,426

Provision for decommissioning

The Group makes full provision for the future costs of decommissioning its oil production facilities and pipelines on a discounted basis.  With respect to the Heather field, the decommissioning provision is based on the Group's contractual obligation of 37.5% of the decommissioning liability rather than the Group's equity interest in the field.

The provision represents the present value of decommissioning costs which are expected to be incurred up to 2032 assuming no further development of the Group's assets. The liability is discounted at a rate of 5.0% (2012: 5.0%). The unwinding of the discount is classified as a finance cost (note 6).

These provisions have been created based on internal and third party estimates. Assumptions based on the current economic environment have been made which management believe are a reasonable basis upon which to estimate the future liability. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning liabilities is likely to depend on the dates when the fields cease to be economically viable. This in turn depends on future oil prices which are inherently uncertain.

Carry provision

Consideration for the acquisition of 40% of the Kraken field from Nautical and First Oil in 2012 was through development carries.  A provision has been recognised for the 'contingent' carry which is dependent on a reserves determination.  The reserves determination would be triggered by the carried parties, based on drilling work, or if later the date on which the 'firm' carry expires.  The 'contingent' carry is pro-rated between 100 and 166 million barrels of proven and probable reserves.  The FDP which was approved in November 2013 stated 137 million barrels and this would give rise to a carry of approximately US$80,000,000.  The carry is estimated to be paid 12 months after the 'firm' carry has expired in late 2014 or early 2015.

24.       Trade and other payables

		2013	2012
		US$'000	US$'000
Trade payables		131,526	81,885
Accrued expenses		231,295	232,877
Other payables		489	14,904
		363,310	329,666

Trade payables are non-interest bearing and are normally settled on terms of between 10 and 30 days. Certain trade and other payables will be settled in currencies other than the reporting currency of the Group, mainly in Sterling.

Accrued expenses include accruals for capital and operating expenditure in relation to the oil and gas assets.

The carrying value of the Group's trade and other payables as stated above is considered to be a reasonable approximation to their fair value largely due to the short-term maturities.

25.       Commitments and contingencies

Commitments

(i) Operating lease commitments

The Group has financial commitments in respect of non-cancellable operating leases for office premises. These leases have remaining non-cancellable lease terms of between one and nine years. The future minimum rental commitments under these non-cancellable leases are as follows:

	2013	2012
	US$'000	US$'000
Not later than one year	2,703	2,025
After one year but not more than five years Over five years	3,267 2,235	4,781 2,772
	8,205	9,578

Lease payments recognised as an operating lease expense during the year amounted to US$2,676,000 (2012: US$2,324,819).

Under the Dons Northern Producer Agreement a minimum notice period of 12 months exists whereby the Group expects the minimum commitment under this agreement to be approximately US$24,363,000 (2012: US$17,240,000).

(ii) Finance lease commitments

The Group had the following obligations under finance leases as at the balance sheet date:

	2013 Minimum payments		2013 Present value of payments	2012 Minimum payments	2012 Present value of payments
		US$'000	US$'000	US$'000	US$'000
Due in less than one year		36	35	37	34
Due in more than one year but not more than five years		74	72	110	107
		110	107	147	141
Less future financing charges		(3)	-	(6)	-
		107	107	141	141

The leases are fixed rate leases with an effective borrowing rate of 2.37% (2012: 2.37%)  and have an average remaining life of two years (2012: three years).

On 20 December 2013, the Group entered into a bareboat charter with Armada Kraken PTE Limited (Armada) for the lease of an FPSO vessel for the Kraken field. The lease will commence on the date of first production which is currently targeted to come onstream by 2017.  Armada will construct the vessel and the Group will incur an initial payment, before the lease commences, of US$100,000,000 due on certain milestones being reached by Armada.

 (iii) Capital commitments

At 31 December 2013, the Group had capital commitments excluding the above lease commitments amounting to US$447,293,000 (2012: US$203,620,000).

Contingencies

As part of the KUFPEC farm in agreement, a reserves protection mechanism was agreed with KUFPEC to enable KUFPEC to recoup its investment to the date of first production. If on 1 January 2017, KUFPEC's costs to first production have not been recovered or deemed to have been recovered, EnQuest will pay to KUFPEC an additional 20% share of net revenue (giving them 55% in total).  This additional revenue is to be paid from January 2017 until the actual net revenue or the deemed net revenue equals or exceeds the costs to first production.

In addition, there is contingent consideration of US$20,000,000 after the acquisition of Nio (Sabah) Limited which will be determined based on proven and probable reserves associated with an approved FDP on Blocks SB307 and SB308 in Malaysia.  An exploration/appraisal well is expected to be drilled in the area in 2014.

There is also deferred consideration of US$3,000,000 dependent on FDP approval in relation to the 20% interest in Kildrummy acquired from ENI UK Limited during the year ended 31 December 2012.

26.       Related party transactions

The Group financial statements include the financial statements of EnQuest PLC and its subsidiaries. A list of the Group's principal subsidiaries is contained in note 29 to these Group financial statements.

Balances and transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note.

All sales to and purchases from related parties are made at normal market prices and the pricing policies and terms of these transactions are approved by the Group's management.  There have been no transactions with related parties who are not members of the Group during the year ended 31 December 2013 (2012: nil).

Compensation of key management personnel

The following table details remuneration of key management personnel of the Group comprising Executive and Non-Executive Directors of the Company and other senior personnel:

	2013	2012
	US$'000	US$'000
Short term employee benefits	3,775	4,306
Share-based payments	4,314	4,086
Post employment pension benefits	31	30
	8,120	8,422

27.       Risk management and financial instruments

Risk management objectives and policies

The Group's principal financial assets and liabilities comprise trade and other receivables, cash and short term deposits, interest-bearing loans, borrowings and finance leases, derivative financial instruments and trade and other payables. The main purpose of these financial instruments is to manage short term cash flow and raise finance for the Group's capital expenditure programme.

The Group's activities expose it to various financial risks particularly associated with fluctuations in oil price, foreign currency risk, liquidity risk and credit risk. Management reviews and agrees policies for managing each of these risks, which are summarised below. Also presented below is a sensitivity analysis to indicate sensitivity to changes in market variables on the Group's financial instruments and to show the impact on profit and shareholders' equity, where applicable. The sensitivity has been prepared for periods ended 31 December 2013 and 2012 using the amounts of debt and other financial assets and liabilities held at those reporting dates.

Commodity price risk - oil prices

The Group is exposed to the impact of changes in Brent oil prices on its revenues and profits generated from sales of crude oil.

During 2012, the Board of EnQuest approved a policy to hedge up to a maximum of 75% of annual oil production.  In November 2011, the Group entered into five separate put and call options to hedge approximately 3,000,000 barrels of oil in 2012. During November 2012, the Company entered into three put and call options to hedge approximately 1,000,000 barrels of oil in the first quarter of 2013 and during the year the Group entered into put and call options covering a further 3,600,000 barrels of oil production for 2013.  These contracts consisted of put spreads at US$95-US$100 per barrel and US$70-US$75 per barrel and calls at an average of US$121.6 per barrel, all executed at nil cost.

In August and September 2013, some commodity hedging contracts were entered into partially to hedge the exposure to fluctuations in the Brent oil price during 2014.  A total of 3,600,000 barrels of puts (300,000 barrels a month) were bought at a price of US$106 per barrel and 7,200,000 barrels of calls were sold at a price of US$106, which are only triggered if the monthly average price of Brent exceeds a fixed price for the given month (ranging from US$119 to US$124 per barrel).  Since the year end the Company has swapped an additional 1,000,000 barrels in Q2 at prices of approximately US$109 per barrel.

The following table summarises the impact on the Group's pre-tax profit and total equity of a reasonably possible change in the Brent oil price, with all other variables held constant:

	Pre-tax profit			Total equity
	+US$10/Bbl  increase	-US$10/Bbl decrease		+US$10/Bbl  increase	-US$10/Bbl decrease
	US$'000	US$'000		US$'000	US$'000
31 December 2013	12,069	(35,907)		4,586	(13,645)
31 December 2012	76,337	(76,323)		29,008	(29,003)

This analysis includes the impact of the ineffective oil hedges outstanding on 31 December 2013.

Foreign currency risk

The Group has transactional currency exposures.  Such exposure arises from sales or purchases in currencies other than the Group's functional currency and the bond which is denominated in Sterling.  The Group manages this risk by converting United States Dollar receipts at spot rates periodically and as required for payments in other currencies.  Approximately 1% (2012: 1%) of the Group's sales and 91% (2012: 89%) of costs are denominated in currencies other than the functional currency.

During the year ended 31 December 2011, the Group had entered into 11 forward currency contracts partially to hedge the Group's exposure to fluctuations in foreign currencies, namely Sterling and Euro.  The contracts matured during 2012 and 2013.

During the first half of 2013, the Group entered into a series of forward contracts and structured products to hedge a portion of its Sterling, Euro and Norwegian Krone exposure throughout 2013 and 2014.  In 2013, a total of £223,000,000 was hedged at an average rate of US$1.51:£1.  The structured products have an average strike price of US$1.46:£1.  If the spot rate at expiry is above US$1.64:£1 then there is no trade and the Group funds its Sterling requirement through the spot market or drawing Sterling on the bank facility.  Between US$1.64:£1 and US$1.33:£1, EnQuest trades at the lower of US$1.46:£1 and the spot rate and below US$1.33:£1, EnQuest trades a higher volume of currency at US$1.46:£1.  This structure has also been used for hedging a total of £182,000,000 of Sterling exposure in 2014.

The same structure has also been used to hedge the Group's Norwegian Krone (NOK) exposure which arises as part of the Kraken development project.  In 2013, a total of NOK255,000,000 was hedged and in 2014 NOK367,000,000 has been hedged.

In 2013, EnQuest exchanged a total of €74,000,000 for US$96,000,000 mainly done by placing forward contracts, however €11,000,000 was placed on the same structured basis as the Sterling and Norwegian Krone arrangements described above. 

The following table summarises the impact on the Group's pre-tax profit and equity (due to the change in the fair value of monetary assets and liabilities) of a reasonably possible change in the United States Dollar to Sterling exchange rate:

	Pre-tax profit		Total equity
	+10% US Dollar rate increase	-10% US Dollar rate decrease	+10% US Dollar rate increase	-10% US Dollar rate decrease
	US$'000	US$'000	US$'000	US$'000
31 December 2013 31 December 2012	(30,917) (24,918)	30,917 24,918	(11,748)  (9,234)	11,748 9,234

Credit risk

The Group trades only with recognised international oil and gas operators and at 31 December 2013 there were no trade receivables past due (2012: nil), and US$1,981,000 of joint venture receivables past due but not impaired (2012: US$4,078,000).  Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary.

	2013	2012
Ageing of past due but not impaired receivables	US$'000	US$'000
Less than 30 days	4	143
30-60 days	-	144
60-90 days	-	78
90-120 days	-	89
120+ days	1,977	3,624
	1,981	4,078

At 31 December 2013, the Group had two customers accounting for 72% of outstanding trade and other receivables (2012: one customer, 87%) and three joint venture partners accounting for 99% of joint venture receivables (2012: three joint venture partners, 90%). 

With respect to credit risk arising from the other financial assets of the Group, which comprise cash and cash equivalents, the Group's exposure to credit risk arises from default of the counterparty, with a maximum exposure equal to the carrying amount of these instruments.

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.

Liquidity risk

The Group monitors its risk to a shortage of funds by reviewing its cash flow requirements on a regular basis relative to its existing bank facilities and the maturity profile of these facilities. Specifically the Group's policy is to ensure that sufficient liquidity or committed facilities exist within the Group to meet its operational funding requirements and to ensure the Group can service its debt and adhere to its financial covenants. Throughout the year and at 31 December 2013 the Group was in compliance with all financial covenant ratios agreed with its bankers.

At 31 December 2012 the Group had a US$900,000,000 multi-currency revolving credit facility agreement with Lloyds TSB Bank, Bank of America Merrill Lynch, Barclays, BNP Paribas, Crédit Agricole CIB, NICB Bank and Royal Bank of Scotland comprising a committed amount of US$525,000,000 with an additional US$375,000,000 available primarily for investment opportunities with the lenders' consent. On 31 October 2013, the Group established a six year US$1,700,000,000 multi-currency credit facility, comprising of a committed amount of US$1,200,000,000 with a further US$500,000,000 available through an accordion structure.  An upfront arrangement fee of 2.00% was payable.

Interest on the revolving credit facility is payable at LIBOR relative to each agreed loan period plus a margin of 2.50% to 3.75% dependent on the Group's leverage ratio. Facility non-utilisation commitment fees are payable at 40% of the interest margin. 

The maturity profiles of the Group's non-derivative financial liabilities are as follows:

Year ended 31 December 2013		On demand		Up to 1 year		1 to 2 years		2 to 5 years		Over 5 years		Total
		US$'000		US$'000		US$'000		US$'000		US$'000		US$'000
Loans and borrowings		-		26,100		21,580		38,310		255,809		341,799
Bond		-		14,140		14,140		42,418		299,502		370,200
Obligations under finance leases		-		35		36		36		-		107
Accounts payable and accrued liabilities		363,310		-		-		-		-		363,310
Other liability		-		164,176		-		-		-		164,176
Carry provision		-		-		80,000		-		-		80,000
		363,310		204,451		115,756		80,764		555,311		1,319,592
Year ended 31 December 2012	On demand		Up to 1 year		1 to 2 years		2 to 5 years		Over 5 years		Total
	US$'000		US$'000		US$'000		US$'000		US$'000		US$'000
Loans and borrowings	-		-		-		34,600		-		34,600
Obligations under finance leases	-		34		35		72		-		141
Accounts payable and accrued liabilities	329,666		-		-		-		-		329,666
Financial expenses	-		1,123		-		-		-		1,123
Other liability	-		17,150		-		-		-		17,150
	329,666		18,307		35		34,672		-		382,680

The following tables detail the Group's expected maturity of payables/(receivables) for its derivative financial instruments.  The amounts in these tables are different from the balance sheet as the table is prepared on a contractual undiscounted cash flow basis.

Year ended 31 December 2013
	On demand	Less than 3 months	3 to 12 months	1 to 2 years	>2 years	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Foreign exchange forward contracts	-	16,126	43,440	45,475	-	105,041
Foreign exchange forward contracts	-	(16,126)	(43,440)	(45,475)	-	(105,041)
	-	-	-	-	-	-
Year ended 31 December 2012
	On demand	Less than 3 months	3 to 12 months	1 to 2 years	>2 years	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Foreign exchange forward contracts	-	6,298	-	-	-	6,298
Foreign exchange forward contracts	-	(6,298)	-	-	-	(6,298)
	-	-	-	-	-	-

At 31 December 2012 and 2013, the Group held commodity forward contracts for which, based on the oil price at 31 December 2012 and 2013, there were no projected contracted cash flows.

Capital management

The capital structure of the Group consists of debt, which includes the borrowings disclosed in notes 20 and 25, cash and cash equivalents and equity attributable to the equity holders of the parent, comprising issued capital, reserves and retained earnings as in the Group Statement of Changes in Equity on page 87.

The primary objective of the Group's capital management is to optimise the return on investment, by managing its capital structure to achieve capital efficiency whilst also maintaining flexibility for future acquisitions.  The Group regularly monitors the capital requirements of the business over the short, medium and long term, in order to enable it to foresee when additional capital will be required.  Note 20 to the financial statements provides further details of the Group's financing activity.

The Group has approval from the Board to hedge the exchange risk on up to 70% and 50% of the non US Dollar portion of the Group's annual capital budget and operating expenditure respectively.  In addition there is approval from the Board to hedge up to 75% of annual production in year 1, 60% in year 2 and 50% in year 3. This is designed to minimise the risk of adverse movements in exchange rates and prices eroding the return on the Group's projects and operations.

The Board regularly reassesses the existing dividend policy to ensure that shareholder value is maximised.  It continues to believe that, in the light of the Group's significant capital projects and exploration and acquisition opportunities, the enhancement of shareholder value can best be achieved by reinvesting the Group's cash.  Any future payment of dividends is expected to depend on the earnings and financial condition of the Company and such other factors as the Board considers appropriate.

The Group monitors capital using the gearing ratio and return on shareholders' equity as follows:

	2013		2012
	US$'000		US$'000
Loans, borrowings and bond net (A)	453,896		34,600
Cash and short term deposits	(72,809)		(124,522)
Net debt/(cash) (B)	381,087		(89,922)
Equity attributable to EnQuest PLC shareholders (C)	1,484,709		1,293,869
Profit for the year attributable to EnQuest PLC shareholders (D)	189,604		362,218
Profit for the year attributable to EnQuest PLC shareholders excluding exceptionals (E)	193,149		259,665
Gross gearing ratio (A/C)	0.306		0.027
Net gearing ratio (B/C)	0.257		n/a
Shareholders' return on investment (D/C)	13%		28%
Shareholders' return on investment excluding exceptionals (E/C)	13%		20%

28.       Post balance sheet events

In January 2014, EnQuest was offered and accepted two licences in the Norwegian 2013 Awards in Pre-defined Areas licensing round, both located in the Norwegian Sea.  EnQuest was offered production licence 758 (Rosslyng), with EnQuest as the operator and having a 35% interest.  EnQuest was also offered licence 760 (Chinook), with Total as the operator, both Total and EnQuest having a 50% interest each. In both cases, the work commitments in the initial two year period entail 3D seismic licensing and reprocessing.

In Q1 2014, EnQuest accepted an 'out of round' licence in the Don North East (Don NE) area for blocks 211/18e and 211/19c, including Area 23 and Area 24 and an undrilled extension to the Don NE field.  Within the first twelve months of the licence, it is intended to submit a field development plan in relation to Area 24, to include at least one production well.  This will provide further opportunities to enhance Dons area production.

Acquisition of Greater Kittiwake assets

On 22 October 2013, the Group announced an agreement with Centrica North Sea Oil Limited (Centrica) to acquire the UKCS Greater Kittiwake area assets as well as Centrica's 100% interest in the Kittiwake to Forties oil export pipeline.  Consideration is US$39,900,000 and will additionally assume net debt of US$5,100,000, which is subject to certain working capital and other adjustments.  The Group acquired the Greater Kittiwake assets partly due to its proximity to the Scolty/Crathes field and the potential for a tie-back, in addition, the Group sees significant potential to improve production through infill drilling and through exploring further prospects in the area.

The acquisition completed on 28 February 2014.

The provisional fair values of the identifiable assets and liabilities of Greater Kittiwake, as at the date of acquisition are:

	Provisional fair value recognised on acquisition
	US$'000
Property, plant and equipment Intangible assets Working capital Underlift position	59.2 19.8 (9.2) 6.0
Decommissioning provision	(66.2)
Deferred tax liability	(7.9)
Total identifiable net assets at fair value	1.7
Goodwill arising on acquisition	55.0
Purchase consideration	56.7

Purchase consideration

	US$'000
Purchase consideration transferred	30.0
Contingent consideration	26.7
Total purchase consideration	56.7

The fair values are provisional as the acquisition completed after the year end and a full assessment of the fair values is still required.  The review of the fair value of the assets and liabilities acquired will be completed within 12 months of the acquisition.

The goodwill of US$55,000,000 comprises the value of expected synergies arising from the acquisition.  None of the goodwill recognised is expected to be deductible for income tax purposes.

As the acquisition did not complete prior to the end of the year then there has been no contribution to revenue or profit before tax for the Group.

Transaction costs have been expensed and will be included in administration expenses.

The Group will pay deferred consideration of US$30,000,000 contingent on regulatory approval of a Field Development Plan for the Scolty field and/or the Crathes field.  This has been fair valued at US$18,000,000. In addition contingent consideration may be payable subject to future exploration success with a fair value of US$8,700,000.  At the acquisition date, the fair value of the total contingent consideration was estimated to be US$26,700,000. 

29.       Subsidiaries

At 31 December 2013, EnQuest PLC had investments in the following subsidiaries:

Name of company	Principal activity	Country of incorporation	Proportion of nominal value of issued shares controlled by the Group
EnQuest North Sea BV	Intermediate holding company	Netherlands	100%
EnQuest Britain Limited	Intermediate holding company and provision of Group manpower and contracting/procurement services	England	100%
EnQuest Dons Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Dons Oceania Limited (i)	Exploration, extraction and production of hydrocarbons	Cayman Islands	100%
EnQuest Heather Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Thistle Limited (i)	Extraction and production of hydrocarbons	England	100%
Stratic Energy (UK) Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
Stratic UK (Holdings) Limited (i)	Intermediate holding company	England	100%
Grove Energy Limited (i)	Intermediate holding company and exploration of hydrocarbons	Canada	100%
Grove Energy (Tunisia) Limited (i)	Exploration, extraction and production of hydrocarbons	USA	100%
EnQuest ENS Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest UKCS Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Norge AS EnQuest Heather Leasing Limited (i) Nio Petroleum (Sabah) Limited (i) EnQuest Dons Leasing Limited (i)	Exploration, extraction and production of hydrocarbons Leasing Exploration, extraction and production of hydrocarbons Dormant	Norway England England England	100%                100%                100%                100%
EQ Property Limited (i)	Property development	England	100%
EnQuest Energy Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Production Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Global Limited (i)	Intermediate holding company	England	100%
EnQuest NWO Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Malaysia Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest UK Limited (i)	Dormant	England	100%
EnQuest ED Limited (i)	Dormant	England	100%
EQ Petroleum Developments Malaysia SDN. BHD (i)	Exploration, extraction and production of hydrocarbons	Malaysia	100%
(i)            Held by subsidiary undertaking.

 

END

 

 

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