Final Results

RNS Number : 1184A

EnQuest PLC

27 March 2012

ENQUEST PLC, 27 March 2012

Results for the 12 months to 31 December 2011

Delivering Strong Growth

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

Highlights

· EnQuest PLC, performed strongly in 2011, with a 12.5% increase in production over pro-forma^* 2010

· EnQuest's net 2P reserves at the start of 2012 were 115.2 MMboe, a 30.2% increase on the start of 2011, reflecting a reserves replacement ratio of 419.4%

· Cash flow from operations was $656.3m, resulting in net cash of $378.9m at the end of the period.

· A new credit facility of up to $900m was finalised in Q1 2012, securing EnQuest access to further capital resources

· Four significant business development transactions were agreed in 2011, with a further three so far in 2012

· Performance in Q1 2012 is on track for EnQuest's previously announced full year 2012 production target of between 20,000 Boepd and 24,000 Boepd

	Reported		Pro-forma*	Reported	Change**
		2011	2010	2010	%
Production (Boepd)		23,698	21,074	-	12.5
Revenue ($m)		936.0	614.4	583.5	52.3
Realised oil price $/bbl (reflecting hedge)		107.6	81.3	-	32.3
Gross profit ($m)		444.2	208.0	199.0	113.6
Profit before tax & net finance costs ($m)		390.1	169.4	163.7	130.3
EBITDA***		629.1	369.3	-	70.3
Cash flow from operations ($m)		656.3	-	267.7	145.2
Cash flow from operations per share (cents)		81.9	-	39.0	110.0
Earnings per share (cents)		7.6	-	4.0	90.0
Net cash ($m)		378.9	-	41.4	815.2

* The pro-forma data in the above table presents the trading results for the combination of the legal entities which include all of the producing assets from the start of the 2010 calendar year, as though the combination was part of the Group for the full 12 months ended 31 December 2010. ** 2011 reported business performance against 2010 pro-forma for production and income statement items for EBITDA and above, 2011 reported against 2010 reported financial results for items below EBITDA. *** EBITDA is calculated by taking profit from operations before tax and finance income/(costs),deducting gain on disposal of asset held for sale and adding back depletion, depreciation, impairment, gain on disposal and write off of tangible and intangible oil and gas assets.

EnQuest CEO Amjad Bseisu said:

"2011 was another strong year for EnQuest as our operational performance continued to generate high levels of cash flow. We produced an average of 23,698 Boepd in 2011, reinforcing our position as the largest UK independent producer in the UK North Sea. Each of our hubs increased production, with Thistle's gross production being over 2 MMboe for the first time in a decade. We successfully brought the 29 MMboe Alma and Galia development to sanction, formal field development approval is imminent.

We have also significantly consolidated and expanded our asset base, adding interests at Broom, Crawford/Porter, Crathes/Scolty, Kildrummy and Kraken, assuming operatorship and control where we did not already hold it. EnQuest will be the operator of all of its hubs and all but one of its undeveloped discovery blocks in 2012. This is central to EnQuest's model of adding value to assets through its operational and project development expertise. We are also pleased to announce today that we have agreed to purchase an additional 18.5% interest in West Don, increasing our interest to 63.45%.

EnQuest welcomes the recent oil and gas investment fiscal adjustments in the UK 2012 Budget, including the improvements to encourage the development of small fields. These positive fiscal changes clearly make the UK Oil and Gas sector more competitive. EnQuest will continue to work with the Government and the industry to achieve further development of the substantial unrealised potential in the UK North Sea. Following EnQuest's nine well programme and $361 million of capital expenditure in 2011, EnQuest anticipates investing around $1,000 million in 2012. Oil & Gas UK estimate that this level of investment potentially creates around 9,000 jobs, directly and indirectly. EnQuest's 2012 capital programme includes 11 new wells and puts the Alma and Galia development on track for first oil by the end of 2013.

EnQuest remains confident in its production growth targets for the medium term and reaffirms its earlier guidance of net production greater than 40,000 Boepd by 2014. There is additional future production potential in the discoveries at Kraken, Kildrummy, Crawford and in the Crathes area. EnQuest has the operational capability and the financial capacity to ensure sustainable delivery of long term growth."

Production, Development & Reserves

	Reported Net daily average	Pro-forma* Net daily average		Reported Net cumulative	Pro-forma* Net cumulative
	FYR'11		FYR'10	FYR'11	FYR'10
	(Boepd)	(Boepd)		(Boe)	(Boe)
Thistle/Deveron	5,436	4,836		1,984,156	1,765,269
The Don Fields	12,770	11,660		4,661,216	4,255,704
Heather/Broom	5,492	4,578		2,004,554	1,671,011
Total	23,698	21,074		8,649,926	7,691,984

In 2011, all three asset hubs showed good production growth on the equivalent period in 2010.

Thistle/Deveron

· Production increased by 12.4% compared to 2010

· Well A56/13 (formerly NWFB-P1) came on stream in May 2011

· Well A57/58 (formerly EFB-P1) came on stream in October 2011

· The DEV-P1 is successful and is expected to start up shortly

Don and Conrie fields

· Production increased by 9.5% compared to 2010 and contributed over 50% to total EnQuest production in 2011

· The S8Z producer and the S9 injector wells on Don Southwest were completed successfully in Q3 2011

· The Area E exploration well S7 was successful in Q1 2011, and was brought on stream less than eight months later, in August 2011. The discovery is now known as the Conrie field

· Although the S8Z and S7 wells both declined more quickly than anticipated, they subsequently stabilised and are successful wells

Heather/Broom

· Production increased by 20.0% compared to 2010. This resulted from the benefit of the mid-year increase in EnQuest's working interest in Broom from 55% to 63% and from better than expected performance from the existing well stock. The Broom field also had a full year's benefit of the new Broom to Heather flowline which was installed in 2010

· The rig reactivation programme on Heather is now well underway, drilling activity will commence in late 2012

Development

· Formal field development approval for the Alma/Galia development is anticipated imminently, this adds a fourth hub, with peak gross production of over 20,000 Boepd

Reserves

· 30.2% year on year growth in audited net 2P reserves to 115.2 MMboe, an excellent reserves replacement ratio of 419.4%, after production of 8.6 MMBoe during 2011. Net 2P reserves growth was driven by 29.3 MMboe from Alma/Galia

Financial

· 2011 revenue of $936.0m was 52.3% higher than the pro-forma equivalent for 2010, due to the combined impact of the increase in production and an increase in the realised average price per barrel of oil sold

· Strong cash generation, with cash flow from operations of $656.3m, resulting in net cash at the end of the period of $378.9m

· 2011 profit from operations before tax and net finance costs was $390.1m, compared to a pro-forma equivalent of $169.4m in 2010

· Unit production and transportation cost per barrel was $31.9, reflecting production increases from the Dons and Thistle and the costs of a major Thistle shutdown programme and a Don Southwest well intervention

· Capex of $360.6m was mainly invested in the nine well drilling programme, this included four production wells, the S7 on Conrie, the S8Z on Don Southwest and the A56/13 and the A57/58 on Thistle and also the successful Crathes exploration well. Approximately $80m was incurred on the Alma and Galia development, enabling the commencement of drilling in Q1 2012

· New credit facility announced today. In Q1 2012 EnQuest secured a new Multi-Currency Revolving Credit Facility of up to $900m, for up to five years, comprising a committed $525m, with a further $375m available with the lenders' consent, primarily for acquisitions

Business Development

§ Further acquisition announced today

- An additional 18.5% interest in West Don, being acquired from JX Nippon Exploration and Production (UK) Ltd ('JX') for a cash consideration of $34m. This acquisition includes $2m of tax allowances and it takes EnQuest's holding in West Don to 63.45%. Completion of the transaction is subject to co-venturer approvals

Outlook 2012 and beyond

Summary

· Despite particularly difficult weather conditions in the Northern North Sea in Q1 2012, average net export production in 2012 remains on track to meet the full year target of an average of between 20,000 Boepd and 24,000 Boepd, this reflects natural declines compared to 2011, and is ahead of Alma and Galia coming on stream in 2013

· EnQuest is also reaffirming its anticipation of producing between 25,000 Boepd and 30,000 Boepd for 2013, and in excess of 40,000 Boepd for 2014

· Capex in 2012 will be approximately $1,000m, with around $500m on Alma/Galia. As a result of this extensive capital programme, EnQuest has hedged approximately 3 MMboe of production, for 2012. The hedging programme uses a put spread of $95/bbl and $70/bbl, with the call at an average of approximately $122/bbl, all executed on a costless basis

· Total production and transportation costs in 2012 are anticipated to be broadly similar to 2011

· Exploration and Appraisal. An exploration well will be drilled on Tryfan and an appraisal well at the Kildrummy discovery

· EnQuest continues to look at additional acquisition opportunities both in the UK and internationally

By Asset

· Thistle/Deveron. Well DEV-P1 was completed in Q1 2012 and is due to start production shortly, the Area 6-P1 (ESP) production well is due to come on stream in Q4 2012.

· Dons/Conrie. In Don Southwest two wells will be drilled; a replacement for S1 will be drilled in an updip location and a new well will be drilled to the highest point of the horst updip of the successful S5 well. On West Don, W2 will be sidetracked in Q3 2012 and a new water injection well W5, will be drilled in Q4 2012.

· Heather. Following the completion of the rig reactivation programme, drilling activity will start in Q4 2012

· Alma/Galia. Drilling commenced in January 2012. The Uisge Gorm Floating Production and Storage Offloading vessel ('FPSO') was procured (renamed as the EnQuest Producer) and moved to Hamburg to begin modification and life extension works

· Crathes/Scolty/Torphins. Following the successful Crathes exploration well, the commerciality of these discoveries will be assessed

· Crawford. Development options are being assessed and a development decision is anticipated in 2012

· Kraken. EnQuest anticipates taking on operatorship and is working with the partners to deliver first oil in 2015

Ends

For further information please contact:

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

Amjad Bseisu (Chief Executive)

Jonathan Swinney (Chief Financial Officer)

Michael Waring (Head of Communications & Investor Relations)

Finsbury Tel: +44 (0)20 7251 3801

James Murgatroyd

Conor McClafferty

Dorothy Burwell

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:

UK: +44 (0) 20 7784 1036

USA: +1 646 254 3367

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 assets include the Thistle, Deveron, Heather, Broom, West Don, Don Southwest and Conrie producing fields and the Alma and Galia development. At the end of 2011, EnQuest had interests in 22 production licences covering 27 blocks or part blocks in the UKCS, of which 19 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.

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.

Chairman's Statement

Overview

I am pleased to report that EnQuest delivered another strong performance in 2011. Production was up 12.5% on 2010 and reserves replacement, at a ratio of over 400%, was well ahead of the targets set out at the time of EnQuest's IPO. The operational capabilities of the EnQuest organisation have grown significantly during the year. EnQuest's basic earnings per share were 7.6 cents in 2011, up by 90% over 2010. EnQuest is continuing to deliver on the plans it laid out at the time of its inception.

Market conditions

In 2011, EnQuest's average realised oil price, net of hedging, was $107.6 per barrel, up from $81.3 per barrel in 2010. EnQuest's averaged invoiced oil price in 2011 was $111.8 per barrel.

Oil prices, although volatile, nonetheless stayed above $100 per barrel for most of 2011. This was due partly to a general tightness in the markets for crude oil, exacerbated by increased levels of producer domestic consumption and by supply disruption from North Africa and the Middle East, in particular Libya, and Iran. Despite the uncertainties in the global economy which continue today, it seems clear that following the 'Arab Spring', there have been structural increases in the level of social costs in Middle Eastern countries. Maintaining oil prices at high levels will be critical if Middle Eastern countries are to meet these increased costs. High prices have not stimulated a dramatic supply expansion and the Organisation of Petroleum Exporting Countries has adjusted its price targets.

EnQuest, along with the industry, has been actively engaged in working with the UK Government to promote changes in the fiscal structure and is encouraged by the UK North Sea investment incentive measures recently announced in the 2012 Budget.

Macro-economic concerns have again focused attention on the challenges companies face in accessing capital to fund developments and acquisitions. EnQuest is fortunate to be differentiated by the strength of its balance sheet and its cash flow and consequently by the scale of the borrowing facilities it can secure, as demonstrated by its new $900 million credit facility. In these difficult markets, EnQuest's technical skills, operational scale and considerable financial strength are substantial competitive advantages.

The EnQuest model

EnQuest's development and production model is focused on realising the untapped potential in mature assets and undeveloped oil fields. EnQuest concentrates on production hubs, on near field appraisal and exploration, and on business development. Members of the Board and I have had considerable experience of successfully deploying this model. Reassessing and redeveloping fields is a relatively low risk way of steadily generating shareholder value. Now, two years post IPO, we believe it has been successfully established at EnQuest. Indeed EnQuest has created a powerful new force in integrated development. This has enabled us to sanction the Alma and Galia development, EnQuest's fourth hub and a substantial contributor to our expected production growth. Formal field development ('FDP') approval for Alma/Galia is anticipated in the coming weeks.

The EnQuest Board

During EnQuest's critical early days it was invaluable to have Alexandre Schneiter as a non-executive director, given his knowledge of the Heather/Broom and Thistle/Deveron hubs through his association with Lundin Petroleum AB. Alexandre was however not independent for the purposes of the Combined Code, and therefore EnQuest undertook that he would in due course stand down from the Board. Alexandre Schneiter will duly be retiring at the Annual General Meeting on 30 May 2012. The Board and I would like to thank Alexandre for his important contribution to the successful establishment and subsequent development of EnQuest. The Board plans to appoint a new independent non-executive director in due course.

In July 2011, I was delighted to welcome Clare Spottiswoode to the Board as a new EnQuest non-executive director. Clare's wealth of experience, from within and beyond the energy industry, makes her a valuable addition to the Board.

The Board would like to thank EnQuest's employees for their continuing commitment, enthusiasm and support. EnQuest's values are critical to our success; respect, focus, agility, creativity, passion, collaboration and empowerment. EnQuest people live and breathe these values and this has been essential to the delivery of the achievements we are reporting today.

The updated EnQuest Code of Conduct

In 2010, EnQuest launched its Code of Conduct, setting out the behaviour EnQuest expects of its directors, managers and employees, of our suppliers, contractors, agents and partners. EnQuest is committed to complying with the applicable legal requirements, to upholding the highest ethical standards and to acting with complete integrity at all times. In 2011, EnQuest launched an updated version of the Code of Conduct. While the majority of the existing code remains in place, we have augmented the sections dealing with business ethics, in particular those impacted by the UK Bribery Act, these include sections on business gifts and entertainment, as well as facilitation payments and how EnQuest must deal with partners and suppliers. The integrity of EnQuest's employees and everyone we work with underpins our future progress and success.

Delivering sustainable growth

2011 was an important year for EnQuest, one of both consolidation and growth, bedding in and developing the organisation we launched in 2010 and putting in place the people and structures to execute our long term growth plans. EnQuest's focus on hubs delivered strong production growth, as well as the sanction of Alma and Galia. We had an active business development programme and consolidated our positions in Broom, Crawford and Porter and we also farmed in to the Kildrummy discovery. The strong 2011 reserves and resources performance has already been materially augmented in 2012, with the acquisition of a 45% stake in the Kraken discovery. The macro environment has thrown up challenges, but also opportunities, and the EnQuest team has been able to respond quickly and effectively. The EnQuest Board remains as excited and confident as ever of EnQuest's very considerable potential.

Chief Executive's Report

Delivering strong growth

2011 was a strong year for EnQuest, with annual production at 23,698 Boepd, up 12.5% on 2010. Our operations generated an excellent financial performance with cash flow from operations of $656.3 million and EBITDA of $629.1 million. Profit before tax and net finance costs increased to $390.1 million, up 130.3% on the prior year pro-forma equivalent. At the end of 2011, audited net 2P reserves were 115.2 MMboe, an increase of 30.2% over 2010 and of 43.1% over IPO levels, well above our 10% per annum long term reserves growth target. This 115.2 MMboe at the end of 2011, represents an excellent reserve replacement ratio of 419.4%. This growth in reserves was driven partly by the Alma and Galia development project, and also by our active business development programme. These transactions brought further consolidation of EnQuest's existing asset positions and also took us into a number of new development projects.

In 2011 EnQuest put in place the organisational building blocks needed to ensure sustainable delivery of medium and long term growth. The substantial growth in reserves demonstrates EnQuest's ability to deliver sustainable production growth for the medium and the long term.

EnQuest's 2011 production of 23,698 Boepd represents a further consolidation of our position as the largest UK independent producer in the UK North Sea. The strong production performance reflected good growth at each of our three existing production hubs, we invested $360.6 million in 2011, with nine wells drilled and four production wells brought on stream.

Implementing EnQuest's development and production focused strategy

With approximately 340 undeveloped fields in the UKCS, there is a significant opportunity for EnQuest in the UK North Sea, particularly in the smaller oil fields which we target. EnQuest is the right company in size, scale and financial strength to exploit the remaining opportunities in the North Sea and beyond. We are focused on both existing and new hubs, on low cost near field exploration and appraisal and on business development opportunities. Our business model extends asset lives to realise the untapped potential in maturing assets, as well as resources within undeveloped oil fields.

In 2011, through our hub focus we added 29.3 MMboe to EnQuest's net 2P reserves for the Alma Galia development. We delivered exploration successes with the Conrie and Crathes discoveries. Our execution skills are exemplified by our Conrie discovery and development which took less than eight months between discovery and first oil. The Kildrummy appraisal farm in agreed at the end of the year was the last of a steady flow of business development transactions in 2011.

EnQuest significantly increased its technical capabilities during 2011, enabling us to take on large development opportunities such as Alma and Galia, and more recently Kraken. Once we have identified opportunities, EnQuest uses its considerable expertise and capability to find and implement the right development solution to bring projects on stream, in a timely and cost efficient manner.

A leading force in integrated development

In 2011, EnQuest developed its operations organisation at all levels. In Aberdeen we have what we believe is one of the best teams in the UK, leaders in innovative and cost efficient developments. The wells delivery team in particular has produced a number of industry leading performances, including a 12,650ft bit run for the Conrie exploration well in the Dons area.

These capabilities are a key differentiator and are critical to our ability to add value to the projects which EnQuest invests in. We have continued to add highly skilled industry professionals with extensive experience. This scale of organisational development is critical to delivering EnQuest's ambitious growth plans. With the EnQuest workforce now more than double its size at flotation, we are ready for the next phase of our growth and beyond. The EnQuest development machine is in place.

Heath, safety, environment and quality ('HSEQ')

HSEQ is EnQuest's top priority. It is a critical and a deeply embedded part of our culture and values, and is integral to how we manage our business, with regard to people, installations and the environment in which we operate.

In 2011, EnQuest's safety performance was strong, achieving performance levels which were in the top quartile for the industry. We evolved and strengthened the HSEQ team with the appointment of a new head of Health, Safety, Environment and Quality, and with the creation of three other new professional positions. This additional focus will help to bring further rigour to our performance and operational HSEQ measures, reinforcing a proactive continuous improvement culture in all of our assets and development projects.

EnQuest's first new hub - the Alma and Galia development

In November 2011, EnQuest gave its internal sanction to the Alma and Galia joint development, subject to anticipated regulatory approvals. The Alma and Galia base case adds 29.3 MMboe to EnQuest's net 2P reserves, underpinning our medium term production growth. First oil is expected in Q4 2013, with peak gross production of over 20,000 Boepd. This project is anticipated to increase EnQuest's production levels to over 40,000 Boepd in 2014, approximately a two thirds increase on 2011. EnQuest intends to fund this development fully from current financial resources. EnQuest secured the Alma and Galia licences as part of the 26^th licensing round, and the project was sanctioned less than a year after award. First oil is targeted two years from project sanction. Field Development Plan ('FDP') approval is anticipated in the coming weeks, following which EnQuest expects to review a number of farm in proposals from potential partners.

The Alma/Galia project exemplifies EnQuest's capabilities, deploying many of the skills and methodologies used on the Don fields development, with a fast track development solution, reusing an existing facility. The development will be tied back to the modified EnQuest Producer, a Floating, Production, Storage and Offloading ('FPSO') vessel. EnQuest took out an option to purchase this FPSO from Bluewater Operations Limited, and this was duly exercised in Q1 2012, for a cash consideration of $52.5 million. Alma, originally named the Argyll field, was the very first oil field developed in the UK and was abandoned in 1992 at a 70% water cut. The EnQuest development plan is designed to be capable of processing high water cut levels in excess of 95%. Using established modern technology, the lives of these two fields can now be extended significantly.

Business development and EnQuest asset update

EnQuest's asset base continues to grow, Alma/Galia will be our fourth hub and will take us from seven to nine operated producing fields. In 2011, our business development efforts successfully demonstrated that there continue to be good opportunities in the North Sea, where we consolidated our positions in existing assets, as well as entering into new appraisal and development opportunities.

In May 2011, EnQuest agreed to increase its interest in Crawford/Porter from 19% to 51%, in exchange for carrying the previous operator's development costs, up to a maximum of $55.8 million. In August 2011, EnQuest announced an increase in its stake in the producing Broom field, up by 8% to 63% for $7.5 million, increasing net 2P reserves by almost 1 MMboe. At the same time, EnQuest announced its farm in to the Crathes prospect, taking a 40% interest and assuming operatorship for zero consideration. The subsequent exploration well at Crathes was successful and EnQuest is evaluating the potential commerciality of the Scolty, Crathes and Torphins area. Finally, in November 2011, EnQuest agreed to farm in to a 40% interest in the Kildrummy discovery, and to assume operatorship of the project.

EnQuest's acquisition model is predicated on the value we can add to projects through our integrated development skill set, rather than on being able to secure assets below market value. EnQuest maintains a disciplined and rigorous approach to reviewing potential opportunities, requiring projects and acquisitions to meet returns criteria dependent on the specific risk profile.

Another strong financial performance - cash flow from operations of $656.3 million

Profit before tax and net finance costs increased by 130.3% on the prior year pro-forma equivalent to $390.1 million. Pre-exceptionals EBITDA rose by 70.3% to $629.1 million and cash flow from operations was up 145.2% to $656.3 million, both driven by the increased production and the increase in the oil price. The same factors led to a 110.0% increase in reported cash flow from operations per issued Ordinary share, up to 81.9 cents per share from 39.0 cents per share in 2010. EnQuest continues to have a strong balance sheet, with net cash at the year end of $378.9 million, up substantially from the $41.4 million at the end of 2010. The unit cost of sales production and transportation was $31.9 per Boe in 2011, up on the pro-forma $30.4 per Boe in 2010. The increase was related to the net impact of the costs of the Thistle shutdown programme and the Don Southwest well intervention, offset by production increases from the Don and Thistle fields. Capital expenditure was $360.6 million in 2011, this included expenditure in relation to EnQuest's sanctioning of the Alma/Galia project in Q4 2011, ahead of first drilling on Alma/Galia in Q1 2012. The total investment in Alma/Galia in 2011 was approximately $80 million, with around $95 million of capital expenditure on Thistle, $80 million on the Don fields and $30 million on Heather.

2012 highlights so far

Business development in 2012 has started strongly with several substantial transactions already negotiated. EnQuest agreed the acquisition of 45% of the Kraken discovery, with 20% being acquired from Canamens Limited for $45 million in cash and a further $45 million payable at FDP, and a further 25% acquired from Nautical Petroleum plc ('Nautical') through a development carry. The Kraken development has substantial potential, with the surrounding areas also bringing additional exploration and appraisal opportunities. EnQuest has also agreed a farm in option for 45% of the nearby Ketos discovery.

With its technical skills, operational scale and financial strength, EnQuest is increasingly becoming the natural partner of choice for integrated development projects in the UKCS and beyond. If Kraken proceeds to sanction and development, the timing of the anticipated cash flows from Alma/Galia will be complementary to the funding of Kraken.

Since the start of the year EnQuest has also agreed to acquire an additional 18.5% interest in West Don, from JX Nippon Exploration and Production (UK) Ltd ('JX') for a cash consideration of $34 million. The acquisition also includes tax allowances of $2 million. This transaction takes EnQuest to a 63.45% position in West Don. We are proud of our considerable achievement on the Don fields and pleased to be further consolidating our position on West Don. Completion of the transaction is subject to co-venturer approvals.

In Q1 2012, EnQuest established a new $900 million Multi-Currency Revolving Credit Facility, comprising of a committed amount of $525 million and with a further $375 million potentially available primarily for acquisitions. This facility replaces the previous $280 million facility which expired in Q1 2012. EnQuest is pleased with the support it received from the seven lending institutions which provided the new facility.

Outlook and plans for 2012 and beyond

Despite particularly difficult weather conditions in the Northern North Sea in Q1 2012, production year to date in 2012 has been in line with expectations and consequently EnQuest reaffirms its previous annual production guidance of between 20,000 Boepd to 24,000 Boepd.

Over the course of 2012, EnQuest's extensive programme encompasses the drilling of at least 11 wells, two on Thistle/Deveron, four on the Dons, three from batch drilling on Alma/Galia, an exploration well at Tryfan and an appraisal well at Kildrummy. EnQuest will also complete the power upgrade installation at Thistle and the rig reactivation programme at Heather. EnQuest's 2012 capital investment will be approximately $1,000 million, with around $500 million at Alma/Galia. This is EnQuest's most active annual work programme so far and we believe that it is one of the largest 2012 capital expenditure and drilling commitments in the North Sea. It is a programme which should provide a contribution to reserves and production in 2012 and also provide a bedrock for future reserves and production growth.

EnQuest welcomes the recent oil and gas fiscal adjustments in the UK 2012 Budget and looks forward to working with the Government and the industry to achieve the optimum development of the unrealised potential in the UK North Sea. EnQuest believes that these positive fiscal changes are steps in the right direction to bring small field developments to sanction.

EnQuest has met the cumulative reserves and production growth targets we set at the time of our IPO and our track record is proving that we can sustainably deliver substantial growth in reserves, production and in cash flow. Today we have three producing hubs, with a fourth hub in development and in Kraken a potential fifth hub. At the end of 2011, EnQuest had 22 production licences covering 27 blocks or part blocks, with EnQuest operating 19 of these licences. These include at least five discoveries on which developments are being actively considered. We are building our inventory on the mature Thistle and Heather fields and extending the lives of those fields which have the potential of substantial remaining oil in place combined with recovery levels which are still materially below those of analogous fields. We have been steadily growing and diversifying our asset base, and have added both capacity and capability to our workforce. This operational strength is underpinned by a very strong balance sheet and substantial borrowing capacity, even after the major investment we have commenced in Alma/Galia. EnQuest has the technical skills, the operational scale and the financial strength to be a powerful development and production company in 2012 and far beyond.

Principal risks and uncertainties

The Group's risks and uncertainties are unchanged from those disclosed in the Group's Annual Report and Accounts 2010, apart from the addition of a capital project execution risk which has been included recognising the significance of the Alma and Galia development. To be successful, the Group must ensure that the project implementation is both timely and on budget. Failure to do so may have a material negative impact on the Group's performance. The Group has mitigated this risk through embedding detailed controls, systems and monitoring processes to ensure that deadlines and budgets are met and that design concepts and Field Development Plans are strictly adhered to and implemented.

Operating Review

Overview

In 2011 EnQuest delivered a good operational performance. Production increased by 12.5% for year 2011 over 2010. EnQuest started 2011 with 2P reserves of 88.51 MMboe and produced 8.4 MMboe during 2011. Audited year end reserves grew by 30.2% to 115.21 MMboe, with a large part of the increase due to the Alma/Galia development which added net 2P reserves of 29.3 MMboe. This is equivalent to a reserves replacement ratio of 419.4%. EnQuest increased contingent resources to 116.78 MMboe at the end of 2011. Nine wells were finished during the year (eight of these were operated by EnQuest) and two new exploration discoveries were made at Conrie and Crathes.

A good HSEQ performance was achieved, with top quartile performance on the key measures of lost time accidents and recordable injuries. A new head of HSEQ was appointed and a proactive HSEQ programme with more emphasis on leading indicators was developed.

The EnQuest operating organisation was developed significantly during the year, to prepare for new projects. During the year the leadership team in Aberdeen was strengthened. In addition, the engineering and the new developments teams were trebled in size, and the drilling team was doubled in size.

2011 Operational summary

Two wells were drilled on Thistle and Deveron in 2011, following the 2010 rig refurbishment and drilling facilities upgrade. This resulted in Thistle producing at its highest annual rate for over ten years.

At Heather and Broom, following the subsurface review in 2010, 2011 was focused on the first phases of the oil rig reactivation programme. Production at Heather and Broom delivered the strongest growth of all of our hubs, up 20%, partly due to the new pipeline installed between the fields in 2010.

The Don fields contributed over 50% of our total production in 2011. Production for the year also benefited from the discovery in early 2011 of the Conrie field, with the S7 well coming on stream in August 2011. Both this S7 well and the S8Z well in Area 6 of the Don Southwest field produced less oil in 2011 than was anticipated at the time of EnQuest's production outlook guidance in April 2011, and revised production guidance was issued in September 2011. Following this quicker than expected initial decline from S8Z, production from the S8Z and S9 injector pair subsequently stabilised.

EnQuest's exploration strategy is focused on low cost, near field opportunities. Two exploration discoveries were made in 2011. In January 2011, a discovery was made at Conrie near the Don fields; this was completed and on production by August 2011. Later in 2011 a further discovery was made at Crathes. EnQuest is evaluating the potential commerciality of the combined Crathes, Scolty and Torphins area. In 2011 unsuccessful exploration wells were drilled at Don Southwest Area 26, Ivy, Moon and the non-operated Tudor Rose.

Outlook for 2012

The 2012 programme is substantially larger than the 2011 programme. As well as continuing to operate and develop our existing seven production fields, the drilling programme will expand to three operated drilling rigs. Eleven new wells will be drilled. Detailed design, procurement and construction of the Alma/Galia project will continue. Assessment of the Crawford field and the Crathes/Scolty area for development will also continue. In addition, EnQuest will play a leading role in the recently announced acquisition of the Kraken field development. Total capital expenditure for 2012 is expected to be around $1,000 million.

Producing Oil Fields

Thistle and Deveron

Working interest

- 99% in both fields

Decommissioning liabilities:

- remain with former owners (apart from new incremental developments)

Fixed steel platform

Daily average net production:

- 2011: 5,436 Boepd

- 2010: 4,836 Boepd

2011

Production at Thistle/Deveron achieved a net 5,436 Boepd in 2011, up 12.4% on 2010, despite poorer power generating uptime which impacted on water injection. Two new wells were finished during the year. A56/13 was the first well on Thistle to be completed with an electric submersible pump; this well came on stream in May 2011 at slightly above the expected rate. A57/58 came on stream in October 2011 at a higher rate than expected. The Deveron P1 well, was delayed into 2012. As a result of the poor power generation uptime a new project was sanctioned to build a new 30 MW power generation turbine due for completion at the end of 2012. This will enhance future water injection uptime.

2012

In 2012 two new wells will be finished, the DEV-P1 and the Area 6-P1 well, there will also be three workovers and an abandonment. In Q4 2012 the rig crew will transfer to Heather to commence drilling and will later return to Thistle. The new 30 MW power generation package will start up in late 2012. In addition, with the success of the drilling on Thistle, a series of projects for control and safety system upgrade, process simplification, structural integrity and topsides integrity will be defined in 2012.

The Don and Conrie Fields

Working interests:

- Don Southwest, 60%

- Conrie, 60%

- West Don, 44.95% (an increase to 63.45% was agreed in Q1 2012)

Decommissioning liabilities:

- as per working interests

Floating production unit with subsea wells

Daily average net production:

- 2011: 12,770 Boepd

- 2010: 11,660 Boepd on a pro-forma basis

2011

Production at the Dons and Conrie achieved a net 12,770 Boepd in 2011, up 9.5% over 2010. This was somewhat less than expected as both the Conrie well S7 and Don Southwest S8Z wells had lower initial production rates than expected, although this has not impacted reserves. The Conrie well discovery was made early in 2011; the development plan was prepared, the well completed and brought on production less than eight months from discovery. A new producer injector pair was drilled successfully in 2011. The S8Z well came on production in Q3 2011 and was later supported by the S9 water injection well. A Don Southwest Area 26 sidetrack appraisal well was drilled, but found sub commercial hydrocarbons. A workover was performed on the Don Southwest S2Z well.

2012

In 2012 four new wells will be drilled in the Don fields. At West Don a new W5 water injection well will be drilled to support the highly successful W4 production well, and an updip sidetrack to well W2 will be drilled as a producer at the crest. In Don Southwest a new production well will be drilled at the highest point of the horst, and also a further well updip of S1. In Q1 2012 EnQuest agreed the acquisition of a further 18.5% working interest in West Don, increasing the interest in West Don to 63.45%.

Heather and Broom

Working interest:

- Heather, 100%

- Broom, 63% (increased by 8% through acquisition, with effect from 1 July 2011)

Decommissioning liabilities:

- Heather, 37.5%

- Broom, 63%

Fixed steel platform

Daily average net production:

- 2011: 5,492 Boepd

- 2010: 4,578 Boepd (based on the 55% working interest in 2010)

2011

Production at Heather/Broom achieved a net 5,492 average Boepd in 2011, up 20.0% on 2010. This resulted from the benefit of the mid-year increase in EnQuest's working interest in Broom from 55% to 63% and from better than expected performance from the existing well stock. The Broom field also had a full year's benefit of the new Broom to Heather flowline which was installed in 2010.

In H1 2011 hydrocyclones were successfully installed and commissioned on Heather to improve oil in produced water.

The Heather drilling rig upgrade programme started in H1 2011, in preparation for a development drilling programme planned to start in Q4 2012.

In H2 2011 an unsuccessful exploration well was drilled on the Ivy prospect, south of Heather.

2012

The first drilling on Heather in 6 years will start in Q4 2012 with an initial programme of nine wells. We have commissioned new 2012 seismic across Heather and Broom and expect this will further enhance our infill drilling programme, this analysis will also cover the area between Heather and Broom.

Alma and Galia Development

Working interest:

- 100% in both fields

Decommissioning liabilities:

- 100% in both fields

Floating Production Storage and Offloading unit with subsea wells

First oil anticipated Q4 2013:

- Gross peak production to be in excess of 20,000 Boepd

2011

These fields previously called Argyll and Duncan were awarded to EnQuest in the 26^th licence round in early 2011.

EnQuest has designed a redevelopment project with nine wells to recover 29 MMboe of 2P reserves, with first production anticipated in Q4 2013 at a gross peak rate of over 20,000 Boepd.

Opportunities on other EnQuest blocks

Crathes/Scolty/Torphins

In Q4 2011, EnQuest's Crathes exploration well, 21/13a-5 encountered a 52ft light oil column in excellent quality Palaeocene sands. Following this result, EnQuest plans to evaluate the potential commerciality of the Scolty, Crathes and Torphins area. EnQuest acquired its 40% interest in Crathes through a farm in earlier in 2011.

Crawford

EnQuest is evaluating development options for the Crawford field and expects to make a decision regarding development during 2012.

Kildrummy

EnQuest agreed a farm in to a 40% interest in the Kildrummy discovery on 15/12b and 15/17, by drilling an appraisal well. The discovery is estimated to contain 40 MMboe of original oil in place in excellent reservoir sands, 8km from the Piper platform. EnQuest has assumed operatorship of Kildrummy and will operate the appraisal well, which is expected to be drilled in 2012. If the appraisal is successful EnQuest will also operate any subsequent field development project.

Kraken

In early 2012, EnQuest acquired a 45% interest in the Kraken discovery and anticipates becoming the operator of the proposed development of Kraken. The transaction also gives EnQuest an agreed farm in to the adjacent Ketos discovery, which is to be appraised.

Kraken is a large heavy oil accumulation in the UK North Sea, located in the East Shetland basin, to the west of the North Viking Graben. The joint venture partners are working towards first oil in 2015.

Financial Review

Financial Overview

In the year ended 31 December 2011, the Brent crude oil price averaged $111.3 per barrel, up $31.8 per barrel on the average for 2010, despite continued instability in the global economy.

The Group's financial performance in 2011 reflects good operational performance throughout the year, with revenue up by 52.3% compared with 2010 pro-forma, resulting in a $259.8 million increase in EBITDA from $369.3 million on a pro-forma basis for 2010 to $629.1 million in 2011, reflecting higher production volumes and higher realised sales prices.

The Group enters 2012 with $378.9 million cash as a result of strong ongoing operating cash flows from its existing portfolio of assets. In addition, the Group secured a $900.0 million bank facility on 6 March 2012, which is available for normal business, letters of credit, development activities and acquisition opportunities.

Income Statement

Production and revenue

Production levels, on a working interest basis, for the 12 months to 31 December 2011 averaged 23,698 Boepd, up 12.5% compared with 2010 pro-forma. The increase in production is due mainly to higher volumes on West Don as a result of having a full year's production from the W4 well and a full year's increased equity share following the acquisition of Stratic in November 2010. There was also strong performance from the Broom field existing well stock and the field had a full year's benefit of the new flowline, which was installed in 2010. In addition, two new Thistle wells came onstream during the year, and the Conrie discovery well S7 and the Don Southwest wells S8Z and S9 came onstream in August 2011. Saleable production was approximately 3% lower than the export meter production volumes, primarily as a result of volume adjustments being applied by the Sullom Voe Terminal operator.

The Group's blended average realised price per barrel of oil sold was $107.6 for the 12 months to 31 December 2011, compared with $81.3 per barrel for 2010 on a pro-forma basis, reflecting the increase in market prices for Brent crude and oil collar hedging costs of $36.5 million incurred in 2011. The average sales price per barrel of oil sold excluding oil collar hedging costs was $111.8.

Operating costs

Cost of sales for the Group (pre-exceptionals and fair value adjustments) are as follows:

	Reported	Pro-forma*	Reported
	Year ended 31 December	Year ended 31 December	Year ended 31 December
	2011	2010	2010
	$ million	$ million	$ million

Cost of sales	491.8	406.4*	384.5

	$	$	$
Unit operating cost, adjusted for over/under-lift and inventory movements (per Boe):
-Production and transportation costs	31.9	30.4*	30.8
-Depletion of oil and gas properties	23.2	22.8*	22.2
	55.1	53.2*	53.0

The increase in the Group's average unit production and transportation cost of $1.5 per Boe for the year ended 31 December 2011 compared with 2010 pro-forma, is primarily attributable to the cost of a major shutdown programme performed on Thistle and the Don Southwest S2z well intervention costs, partially offset by increased production volume from the Dons and Thistle fields.

The Group's depletion expense per Boe for the year is broadly consistent with the previous year's pro-forma rate, with an increase of $0.4 per Boe (2%).

The well abandonment expenses of $8.2 million which were reported in 2010 have been credited in 2011 following a further review of options to recover these funds from the previous owners.

The Group's change in lifting position expense was $14.6 million for the year ended 31 December 2011, compared with $1.3 million in 2010 on a pro-forma basis. The increase in expense of $13.3 million has arisen primarily due to over-lifting of Dons volumes at 31 December 2011, compared to under-lifting at 31 December 2010.

Exploration and evaluation expenses

Exploration and evaluation expenses were $37.0 million in the year ended 31 December 2011, compared with $23.0 million reported in the previous year, excluding exceptional items. The expenses primarily relate to the cost of unsuccessful exploration wells at Don Southwest Area 26, Ivy, Moon and the non-operated Tudor Rose well.

General and administrative expenses

General and administrative expenses were $16.0 million in the year ended 31 December 2011 compared with $13.8 million reported in the previous year, excluding exceptional items. The expenses primarily relate to the Group's general management and business development expenses and the increase is mainly due to the increased levels of business development activity.

Taxation

The tax charge for the year of $239.4 million excluding exceptional items, represents an effective tax rate of 64% compared with 51% in the previous year. The increase in the Group's effective tax rate in the year results from the increase in the UK supplementary corporation tax from 24^th March 2011 (9% pro-rata increase compared with 2010) and petroleum revenue tax ('PRT') on the Thistle field, offset by ring fence expenditure supplement receivable and prior year adjustments.

Exceptional items and depletion of fair value uplift

Exceptional costs totalling $12.6 million before tax have been disclosed separately in the year ended 31 December 2011 relating to:

· non-cash gain on disposal of $8.6 million resulting from the disposal of the Slovenian Petisovci asset, which was obtained on acquisition of Stratic, to Ascent Resources plc on 11 February 2011 in return for an equity stake;

· non-cash impairment of $12.5 million in relation to the accounting valuation of the Group's shareholding in Ascent Resources plc; and

· non-cash well abandonment credit of $8.2 million recognised following further review of options to recover these funds from the previous Thistle field owners.

In addition, a one-off deferred tax adjustment of $68.1 million in respect of the increase in the supplementary charge on UK oil and gas production has also been reported as an exceptional item. The effective tax rate including the one-off charge for the increase in supplementary corporation tax rate was 83%. The UK government has also released draft legislation to restrict the tax relief available on decommissioning expenditure to 50% in 2012. This change is not yet substantively enacted but would be likely to give rise to a one-off exceptional additional tax charge in 2012 in the order of $21.6 million.

Additional depletion costs of $17.0 million ($3.8 per Boe) have resulted 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 $18.6 million include $7.8 million unwinding of discount on decommissioning provisions, $4.8 million of costs associated with the Group's revolving credit facility and letter of credit utilisation during the year and a one-off premium of $5.9 million following a decision to re-price the Group's 2011 oil collars in the second half of the year.

Finance income

Finance income of $4.0 million includes $1.8 million of bank interest receivable and a non-cash, unrealised accounting valuation of the mark to market gain of $2.1 million on the Group's 2012 oil collars which are deemed ineffective for hedge accounting purposes.

Earnings per share

The Group's reported basic earnings per share were 7.6 cents for the year ended 31 December 2011 compared with 4.0 cents in 2010. The increase of 3.6 cents is attributable to the combined impact of an increase in production volumes and realised oil price in the year ended 31 December 2011 compared with the previous year.

Cash flow and liquidity

The Group's reported cash generated from operations in 2011 increased by $388.6 million to $656.3 million (2010: $267.7 million), generating an increase in the reported cash flow from operations per issued Ordinary share of 110% to 81.9 cents per share compared to the previous year (2010: 39.0 cents per share). This increase results mainly from the combination of higher average reported realised oil prices and additional production volumes in 2011 compared with 2010.

During the year ended 31 December 2011, $10.9 million of income tax payments were made, mainly in settlement of Stratic Energy Corporation ('Stratic') pre-acquisition Italian tax liabilities. As a result of acquisitions and transactions made since the year end, it is expected that the underlying effective tax rate for 2012 will be around 62%, excluding one-off exceptional tax items, and that there will be no cash outflow for UK income tax before 2014.

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

		Pro-forma*
	2011	2010
	$ million	$ million

Expenditure on producing oil and gas assets	170.9	171.4
Development expenditure	43.6	-
Exploration and evaluation expenditure	54.0	17.1
Other capital expenditure	9.4	7.8
	277.9	196.3

Significant projects were undertaken during the year, including:

· expenditure on the Alma and Galia joint development;

· drilling and completing Don Southwest S8Z and S9 development wells;

· drilling and completing Conrie S7 development well;

· West Don W1 intervention well drilling programme;

· drilling and completing Thistle A56/13 and A57/58 development wells, and drilling of the Thistle DEV-P1 development well which was completed in Q1 2012;

· Thistle power generation upgrade programme;

· Heather rig reactivation programme;

· Crathes exploration and appraisal well;

· unsuccessful Don Southwest Area 26, Ivy, Moon and Tudor Rose exploration and appraisal wells.

Net cash at 31 December 2011 amounted to $378.9 million compared to $41.4 million in 2010.

On 6 March 2012, in anticipation of the maturity of the existing Revolving Credit Facility Agreement, the Group established a $900.0 million Multi-Currency Revolving Credit Facility Agreement with Lloyds TSB Bank, Bank of America Merrill Lynch, Barclays, BNP Paribas, Crédit Agricole CIB, NIBC Bank and Royal Bank of Scotland. The facility comprises a committed amount of $525.0 million for three years, extendable to four years at the option of the Company and a further year with consent of the lenders. A further $375.0 million is available with the lenders' consent, primarily for investment opportunities. $123.7 million of this facility is currently utilised for Letters of Credit.

Balance Sheet

The Group's total asset value has increased by $487.7 million to $1,948.7 million at 31 December 2011 (2010: $1,461.0 million).

Property, plant and equipment

Property, plant and equipment has increased to $1,273.6 million at 31 December 2011 from $1,134.2 million at 31 December 2010. The increase of $139.4 million is mainly due to oil and gas asset additions of $291.7million, additional decommissioning provisions arising on drilling new development wells of $33.8 million and reclassification of the Don Southwest Area E (Conrie) well from intangible assets of $11.2 million, partially offset by depletion and depreciation charges of $219.0 million in the year.

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


	2011
	$ million

Dons hub	78.2
Thistle hub	93.9
Heather and Broom hub	32.5
Alma / Galia	82.4
Other new developments	4.7
	291.7

Goodwill

Provisional goodwill of $100.1 million and $1.8 million was recorded in 2010 in connection with the acquisition of Petrofac Energy Developments Limited ('PEDL') and Stratic respectively. During 2011 the PEDL fair value allocation was reviewed and updated to reflect the finalisation of working capital adjustments, resulting in a $2.8 million decrease in the recorded goodwill. Similarly, the Stratic fair value allocation was reviewed and updated to reflect the finalisation of tangible and intangible asset valuations and tax estimates; resulting in an increase in goodwill of $8.7 million.

Investments

Following the disposal of the Slovenian Petisovci asset on 11 February 2011 and the purchase of a further 10,000,000 shares in the year, the Group holds an investment of 160,903,958 new ordinary shares in Ascent Resources plc which is valued at $6.7 million based on the quoted bid price as at 31 December 2011.

Asset held for sale

During 2011, $1.3 million of costs associated with the Group's Dutch licences were reclassified to asset held for sale and the 2010 balance of $9.8 million was released on the sale of the Petisovci asset.

Trade and other receivables

Trade and other receivables have decreased by $6.0 million to $126.6 million at 31 December 2011 compared with $132.6 million in 2010. The decrease is primarily due to a reduction in joint venture receivables in relation to the Don fields.

Cash and bank

The Group has a strong liquidity position at 31 December 2011, with $378.9 million of cash and cash equivalents despite undertaking a significant capital expenditure programme, with $277.9 million spend in the year, and $13.1 million incurred on the purchase of Company shares by the Employee Benefit Trust.

Provisions

The Group's decommissioning provision increased by $41.1 million to $181.2 million at 31 December 2011 (2010: $140.1 million). The increase is due to the combined impact of additions of $33.8 million during the year resulting from the Group's drilling programme, $16.9 million resulting from a change in decommissioning estimates and unwinding of the discount of $7.8 million, offset by utilisation of the provision of $17.4 million on well abandonment and various small facility decommissioning workscopes.

Deferred tax liability

The Group's deferred tax liability (net of deferred tax asset) has increased by $295.9 million to $577.4 million at 31 December 2011 from $281.5 million in 2010. The increase is due mainly to a one-off deferred tax adjustment of $68.1 million in respect of the increase in the supplementary charge on UK oil and gas production which has been reported as an exceptional item, the significant capital expenditure programme undertaken by the Group during the year which provides the Group with 100% first year capital allowance claims, and partial utilisation of taxation losses brought forward. Total losses carried forward at the year end amount to approximately $185 million of which $34 million relates to losses carried forward relating to the Don assets and $123 million in respect of the Stratic acquisition.

Trade and other payables

Trade and other payables have increased to $234.3 million at 31 December 2011 from $135.7 million at 31 December 2010. The increase of $98.6 million is primarily due to an increase in accruals of $71.7 million and an increase in trade creditors of $14.5 million resulting from the Group's drilling and capital project programmes which were ongoing at the end of 2011 and an increase in other payables of $12.5 million which was mainly due to the increase in the year end over-lift position compared with 2010.

Financial risk management

The Group is exposed to the impact of changes in Brent crude oil prices on its revenue and profits. During 2010 the Group entered into four zero premium oil price collars covering approximately 4 million barrels of 2011 production with an average floor price of $75 per barrel and an average cap of $100 per barrel. In August 2011, two of the oil price collars were re-priced to give a revised average cap of $108 per barrel.

In November 2011, a further five put and call options covering approximately 3 million barrels of oil production in 2012 were entered into partially to hedge the exposure to fluctuations in the Brent oil price. The 2012 oil price hedge contracts consist of put spreads at $95 per barrel and $70 per barrel and calls at an average of $122 per barrel, all executed on a costless basis.

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. During the second half of 2011, the Group entered into a number of forward currency contracts to hedge a total of £123.0 million (at an average rate of $1.58 to £1) and €57.0 million (at an average rate of $1.34 to €1) of forecast 2012 capital project spend.

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 counter-party credit risks.

Key Performance Indicators

	2011	2010

Lost Time Incident Frequency (LTIF)**	0.44	0.96**

2P reserves (MMboe)	115.21	88.51

Business performance data:
Production (Boepd) Revenue ($ million)	23,698 936.0	21,074* 614.4*
Realised oil price per barrel ($)	107.6	81.3*
Opex per barrel (production and transportation costs) ($)	31.9	30.4*
Gross profit ($ million)	444.2	208.0*
Capex ($ million)	360.6	196.3*

Reported data:
Cash flow generated from operations ($ million)	656.3	267.7
Net cash ($ million)	378.9	41.4
Profit before tax ($ million)	362.8	55.8
Cash flow generated from operations per share (cents)	81.9	39.0
Basic earnings per share (cents)	7.6	4.0

** During the year, the Group changed the metric for recording lost time incidents to Lost Time Incident Frequency (LTIF) to align with the industry standard. The 2010 comparative figure has therefore been restated from Lost Time Accidents (days) of 0.21 days to a LTIF of 0.96.

ABRIDGED GROUP INCOME STATEMENT

For the year ended 31 December 2011

2011

2010

Pro-forma*

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

935,974

614,357

Cost of sales

(491,817)

(16,973)

(508,790)

(406,403)

(16,319)

(422,722)

Gross profit/(loss)

444,157

(16,973)

427,184

207,954

(16,319)

191,635

Exploration and evaluation expenses

(36,962)

(22,987)

(57,870)

(80,857)

Gain on disposal of asset held for sale

8,644

Impairment on available for sale assets

(12,497)

Impairment of oil and gas assets

(2,121)

Well abandonment expenses

8,194

(8,194)

General and administration expenses

(16,049)

(17,126)

(13,432)

(30,558)

Other (expenses)/income, net

(1,050)

1,546

Profit/(loss) from operations before tax and finance income/(costs)

390,096

(12,632)

377,464

169,387

(97,936)

71,451

EBITDA**

629,102

8,194

637,296

369,342

(21,627)

347,715

Notes:

* In April 2010 EnQuest PLC acquired the demerged UK North Sea assets of Petrofac Limited and Lundin Petroleum AB respectively. This transaction was accounted for as a capital restructuring of EnQuest and the former Lundin business (Lundin North Sea, 'LNS') and an acquisition of the former Petrofac business (Petrofac Energy Developments Limited, 'PEDL'). Consequently the Group statement of comprehensive income for 2010, prepared in accordance with IFRS, includes the results of LNS from the start of the calendar year but only from 5 April 2010 for PEDL. The results of EnQuest are included from its incorporation date of 29 January 2010. This abridged 2010 pro-forma income statement presents the trading results for both LNS and PEDL from the start of the calendar year, as though PEDL was part of the group for the full year ended 31 December 2010.

** EBITDA is calculated by taking profit/loss from operations before tax and finance income/(costs), deducting gain on disposal of asset held for sale (note 14) and adding back depletion (note10), depreciation (note 10), impairment (note 13 & 15) and write off of tangible and intangible oil and gas assets (note 13 & 15). EBITDA is not a measure of financial performance under IFRS.

OIL AND GAS RESERVES AND RESOURCES

At 31 December 2011

	UKCS		Other Regions	Total
	MMboe	MMboe	MMboe	MMboe

Proven and Probable Reserves (notes 1, 2, 3 & 6)

At 1 January 2011		88.51	-	88.51
Revisions of previous estimates		4.55	-	4.55
Discoveries, extensions and additions (note 7)		29.69	-	29.69
Acquisitions (note 8)		0.82	-	0.82
Production:
Export meter	(8.65)
Volume adjustments (note 5)	0.29
		(8.36)	-	(8.36)
Proven and Probable Reserves at 31 December 2011		115.21	-	115.21

Contingent Resources (notes 1, 2 & 4)

At 1 January 2011		96.99	8.07	105.06
Revisions of previous estimates		10.97	-	10.97
Discoveries, extensions and additions		11.87	-	11.87
Acquisitions		31.78	-	31.78
Disposals		(10.50)	(3.06)	(13.56)
Promoted to reserves		(29.34)	-	(29.34)
Contingent Resources at 31 December 2011		111.77	5.01	116.78

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 have been audited by a recognised Competent Person in accordance with the definitions set out under the 2007 Petroleum Resources Management System and supporting guidelines issued by the Society of Petroleum Engineers.

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

(5) Conversion of export to sales volumes.

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

(7) The Conrie field was discovered and brought on line. Contingent Resources have been reclassified as reserves following the preparation of the Field development Plans for Alma and Galia.

(8) An additional 8% equity in Broom was acquired in 2011.

GROUP STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2011

			*2011*		2010
	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)	935,974	-	935,974	583,468	-	583,468
Cost of sales	5(b)	(491,817)	(16,973)	(508,790)	(384,485)	(16,319)	(400,804)

Gross profit/(loss)		444,157	(16,973)	427,184	198,983	(16,319)	182,664
Exploration and evaluation expenses	5(c)	(36,962)	-	(36,962)	(22,987)	(57,870)	(80,857)
Gain on disposal of asset held for sale		-	8,644	8,644	-	-	-
Impairment on investments		-	(12,497)	(12,497)	-	-	-
Impairment of oil and gas assets		-	-	-	-	(2,121)	(2,121)
Well abandonment		-	8,194	8,194	-	(8,194)	(8,194)
General and administration expenses	5(d)	(16,049)	-	(16,049)	(13,770)	(13,432)	(27,202)
Other income	5(e)	7,336	-	7,336	7,024	-	7,024
Other expenses	5(f)	(8,386)	-	(8,386)	(5,526)	-	(5,526)

Profit/(loss) from operations before tax and finance income/(costs)		390,096	(12,632)	377,464	163,724	(97,936)	65,788
Finance costs	6	(18,598)	-	(18,598)	(11,187)	-	(11,187)
Finance income	6	3,955	-	3,955	1,174	-	1,174

Profit/(loss) before tax		375,453	(12,632)	362,821	153,711	(97,936)	55,775

Income tax	7	(239,400)	(62,430)	(301,830)	(78,647)	49,948	(28,699)

Profit/(loss) for the year attributable to owners of the parent		136,053	(75,062)	60,991	75,064	(47,988)	27,076

Other comprehensive income for the year, after tax:
Cash flow hedges (net of tax)	22			(2,600)			-
Available for sale financial assets	15			-			-
Total comprehensive income for the year, attributable to owners of the parent				58,391			27,076

Earnings Per Share	8			US$			US$
Basic				0.076			0.040
Diluted				0.076			0.040

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

GROUP BALANCE SHEET

At 31 December 2011

	Notes	2011	2010 Restated¹
ASSETS		US$'000	US$'000
Non-current assets
Property, plant and equipment	10	1,273,558	1,134,249
Goodwill	12	107,760	107,760
Intangible oil and gas assets	13	24,347	9,602
Asset held for sale	14	1,254	9,778
Investments	15	6,734	-
Deferred tax assets	7	12,617	13,227
		1,426,270	1,274,616

Current assets
Inventories	16	11,842	12,404
Trade and other receivables	17	126,554	132,617
Income tax receivable		2,618	-
Cash and cash equivalents	18	378,907	41,395
Other financial assets	22	2,510	-
		522,431	186,416
TOTAL ASSETS		1,948,701	1,461,032

EQUITY AND LIABILITIES
Equity
Share capital	19	113,433	113,174
Merger reserve		662,855	662,855
Cash flow hedge reserve		(2,600)	-
Share-based payment reserve		(5,961)	2,540
Retained earnings		166,481	104,327
TOTAL EQUITY		934,208	882,896

Non-current liabilities
Provisions	23	181,237	140,108
Other financial liabilities	22	335	-
Deferred tax liabilities	7	590,010	294,699
		771,582	434,807

Current liabilities
Trade and other payables	24	234,337	135,723
Other financial liabilities	22	6,870	-
Income tax payable		1,704	7,606
		242,911	143,329

TOTAL LIABILITIES		1,014,493	578,136

TOTAL EQUITY AND LIABILITIES		1,948,701	1,461,032

¹ Restated for fair value adjustments as set out in note 11. In addition the 2010 comparatives are restated to be consistent with the treatment in 2011.

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

GROUP STATEMENT OF CHANGES IN EQUITY

At 31 December 2011

	Share capital	Merger reserve	Cash flow hedge reserve	Other reserves	Share-based payments reserve	Available for sale reserve (note 15)	Retained earnings	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

At 1 January 2010	32,164	50,785	-	83	-	-	77,168	160,200

Total comprehensive income for the year: profit for the year	-	-	-	-	-	-	27,076	27,076
Issue of Ordinary shares	80,480	486,850	-	-	-	-	-	567,330
Capital contribution on assignment of debt on de-merger	-	125,220	-	-	-	-	-	125,220
Issue of shares to Employee Benefit Trust	530	-	-	-	(530)	-	-	-
Share-based payment charge	-	-	-	-	3,070	-	-	3,070
Share option programme transfer to retained earnings	-	-	-	(83)	-	-	83	-

At 31 December 2010	113,174	662,855	-	-	2,540	-	104,327	882,896

Profit for the year	-	-	-	-	-	-	60,991	60,991
Other comprehensive income:
Losses arising during the year on cash flow hedges (net of tax)	-	-	(2,600)	-	-	-	-	(2,600)
Marked to market value of investment	-	-	-	-	-	(10,629)	-	(10,629)
Reclassification of impairment of investments	-	-	-	-	-	10,629	-	10,629
Total comprehensive income for the year	-	-	(2,600)	-	-	-	60,991	58,391

Issue of shares to Employee Benefit Trust	259	-	-	-	(259)	-	-	-
Share-based payment charge	-	-	-	-	4,881	-	-	4,881
Bonus liability accrual settled in shares granted during the year	-	-	-	-	-	-	1,163	1,163
Shares purchased on behalf of Employee Benefit Trust	-	-	-	-	(13,123)	-	-	(13,123)

At 31 December 2011	113,433	662,855	(2,600)	-	(5,961)	-	166,481	934,208

GROUP STATEMENT OF CASH FLOWS

For the year ended 31 December 2011

		2011	2010
	Notes	US$'000	US$'000
CASH FLOW FROM OPERATING ACTIVITIES
Profit before tax		362,821	55,775
Depreciation	5(d)	1,784	845
Depletion	5(b)	217,233	177,185
Exploration costs impaired and written off	5(c)	36,962	80,857
Impairment of oil and gas assets	4	-	2,121
Well abandonment	4	(8,194)	-
Gain on disposal of asset held for sale	4	(8,644)	-
Impairment on available for sale investments	4	12,497	-
Share-based payment charge	5(g)	4,881	3,070
Long-term incentive plan	5(g)	-	717
Unwinding of discount on decommissioning provisions	6	7,793	5,196
Unrealised exchange losses		3,344	164
Net finance costs		6,850	4,817
Operating profit before working capital changes		637,327	330,747
(Increase)/decrease in trade and other receivables		(1,940)	8,532
Decrease in due from related parties		-	552
Decrease in inventories		562	442
Increase/(decrease) in trade and other payables		20,383	(72,038)
Decrease in due to related parties		-	(497)
Cash generated from operations		656,332	267,738
Long-term incentive plan		-	(1,036)
Decommissioning spend		(9,192)	-
Income taxes paid		(10,855)	(4,093)
Net cash flows from operating activities		636,285	262,609

INVESTING ACTIVITIES
Purchase of property, plant and equipment		(223,947)	(137,494)
Purchase of intangible oil and gas assets		(53,964)	(17,374)
Acquisition of subsidiaries - cash		-	21,556
Acquisition of available for sale investments		(808)	-
Interest received		1,834	35
Net cash flows used in investing activities		(276,885)	(133,277)

FINANCING ACTIVITIES
Shares purchased by Employee Benefit Trust		(13,123)	-
Repayment of loans and borrowings		-	(86,251)
Interest paid		(1)	(3,393)
Other finance costs paid		(9,633)	(5,030)
Net cash flows used in financing activities		(22,757)	(94,674)

NET INCREASE IN CASH AND CASH EQUIVALENTS		336,643	34,658
Net foreign exchange on cash and cash equivalents		869	(1,156)
Cash and cash equivalents at 1 January		41,395	7,893
CASH AND CASH EQUIVALENTS AT 31 DECEMBER		378,907	41,395

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

NOTES TO THE GROUP FINANCIAL STATEMENTS

For the year ended 31 December 2011

1. Corporate information

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

The Group's principal activities are the exploration for, and extraction and production of hydrocarbons in the UK Continental Shelf.

The Group's financial statements for the year ended 31 December 2011 were authorised for issue in accordance with a resolution of the Board of Directors on 26 March 2012.

A listing of the principal Group companies is contained in note 29 to these Group financial statements.

The financial information contained in this announcement does not constitute statutory financial statements within the meaning of section 435 of Companies Act 2006.

The statutory accounts for the year ended 31 December 2011 have been audited, and the report of the auditors on those accounts is unqualified and will be delivered to the Registrar of Companies in due course. The comparative figures for the financial year ended 31 December 2010 are the equivalent of the Company's statutory accounts for that financial year. Those accounts, which were prepared under IFRS, have been reported on by the Company's auditors and delivered to the registrar of companies. The auditors issued an unqualified opinion on those accounts.

Copies of the 2011 Annual Report and Accounts will be posted to shareholders in advance of the Annual General Meeting which is planned to take place on 30 May 2012. Further copies will be available from the Company's headquarters, from the date of posting or request via the Company's web-site at www.enquest.com.

2. Summary of significant accounting policies

Basis of preparation

The Group financial information has been prepared in accordance with International Financial Reporting Standards ('IFRS') as adopted by the European Union as they apply to the financial statements of the Group for the year ended 31 December 2011 and applied in accordance with the Companies Act 2006. The accounting policies which follow set out those policies which apply in preparing the financial statements for the year ended 31 December 2011.

The Group financial information has been prepared on a historical cost basis. The presentation currency of the Group financial information is United States dollars and all values in the Group financial information are rounded to the nearest thousand (US$'000) except where otherwise stated.

Going concern concept

The Directors' assessment of going concern concludes that the use of the going concern basis is appropriate because there are no material uncertainties that may cast significant doubt about the ability of the Group to continue as a going concern.

Group formation

The Company was incorporated on 29 January 2010 as a holding Company to effect a business combination between Lundin North Sea BV ('LNS') and Petrofac Energy Developments Limited ('PEDL'). On 5 April 2010 the Company acquired 100% of the voting shares of PEDL and on 6 April 2010 acquired 100% of the voting shares of LNS. Both acquisitions were satisfied by the allotment and issuance of Ordinary shares in the Company.

The combination of LNS with EnQuest in 2010 has been accounted for as a capital restructuring under the pooling of interests method.

IFRS 3 Business Combinations (Revised) requires the identification of the acquirer. Legally EnQuest acquired both PEDL and LNS, however in considering this transaction management looked to the application guidance provided by IFRS 3 (Revised) which applies where a new entity is formed to effect a combination between two or more existing entities. The guidance indicates where such a new entity issues equity instruments in itself in exchange for equity instruments in the acquired subsidiaries, then one of the acquired subsidiaries should be identified as the acquirer. As EnQuest did not meet the definition of a business combination then the combination of EnQuest with LNS was accounted for as a capital re-structuring.

The combination of PEDL with LNS has been accounted for using the acquisition method, with LNS identified as the acquirer after considering the following principles:

(i) the relative voting rights in the combined entity after the business combination;

(ii) the existence of a large minority voting interest in the combined entity;

(iii) the composition of the governing body of the combined entity;

(iv) the composition of the senior management of the combined entity;

(v) the terms of the exchange of equity interests.

The approach adopted has a number of consequences including that:

· the Group's financial statements are prepared on the basis that EnQuest and LNS had always been combined, with the results of LNS being included for the year ended 31 December 2010 and EnQuest results being included from its incorporation date of 29 January 2010;

· the Group's equity reflects the capital restructuring of EnQuest and LNS at the beginning of 2009 and LNS's retained earnings carry forward within Group equity together with EnQuest's retained earnings;

· the carrying value of LNS net assets are unadjusted for the combination with EnQuest under the pooling of interests method; no goodwill arises as a result of the combination of LNS with EnQuest;

· the additional share premium resulting from capitalisation of LNS's long term loans payable is eliminated by transfer to the Group merger reserve;

· the consideration for the acquisition of PEDL is derived from the market value of EnQuest Ordinary shares issued to effect the acquisition;

· the identifiable net assets of PEDL are measured at fair value at the date of the acquisition; and

· the Group merger reserve represents the difference between the market value of shares issued to effect the business combinations less the nominal value of shares issued; and consolidation adjustments which arise under the application of the pooling of interests method.

Basis of consolidation

Subsidiaries

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

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

Unincorporated jointly controlled assets

Oil and gas operations are conducted by the Group as co-licensees in unincorporated joint ventures with other companies. The Group's financial statements reflect the relevant proportions of production, capital costs, operating costs and current assets and liabilities of the joint venture applicable to the Group's interests. The Group's current joint venture interests are detailed in the Annual Report and Accounts.

Business combinations

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

New standards and interpretations

The Group has adopted new and revised IFRS that are relevant to its operations and effective for accounting periods beginning on or after 1 January 2011. The principal effects of the adoption of these new and amended standards and interpretations are discussed below:

IAS 24 Related Party Transactions (Amendment)

The IASB issued an amendment to IAS 24 that clarifies the definitions of a related party. The new definitions emphasise a symmetrical view of related party relationships and clarifies the circumstances in which persons and key management personnel affect related party relationships of an entity. The adoption of the amendment did not have any impact on the financial position or performance of the Group.

IAS 32 Financial Instruments

The IASB issued an amendment that alters the definition of a financial liability in IAS 32 to enable entities to classify rights issues and certain options or warrants as equity instruments. The amendment has had no effect on the financial position or performance of the Group because the Group does not have these types of instruments.

Amendments to IFRS 1 Limited Exemption from Comparative IFRS 7 Disclosures for First-Time Adopters

The IASB issued an amendment to IFRS 1 which provides a limited exemption for first-time adopters from providing comparative fair-value hierarchy disclosures under IFRS 7. The adoption of the amendment did not have any impact on the financial position or performance of the Group.

Improvements to IFRSs (Issued in May 2010)

The IASB issued improvements to IFRS, an omnibus of amendments to its IFRS standards. The adoption of the following amendments resulted in changes to accounting policies, but no impact on the financial position or performance of the Group.

IAS 1 Presentation of Financial Statements - The amendment clarifies that an entity may present an analysis of each component of other comprehensive income either in the statement of changes in equity or in the notes to the financial statements.

IAS 34 Interim Financial Statements - Emphasises that disclosure about significant events and transactions in interim periods should update relevant information presented in the most recent financial report and how to apply this principle in respect of financial instruments and their fair values.

Other amendments resulting from improvements to IFRSs to the following standards did not have an impact on the accounting policies, financial position or performance of the Group:

IFRS 7 Financial Instruments - Disclosures

Interpretations

The following Interpretations did not have any impact on the accounting policies, financial position or performance of the Group:

IFRIC 19 Extinguishing Financial Liabilities with Equity Instruments

Standards issued but not yet effective

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

IAS 1 Presentation of items of other comprehensive income - Amendments to IAS 1

The amendments change the grouping of items presented in the statement of comprehensive income. Items that would be reclassified to profit or loss at a future point in time would be presented separately from items that will never be reclassified. The revisions become effective for annual periods beginning on or after 1 July 2012.

IFRS 7 (amended) Disclosures - Transfers of Financial Assets

The revision requires enhancements to the existing disclosures in IFRS 7 where an asset is transferred but not derecognised and introduces new disclosures for assets that are derecognised but the entity continues to have continuing exposure to the asset after sale. The revisions become effective for annual periods beginning on or after 1 July 2011.

IFRS 9 Financial Instruments - Classification and Measurement

IFRS 9 as issued reflects the first phase of the IASB's work on the replacement of IAS 39 and applies to classification and measurement of financial assets as defined in IAS 39. The Standard is effective for annual periods beginning on or after 1 January 2015. In subsequent phases, the IASB will address classification and measurement of financial liabilities, hedge accounting and derecognition. The adoption of IFRS 9 will have an effect on the classification and measurement of the Group's financial assets. However, the Group determined that the effect shall be quantified in conjunction with the other phases when issued to present a comprehensive picture.

IFRS 10 Consolidated Financial Statements/ IAS 27 (Revised) - Separate Financial Statements

IFRS 10 establishes a single control model that applies to all entities and introduces changes which will require management to exercise significant judgement to determine which entities are controlled, and therefore, are required to be consolidated by a parent. The consolidation requirements forming part of IAS 27 will be revised and contained within IFRS 10. These Standards are effective for annual periods beginning on or after 1 January 2013.

IFRS 11 Joint Arrangements

IFRS 11 establishes a clear principle that is applicable to the accounting for all joint arrangements. The Standard is effective for annual periods beginning on or after 1 January 2013. The most significant change is that IFRS 11 requires the use of the equity method of accounting for interests in jointly controlled entities thereby eliminating the proportionate consolidation method.

IAS 28 (Revised) - Investments in Associates and Joint Ventures

The Standard will be revised due to the introduction of IFRS 10 and 11. The revision will become effective for annual periods beginning on or after 1 January 2013.

IFRS 12 Disclosure of Interests in Other Entities

Includes disclosure requirements for interests in subsidiaries, joint arrangements, associates and unconsolidated structured entities. The Standard is effective for annual periods beginning on or after 1 January 2013.

IFRS 13 Fair Value Measurement

The Standard defines fair value, provides guidance on its determination and introduces consistent requirements for disclosures on fair value measurements. The Standard does not include requirements on when fair value measurement is required but prescribes how fair value is to be measured if another Standard requires it. The Standard is effective for annual periods beginning on or after 1 January 2013.

Critical accounting estimates and judgements

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

Estimates in oil and gas reserves

The business of the Group is the exploration for, development of and production of oil and gas reserves. Estimates of oil and gas reserves are used in the calculations for impairment tests and accounting for depletion and decommissioning. Changes in estimates of oil and gas reserves resulting in different future production profiles will affect the discounted cash flows used in impairment testing, the anticipated date of decommissioning and the depletion charges in accordance with the unit-of-production method.

Estimates in impairment of assets (excluding goodwill)

For details of policy see Impairment of assets (excluding goodwill) and refer to the further economic assumptions above within Estimates in oil and gas reserves.

Group formation

For details see Group formation under the basis of preparation section of the accounting policies.

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

The Group determines the fair value of property, plant and equipment acquired based on the discounted cash flows at the time of acquisition, from the proven and probable reserves. In assessing the discounted cash flows the estimated future cash flows attributable to the asset are discounted to their present value using a pre-tax discount rate that reflects the market assessments of the time value of money and the risks specific to the asset at the time of the acquisition. In calculating the asset fair value the Group will apply the long term oil price assumption, escalated for inflation and discounted at the pre-tax rate. The oil price assumption will represent management's view of the long term oil price at the time of the transaction.

Decommissioning provision

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

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

In estimating decommissioning provisions, the Group applies an annual inflation rate of 2% (2010: 2%) and an annual discount rate of 5% (2010: 5%).

Estimates in impairment of goodwill

Determination of whether goodwill has suffered any impairment requires an estimation of the value in use of the cash-generating units ('CGU') to which goodwill has been allocated. The present value calculation requires the entity to estimate the future cash flows expected to arise from the CGU and a suitable discount rate. In calculating the present value in use of the CGU, the Group has used forward curve prices for the first four years before reverting to the Group's long term pricing assumption and discounted at a pre-tax rate of 21.3% (2010: US$85 per barrel, escalated at 2% and discounted at a pre-tax rate of 19%).

Taxation

The UK's corporation tax legislation is relatively complex. The Group's operations are subject to a number of specific rules which apply to UK North Sea exploration and production. In addition, the tax provision is prepared before the relevant companies have filed their UK Corporation tax and supplementary charge returns with HMRC and significantly, before these have been agreed. As a result of these factors the tax provision process necessarily involves the use of a number of estimates and judgements including those required in calculating the effective tax rate arising on exceptional items. In considering the tax on exceptionals, the Company considered varying rates depending on the category of expense but believes that using the effective rate, after adjusting for significant one-off charges, gives an overall approximation to the tax rate on exceptional items.

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

Foreign currencies

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

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

Classification and recognition of assets and liabilities

Non-current assets and non-current liabilities including provisions consist, for the most part, solely of amounts that are expected to be recovered or paid more than twelve months after the balance sheet date. Current assets and current liabilities consist solely of amounts that are expected to be recovered or paid within twelve months after the balance sheet date.

Property, plant and equipment

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

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

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

Office furniture and equipment 25% - 100%

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

No depreciation is charged on land or assets under construction.

The carrying amount of an item of property, plant and equipment is derecognised on disposal or when no future economic benefits are expected from its use or disposal. The gain or loss arising from the derecognition of an item of property, plant and equipment is included in the statement of comprehensive income when the item is derecognised. Gains are not classified as revenue.

Capitalised costs

Oil and gas assets are accounted for using the successful efforts method of accounting.

Intangible oil and gas assets

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

Oil and gas assets

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

Changes in unit-of-production factors

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

Borrowing costs

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

Impairment of assets (excluding goodwill)

At each balance sheet date, the Group reviews the carrying amounts of its oil and gas assets to assess whether there is an indication that those assets may be impaired. If any such indication exists, the Group makes an estimate of the asset's recoverable amount. An asset's recoverable amount is the higher of an asset's fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows attributable to the asset are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. In calculating the asset fair values the Group has applied an oil price assumption of US$119.25 per barrel in 2012, US$112.08 per barrel in 2013, US$104.73 per barrel in 2014, US$98.67 per barrel in 2015, US$97.42 per barrel in 2016 and inflated at 2% per annum thereafter. (2010: US$85 per barrel, escalated at 2% per annum) and a discounted pre-tax rate of 21.3% (2010: 19%).

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

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

Goodwill

Goodwill acquired in a business combination is initially measured at cost, being the excess of the cost of the business combination over the net fair value of the identifiable assets, liabilities and contingent liabilities of the entity at the date of acquisition. Following initial recognition, goodwill is stated at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that such carrying value may be impaired.

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

Impairment is determined by assessing the recoverable amount of the cash-generating unit to which the goodwill relates. Where the recoverable amount of the cash-generating unit is less than the carrying amount of the cash-generating unit and related goodwill, an impairment loss is recognised.

Where goodwill has been allocated to a cash-generating unit and part of the operation within the unit is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation. Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the cash-generating units retained.

Non-current assets held for sale

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

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

Financial assets

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

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

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

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

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

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

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

Financial assets at FVTPL are stated at fair value, with any gains or losses arising on remeasurement recognised in profit or loss.

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

The Group evaluates its financial assets held for trading, other than derivatives, to determine whether the intention to sell them in the near term is still appropriate. Where the Group is unable to trade these financial assets or management's intention to sell them in the foreseeable future changes significantly, the Group may elect to reclassify these assets. The reclassification to loans and receivables, available-for-sale or held to maturity depends on the nature of the asset. This evaluation does not affect any financial assets designated at FVTPL using the fair value option at designation, these instruments cannot be reclassified after initial recognition.

Held- to-maturity investments

Non-derivative financial assets with fixed or determinable payments and fixed maturity are classified as held-to-maturity when the Group has the positive intention and ability to hold them to maturity. After initial measurement, held-to-maturity investments are measured at amortised cost using the effective interest method (EIR), less impairment. Amortised cost is calculated by taking into account any discount or premium on acquisition and fees or costs that are an integral part of the EIR. The EIR amortisation and losses arising from impairment are included in the profit or loss.

Available-for-sale financial investments

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

Loans and receivables

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

Impairment of financial assets

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

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

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

Derivatives

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

The Group categorises derivatives as follows:

Fair value hedge

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

Cash flow hedge

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

Net investment hedge

Hedges of net investments in foreign operations are accounted for in a similar manner as cash flow hedges. The gain or loss accumulated in shareholders´ equity is transferred to the profit or loss at the time the foreign operation is disposed of.

Derivatives that do not qualify for hedge accounting

When derivatives do not qualify for hedge accounting, changes in fair value are recognised immediately in the profit or loss.

Trade receivables

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

Inventories

Inventories of consumable well supplies are stated at the lower of cost and net realisable value, cost being determined on a first in first out ('FIFO') basis. Inventories of hydrocarbons are stated at the lower of cost and net realisable value.

Under/over-lift

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

Cash and cash equivalents

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

Equity

Share capital

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

Merger reserve

Merger reserve represents the difference between the market value of shares issued to effect business combinations less the nominal value of shares issued and the consolidation adjustments that arise under the application of the pooling of interest method.

Cash flow hedge reserve

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

Share-based payments reserve

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

Retained earnings

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

Employee benefit trust

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

Provisions

Decommissioning

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

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

Other

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

Derecognition of financial assets and liabilities

Financial assets

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

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

· the Group retains the right to receive cash flows from the asset, but has assumed an obligation to pay them in

full without material delay to a third party under a 'pass-through' arrangement; or

· the Group has transferred its rights to receive cash flows from the asset and either (a) has transferred

substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all

the risks and rewards of the asset, but has transferred control of the asset.

Financial liabilities

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

If an existing financial liability is replaced by another from the same lender, on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability such that the difference in the respective carrying amounts together with any costs or fees incurred are recognised in the statement of comprehensive income.

Interest-bearing loans and borrowings

Interest-bearing loans and borrowings are recognised initially at fair value, net of transaction costs incurred.

Borrowing costs are stated at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis.

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

Revenue

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

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

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

Exceptional items

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

Depletion of fair value uplift to property, plant and equipment on acquiring strategic investments

IFRS requires that a fair value exercise is undertaken allocating the cost of acquiring controlling interests to the fair value of the acquired identifiable assets, liabilities and contingent liabilities. Any difference between the cost of acquiring the interest and the fair value of the acquired net assets, which includes identified contingent liabilities, is recognised as acquired goodwill. The fair value exercise is performed as at the date of acquisition.

The Directors have determined that for strategic investments it is important to separately identify the earnings impact of increased depletion arising from the acquisition date fair value uplifts made to property, plant and equipment over their useful economic lives. As a result of the nature of fair value assessments in the oil and gas industry the value attributed to strategic assets is subjective, based on a wide range of complex variables at a point in time. The subsequent depletion of the fair value uplifts bears little relationship to current market conditions, operational performance or cash generation. Management therefore reports and monitors the business performance of strategic investments before the impact of depletion of fair value uplifts to property, plant and equipment and the uplift is excluded from the business result presented in the Group statement of comprehensive income.

Leases

For a lease to qualify as a finance lease, substantially all of the risks and benefits of ownership must pass to the lessee. In all other cases the lease will be classified as an operating lease. Payments made under operating leases (net of any incentives received from the lesser) are charged to the statement of comprehensive income on a straight-line basis over the period of the lease.

Employee benefits

Short-term employee benefits

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

Pension obligations

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

Share-based payment transactions

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

Equity-settled transactions

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

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

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

Taxes

Income taxes

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

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

Deferred tax assets are recognised to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilised.

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

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

Production taxes

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

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

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 operating segment being the exploration for, and the extraction and production of hydrocarbons in the United Kingdom Continental Shelf.

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$954,051,000 or 98% of total revenue (excluding oil hedge gains and losses) in the year ended 31 December 2011 (2010: US$570,518,000 or 98% of total revenue).

4. Exceptional items and depletion of fair value uplift

	2011	2010
	US$'000	US$'000
Recognised in arriving at profit from operations before tax and finance income/ (costs):
Gain on disposal of asset held for sale	(8,644)	-
Impairment of available for sale assets	12,497	-
Initial Public Offering and acquisition costs	-	8,143
Costs relating to the acquisition of Stratic	-	5,289
Impairment of oil and gas assets	-	59,991
Well abandonment	(8,194)	8,194
	(4,341)	81,617
Tax	62,430	(49,948)
	58,089	31,669
Depletion of fair value uplift	16,973	16,319
	75,062	47,988

Gain on disposal of asset held for sale

During the year the Group disposed of its held for sale interest in the Petisovci project in Slovenia in return for 150,903,958 new ordinary shares in Ascent Resources plc (Ascent) at a market value of US$18,422,000 creating a gain of US$8,644,000.

Impairment of available for sale assets

Following disposal of the held for sale Petisovci asset, the Group held an investment in Ascent. The accounting valuation of this shareholding at 31 December 2011 resulted in a non-cash impairment of US$12,497,000.

Initial Public Offering and acquisition costs

In 2010, expenses relating to the acquisition of LNS and PEDL and the Company's listing on the London Stock Exchange and Stockholm NASDAQ OMX market of US$8,143,000 were included in general and administrative expenses in the statement of comprehensive income.

Costs relating to the acquisition of Stratic

In 2010, costs of US$5,289,000 relating to the acquisition of Stratic Energy Corporation ('Stratic') were included in general and administrative expenses in the statement of comprehensive income.

Impairment of oil and gas assets

There were no exceptional oil and gas assets impairment expenses during the year ended 31 December 2011. In the year ended 31 December 2010, impairment expenses were recognised on the Scolty (US$25,034,000) and Peik area (US$34,957,000) assets, of which US$2,121,000 related to property, plant and equipment oil and gas assets (note 10) and US$32,836,000 related to intangible oil and gas assets (note 13).

Well abandonment expenses

During the year a credit of US$8,194,000 (2010: debit of US$8,194,000) was recognised following a further review of options to recover funds from the previous Thistle field owners, relating to partial decommissioning of two wells covered by the Intervening Period and Decommissioning Liability Agreements.

Depletion of fair value uplift

Additional depletion arising from the fair value uplift of PEDL's oil and gas assets on acquisition of US$16,973,000 (2010: US$16,319,000) is included within cost of sales in the statement of comprehensive income.

Tax

In 2011, the enactment of the increase in the UK supplementary corporation tax rate on oil and gas activities in the North Sea increased the deferred tax charge in the income statement by US$78,149,000, of which US$68,086,000 relates to the revaluation of the opening deferred tax corporation tax balance. After adjusting for significant one-off charges, the Group has applied the Group's effective tax rate of 64.4% (2010: 51%) on exceptional items where appropriate.

5. Revenue and expenses

(a) Revenue

	Year ended 31 December	Year ended 31 December
	2011	2010
	US$'000	US$'000

Revenue from crude oil sales	960,401	570,518
Loss on realisation of cash flow hedges	(36,509)	-
Revenue from condensate sales	-	1,695
Tariff revenue	11,672	11,255
Other operating revenue	410	-
	935,974	583,468

(b) Cost of sales

	Year ended 31 December	Year ended 31 December
	2011	2010
	US$'000	US$'000

Cost of operations	233,008	180,903
Tariff and transportation expenses	43,043	41,661
Change in lifting position	14,631	3,864
Inventory movement - hydrocarbons	875	(2,809)
Depletion of oil and gas assets (note 10)	217,233	177,185
	508,790	400,804

	Year ended 31 December	Year ended 31 December
	2011	2010
	US$'000	US$'000

Unsuccessful exploration expenditure written off (note 13)	-	13,608
Impairment charge (note 13)	36,962	67,249
	36,962	80,857

(d) General and administration expenses

	Year ended 31 December	Year ended 31 December
	2011	2010
	US$'000	US$'000

Staff costs (note 5(g))	45,177	31,788
Depreciation (note 10)	1,784	845
Other general and administration costs	12,523	17,280
Recharge of costs to operations and joint venture partners	(43,435)	(22,711)
	16,049	27,202

(e) Other income

	Year ended 31 December	Year ended 31 December
	2011	2010
	US$'000	US$'000

Foreign exchange gains	5,042	4,838
Other income	2,294	2,186
	7,336	7,024

(f) Other expenses

	Year ended 31 December	Year ended 31 December
	2011	2010
	US$'000	US$'000

Foreign exchange losses	8,386	5,526
	8,386	5,526

(g) Staff costs

	Year ended 31 December	Year ended 31 December
	2011	2010
	US$'000	US$'000

Wages and salaries	21,279	12,823
Social security costs	3,137	3,177
Defined contribution pension costs	1,194	841
Expense of share-based payments (note 20)	4,881	3,070
Long-term incentive plan costs (note 20)	-	717
Other staff costs	1,845	651
Contractor costs	12,841	6,174
Redundancy costs	-	4,335
	45,177	31,788

The redundancy costs of US$4,335,000 which were incurred by the Group in the prior year were as a result of the Stratic acquisition. These costs are included in 'costs relating to the acquisition of Stratic' which were reported as an exceptional item (note 4).

The average number of persons employed by the Group during the year was 112 (2010: 60).

Details of remuneration, pension entitlement and incentive arrangements for each Director are set out in the Remuneration Report in the Annual Report and Accounts.

(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 31December
	2011	2010
	US$'000	US$'000

Audit of the Group financial statements	136	141
Local statutory audits of subsidiaries	127	228
Tax services (i)	913	80
Other services pursuant to legislation	78	63
Corporate finance services (ii)	-	651
	1,254	1,163

(i) Costs of US$620,000 (2010: nil) relating to tax advice on asset and corporate acquisitions are included in the balance sheet and will be capitalised as part of the cost of the asset.

(ii) Corporate finance services relate to the IPO and are included in the Initial Public Offering and acquisition costs of US$8,143,000 which are presented as an exceptional item (note 4) for the year ended 31 December 2010.

6. Finance income/costs

	Year ended 31 December	Year ended 31December
	2011	2010
	US$'000	US$'000

Finance costs:
Loan interest payable	-	1,693
Unwinding of discount on decommissioning provisions (note 23)	7,793	5,196
Cash flow hedge re-price premium	5,867	-
Other financial expenses	4,938	4,298
	18,598	11,187
Finance income:
Bank interest receivable	1,808	939
Ineffectiveness of financial derivatives (note 22)	2,147	-
Other financial income	-	235
	3,955	1,174

7. Income tax

(a) Income tax

The major components of income tax expense are as follows:

	Year ended 31 December	Year ended 31 December
	2011	2010
Group statement of comprehensive income	US$'000	US$'000
Current income tax
Current income tax charge	860	4,344
Adjustments in respect of current income tax of previous years	807	(2,121)

Deferred income tax
Relating to origination and reversal of temporary differences	226,970	25,899
Adjustments in respect of one-off increase in supplementary corporation tax	78,149	-
Adjustments in respect of deferred income tax of previous years	(4,956)	577
Income tax expense reported in statement of comprehensive income	301,830	28,699

(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
	2011	2010
	US$'000	US$'000
Profit before tax	362,821	55,775

Statutory rate of corporation tax in the UK of 59.3% (2010: 50%)	215,168	27,888
Supplementary corporation tax non-deductible expenditure	888	1,364
Non-deductible expenditure	3,195	3,682
Petroleum revenue tax (net of income tax benefit)	14,465	3,241
Ring fence expenditure supplement	(6,341)	(6,093)
Tax in respect of non-ring fence trade	1,596	971
Deferred tax rate increase on North Sea oil and gas activities	78,149	-
Adjustments in respect of prior years	(4,149)	(1,544)
Overseas tax	(1,141)	(810)
At the effective income tax rate of 83% (2010: 51%)	301,830	28,699

Deferred income tax relates to the following:

	Group balance sheet		Group statement of comprehensive income
	2011	2010 Restated¹	2011	2010
	US$'000	US$'000	US$'000	US$'000
Deferred tax liability
Accelerated capital allowances	775,486	552,829	222,657	(33,290)
Other temporary differences	46,345	6,347	39,999	2,334
	821,831	559,176
Deferred tax asset
Losses	(95,558)	(202,842)	107,284	69,525
Decommissioning liability	(112,368)	(70,054)	(42,314)	(12,093)
Other temporary differences	(36,512)	(4,808)	(27,463)	-
	(244,438)	(277,704)
Deferred tax expense			300,163	26,476
Deferred tax liabilities, net	577,393	281,472

Reflected in balance sheet as follows:
Deferred tax assets	(12,617)	(13,227)
Deferred tax liabilities	590,010	294,699
Deferred tax liabilities, net	577,393	281,472

¹ Restated for fair value adjustments as set out in note 11. In addition the 2010 comparatives are restated to be consistent with the treatment in 2011.

In addition to the amount charged to the profit and loss, a deferred tax credit of US$4,242,000 (2010: nil) has been taken directly to equity in respect of cash flow hedges (note 22).

(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.

During the prior year, deferred tax assets of US$9,669,000 were recognised on the acquisition of Stratic (note 11) in relation to unutilised tax losses. The tax losses relate to UK trading losses arising in Stratic Energy UK Limited prior to 2010, recoverability of which is dependent on future taxable trading profits in excess of those arising from the reversal of deferred tax liabilities in that company. It is anticipated that Stratic Energy UK Limited will generate taxable trading profits in the future in excess of the losses carried forward, and this company had taxable trading profits in 2011.

The Group has unused overseas tax losses in Canada of approximately CAD$76,577,000 (2010: CAD$77,361,000) and in Holland of €920,000 (2010: €920,000) 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 2012, and are subject to utilisation in restricted circumstances following the change in control of Stratic. Tax losses in Holland can be carried forward for a period up to nine years and are likely to expire in 2012. The overseas tax losses result from the Stratic acquisition on 5 November 2010 and there was a high degree of uncertainty in relation to the tax loss position of the acquired overseas entities following acquisition as the tax compliance in the overseas entities had not been completed for a number of years. The Group undertook a significant exercise to update the tax compliance history of the overseas entities acquired, which completed in December 2011, giving a basis for estimating the unused tax loss position as at 31 December 2010 and 2011.

(e) Change in legislation

The UK Government has released draft legislation to restrict the tax relief available on decommissioning expenditure to 50% in 2012. This change is not yet substantively enacted but is likely to give rise to a one-off exceptional additional tax charge in 2012 in the order of US$21,600,000.

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
	2011		2010	2011	2010	2011	2010
		US$'000	US$'000	Million	Million	US$	US$

Basic		60,991	27,076	801.7	686.8	0.076	0.040
Dilutive potential of Ordinary shares granted under share-based incentive schemes		-	-	2.9	5.6	-	-
Adjusted		60,991	27,076	804.6	692.4	0.076	0.040

9. Dividends paid and proposed

The Company paid no dividends during the year ended 31 December 2011 (2010: nil).

10. Property, plant and equipment

	Oil and gas assets	Office furniture and equipment	Total
	US$'000	US$'000	US$'000
Cost:
At 1 January 2010	835,926	4,646	840,572
Additions	148,492	2,366	150,858
Change in decommissioning provision	15,172	-	15,172
Acquisition of subsidiaries (restated¹)	629,011	801	629,812
At 31 December 2010 (restated¹)	1,628,601	7,813	1,636,414
Additions	291,723	4,677	296,400
Reclassified from intangible assets (note 13)	11,204	-	11,204
Change in decommissioning provision	50,722	-	50,722
At 31 December 2011	1,982,250	12,490	1,994,740

Depletion and depreciation:
At 1 January 2010	318,683	3,331	322,014
Impairment charge for the year	2,121	-	2,121
Charge for the year	177,185	845	178,030
At 31 December 2010	497,989	4,176	502,165
Charge for the year	217,233	1,784	219,017
At 31 December 2011	715,222	5,960	721,182

Net carrying amounts:

At 31 December 2011	1,267,028	6,530	1,273,558

At 31 December 2010	1,130,612	3,637	1,134,249

At 1 January 2010	517,243	1,315	518,558

¹ Restated for fair value adjustments as set out in note 11.

No interest has been capitalised within oil and gas assets during the year (2010: nil).

The net book value at 31 December 2011 includes US$107,433,000 (2010: US$5,344,000), of pre-development assets and development assets under construction which are not being depreciated.

During the year ended 31 December 2011 there were no tangible asset write offs. During the prior year, capitalised pre-development costs of US$2,121,000 and intangible asset licence costs of US$32,836,000 (note 13) associated with the Peik area were written off based on the Group's latest economic evaluation of the asset which did not support the delivery of an economic development.

11. Business combinations

Acquisition of Stratic

The acquisition of Stratic was completed on 5 November 2010 whereby the Group acquired 100% of the issued share capital for a consideration of US$54,163,000, satisfied by the issue and allotment of 24,434,983 EnQuest Ordinary shares.

The fair value allocation of the former Stratic assets and liabilities was accounted for using the acquisition method in 2010. The fair value was provisional at 31 December 2010 and has been reviewed in accordance with the provisions of IFRS 3 Business Combinations (Revised).

The fair value of the purchase consideration was derived from the opening share price of EnQuest shares on 5 November 2010, as quoted on the London Stock Exchange.

The initial fair values of assets and liabilities recognised on acquisition have been updated to reflect the finalisation of tax estimates and working capital adjustments and revisions to the valuation of intangible assets. The 48.75% interest in the Petisovci project was initially fair valued at the 30 day average market value of the 150,903,958 new ordinary shares in Ascent Resources plc ('Ascent'), which were received in return for the disposal of the asset on 11 February 2011. Following further review of the trading levels and price volatility of the Ascent shares, this valuation has been amended resulting in a reduction to the acquisition fair value of US$8,886,000. Also, following our unsuccessful sale process during the year, the fair value of the Dutch Sector P8 (Horizon West) area was reduced to nil.

The changes to the fair value of the identifiable assets and liabilities of Stratic are as follows:

	Revised fair values	Initial fair value recognised on acquisition	(Decrease)/increase to the fair value recognised on acquisition
	US$'000	US$'000	US$'000
Assets
Property, plant and equipment	129,286	131,486	(2,200)
Intangible oil and gas assets	11,222	22,809	(11,587)
Deferred tax assets	9,669	5,149	4,520
Inventories	2,215	2,215	-
Trade receivables	55	55	-
Other receivables and prepayments	4,869	4,506	363
Cash	5,421	5,421	-
	162,737	171,641	(8,904)
Liabilities
Provision - decommissioning	(10,840)	(10,840)	-
Loans and borrowings	(87,969)	(87,969)	-
Trade and other payables	(9,576)	(9,793)	217
Accrued expenses	(10,692)	(10,692)	-
	(119,077)	(119,294)	217

Total identifiable net assets at fair value	43,660	52,347	(8,687)

Goodwill arising on acquisition	10,503	1,816	8,687
Purchase consideration transferred,
comprising 24,434,983 Ordinary £0.05 EnQuest shares	54,163	54,163	-

The goodwill recognised above is attributed to the expected synergies and other benefits from combining the assets and activities of Stratic with those of the Group including the benefits of greater financial and commercial strength. None of the recognised goodwill will be deductible for income tax purposes.

No business combination expenses relating to the above transactions have been expensed in the year (2010: US$5,289,000). During 2010, from the date of acquisition, Stratic contributed US$6,511,000 to revenue and US$70,000 to the net profit before tax of the Group. If the combination had taken place at the beginning of 2010, net profit of the Group for 2010 would have been US$28,767,000 and revenue would have been US$608,210,000.

Acquisition of Petrofac Energy Developments Limited

The acquisition of Petrofac Energy Developments Limited ('PEDL') was completed in 2010 whereby the Group acquired 100% of the ordinary shares satisfied by the issue and allotment of 345,629,916 EnQuest Ordinary shares. The fair value allocation was accounted for using the acquisition method in 2010. The fair value allocation of the former PEDL assets and liabilities was provisional at 31 December 2010 and has been reviewed in accordance with the provision of IFRS 3 Business Combinations (Revised).

The fair value of the purchase consideration transferred to acquire PEDL was derived from the opening day share price of EnQuest shares on 6 April 2010, as quoted on the London Stock Exchange.

The initial fair values of assets and liabilities recognised on acquisition have been updated to reflect the finalisation of working capital adjustments.

The changes to the fair value of the identifiable assets and liabilities of PEDL are as follows:

	Revised fair values	Initial fair value recognised on acquisition	Increase/(decrease) to the fair value recognised on acquisition
	US$'000	US$'000	US$'000
Assets
Property, plant and equipment	500,526	500,526	-
Deferred income tax asset	27,310	27,310	-
Inventories	9,335	9,335	-
Trade receivables	5,626	4,884	742
Joint venture receivables	30,551	51,678	(21,127)
Other receivables and prepayments	21,253	20,051	1,202
Cash	16,135	16,135	-
	610,736	629,919	(19,183)

Liabilities
Provision	(55,966)	(55,966)	-
Deferred tax liability	(40,510)	(37,665)	(2,845)
Trade and other payables	(69,310)	(94,183)	24,873
Accrued expenses	(29,040)	(29,040)	-
	(194,826)	(216,854)	22,028

Total identifiable net assets at fair value	415,910	413,065	2,845

Goodwill arising on acquisition	97,257	100,102	(2,845)
Purchase consideration transferred,
comprising 345,629,616 Ordinary £0.05 EnQuest shares	513,167	513,167	-

The goodwill recognised above is attributed to the expected synergies and other benefits from combining the assets and activities of PEDL with those of the Group including the benefits of operational scale, access to a wider technical skill base and greater financial strength. None of the recognised goodwill will be deductible for income tax purposes.

No business combination expenses relating to the above transactions have been expensed in the year (2010: US$1,733,000).

During 2010 from the date of acquisition, PEDL contributed US$281,612,000 to revenue and US$75,759,000 to the net profit before tax of the Group. If the combination had taken place at the beginning of 2010, the net profit before tax of the Group for 2010 would have been US$54,311,000 and revenue would have been US$614,357,000.

12. Goodwill

A summary of the movement in goodwill is presented below:

	2011	2010 Restated¹
	US$'000	US$'000

At 1 January	107,760	-

Acquisitions:
Petrofac Energy Developments Limited	-	97,257
Stratic Energy Corporation	-	10,503

At 31 December	107,760	107,760

¹ Restated for fair value adjustments as set out in note 11.

Goodwill acquired through business combinations has been allocated to a single cash-generating unit ('CGU'), the UKCS, being the Group's only operating segment and therefore the lowest level that goodwill is reviewed by the Board.

Impairment testing of goodwill

In accordance with IAS 36 Impairment of Assets, goodwill was reviewed for impairment at the year end. In assessing whether goodwill has been impaired, the carrying amount of the CGU, including goodwill, is compared with its recoverable amount.

The recoverable amount of the CGU has been determined on a value in use basis using a discounted cash flow model comprising asset-by-asset life of field projections. The discount rate used is derived from the Group's post-tax weighted average cost of capital and is reassessed each year. 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 four years before reverting to the Group's long term pricing assumptions. For the purposes of calculating value in use, management has applied an oil price assumption of US$119.25 per barrel in 2012, US$112.08 per barrel in 2013, US$104.73 per barrel in 2014, US$98.67 per barrel in 2015, US$97.42 per barrel in 2016 and inflated at 2% per annum thereafter. In 2010, oil prices were based on management's assessment of oil price using publicly available forecast commodity prices; US$85 per barrel, escalated at 2% per annum.

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 discount rate applied to the Group's pre-tax cash flow projections is 21.3% (2010: 19%).

Sensitivity to changes in assumptions

There are reasonably possible changes in key assumptions which could erode the estimated amount of US$984,000,000 by which the calculated value in use exceeds the carrying value of the CGU. These are discussed below:

· oil price: management has considered the possibility of lower oil prices in the future. Revenue for the Group's

future oil production is directly linked to the market price of Brent blend oil. A fall in the price for Brent blend would directly impact the Group's revenue and potentially the economic life of assets in the CGU. It is estimated that the long-term price of oil that would cause the recoverable amount to be equal to the carrying amount of the CGU would be US$80.71 per barrel, escalated at 2% per annum (2010: US$65 per barrel, escalated at 2% per annum).

· production volumes: estimated production volumes were taken from the report prepared by the Group's independent reserve assessment experts. On a weighted average basis, production would need to fall by 13% (2010: 24%) to cause the recoverable amount to fall below the carrying amount of the CGU (using a simplified oil price assumption of $90 per barrel).

13. Intangible oil and gas assets

		US$'000
Cost
At 1 January 2010		102,914
Additions		17,374
Acquisition of subsidiaries (restated¹)		11,222
Unsuccessful exploration expenditure written off		(13,608)
Reclassified to asset held for sale (note 14)		(9,778)
At 31 December 2010 (restated¹)		108,124
Additions		64,165
Write-off of relinquished licences previously impaired		(34,127)
Reclassified to tangible fixed assets (note 10)		(11,204)
Reclassified to asset held for sale (note 14)		(1,254)
At 31 December 2011		125,704

Provision for impairment
At 1 January 2010		(31,273)
Impairment charge for the year		(67,249)
At 31 December 2010		(98,522)
Impairment charge for the year		(36,962)
Write-off of relinquished licences previously impaired		34,127
At 31 December 2011		(101,357)

Net carrying amount:

At 31 December 2011		24,347

At 31 December 2010		9,602

At 1 January 2010		71,641

¹ Restated for fair value adjustments as set out in note 11.

During the year ended 31 December 2011, US$34,127,000 of costs relating to relinquished licences were written off. These had previously been impaired in full. Also, during the year costs of US$36,962,000 were impaired relating to dryhole wells or uneconomic assessment on evaluation of the assets.

During the prior year, capitalised intangible asset licence costs of US$32,836,000 and pre-development costs of US$2,121,000 (note 10), associated with the Peik area were impaired based on the Group's initial evaluation of the asset which did not support the delivery of an economic development.

Also, during the year ended 31 December 2010, following a decision taken to discontinue field specific exploration activities on certain licences, US$48,021,000 of capitalised evaluation costs were impaired and written off including US$25,034,000 in relation to the Scolty area. During 2011, the Group acquired a 40% farm in interest in the Crathes area. Following a successful Crathes exploration well in Q4 2011, the Group is evaluating the potential commerciality of the combined Crathes, Scolty and Torphins area; however reversal of the 2010 Scolty impairment will not be considered until commerciality of the area development is confirmed on Field Development Plan (FDP) approval.

14. Assets held for sale

		US$'000

At 1 January 2010		-
Reclassified from intangible fixed assets (note 13)		9,778
At 31 December 2010 (restated¹)		9,778
Disposals		(9,778)
Reclassified from intangible fixed assets (note 13)		1,254
At 31 December 2011		1,254

¹ Restated for fair value adjustments as set out in note 11.

On 11 February 2011, the Group disposed of its held for sale interest in the Petisovci project ('Petisovci') in Slovenia in return for 150,903,958 new ordinary shares in Ascent at a market value of US$18,422,000, creating a gain of US$8,644,000.

During 2011, the 'FQuad' Dutch assets were reclassified as 'held for sale' as they are subject to a swap arrangement whereby these will be transferred to Sterling Resources Limited for a 50% share in the Cairngorm licence Block 16/3d.

15. Investments

		2011
		US$'000
Cost
At 1 January 2011		-
Additions		19,231
At 31 December 2011		19,231

Provision for impairment
At 1 January 2011		-
Impairment charge for the year		(12,497)
At 31 December 2011		(12,497)

Net carrying amount:
At 31 December 2011		6,734

At 31 December 2010		-

The Group acquired an investment of 150,903,958 new ordinary shares in Ascent at a market value of US$18,422,000 on the disposal of the held-for-sale Petisovci asset on 11 February 2011. A further 10,000,000 shares were purchased during the year increasing the value of the investment to US$19,231,000. The accounting valuation of the Group's shareholding (based on the movement in the quoted share price of Ascent) resulted in an initial non-cash impairment of US$10,629,000 followed by a further non-cash impairment of US$1,868,000. The total non-cash impairment at 31 December 2011 is US$12,497,000.

16. Inventories

	2011	2010
	US$'000	US$'000

Crude oil	11,842	12,404

17. Trade and other receivables

	2011	2010 Restated¹
	US$'000	US$'000

Trade receivables	75,031	77,945
Joint venture receivables	33,411	41,535
Other receivables	9,313	5,430
	117,755	124,910
Prepayments and accrued income	8,799	7,707
	126,554	132,617

¹ Restated for fair value adjustments as set out in note 11 and joint venture receivables are restated to be consistent with the treatment in 2011.

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 2011 no impairment provision for trade receivables was necessary (2010: nil).

Joint venture receivables relate to billings to joint venture partners and were not impaired. There were US$705,000 of joint venture receivables past due and not impaired at 31 December 2011 (2010: US$547,000 past due but not impaired).

As at 31 December 2011 other receivables of nil (2010: US$8,194,000) were determined to be impaired. During the year, the prior year impairment was reversed following a further review of options to recover these expenses (note 4).

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.

18. 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.

19. Share capital

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

	2011	2010
Authorised, issued and fully paid	US$'000	US$'000

802,660,757 (2010:799,462,905) Ordinary shares of £0.05 each	61,249	60,990
Share premium	52,184	52,184
	113,433	113,174

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

On 14 April 2011, 3,197,852 (7 April 2010: 6,962,020) Ordinary shares of £0.05 each were issued at par and allotted to the Company's Employee Benefit Trust to satisfy awards made under the Company's share-based incentive schemes.

On incorporation, the Company issued and allotted two Ordinary shares of £1.00 each. On 18 March 2010 the Board approved a 20:1 share split whereby each £1.00 Ordinary share was converted to 20 Ordinary shares of £0.05.

On 5 April 2010, the Company issued and allotted, in aggregate, 345,629,616 Ordinary shares of £0.05 each to the shareholders of Petrofac Limited, the ultimate holding Company of PEDL, in consideration for the transfer of PEDL's voting shares to EnQuest.

On 6 April 2010, the Company issued and allotted 422,436,246 Ordinary shares of £0.05 each to Lundin Petroleum AB, the ultimate holding Company of LNS, in consideration for the transfer of LNS's voting shares to EnQuest.

On 8 November 2010, a further 24,434,983 Ordinary shares of £0.05 each were issued and allotted to the shareholders of Stratic in consideration for the transfer of Stratic's voting shares to the Company.

20. 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,.

Deferred Bonus Share Plan (DBSP)

Directors and 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 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 four year 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

2011 awards

2010 awards

137p

101p

84%

98%

The following shows the movement in the number of shares held under the DBSP scheme outstanding but not exercisable:

2011

Number*

2010

Number*

Outstanding at 1 January

Granted during the year

Vested during the year

Forfeited during the year

390,730

351,444

(94,292)

(121,802)

390,730

Outstanding at 31 December

526,080

390,730

* Includes invested and matching shares.

The charge recognised in the 2011 statement of comprehensive income in relation to matching share awards amounted to US$308,000 (2010: US$72,000).

Restricted Share Plan (RSP)

Under the Restricted Share Plan scheme, employees are granted shares in EnQuest over a discretionary vesting period, which may or may not be, at the direction of the Remuneration Committee of the Board of Directors of EnQuest, subject to the satisfaction of performance conditions. Awards made in 2010 and 2011 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

2011 awards

2010 awards

119p

104p

95%

98%

The following table shows the movement in the number of shares held under the RSP scheme outstanding but not exercisable:

2011

Number

2010

Number

Outstanding at 1 January

Granted during the year

Vested during the year

Forfeited during the year

7,926,411

829,845

(298,515)

(420,786)

7,926,411

Outstanding at 31 December

8,036,955

7,926,411

The charge recognised in the year ended 31 December 2011 amounted to US$3,767,000 (2010: US$2,997,000).

Performance Share Plan (PSP)

Under the Performance Share Plan, the shares vest subject to performance conditions. The 2010 PSP share awards granted in 2011 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.

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

2011 awards

137p

97%

The following table shows the movement in the number of shares held under the PSP scheme outstanding but not exercisable:

2011

Number

2010

Number

Outstanding at 1 January

Granted during the year

Vested during the year

Forfeited during the year

1,722,022

(53,500)

Outstanding at 31 December

1,668,522

The charge recognised in the year ended 31 December 2011 amounted to US$806,000 (2010: nil).

The Company has recognised a total charge of US$4,881,000 (2010:US$3,070,000) in the statement of comprehensive income during the year, relating to the above employee share-based schemes.

Long-Term Incentive Plan scheme (LTIP)

Prior to the formation of EnQuest PLC, LNS participated in the Lundin Petroleum Group LTIP scheme which consisted of an annual grant of units that converted into cash payment at vesting. The cash payment was determined at the end of each vesting period by multiplying the number of units by the share price. The LTIP had a three year duration whereby the initial grant of units vested equally in three tranches; one third after one year, one third after two years and the final third after three years. The demerger of LNS from the Lundin Petroleum Group resulted in all LTIP awards vesting due to the change in control in 2010, resulting in total costs of US$717,000 for the year ended 31 December 2010. There were no costs incurred in the year ended 31 December 2011.

Share Option Programme

LNS participated in the Lundin Petroleum Group Share Option programme prior to the formation of EnQuest PLC, whereby warrants were issued to employees enabling them to buy shares in Lundin Petroleum AB. All incentive warrants issued under this scheme expired by 30 June 2010.

Movements in the number of incentive warrants outstanding in relation to employees of the Group and the related weighted average exercise prices are as follows:

	2011	2011	2010	2010
	Average weighted exercise price	Number of shares	Average weighted exercise price	Number of shares
	SEK per share		SEK per share


At 1 January	-	-	78.05	118,250
Lapsed	-	-	78.05	(118,250)
At 31 December	-	-	-	-

21. Loans and borrowings

(i) Revolving credit facility

At 31 December 2011 the Group had a two year US$280,000,000 Revolving Credit Facility Agreement with Bank of Scotland and BNP Paribas which is secured on the assets of the Group and due to mature on 17 March 2012. Under the terms of the facility agreement, the Group has the ability to draw loans to a maximum value of US$156,250,000 and utilise Letters of Credit ('LoC') to a maximum aggregate value of US$123,750,000.

Interest on the revolving credit facility is payable at US LIBOR (relative to each agreed loan period) plus a margin of 2.25% to 3.25%, dependent on specified covenant ratios. A facility non-utilisation commitment fee is payable at 50% of the interest margin.

At 31 December 2011, there were no borrowings under the Group's facility agreement (2010: nil) and LoC utilisation of US$123,750,000 (2010: US$74,000,000).

(ii) Term loan

At 31 December 2009, LNS had a term loan under the Lundin Petroleum AB Group term loan facility with BNP Paribas. On 31 March 2010, in anticipation of the combination of LNS with EnQuest, this term loan was assigned from LNS to Lundin Petroleum BV. The resulting liability between LNS and Lundin Petroleum BV, net of a long-term loan receivable by LNS and a working capital settlement payable by LNS, was capitalised on 6 April 2010.

Reconciliation of loan assignment to capital contribution on assignment of debt on de-merger:

	US$'000

Loans assigned to Lundin Petroleum on de-merger	156,000
Working capital settlement payable to Lundin Petroleum	(9,337)
Loan receivable from Lundin Petroleum at 31 December 2009	(21,443)
Capital contribution on assignment of debt on de-merger	125,220

22. Other financial assets and financial liabilities

	2011	2010
	US$'000	US$'000
Financial instruments at fair value through other comprehensive income
Current liabilities
Cash flow hedges:
Forward foreign currency contracts	6,507	-

Non-Current liabilities
Cash flow hedges:
Forward foreign currency contracts	335	-

Financial instruments at fair value through profit or loss
Current assets
Derivatives not designated as hedges:
Commodity forward contracts	2,510	-

Current liabilities
Derivatives not designated as hedges:
Commodity forward contracts	363	-

Total current assets	2,510	-
Total assets	2,510	-

Total current liabilities	6,870	-
Total non-current liabilities	335	-
Total liabilities	7,205	-

The fair value measurements of the financial instruments held by the Group have been derived based on observable market inputs (as categorised within Level 2 of the fair value hierarchy under IFRS 7).

Commodity forward contracts

During the fourth quarter of 2010, the Group entered into four zero premium oil price collars to partially hedge its exposure to fluctuations in oil prices in 2011. Each collar hedged the price of approximately 1,000,000 barrels of oil in 2011. Losses of US$36,509,000 (2010:nil) on the unwinding of these contracts during the year are included within revenue in the comprehensive income statement.

In November 2011, the Group entered into five separate put and call options in order to hedge the changes in future cash flows from the sale of Brent Oil production for approximately 3,000,000 barrels of oil in 2012. These instruments were deemed to be ineffective and are therefore designated as at fair value through profit and loss (FVTPL). The derivative instruments had a net asset fair value of US$2,147,000 (2010: nil) and gains of US$2,147,000 (2010: nil) were taken into profit and loss during the year and are included within other financial income.

Forward foreign currency contracts

During the year ended 31 December 2011, the Group had also entered into 11 forward currency contracts to partially hedge the Group's exposure to fluctuations in foreign currencies, namely Sterling and Euro, of which nine will mature in 2012 and 2013.

These contracts qualify for hedge accounting. At 31 December 2011 the total fair value of these derivatives was a liability of US$6,842,000 (2010: nil). An unrealised loss of US$2,600,000 (2010: nil) relating to the hedging instruments are included in other comprehensive income net of deferred tax of US$4,242,000 (2010: nil). There was no impact in profit or loss during the year (2010: nil) in respect of these contracts.

23. Provisions

	Decommissioning	Others	Total
	US$'000	US$'000	US$'000

At 1 January 2010	52,934	264	53,198
Additions during the year	10,897	-	10,897
Acquisition of subsidiaries	66,806	-	66,806
Changes in estimates	4,275	-	4,275
Unwinding of discount	5,196	-	5,196
Utilisation	-	(264)	(264)
At 31 December 2010	140,108	-	140,108
Additions during the year	33,821	-	33,821
Changes in estimates	16,901	-	16,901
Unwinding of discount	7,793	-	7,793
Utilisation	(17,386)	-	(17,386)
At 31 December 2011	181,237	-	181,237

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 2030 assuming no further development of the Group's assets. The liability is discounted at a rate of 5.0% (2010: 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.

24. Trade and other payables

	2011	2010 Restated¹
	US$'000	US$'000

Trade creditors	26,215	8,016
Accrued expenses	192,494	124,536
Other payables	15,628	3,171
	234,337	135,723

¹ Restated for fair value adjustments as set out in note 11 and accrued expenses are restated to be consistent with the treatment in 2011.

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 GBP.

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.

25. Commitments and contingencies

Commitments

Leases

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 five years. The future minimum rental commitments under these non-cancellable leases are as follows:

	2011	2010
	US$'000	US$'000

Not later than one year	1,372	1,725
After one year but not more than five years	2,170	3,433
	3,542	5,158

Lease payments recognised as an operating lease expense during the year amounted to US$2,066,054 (2010: US$1,163,446).

Under the Dons Northern Producer agreement a minimum notice period of twelve months exists, whereby the Company expects the minimum commitment under this agreement to be approximately US$47,000,000 (2010: US53,000,000).

Capital commitments

At 31 December 2011, the Group had capital commitments excluding the above lease commitments amounting to US$310,408,000 (2010: US$78,602,000).

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.

The following table provides the total amount of transactions which have been entered into with related parties who are not members of the group:

	Sales to related	Purchases from	Amounts owed	Amounts owed
	parties	related parties	by related parties	to related parties
	US$'000	US$'000	US$'000	US$'000

2010:
Lundin Petroleum BV	904	-	-	-
Parent Company	904	-	-	-

Following the restructure on 6 April 2010, Lundin Petroleum BV ceased to be a related party. There have been no other transactions with related parties during 2011.

The carrying value of the Group's related party assets and liabilities as stated above is considered to be a reasonable approximation to their fair value.

Compensation of key management personnel

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

	2011	2010
	US$'000	US$'000

Short-term employee benefits	3,849	4,992
Share-based payments	2,850	2,323
Post employment pension benefits	29	38
	6,728	7,353

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 and borrowings, 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 2011 and 2010 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 2010, the Board of EnQuest approved a policy to hedge up to a maximum of 50% of annual oil production. During the fourth quarter of 2010, four zero premium oil price collars were entered into to hedge the Group's exposure to fluctuation in oil prices, hedging approximately 4,000,000 barrels of oil in 2011. In November 2011, the Group entered into five separate put and call options to hedge approximately 3,000,000 barrels of oil in 2012.

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 2011	70,836	(67,500)	26,918	(25,650)
31 December 2010	69,746	(69,746)	20,661	(33,478)

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. The Group manages this risk by converting US$ receipts at spot rates periodically and as required for payments in other currencies. Approximately 2% (2010: 6%) of the Group's sales and 86% (2010: 79%) 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 of which nine mature in 2012 and 2013 to partially hedge the Group's exposure to fluctuations in foreign currencies, namely Sterling and Euro. These contracts qualify for hedge accounting and have been disclosed within note 22.

The following table summarises the impact on the Group's pre-tax profit and equity (due to change in the fair value of monetary assets and liabilities) of a reasonably possible change in United States dollar exchange rates with respect to different currencies:

	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 2011	(25,056)	25,056	1,438	(1,438)
31 December 2010	(22,664)	22,664	(10,879)	10,879

Credit risk

The Group trades only with recognised, international oil and gas operators and at 31 December 2011 there were no trade receivables past due (2010: nil), and US$705,000 of joint venture receivables past due but not impaired (2010: US$547,000). Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary.

	2011	2010
Aging of past due but not impaired receivables:	US$'000	US$'000

Less than 30 days	7	14
30-60 days	-	4
60-90 days	622	529
90-120 days	21	-
120+ days	55	-
	705	547

At 31 December 2011, the Group had one customer accounting for 92% of outstanding trade and other receivables (2010: one customer, 97%) and six joint venture partners accounting for 80% of joint venture receivables (2010: three joint venture partners, 82%).

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 2011 the Group was in compliance with all financial covenant ratios agreed with its bankers.

At 31 December 2011, the Group had US$156,250,000 (2010: US$206,000,000) of undrawn committed borrowing facilities available which were due to expire in March 2012. On 6 March 2012, a new 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 was established. The new facility comprises a committed amount of US$525,000,000 for three years, extendable to four years at the option of the Group (provided conditions are met) and a further year with the consent of the lenders. In addition, US$375,000,000 is available primarily for investment opportunities also with the lenders consent. The Letters of Credit of US$123,750,000 under the old facility have been rolled into the new facility. An upfront arrangement fee of 1.75% was payable.

Interest on the revolving credit facility is payable at LIBOR relative to each agreed loan period plus a margin of 2.25% to 3.25% 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 2011	On demand	Up to 1 year	1 to 2 years	2 to 5 years	Total
	US$'000	US$'000	US$'000	US$'000	US$'000

Accounts payable and accrued liabilities	234,337	-	-	-	234,337
Financial expenses	-	922	-	-	922
	234,337	922	-	-	235,259


Year ended 31 December 2010	On demand	Up to 1 year	1 to 2 years	2 to 5 years	Total
	US$'000	US$'000	US$'000	US$'000	US$'000

Accounts payable and accrued liabilities	135,723	-	-	-	135,723
Financial expenses	-	3,983	1,320	-	5,303
	135,723	3,983	1,320	-	141,026

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

Year ended 31 December 2011
	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	-	50,691	219,750	25,395	-	295,836
Foreign exchange forward contracts	-	(50,691)	(219,750)	(25,395)	-	(295,836)
	-	-	-	-	-	-

At 31 December 2011, the Group held commodity forward contracts for which, based on the oil price at 31 December 2011, there were no projected contracted cash flows.

At 31 December 2010, the Group did not hold any foreign exchange forward contracts. In respect of the oil price collars held at 31 December 2010 the oil price was between the cap and floor prices and therefore there were no projected contracted cash flows.

Capital management

The Group's management is committed to delivering and enhancing shareholder value, and building upon the progress made during the current year. The Board believes that this can best be achieved by reinvesting in the Group's core business and through pursuing selective acquisitions and development opportunities. In light of the Group's commitment to investment in ongoing production operations development, exploration projects and acquisitions, the Directors do not recommend payment of a dividend at this time. This is, however, re-assessed by the Board on a regular basis.

The Group seeks to optimise the return on investment, by managing its capital structure to achieve capital efficiency whilst also maintaining flexibility for future acquisitions. The Group keeps under review the costs and access to debt funding to ensure it has appropriate flexibility. Note 21 to the financial statements provides further details of the Group's financing activity.

Capital for the Group is equity attributable to the equity holders of the Parent Company, and is in the Group statement of changes in equity.

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

	2011	2010
	US$'000	US$'000
Loans and borrowings, net (A)	-	-
Cash and short-term deposits	378,907	41,395
Net debt (B)	378,907	41,395

Equity attributable to EnQuest PLC shareholders (C)	934,208	882,896

Profit for the year attributable to EnQuest PLC shareholders (D)	60,991	27,076

Gross gearing ratio (A/C)	n/a	n/a

Net gearing ratio (B/C)	n/a	n/a

Shareholders' return on investment (D/C)	7%	3%

28. Post balance sheet events

On 9 January 2012, the Group announced its agreement with Canamens Limited to acquire two of its companies, whose assets include a 20% interest in the Kraken oil discovery. The Group paid an initial consideration of US$45,000,000 in cash and a further payment of US$45,000,000 is contingent upon approval of the Kraken Field Development Plan (FDP) by the Department of Energy and Climate Change (DECC). Due to the proximity to the year end, an assessment of whether this acquisition should be accounted for as an asset acquisition or business combination has still to be made and will be reviewed prior to the Group's 2012 half year results announcement.

On 13 January 2012, the Group entered a Sale and Purchase Agreement with JX Nippon Exploration & Production (UK) Limited to purchase a 18.5% working interest in the West Dons Field for US$34,000,000.

On 24 January 2012, the Group announced an agreement with Nautical Petroleum plc to acquire a further 25% interest in the Kraken oil discovery, together with interests in surrounding exploration acreage. This agreement is subject to the normal regulatory and partner consents. EnQuest will pay Nautical between US$150,000,000 and US$240,000,000 (dependant on a future determination of the gross 2P reserves), by way of a development carry arrangement in relation to Nautical's remaining interest in the discovery.

The Uisge Gorm Floating Production and Storage Offloading vessel ('FPSO') was procured on 25 January 2012 for US$52,500,000.

On 6 March 2012, in anticipation of the maturity of the existing Revolving Credit Facility Agreement, the EnQuest PLC established a three year US$900,000,000 Multi-Currency Revolving Credit Facility Agreement, the details of which can be found within note 27 to the financial statements under liquidity risk.

29. Subsidiaries

At 31 December 2011, EnQuest PLC had investments in the following principal 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 (i)	Intermediate holding Company and provision of Group manpower and contracting/procurement services	England	100%

EnQuest Dons Limited	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%

Grove Energy Limited (i)	Intermediate holding Company and exploration of hydrocarbons	Canada	100%

(i) Held by subsidiary undertaking.

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