Final Results

RNS Number : 9567A

EnQuest PLC

27 March 2013

ENQUEST PLC, 27 March 2013

Results for the 12 months to 31 December 2012

Sustained strong cash flow generation

Major project execution on track

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

Highlights

· EnQuest performed well in 2012, delivering production of 22,802 Boepd, above the mid-point of guidance due to a successful drilling programme

· EnQuest's net 2P reserves at the start of 2013 were 128.5 MMboe, an 11.5% increase on the start of 2012; reflecting a reserves replacement ratio of 262.2% and a reserve life of 15.6 years

· Revenue of $889.5 million, EBITDA^* of $626.2 million and cash generated from operations of $593.9 million, reflecting strong underlying operational performance and cost control

· Profit after tax was $259.7 million, up 90.8% on the prior year

· 2012 capital investment on property, plant and equipment oil and gas assets amounted to $802.9 million

· The Alma/Galia development project is on track for first oil in Q4 2013 and the new Kraken development is on schedule for the submission of the Field Development Plan ('FDP') in Q2 2013

· Average production guidance for the full year 2013 is between 22,000 Boepd and 27,000 Boepd, as approximately 1,000 Boepd has been lost, primarily due to third party shutdowns of the Brent pipeline in Q1 2013

	2012		2011	Change %
Production (Boepd)		22,802	23,698	(3.8)
Revenue ($m)		889.5	936.0	(5.0)
Realised oil price $/bbl		111.6	107.6	3.7
Gross profit ($m)		441.3	444.2	(0.1)
Profit before tax & net finance costs ($m)		405.1	390.1	3.8
Profit after tax ($m)		259.7	136.1	90.8
EBITDA * ($m)		626.2	629.1	(0.5)
Cash generated from operations ($m)		593.9	656.3	(9.5)
Reported basic earnings per share (cents)		46.2	7.6	507.9
Net cash ^** ($m)		89.9	378.9	(76.3)

* EBITDA is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion (adjusted for depletion of fair value uplift), depreciation, impairment and write-off of intangible oil and gas assets. ** Net cash represents cash and cash equivalents less borrowings as at the reported cash flow statement date of 31 December.

EnQuest CEO Amjad Bseisu said:

"In 2012, our successful drilling programme and strong operational performance produced 22,802 Boepd, above the mid-point of our guidance. This was driven by five production wells being brought onstream and by strong operations execution at Thistle and the Dons. In 2012, EnQuest generated $593.9 million in cash flow from operations. In the three years since our inception, we have built a strong technically focused organisation that has generated total cash from operations of over $1.5 billion.

The execution of our major new development projects is on track; Alma/Galia is set to produce first oil in Q4 of this year and we are planning to submit our Field Development Plan ('FDP') for the new Kraken development in Q2 2013. With the Kraken and Alba acquisitions and through the 27^th UK Licensing Round, we have further expanded our asset base. In 2012, EnQuest doubled the number of UKCS blocks in which it has an interest and established a presence in oil basins outside the UK North Sea. At the end of 2012, EnQuest had increased 2P reserves to 128.5 MMboe, representing a reserve replacement ratio of 262.2% and a reserve life of over 15 years."

2013 Outlook

Summary

· In total, EnQuest plans to deliver 12 wells in 2013. This includes six production wells, three injection wells and three exploration/appraisal wells

· Capital expenditure in 2013 is expected to be approximately $750 million with around $350 million invested in the Alma/Galia development and about $75 million pre-development expenditure for the new Kraken development prior to submission of the Field Development Plan ('FDP'); this Kraken pre-development expenditure includes an appraisal well to be drilled in Q2 2013

· Production and transportation costs for 2013 are expected to be in the range $310 million to $340 million

· Exploration and appraisal. Appraisal wells will be drilled at Cairngorm and Kraken. In H2 2013, an exploration/appraisal well is expected to be drilled in the Sabah area, offshore Malaysia

· Development opportunities. Options for a proposed Crathes/Scolty development are being analysed and a range of development options continues to be evaluated at Kildrummy. Development studies at Crawford/Porter also continue

· EnQuest's UK production licences increased from 22 at the start of 2012, to 39 at the start of 2013, including 11 licences from the UK's 27^th Licensing Round

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

By Production and Development Asset

Thistle/Deveron

· In February 2013, EnQuest announced that it had sanctioned the next phase of the Thistle life extension project, facilitated by its qualification for the UK government brownfield allowance programme. The current Thistle drilling campaign has been extended and the final well in the current phase, a new production well in the West Fault Block, will be drilled in Q2 2013. Drilling will then stop on Thistle for a year, to allow for the life extension programme to be continued

· Due to the third party closure of the Brent pipeline, production from Thistle was shut down in Q1 2013 for an unscheduled 8 days

Dons

· The Don Southwest Area 6 DS producer is expected online in Q2 2013 and an associated water injector will be drilled later in the year. The West Don W6 (NJ) water injector well was tied in and brought online in Q1 2013

· Due to the third party closure of the Brent pipeline, production from the Dons was shut down in Q1 2013 for an unscheduled 8 days

Heather/Broom

· The drilling programme at Heather will start in Q3 2013, following the completion of drilling on Thistle

Alma/Galia

· In February 2013, EnQuest announced it approved an increase in the scope and specification of the Alma/Galia project with the objective of extending the field life, optimising operating costs and enabling a potential second phase of development

· First oil from Alma/Galia is scheduled for Q4 2013

Kraken

· The new development of Kraken remains on track for submission of FDP in Q2 2013 and is targeting first oil in 2016.

Review of 2012

Financial

· Strong levels of cash generation continued, with cash generated from operations of $593.9 million resulting in net cash of $89.9 million at the end of 2012, after cash outflow of $842.3 million on capital expenditure

· Tax losses increased to approximately $600 million at the end of 2012, reflecting the investment programme

· 2012 revenue of $889.5 million was 5.0% lower than in 2011, due to the expected decrease in production, partly offset by the increase in the realised average price per barrel of oil sold. Revenue for 2012 was also lower than 2011 due to an underlift of $24.4 million in 2012, compared to an overlift of $14.6 million in 2011

· Profit from operations before tax and net finance costs was $405.1 million, a 3.8% increase over 2011. This reflects the $44 million decrease in cost of sales, partly reflecting a $39 million change in the lifting position and also a reduction in the absolute level of operating costs. Underlying operational performance and cost control were strong

· Profit after tax increased by 90.8% to $259.7 million, mainly due to a reduction in income tax expense compared with 2011

· Exceptional items included a $175.9 million gain on disposal from the farm out of a 35% interest in Alma/Galia. There was also a $143.9 million impairment of the Heather and Broom hub following a delay in phasing of production, particularly to allow the drilling of the West Fault Block well at Thistle in 2013; there was also an increase in estimated capital expenditure associated with the field life extension programme. The Heather and Broom hub inherited a high net book value of $423 million, reflecting the fair value uplift when Lundin acquired the Heather and Broom assets prior to the formation of EnQuest

· 2012 capital investment on tangible oil assets amounted to $802.9 million. This included $367.1 million invested in EnQuest's existing producing fields and $421.3 million in executing the Alma/Galia development project plan, of which $86.7 million was the carry element

· The 2012 cash generated from operations of $593.9 million, is lower than the equivalent $656.3 million 2011 figure, primarily due to the $67.5 million increase in year end joint venture receivables, principally in relation to Alma/Galia

Production, Development & Reserves

	Net daily average 2012	Net daily average 2011
	(Boepd)	(Boepd)
Thistle/Deveron	8,058	5,436
The Don Fields	10,992	12,770
Heather/Broom	3,752	5,492
Total	22,802	23,698

Thistle/Deveron

· Base oil production increased significantly over 2011, partly due to more reliable power and to enhanced water injection rates, supplemented with oil production from three electrical submersible pumps ('ESP's'). The Deveron P1 ESP well started production in late Q1 2012, with productivity at the upper end of pre-drill estimates. The A59/45 Area 6 well was completed in late September and the ESP came onstream in October 2012. Following a successful wireline intervention, the Thistle A27/17 well came back on line in December, helping to increase year end production levels. The new gas turbine power generator was lifted onto the Thistle platform in H2 2012, an important milestone in the Thistle life extension project

Dons/Conrie

· The expected year on year decrease was due mainly to the decline in production from the S5 well, which had been drilled and brought onstream in 2010. In July 2012 at Don Southwest, the S11 well came online at a good initial rate. Well W2 on West Don was abandoned in September; following which well W5, the sidetrack of well W2, was brought online in October. A new water injection well, W6, was drilled in 2012 and tied in in Q1 2013. At Don Southwest, the S10Y came onstream in Q4 2012, in line with expectations

Heather/Broom

· The year on year decline at Heather/Broom was as anticipated, reflecting the natural decline in production from Broom BR2. Plant management at Heather was good, resulting in high production efficiency

Alma/Galia

· EnQuest executed well on its development of its new Alma/Galia hub in 2012, finishing the year on track for first oil in Q4 2013. Six wells were batch drilled in 2012 (K1 to K6), the three which had been drilled through the reservoir by the year end were all at or better than prognosis

Kraken

· Following EnQuest's acquisition of 60% of Kraken in 2012 and its assumption of operatorship of the proposed development project in September 2012, EnQuest has been working closely with its partners in preparation for the submission of the project FDP in Q2 2013 and for first oil targeted for 2016

Reserves

· 11.5% year on year growth in audited net 2P reserves to 128.5 MMboe, a strong reserves replacement ratio of 262.2%, after production of 8.2 MMboe during 2012. Reserves growth was driven by 20.4 MMboe which relates to EnQuest's 20% direct interest in Kraken. Contingent resources in respect of the remaining 40% carried interest are anticipated to be recognised as 2P reserves after the FDP has been submitted. Net contingent resources have been increased by 62.9 MMboe in relation to EnQuest's interest in Kraken.

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)

RLM 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 3365

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 2012, including the licences EnQuest was offered through the UK's 27^th Licensing Round, EnQuest had interests in 39 production licences covering 55 blocks or part blocks in the UKCS, of which 31 licences are operated by EnQuest. In addition, EnQuest also has an interest in two blocks offshore in Sabah, Malaysia.

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.

Business Review
Chairman's Statement

Overview
EnQuest delivered on plan in 2012, with production of 22,802 Boepd. In each of the three years since EnQuest's inception, we have reported good results. Across those three years we have generated a total of $1,517.9 million of cash flow from operations, with production up 68% and an overall reserves replacement ratio of 300%. This performance is well ahead of our long term target of an average of 10% per annum growth in production and reserves, and reflects the successful implementation of our development and production strategy.

EnQuest's technical, operational and execution capabilities have continued to grow during the year, particularly with the significant progress on the Alma/Galia development and the rapid assimilation of Kraken.

Market conditions
In 2012, EnQuest's average realised oil price, net of hedging, was $111.6 per barrel, up from $107.6 per barrel in 2011. It is now two years since the Brent oil price last averaged below $100 per barrel and market oil price expectations remain high. Whilst we also continue to be positive on the longer term outlook for oil prices, we nonetheless take a prudent approach in the assumptions we use for business appraisal and planning purposes.

In both 2011 and 2012, EnQuest and the rest of the industry actively engaged with the UK Government, seeking improvements in the fiscal structure of the UK North Sea to encourage investment. The improved allowances in the March 2012 UK Budget were encouraging. These were followed in the autumn by welcome new allowances for brownfield projects in support of investment in mature oil fields. These new allowances are positive for EnQuest as it seeks to extend field lives and to sustain investment in mature North Sea fields such as Thistle and Heather. The investment this creates safeguards existing jobs and supports the creation of new jobs across the energy supply chain, it also partially restores the momentum lost by the initial tax increase.

EnQuest was also encouraged by recent UK Government measures aimed at providing certainty on the availability of tax relief on decommissioning costs, which should have the effect of increasing investment in the UK North Sea and extending the productive life of the UK's oil and gas reserves. Greater certainty on decommissioning tax relief can be more reliably factored into investment decisions and commercial decommissioning security arrangements and should therefore stimulate new commercial activity across the UK Continental Shelf. This will also help to facilitate the sale of assets to companies most suited to invest in them and EnQuest is in a very good position to take advantage of these developments.

The EnQuest strategy and business model

The implementation of EnQuest's strategy is proving its potential to create value. We believe that EnQuest's development and production focused model can provide consistent returns over the production lifecycle, in contrast to the more speculative nature of frontier exploration. EnQuest realises value from oil field development and production opportunities by targeting maturing assets and undeveloped fields. We exercise a high level of control over developments, as a result of having a majority working interest and being the field operator. We believe that its capabilities differentiate EnQuest; with the levels of expertise we maintain in-house, EnQuest's teams can achieve high levels of collaboration, continuity and accumulated shared knowledge.

EnQuest focuses on hubs, utilising three main approaches. Firstly, we extend field lives by upgrading facilities, utilising modern technology. This includes deployment of subsurface expertise and skill, and modern seismic, to identify the well targets and then execute infill drilling programmes. This extends oil field asset lives. We have already proved this model at Thistle. Daily production levels have increased from lows which were approaching 2,000 Boepd in 2005, to over 8,000 Boepd at the end of 2012, which are the highest levels achieved since the late 1990s. We have plans to invest further in Thistle, these have been facilitated by the new brownfield tax allowances. We are also investing in Heather, where we are upgrading the drilling rig to enable us to drill wells for the first time since 2006.

Marginal field solutions are another important leg of EnQuest's value creation model. We target dormant or undeveloped fields, that may have been too small in scale for the majors. We use a flexible approach and develop new solutions, redesigning and upgrading old facilities and using existing infrastructure. The EnQuest team achieved this at the Don fields and is now using a similar approach at Alma/Galia, with first oil due on stream in Q4 2013, less than three years after we secured the licence.

EnQuest's third value creation leg is through new developments. We acquire interests in assets which may have been thought technically or financially too challenging for others and then deploy EnQuest's capabilities, to commercialise and develop discoveries. After Alma/Galia the new development of the Kraken discovery is our current focus, this would be EnQuest's fifth hub.

The EnQuest Board

In August 2012, I was delighted to welcome Dr Philip Nolan to the Board, as a new Non-Executive Director. Phil's wealth of both technical and management expertise makes him a valuable addition to the Board as EnQuest continues to develop and execute its strategy.

After the assembly of an effective operations team in Aberdeen and the successful implementation of EnQuest's strategy in its critical first years, in November 2012 Nigel Hares decided that he was planning to reduce the amount of time dedicated to EnQuest, to be balanced by more time spent on personal affairs.

Nigel therefore stood down from the Board and now advises on future strategy and development. Operations have continued to be managed by David Heslop, General Manager UKCS and his team. Amjad Bseisu, the rest of the Board and I are very grateful to Nigel for the excellent contribution he has made to EnQuest and we look forward to continuing to work closely with him.

EnQuest is its people. I believe that their technical knowledge and capability, their experience and passionate commitment are EnQuest's most important assets. Although the organisation has grown considerably in size, it continues to retain the agility essential to take full advantage of new opportunities. The Board and I would like to thank our workforce for another year of delivery of good results and for putting in place the building blocks for the next stages of EnQuest's growth.

Delivering sustainable growth

EnQuest is proving that it can deliver sustainable growth through increasing production and reserves. Whilst the UK North Sea will continue to be our main focus, there are also potential opportunities to pursue EnQuest's strategy outside the UK. We have taken our first steps internationally, in Norway and Malaysia. We will retain a focused approach to our international expansion.

Business Review

Chief Executive's Report

Delivering on target in 2012

EnQuest executed well in 2012 with production of 22,802 Boepd, which was above the mid-point of our guidance range. This was due to a successful 14 well drilling programme in 2012, including five production wells brought onstream. In the three years since our inception, we have built a strong technically focused organisation that has generated significant levels of production and cash flow. In 2012, cash flow generated from operations was $593.9 million and EBITDA was $626.2 million. A net 3.7% increase in the average realised oil price helped EnQuest to achieve a profit before tax and net finance costs of $405.1 million, 3.8% up on 2011.

Audited net 2P reserves at the end of 2012 were 128.5 MMboe, an increase of 11.5% on 2011, even with the farm out of Alma/Galia. EnQuest achieved a strong reserve replacement ratio of 262.2% in 2012. This reserves growth reflects positive increases at our existing producing fields, as well as reserves relating to our 20% direct interest in Kraken.

Execution of the Alma/Galia development made significant progress, with the successful batch drilling of six wells and with the modifications to the EnQuest Producer vessel well underway. A major proportion of the subsea infrastructure work was successfully carried out during 2012. The farm out of 35% of Alma/Galia was also achieved during the year, recognising the significant value being generated by the project.

In 2012, EnQuest acquired 60% of the Kraken discovery; potentially one of the largest new oil field developments in the UK North Sea since Buzzard. EnQuest took over as operator in September 2012 and has deployed the same integrated project development capabilities utilised on Alma/Galia. The submission of the Kraken Field Development Plan ('FDP') is expected in Q2 2013.

EnQuest's strategy

EnQuest's development and production focused strategy continues to be implemented successfully; reserves and production growth have been delivered above target. Progress on the Alma/Galia development and on the new Kraken development is demonstrating our ability to execute and to bring new fields on stream. The farm out of 35% of Alma/Galia, with the $175.9 million gain on disposal that it generated, was material evidence of EnQuest's success in turning opportunities into value; both the Alma/Galia and the Kraken projects demonstrate that EnQuest is increasingly a natural partner of choice for major integrated development projects in the UK North Sea.

The UK North Sea continues to have very significant opportunities, with over 300 undeveloped fields remaining. In 2012, EnQuest also announced its first steps outside the UK North Sea. EnQuest has prequalified as an operator in Norway. We have also established a presence in Malaysia. We acquired NIO Petroleum (Sabah) Limited, which owns 42.5% in Blocks SB307 and SB308 offshore Sabah. The opportunity for EnQuest in Malaysia is similar to the UK North Sea, where EnQuest can establish development solutions for existing discoveries as well as taking over mature fields no longer material for the major oil companies.

Our company, our people

The breadth and depth of EnQuest's teams, their proven skills in engineering, subsurface, execution and operations, their leadership in innovative integrated developments, are all key to our success. Particularly critical is EnQuest's in-house ability to understand the subsurface and to be able to integrate this fully with all the required facilities elements. EnQuest seeks to be the operator of its developments and fields; through operatorship and majority working interests, we exercise a level of control which allows us to take full advantage of our technical skills and operational scale.

By the end of 2012, EnQuest's direct workforce had grown to approximately 500 people, in excess of four times the level at the time of our IPO. As an integral part of EnQuest's recent establishment of a presence in both Norway and Malaysia, we now have small experienced senior teams in place in Stavanger and in Kuala Lumpur.

Health, safety, environment and assurance ('HSE&A')
HSE&A is our top priority and HSE&A is deeply embedded in our culture and values. It is the most critical aspect of how we manage the business, with regard to our people themselves and to our installations and the environment in which we operate. Exhibiting leadership in safety is key and we seek continuous improvement in our HSE&A performance.

Good levels of performance in HSE&A have continued, with EnQuest achieving top quartile performance in several of key HSE&A KPIs. This included a five year Lost Time Incident free ('LTI' free) milestone for the Thistle drill rig, particularly impressive given its high level of activity. EnQuest also achieved a significant reduction in hydrocarbon releases across our assets.

Operations

EnQuest drilled 14 wells in 2012, successfully delivering the Thistle and Dons drilling programmes, together with the subsequent increase in production. In addition, EnQuest successfully progressed the installation of the new turbine power generator on Thistle which will deliver the power generation capability to sustain high levels of water injection uptime.

The Alma/Galia development

In 2012, EnQuest received the approval of the Department of Energy and Climate Change ('DECC')for the Alma and Galia developments. EnQuest secured Alma/Galia through the 26^th Licensing Round in 2010, extending the life of the first North Sea oil field to come into production.

In February 2013, EnQuest announced an increase in reserves and also in the scope and specification of the Alma/Galia development. The additional scope extends the field life, optimises operating costs and enables a potential second phase of development. Gross project capital expenditure is now approximately $1.3 billion, including contingency. These changes should extend the life of the FPSO vessel, to up to 15 years, and will allow additional wells in any second development phase. With the extended field life, the gross field 2P reserves are increased from 29 MMboe to 34 MMboe. This relates only to the existing first phase of development. The net effect of the capital cost increases, the benefit of the reserves increase and the operational improvements to the project, is a positive increase in the net present value overall; the improvements also create the potential for additional reserves and value in a potential second phase. We remain on track for first oil in Q4 2013.

Kraken - a major development in the North Sea

In 2012, EnQuest acquired the right to 60% of the Kraken oil discovery and became the operator of the proposed development. We are enthusiastic about Kraken, and anticipate it becoming a key part of EnQuest's asset base.

Kraken is anticipated to have a long field life and therefore a production profile that complements shorter life fields such as the Don fields and Alma/Galia. Along with Alma/Galia, Kraken should help to secure EnQuest's medium term production and reserves growth.

EnQuest's execution team is leading the development, utilising its integrated project development capabilities. FDP submission is expected in Q2 2013 and first oil is targeted in 2016.

Near field and low cost exploration and appraisal

EnQuest's exploration and appraisal strategy is focused on low cost and near field opportunities. In 2012 EnQuest participated in two such wells. One was Tryfan, a non-operated well which had significant potential, but proved to be uncommercial. As anticipated, the Kildrummy appraisal well results showed an oil column which was thicker than previously discovered in that field. Analysis of the commerciality of various potential Kildrummy development options is ongoing.

Business development

In 2012, EnQuest further consolidated its existing asset positions and built new ones. Operated oil field development asset opportunities in the UKCS require significant skills and capabilities as well as financial strength. EnQuest is selective and rigorous in its approach, always starting with the fundamentally important subsurface analysis, which is carried out in-house.

In Q1 2012, we agreed the acquisition of a further 18.5% working interest in West Don, increasing our interest to a majority 63.45%. During H1 2012, in three separate tranches, we agreed the acquisition of an aggregate interest of 60% in the Kraken oil discovery, the first tranche for a fixed sum and the second two tranches via development carries. During 2012 EnQuest also increased its interest in the Kildrummy discovery from 40% to 60%.

EnQuest has continued to build its interest in the Cairngorm discovery; having acquired 100% of Block 16/2b of Cairngorm through the acquisition of Stratic Energy Corporation in 2010. We successfully applied for 50% of Block 16/3d, in the UK's 26^th Licensing Round and, in December 2012, EnQuest took on the ownership of the whole of the Cairngorm discovery. This was achieved by completing the acquisition of the remaining 50% of Block 16/3d through a swap arrangement, in exchange for non-core assets which EnQuest owned in Holland.

EnQuest also agreed a small disposal in December 2012, selling a Dutch asset, licence P8 (Horizon West), to Van Dyke Energy for a $3 million initial cash consideration, plus $3 million contingent on future production.

Finally, in October 2012, EnQuest was pleased to have been offered 11 licences in the UK's 27^th Licensing Round.

Another strong financial performance

In 2012, EBITDA was again strong at $626.2 million, a similar level to the $629.1 million generated in 2011. This reflected the 3.7% year on year increase in the realised oil price and also the 3.5% expected decline in production. Underlying operational performance was strong.

EnQuest continues to have a strong balance sheet, ending the year with a $89.9 million positive net cash position. Capital expenditure on tangible oil and gas assets was $802.9 million in 2012. Capital investment on bringing Alma/Galia towards first oil in Q4 2013, amounted to $421.3 million, including $86.7 million in relation to the carry element of the project. The $184.3 million 2012 investment programme at Thistle contributed to the 48.2% increase in its production during 2012. Other elements of the 2012 capex programme included; $54.0 million at Heather/Broom, $128.8 million on the Don and Conrie fields, and $26.0 million on preparatory work at Kraken.

The unit cost of sales production and transportation was $32.3 per Boe in 2012, similar to the $31.9 per Boe in 2011, despite the impact of reduced production, higher oil prices and general upward pressure on market levels of operating costs. This good result reflects EnQuest's focus on control of costs.

2013 highlights so far
In January 2013, EnQuest announced that it had agreed to acquire an 8% non-operated interest in the producing Alba oil field, in the UK North Sea, adding reserves and producing barrels and further diversifying EnQuest's asset base. This transaction completed in late March 2013.

In Q1 2013, EnQuest successfully raised £145 million from the issue of a retail bond, with a 5.5% coupon and a 2022 maturity. We were pleased, both to have been the first oil company to launch a retail bond on the London Stock Exchange's Order Book for Retail Bonds and also that the issue was one of the largest raised in the market. This bond allows EnQuest to diversify its funding base and extend the tenor of its borrowings and complements our already strong balance sheet.

In Q1 2013, EnQuest also sanctioned the next phase of the Thistle life extension project, facilitated by its qualification for the brownfield allowance programme, announced by the UK Government late in 2012. Thistle is a prime example of how EnQuest is able to recover more oil from maturing assets through a combination of innovation and technical expertise.

Outlook for 2013 and beyond

Average production guidance for the full year 2013 is between 22,000 Boepd and 27,000 Boepd, as approximately 1,000 Boepd has been lost, primarily due to third party shutdowns of the Brent pipeline in Q1 2013. In addition to first oil from Alma/Galia, production improvements will come from three production wells in our existing producing fields; one new production well on Don Southwest, one well coming back on stream as a result of a workover on Heather, and another new well on Thistle. In total in 2013, EnQuest plans to deliver 12 wells. This includes three exploration/appraisal wells, with one each at both Cairngorm and Kraken and a further exploration/appraisal well is expected to be drilled in Malaysia in late 2013.

EnQuest's total investment programme in 2013, prior to regulatory approval of the Kraken FDP, is expected to be approximately $750 million, with around $350 million to be invested in the Alma/Galia development. In addition to the wells programme and the Alma/Galia development work, other major projects will also contribute to reserves and production in 2013 and will provide a foundation for future reserves and production growth. At Thistle, these include the next phase of the late life extension project and the delivery of a secure new power supply through the completion and commissioning of the new 30MW gas turbine generator. In Q3 2013, following the successful rig reactivation programme, Heather will return to drilling for the first time since 2006.

We continue to target submission of the Kraken FDP in Q2 2013. Pre-development expenditure of around $75 million for Kraken is included in the Group's 2013 investment programme of $750 million; this pre-development expenditure includes the costs of the Kraken appraisal well, being drilled to provide additional data for the main development. The 2013 Kraken expenditure will depend on phasing, particularly near to the year end, as well as potential spending on long lead items.

At the end of 2012, including the licences it was offered in the UK 27^th Licensing Round, EnQuest had 39 production licences covering 55 blocks or part blocks, up from 22 production licences at the end of 2011. In addition to the current producing fields, EnQuest is actively considering new development proposals on at least three of its other licences. EnQuest has a strong discovery portfolio within its existing asset base and anticipates it will further consolidate these positions and continue to build new ones. EnQuest's net 2P reserves at the start of 2013 have a life of over 15 years, extending to over 25 years if Kraken contingent resources can be converted into reserves.

With our centre of excellence and capability in Aberdeen, we will continue to take advantage of EnQuest's integrated appraisal, development and operations model, both on our existing asset base and on new basins with mature and undeveloped field potential.

Business Review

Operating Review

2012 operational overview - good execution

In 2012, EnQuest delivered a good overall operational performance, with production at an average of 22,802 Boepd, above the mid-point of our guidance. This success was due to thorough preparation and to excellence in execution. In particular, there was good drilling and intervention work at Thistle/Deveron and the Dons. This production result was achieved despite the negative impact of third party pipeline outages in H1 2012. By the start of 2013, EnQuest had grown its net 2P reserves to 128.5 MMboe, having achieved a reserve replacement ratio of 262.2% in 2012; EnQuest is demonstrating its ability to deliver production growth for both the medium and the long term. EnQuest's capability continues to grow across all functions and we are pleased to have been able to increase the quality, strength and depth across the organisation.

Operational highlights of the year also included the safe and effective installation of the new gas turbine generator and local equipment room on Thistle; facilities with a weight of approximately 300 tonnes. The detailed design work for the next phase of the life extension project on Thistle was delivered and work was undertaken to improve water injection capability at Thistle. Another important operational achievement was the improvement in gas compression capability at Heather in H2 2012. The drilling programme at Heather will now start in the second half of the year after the drilling team complete the final well in the current phase on Thistle. Cost performance for all the work performed by the two semi-submersible rigs on contract was enhanced by the commitment to long term contracts in 2011 and 2012 at very competitive rates. Across all our sites in 2011 and 2012, EnQuest has now delivered approximately $100 million of brownfield workscope, demonstrating the commitment and capability in managing mature assets in the North Sea.

In H1 2012, as a natural evolution of its integrated approach to operations management, EnQuest commenced the transition to become the duty holder on its UK operations. The duty holder is responsible for the safe operation of offshore installations. The transition process has been smooth to date and bringing these skills fully in-house will allow EnQuest to develop further its operational capability. Taking over duty holdership will facilitate future growth through the resulting increased direct control, helping to improve operational, production and cost efficiency. EnQuest plans to take on direct duty holder responsibilities on 27 March 2013.

Safety is the priority across all of EnQuest's operations and 2012 was a good year against our HSE&A performance metrics. We had a successful HSE offshore inspection on Thistle and the Thistle HSE safety case was also approved. We therefore believe EnQuest is increasingly being recognised as a leader in the safety management of life extension activity on aging facilities. The HSE safety case approvals were critical elements of EnQuest's preparation for its transfer to duty holdership.

We recently achieved a half a million man hours LTI free at the Blohm & Voss yard in Hamburg, where the EnQuest Producer FPSO is being modified and refurbished. In recognition of this safety achievement, a donation was made to a community charity in the Hamburg area.

Producing oil fields

Thistle and Deveron

2012

Production at Thistle/Deveron achieved a net 8,058 Boepd in 2012, up 48.2% on 2011. Base oil production increased over 2011 and was better than expected due to more reliable power and enhanced water injection rates, supplemented with oil production from three installed electrical submersible pumps ('ESPs').

Two new wells were completed during the year. The Deveron P1 ESP well (now A58/03) was completed in Q1 2012 and started production in Q2 2012, with productivity at the upper end of the pre-drill estimate. Drilling on the new A59/45 (a sidetrack of well A46/45 to Area 6) was completed in late September and the third Thistle ESP came on stream in October 2012.

There were three workovers in 2012, all of which achieved their objectives; including two water injection workovers, both of which successfully increased water injection capacity and achieved better target injection support within the reservoir.

In H2 2012 the new power generator was lifted onto the Thistle platform, ahead of planned testing at the end of 2012.

Following a successful wireline intervention, the Thistle A27/17 injection well came back on line in mid-December, helping to increase year end production levels.

The offshore drilling team on Thistle achieved a major industry safety milestone during the period, with five years of operation without an LTI. The facility also completed a successful regulatory ageing life extension audit.

2013

In February 2013, EnQuest announced that it had sanctioned the next phase of the Thistle life extension project, facilitated by its qualification for the brownfield allowance programme announced by the UK Government at the end of 2012. EnQuest's investment in Thistle so far has included facilities and integrity systems upgrades, a major rig reactivation programme and drilling of six wells, and has resulted in significantly increased production. EnQuest is now implementing a technology led work programme to simplify and streamline processes and to improve production and injection reliability and platform integrity. We anticipate over the medium term this will allow cost reductions on the platform.

In Q1 2013, a workover of the A53/60 injector well was successfully carried out, along with the successful start of the new power turbine generator. In Q2 2013, a new production well is planned in the West Fault Block.

The Don and Conrie Fields

2012

Production at the Don and Conrie fields achieved a net 10,992 Boepd in 2012, down 13.9% on 2011. The year on year decline was expected and was due mainly to the decline in production from the S5 well, which was drilled and brought onstream in 2010. Overall an extensive drilling and intervention programme in the Dons area was successfully completed on time and on budget in 2012.

In 2012, four wells were drilled in the Don fields. The sidetrack of Don Southwest well S1 to the updip 'horst' area of the field (now designated well S11) came online in July with a good initial rate on prognosis at 15,000 Boepd. Also at Don Southwest, S10Y came on stream in Q4 2012, with an initial rate which was in line with expectations.

West Don well W2 had been shut in pending abandonment since an unsuccessful workover in 2010. Operations to abandon the well were completed during September 2012 and then an up-dip sidetrack of well W2 (now designated well W5) was drilled and brought online in October at an initial rate of 2,000 Boepd.

W6 (NJ) southern injector spudded Q4 2012 and was completed with a successful injection test.

2013

The successful 2012 drilling and intervention programme in the Dons area enabled an early start to the 2013 programme in Don Southwest Area 6. Continued infill drilling included a Don Southwest DS production well, drilled in Area 6. Its injector pair well OB will be drilled in Q2 and both should be online in Q3 2013.

The W6 (NJ) well, which was drilled in 2012, was tied in and brought online in Q1 2013.

The facilities upgrade programme will continue at the Don fields, including a gas compression efficiency pipework project. There will be a two week shutdown in 2013.

Heather and Broom

2012

Production at Heather/Broom achieved a net 3,752 Boepd in 2012, down 31.7% on 2011; as anticipated reflecting the natural decline in production from the Broom BR2 well. Plant management at Heather was good, resulting in high production efficiency.

A scheduled one month maintenance shutdown of Heather was successfully completed.

The Heather rig reactivation achieved project milestones, including the installation of an 80 tonne mud treatment package. Extensive maintenance work was required once inspection was completed, which was hindered by the impact of the Norovirus and by a general shortage of helicopters in the North Sea. Completion of the return to drilling programme is expected in Q3 2013.

2013

In 2013, following the return to drilling in Q3, a workover is scheduled to bring H47 back on stream in Q4 2013. A wireline perforation campaign is also scheduled, with additional perforations for three wells planned to result in increases to production. The integrity upgrade programme at Heather will continue into 2013. A three week shutdown will take place in July.

EnQuest will continue with its infill programme at Heather, with 20 potential infill targets, of which nine have been selected for the initial programme.

Alma and Galia Development

Background

These fields, previously called Argyll and Duncan, were awarded to EnQuest in the 26^th Licensing Round in early 2011.

In Q4 2011, EnQuest sanctioned a redevelopment project with nine wells, initially set to recover a gross 29 MMboe of 2P reserves. Having begun with a 100% working interest in the development, EnQuest farmed out 35% to KUFPEC. First production is anticipated in Q4 2013, at a net peak rate of over 13,000 Boepd.

2012

In 2012, DECC approved the FDPs for both the Alma and Galia fields. EnQuest executed well on its development of its new Alma/Galia hub, and finished the year on track for first oil in Q4 2013.

Six wells were successfully batch drilled on Alma in 2012, they were then suspended pending further drilling and the installation of completions. Six wells were batch drilled in 2012 (K1 to K6), of the six, the three that were through the reservoir section at the year end were all at or better than prognosis.

In 2012, the key elements of the project execution required to deliver first oil in Q4 2013 proceeded on schedule. Modification of the floating production storage and offloading ('FPSO') vessel in Hamburg continued with the first dry dock related work nearing completion as planned; destruct work was completed, the refurbishment of the ship systems was well underway and the turret had been reinstalled. The topsides design for the FPSO was finalised around the 2012 year end.

Other key elements of the project also proceeded well, with a major proportion of the subsea infrastructure work successfully carried out by the year end. Pipeline works authorisations were approved for both the Alma and Galia fields and subsea trenching operations were completed. Subsea flowlines were laid between Alma/Galia and the FPSO location, along with the umbilical between Alma and Galia. Riser clump weights were also installed. The mooring installation contract was awarded, as was the pile fabrication sub-contract.

2013

In February 2013, EnQuest announced an increase in the scope and specification of the Alma/Galia project with the objective of extending the field life, optimising operating costs and enabling a potential second phase of development. These improvements add swivel capacity and extend vessel and project life. EnQuest is incurring costs relating to compliance with recent UKCS marine code changes, which require upgrades to the mooring system and strengthening of the swivel and vessel hull.

The Alma/Galia drilling programme continues in 2013. Three of the Alma production wells batch drilled in 2012 will be completed in 2013. A new injection well will also be drilled on Alma. EnQuest anticipates 'sail away' of the FPSO in Q3 2013, ahead of first oil in Q4 2013.

The Kraken Development

In 2012, EnQuest acquired a 60% interest in the Kraken discovery and in H2 2012 EnQuest became the operator of the new development. 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. It is being progressed to development following earlier appraisal well tests, the successful results of which de-risked the project prior to EnQuest's acquisition of its working interests.

The new development remains on track for submission of the FDP in Q2 2013, and subject to the anticipated regulatory approvals, for first oil in 2016. The Kraken Environmental Statement was submitted in Q1 2013 and the DECC consultation process commenced. Following submission of the FDP and confirmation of all the details that are a pre-requisite for that submission, EnQuest will then provide comprehensive updated detailed information on this project. In 2013, an appraisal well will be drilled at Kraken, in order to provide additional data for the field development.

Crathes/Scolty

Options for a proposed Crathes/Scolty development are being analysed, with a number of potential hosts under consideration. In order to accommodate the time required for this ongoing analysis, a licence extension is being sought and is anticipated.

Kildrummy

The results of the H2 2012 Kildrummy appraisal well showed an oil column which was thicker than previously discovered in that field, although not as thick as had been anticipated. A range of development options continue to be evaluated.

Cairngorm

Cairngorm is a basement opportunity, with potential. An appraisal well is to be drilled in 2013.

Crawford/Porter

Development studies at Crawford/Porter continue; the result of further drilling in the vicinity will be factored into project sanction decisions. Combining Crawford/Porter with other adjacent projects may produce a more economically attractive alternative than a stand-alone project. EnQuest therefore no longer recognises 2P reserves for Crawford/Porter.

Malaysia

In H2 2012, EnQuest acquired a 42.5% interest in Blocks SB307 and SB308 offshore in Sabah, Malaysia; with one near field appraisal opportunity at the oil discovery in Bambazon and five prospects. The partners on the Sabah blocks are Lundin Petroleum and PETRONAS Carigali. EnQuest also acquired an office base in Kuala Lumpur and a small management team with extensive experience in South East Asia. An exploration/appraisal well is expected to be drilled in the area in H2 2013.

Business Review

Principal risks and uncertainties

The Group's risks and uncertainties are largely unchanged from those disclosed in the Group's Annual Report and Accounts 2011. However some of the mitigations of these have been strengthened.

Business Review

Financial Review

Financial Overview

The Group's financial performance in 2012 reflects good operational performance and a period of significant capital investment in growth projects throughout the year.

In the year ended 31 December 2012, the Brent crude oil price averaged $111.7 per barrel broadly the same as $111.4 per barrel average for 2011. As anticipated, total production volumes were 3.5% lower for the 12 months to 31 December 2012 and this, together with a net under-lift position at 31 December 2012, resulted in revenues for the year of $890 million compared with $936 million in 2011.

	Business Performance
	2012	2011
	$ million	$ million

Profit from operations before tax and finance income/(costs)	405.1	390.1
Depletion and depreciation	208.0	202.0
Intangible impairments and write-offs	13.1	37.0
EBITDA	626.2	629.1

EBITDA for the 12 months ended 31 December 2012 was $626.2 million compared with $629.1 million in 2011. The lower EBITDA is due to lower production volumes, partially offset by lower intangible impairments and write-offs, lower operating costs, tariffs and transportation costs in 2012 and higher oil collar hedging costs in 2011.

The Group entered 2013 with $89.9 million net cash. Strong ongoing operating cash flows from its existing portfolio of assets and a new credit facility have been used to fund a significant capital investment programme. In March 2012, the Group established a new multi-currency revolving credit facility of up to $900 million with seven banks. Initially $525 million was committed and further amounts will be available depending on oil reserves, including increases resulting from acquisitions. The new facility replaced the previous $280 million facility which expired in March 2012. In Q1 2013, EnQuest successfully raised £145 million from the issue of a retail bond, with a 5.5% coupon and a 2022 maturity. This bond allows EnQuest to diversify its funding base and complements the already strong balance sheet.

Income Statement

Production and revenue

Production levels, on a working interest basis, for the 12 months to 31 December 2012 averaged 22,802 Boepd compared with 23,698 Boepd in 2011. The decrease in production was expected and due mainly to lower volumes on the Don fields and Heather and Broom, offset by higher volumes from Thistle. Production in the Dons fields was lower mainly due to the decline in production from the S5 well. This was partially offset by a full year's production from S8Z and the new S10 and S11 wells and W5 sidetrack as well as the acquisition of an additional 18.5% in West Don. Heather and Broom production was lower than 2011 due to natural field decline, a planned shutdown on Heather and by the unscheduled third party related closure in Q2 2012 of the Ninian Pipeline System. Thistle volumes were higher due to the two new wells that came into production during the year.

The Group's blended average realised price per barrel of oil sold was $111.6 for the 12 months to 31 December 2012, broadly in line with the $111.8 per barrel excluding oil collar hedging costs ($107.6 per barrel including oil collar hedging costs) for 2011. This is consistent with average oil prices for 2012 and 2011. Revenue is predominantly derived from crude oil sales and for the 12 months ended 31 December 2012 crude oil sales were $879.3 million compared with $960.4 million in 2011. The reduction in revenue is due to lower production and an under-lift in the year of $24.4 million compared with an over-lift of $14.6 million in 2011.

Operating costs

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

	Reported	Reported
	Year ended 31 December	Year ended 31 December
	2012	2011
	$ million	$ million

Cost of sales	448.2	491.8

	$	$
Unit operating cost, adjusted for over/under-lift and inventory movements (per Boe):
-Production and transportation costs	32.3	31.9
-Depletion of oil and gas properties	24.7	23.2
	57.0	55.1

Cost of sales pre-exceptionals and depletion of fair value adjustments was $448.2 million for the year ended 31 December 2012 compared with $491.8 million in 2011. The decrease of $43.6m is mainly due to the $39.0 million change in lifting position from a net over-lift in 2011 to a net under-lift at 31 December 2012, together with a decrease in operating costs.

The Group's operating costs comprise cost of operations and tariff and transportation expenses which were $269.5 million for the year ended 31 December 2012 compared with $276.1 million in 2011. The decrease in operating costs was due to shutdowns and major works on Thistle in 2011 and the S2 well intervention on Don Southwest in 2011. This was offset by a full planned shutdown on Heather and the W1 well intervention on West Don, together with lower tariff and transportation costs due to lower production volumes in the year ended 31 December 2012 compared with 2011. The increase in the Group's average unit production and transportation cost of $0.4 per Boe for the year ended 31 December 2012 compared with 2011 is primarily attributable to the lower levels of production in the Don fields and Heather and Broom.

The Group's depletion expense per Boe for the year is broadly consistent with the previous year with an increase of $1.5 per Boe (6%). The primary reason for this is higher estimates of the future capital expenditure requirement on the Don fields.

The Group's change in lifting position was $24.4 million income for the year ended 31 December 2012, compared with expense of $14.6 million in 2011. The net under-lift during 2012 has arisen due to an under-lift balance at 31 December 2012 of $9.3 million mainly in the Don fields combined with the reversal of the over-lift of $15.1 million at the end of 2011 mainly in the Thistle and Broom fields.

Exploration and evaluation expenses

Exploration and evaluation expenses were $23.2 million in the year ended 31 December 2012, compared with $37.0 million reported in the previous year. The expenses in 2012 primarily relate to the costs of Norway licence applications and the UK 27^th Licensing Round, the cost write-off associated with the Juniper, Gorse and Pilot licences following a decision to relinquish these licences and the cost of the unsuccessful Tryfan exploration well.

General and administrative expenses

General and administrative expenses were $6.7 million in the year ended 31 December 2012 compared with $13.8 million reported in the previous year. The expenses primarily relate to the Group's general management and business development expenses net of recharges to joint venture partners. The decrease in general and administrative expenses of $7.1 million reflects the increasing number of joint ventures which are subject to such recharges.

Other income and other expenses

Other income includes monies received from a third party as compensation for the termination of a business development transaction. Other expenses includes net foreign exchange losses of $5.5 million and expenses related to the ineffectiveness of foreign currency contracts designed as hedges of $2.9 million in the year ended 31 December 2012.

Taxation

The tax charge for the year of $126.4 million excluding exceptional items, represents an effective tax rate of 33% compared with 64% in the previous year. The decrease in the Group's effective tax rate for the year is mainly due to the benefit provided by leasing arrangements, the increase in the ring fence expenditure supplement and prior year deferred tax adjustments. Partially offsetting these decreases, in July 2012, the Finance Act 2012 brought in a restriction on the tax relief available on decommissioning expenditure incurred on or after 21 March 2012 to 50% which has resulted in an increase in the tax charge of $3.9 million.

Exceptional items and depletion of fair value uplift

Exceptional income totalling $17.4 million before tax has been disclosed separately in the year ended 31 December 2012 relating to:

· a $175.9 million gain on disposal of 35% of the Alma/Galia development through the farm out and cost carry agreement with KUFPEC;

· a $143.9 million impairment of the Heather and Broom hub following a delay in phasing of production, particularly to allow the drilling of the West Fault Block well at Thistle in 2013 and an increase in estimated capital expenditure associated with the field life extension programme. The Heather and Broom hub inherited a high net book value of $423 million, reflecting the fair value uplift when Lundin acquired the Heather and Broom assets prior to the formation of EnQuest; and

· a non-cash impairment of $4.4 million in relation to the valuation of the Group's shareholding in Ascent Resources plc.

In addition, a one off deferred tax adjustment of $10.4 million in respect of the restriction on the tax relief available on decommissioning expenditure on UK oil and gas offshore activities has been reported as an exceptional item.

Additional depletion costs of $10.3 million 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 $21.2 million include $0.7 million of loan interest payable, $10.1 million unwinding of discount on decommissioning provisions, a non-cash unrealised loss of $2.1 million on the mark-to-market of the Group's 2012 oil collars which are deemed ineffective for hedge accounting purposes. Other financial expenses are primarily commitment and arrangement fees relating to the new bank facilities and letter of credit fees. The Group capitalised $0.4 million for the year ended 31 December 2012 in relation to the interest payable on borrowing costs on its capital development projects.

Finance income

Finance income of $2.2 million includes $0.7 million of bank interest receivable, a non-cash unrealised gain of $0.9 million on the mark-to-market of the Group's 2013 oil collars which are deemed ineffective for hedge accounting purposes and $0.5 million unwinding of discount on the financial asset created as part of the consideration for the farm out of the Alma/Galia development to KUFPEC.

Earnings per share

The Group's reported basic earnings per share were 46.2 cents for the year ended 31 December 2012 compared with 7.6 cents in 2011. The increase of 38.6 cents is attributable to an increase in gross profit, a lower effective income tax rate in the year ended 31 December 2012 compared with the previous year, together with the exceptional gain on the disposal of fixed assets. This was partially offset by the impairment of the Heather and Broom hub. The Group's reported basic earnings per share excluding exceptional items were 33.1 cents for the year ended 31 December 2012 compared with 17.0 cents in 2011. The increase of 16.1 cents is mainly attributable to the lower effective income tax rate in the year ended 31 December 2012 compared with the previous year.

Cash flow and liquidity

The Group's reported cash generated from operations in 2012 was $593.9 million compared with $656.3 million in 2011. The reported cash flow from operations per issued Ordinary share was 75.7 cents per share compared with 81.9 cents per share in 2011. This reduction in cash generated from operations is primarily due to the increase in joint venture receivables which relates to the significant capital expenditure on the Alma/Galia development.

During the year ended 31 December 2012, $0.8 million of income tax payments were made in relation to the settlement of EnQuest North Sea BV's Dutch corporate income tax liabilities. It is anticipated that the underlying effective tax rate for 2013 will be approximately 60%, excluding one-off exceptional tax items. The Group also does not expect a cash outflow for UK income tax on operational activities until beyond 2014. This is due to the projected level of capital expenditure, which benefits from tax deductible first year capital allowances, and accumulated tax losses which are themselves largely attributable to the Group's capital investment programme to date.

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


	2012	2011
	$ million	$ million

Expenditure on producing oil and gas assets	323.9	170.9
Development expenditure	381.1	43.6
Exploration and evaluation capex expenditure	128.4	54.0
Other capital expenditure	8.9	9.4
	842.3	277.9

Significant projects were undertaken during the year, including:

· the Alma/Galia development;

· the Thistle drilling programme including A58/03, A59/45, A56/13, A13/22, A53/60, A22/59 and late life extension programme for facilities including the power generation upgrade;

· the acquisition of a further 18.5% interest in West Don and on the Don fields the S10, S11 and W5 producer wells and W6 injector well;

· the programme to reactivate the drilling rig on the Heather platform;

· the acquisition of the interests in Kraken and subsequent expenditure to progress the opportunity to sanction in 2013; and

· the Kildrummy and Tryfan exploration wells and activities on actual or potential exploration prospects, mainly the UK 27^th Licensing Round and pre-drilling costs.

Net cash at 31 December 2012 amounted to $89.9 million compared with $378.9 million in 2011.

In Q1 2013, EnQuest successfully raised £145 million from the issue of a retail bond, with a 5.5% coupon and a 2022 maturity. This bond allows EnQuest to diversify its funding base and complements the already strong balance sheet.

Balance Sheet

The Group's total asset value has increased by $596.1 million to $2,544.8 million at 31 December 2012 (2011: $1,948.7 million).

Property, plant and equipment

Property, plant and equipment (PP&E) has increased to $1,816.6 million at 31 December 2012 from $1,273.6 million at 31 December 2011. The increase of $543.0 million is mainly due to oil and gas asset capital additions including farm ins and farm outs of $802.9 million, other additions of $8.9 million, a reclassification of Kraken costs of $62.0 million from intangible assets on recognition of 2P reserves and additional decommissioning provisions of $62.2 million, mostly arising on drilling new development wells, partially offset by depletion and depreciation charges of $218.3 million in the year, the impairment of the Heather and Broom hub of $143.9 million and a reclassification of Crawford/Porter to intangible assets of $30.8 million.

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


	2012
	$ million

Dons hub	128.8
Thistle hub	184.3
Heather and Broom hub	54.0
Alma / Galia	421.3
Other new developments	14.5
	802.9

Intangible oil and gas assets

Intangible oil and gas assets increased by $73.2 million to $97.5 million at 31 December 2012. The increase is mainly due to the reclassification of Crawford and Porter costs from PP&E to intangible fixed assets, the cost of the Kildrummy exploration well and the acquisition of the Malaysian exploration licences. The Kraken acquisition costs and the subsequent additions during the year have been transferred to PP&E.

Investments

The Group holds an investment of 160,903,958 new ordinary shares in Ascent Resources plc which is valued at $2.3 million based on the quoted bid price as at 31 December 2012.

Asset held for sale

During 2012, the $1.3 million of costs associated with the Group's Dutch licences, which had been classified as held for sale at 31 December 2011, were reclassified to intangible fixed assets on finalisation of a swap arrangement with Sterling Resources Limited for a 50% share in the Cairngorm licence Block 16/3d.

Trade and other receivables

Trade and other receivables have increased by $113.1 million to $239.7 million at 31 December 2012 compared with $126.6 million in 2011. The increase is mainly due to higher joint venture receivables which relates primarily to the significant capital expenditure on the Alma/Galia development together with an increase in receivables of $9.3 million relating to net under-lift position at 31 December 2012.

Cash and bank

The Group had $124.5 million of cash and cash equivalents at 31 December 2012 and $34.6 million was drawn down on the $900 million multi-currency revolving credit facility. Of the facility, $525 million was initially committed with additional amounts up to $900 million becoming available dependent on increasing reserves or through acquisitions. Included within the cash balance at 31 December 2012 is restricted cash of $14.9 million relating to cash held under Performance Guarantee Agreements with suppliers.

Provisions

The Group's decommissioning provision increased by $51.8 million to $233.0 million at 31 December 2012 (2011: $181.2 million). The increase is due to the combined impact of additions of $37.6 million during the year resulting from the Group's drilling programme, $7.5 million due to farm in and farm out activity, $10.1 million due to changes in estimates and $10.1 million due to the unwinding of the discount. This was offset by utilisation of the provision of $13.6 million on well abandonment and various small facility decommissioning workscopes.

Income tax

The Group's income tax liability increased to $3.8 million at 31 December 2012 from $1.7million at 31 December 2011. The increase of $2.1million is due to UK income tax arising on foreign exchange movements. The income tax asset as at 31 December 2012 represents the expected refund on exploration activities undertaken in Norway, and an expected refund in Holland on the carry back of tax losses incurred in 2012.

Deferred tax liability

The Group's deferred tax liability (net of deferred tax assets) has increased by $31.7 million to $609.1 million at 31 December 2012 from $577.4 million in 2011. The increase is mainly due to the capital expenditure programme undertaken by the Group during the year which provides the Group with 100% first year capital allowance claims as well as an increase in ring fence taxation losses carried forward. There was a one-off deferred tax adjustment of $10.4 million in respect of the restriction on decommissioning relief which has been reported as an exceptional item together with a deferred tax credit of $89.2 million in respect of the impairment of the Heather and Broom hub. Total losses carried forward at the year end amount to approximately $600 million. This excludes $54.5m of pre-trading expenditure which is expected to become tax deductible in 2013.

Trade and other payables

Trade and other payables have increased to $329.7 million at 31 December 2012 from $234.3 million at 31 December 2011. The increase of $95.4 million is primarily due to an increase in trade creditors and accruals of $96.1 million resulting from the Group's drilling and capital project programmes which were ongoing at the end of 2012.

Financial Risk Management

The Group is exposed to the impact of changes in Brent crude oil prices on its revenue and profits. During 2011, put and call options covering 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 consisted of put spreads at $95 per barrel and $70 per barrel and calls at an average of $122 per barrel, all executed at nil cost. In May 2012, one of the oil price collars was re-priced to give a revised average cap of $123.3 per barrel.

Between November 2012 and February 2013, further put and call options covering 4.60 million barrels of oil production for 2013 were entered into to partially hedge the exposure to fluctuations in the Brent oil price. The 2013 oil price hedge contracts consist of put spreads at $95-$100 per barrel and $70-$75 per barrel and calls at an average of $121.6 per barrel, all executed at nil cost.

As a result of the commodity price hedging programme undertaken, EnQuest has protected approximately $440 million of its capital expenditure for 2013, assuming the oil price remains above the lower level of the put spreads. This equates to over half of the capital expenditure programme projected for 2013.

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 £126.5 million (at an average rate of $1.577 to £1) and €52.7 million (at an average rate of $1.34 to €1) of forecast 2012 capital project spend. During 2012 EnQuest did not enter into any foreign exchange hedging contracts. EnQuest continues to look at opportunities to enter into foreign exchange hedging contracts, in line with the policy agreed by the Board which allows for up to 50% of operating expenditure and 70% of capital expenditure to be hedged, in order to mitigate the risks of large fluctuations in the currency markets, specifically the US dollar versus Sterling and the US dollar versus the Euro. Surplus cash balances are deposited as cash collateral against in-place letters of credit as a way of reducing interest costs. Otherwise cash balances can be invested in short term bank deposits and AAA rated liquidity funds, subject to Board approved limits and with a view to minimising counterparty credit risks.

Jonathan Swinney

26 March 2013

KEY PERFORMANCE INDICATORS

	2012	2011

Lost Time Incident Frequency (LTIF)	2.00	0.90

2P reserves (MMboe)	128.52	115.21

Business performance data:
Production (Boepd) Revenue ($ million)	22,802 889.5	23,698 936.0
Realised oil price per barrel ($)	111.6	107.6
Opex per barrel (production and transportation costs) ($)	32.3	31.9
Gross profit excluding exceptional items ($ million)	441.3	444.2
Capex on property, plant and equipment oil and gas assets ($ million)	802.9	291.7
Capex on intangible oil and gas assets ($ million)	116.2	64.2

Reported data:
Cash generated from operations ($ million)	593.9	656.3
Net cash ($ million)	89.9	378.9
Profit before tax ($ million)	403.4	362.8
Cash generated from operations per share (cents)	75.7	81.9
Basic earnings per share (cents)	46.2	7.6
Basic earnings per share excluding exceptional items (cents)	33.1	17.0

During the year, the Group changed the frequency used in recording its Lost Time Incident Frequency (LTIF) metric, to align with the Oil & Gas UK standard, which during 2012 the Group found to be the most appropriate benchmark. The 2011 comparative figure has been restated from an LTIF of 0.44 to an LTIF of 0.90

EnQuest PLC

Abridged Group Income Statement

For the year ended 31 December 2012

2012

2011

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

889,510

935,974

Cost of sales

(448,186)

(10,251)

(458,437)

(491,817)

(16,973)

(508,790)

Gross profit/(loss)

441,324

(10,251)

431,073

444,157

(16,973)

427,184

Exploration and evaluation expenses

(23,157)

(36,962)

Gain on disposal of asset held for sale

8,644

Impairment on available for sale assets

(4,417)

(12,497)

Impairment of oil and gas assets

(143,882)

Gain on disposal of property, plant and equipment

175,929

Well abandonment expenses

8,194

General and administration expenses

(6,650)

(13,755)

Other (expenses)/income, net

(6,445)

(3,344)

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

405,072

17,379

422,451

390,096

(12,632)

377,464

EBITDA*

626,181

629,102

8,194

637,296

Notes:

* EBITDA is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion (note10 adjusted for depletion of fair value uplift), depreciation (note 10), impairment (note 12) and write off of intangible oil and gas assets (note12). EBITDA is not a measure of financial performance under IFRS.

OIL AND GAS RESERVES AND RESOURCES

At 31 December 2012

	UKCS		Other Regions	Total
	MMboe	MMboe	MMboe	MMboe

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

At 1 January 2012		115.21	-	115.21
Revisions of previous estimates		10.23	-	10.23
Discoveries, extensions and additions (note 7)		20.40	-	20.40
Acquisitions and disposals (note 8)		(9.11)	-	(9.11)
Production:
Export meter	(8.35)
Volume adjustments (note 5)	0.14
		(8.21)	-	(8.21)
Proven and Probable Reserves at 31 December 2012		128.52	-	128.52

Contingent Resources (notes 1, 2 & 4)

At 1 January 2012		111.77	5.01	116.78
Revisions of previous estimates		(7.42)	-	(7.42)
Discoveries, extensions and additions		8.69	-	8.69
Acquisitions (note 8)		93.42	-	93.42
Disposals (note 8)		(26.91)	(0.61)	(27.52)
Promoted to reserves (note 7)		(21.80)	-	(21.80)
Contingent Resources at 31 December 2012		157.75	4.40	162.15

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) Correction of export to sales volumes.

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

(7) Contingent Resources previously allocated to Kraken have been classified as reserves as a result of ongoing development planning.

(8) An additional 18.5% equity was acquired in West Don. 35% of the equity in the Alma/Galia development was farmed out.

GROUP STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2012

			2012		2011
	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)	889,510	-	889,510	935,974	-	935,974
Cost of sales	5(b)	(448,186)	(10,251)	(458,437)	(491,817)	(16,973)	(508,790)

Gross profit/(loss)		441,324	(10,251)	431,073	444,157	(16,973)	427,184
Exploration and evaluation expenses Gain on disposal of asset held for sale	5(c) 4	(23,157) -	- -	(23,157) -	(36,962) -	- 8,644	(36,962) 8,644
Impairment of investments	4	-	(4,417)	(4,417)	-	(12,497)	(12,497)
Impairment of oil and gas assets	4	-	(143,882)	(143,882)	-	-	-
Gain on disposal of property, plant and equipment	4	-	175,929	175,929	-	-	-
Well abandonment	4	-	-	-	-	8,194	8,194
General and administration expenses	5(d)	(6,650)	-	(6,650)	(13,755)	-	(13,755)
Other income	5(e)	2,000	-	2,000	-	-	-
Other expenses	5(f)	(8,445)	-	(8,445)	(3,344)	-	(3,344)

Profit/(loss) from operations before tax and finance income/(costs)		405,072	17,379	422,451	390,096	(12,632)	377,464
Finance costs	6	(21,211)	-	(21,211)	(18,598)	-	(18,598)
Finance income	6	2,161	-	2,161	3,955	-	3,955

Profit/(loss) before tax		386,022	17,379	403,401	375,453	(12,632)	362,821

Income tax	7	(126,357)	85,174	(41,183)	(239,400)	(62,430)	(301,830)

Profit/(loss) for the year attributable to owners of the parent		259,665	102,553	362,218	136,053	(75,062)	60,991

Other comprehensive income for the year, after tax:
Cash flow hedges (net of tax)	21			2,554			(2,600)
Total comprehensive income for the year, attributable to owners of the parent				364,772			58,391

Earnings per share	8	US$		US$	US$		US$
Basic		0.331		0.462	0.170		0.076
Diluted		0.326		0.454	0.170		0.076

The attached notes 1 to 28 form part of these Group financial statements.

GROUP BALANCE SHEET

At 31 December 2012

	Notes	2012	2011
ASSETS		US$'000	US$'000
Non-current assets
Property, plant and equipment	10	1,816,591	1,273,558
Goodwill	11	107,760	107,760
Intangible oil and gas assets	12	97,506	24,347
Asset held for sale	13	-	1,254
Investments	14	2,317	6,734
Deferred tax assets	7	23,143	12,617
Other financial assets	21	19,447	-
		2,066,764	1,426,270

Current assets
Inventories	15	15,301	11,842
Trade and other receivables	16	239,722	126,554
Income tax receivable		2,007	2,618
Cash and cash equivalents	17	124,522	378,907
Other financial assets	21	96,472	2,510
		478,024	522,431
TOTAL ASSETS		2,544,788	1,948,701

EQUITY AND LIABILITIES
Equity
Share capital	18	113,433	113,433
Merger reserve		662,855	662,855
Cash flow hedge reserve		(46)	(2,600)
Share-based payment reserve		(11,072)	(5,961)
Retained earnings		528,699	166,481
TOTAL EQUITY		1,293,869	934,208

Non-current liabilities
Borrowings	20	34,600	-
Obligations under finance leases	24	107	-
Provisions	22	232,952	181,237
Other financial liabilities	21	-	335
Deferred tax liabilities	7	632,230	590,010
		899,889	771,582

Current liabilities
Trade and other payables	23	329,666	234,337
Obligations under finance leases	24	34	-
Other financial liabilities	21	17,570	6,870
Income tax payable		3,760	1,704
		351,030	242,911

TOTAL LIABILITIES		1,250,919	1,014,493

TOTAL EQUITY AND LIABILITIES		2,544,788	1,948,701

The attached notes 1 to 28 form part of these Group financial statements.

GROUP STATEMENT OF CHANGES IN EQUITY

At 31 December 2012

	Share capital	Merger reserve	Cash flow hedge reserve	Share-based payments reserve	Available-for-sale reserve	Retained earnings	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

At 1 January 2011	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

Profit for the year	-	-	-	-	-	362,218	362,218
Other comprehensive income	-	-	2,554	-	-	-	2,554
Total comprehensive income for the year	-	-	2,554	-	-	362,218	364,772

Share-based payment charge	-	-	-	5,163	-	-	5,163
Shares purchased on behalf of Employee Benefit Trust	-	-	-	(10,274)	-	-	(10,274)

At 31 December 2012	113,433	662,855	(46)	(11,072)	-	528,699	1,293,869

GROUP STATEMENT OF CASH FLOWS

For the year ended 31 December 2012

		2012	2011
	Notes	US$'000	US$'000
CASH FLOW FROM OPERATING ACTIVITIES
Profit before tax		403,401	362,821
Depreciation	5(d)	1,483	1,784
Depletion	5(b)	216,780	217,233
Exploration and evaluation expenses	5(c)	23,157	36,962
Impairment of oil and gas assets	4	143,882	-
Well abandonment	4	-	(8,194)
Gain on disposal of asset held for sale	4	-	(8,644)
Gain on disposal of property, plant and equipment	4	(175,929)	-
Impairment on available-for-sale investments	4	4,417	12,497
Share-based payment charge	5(g)	5,163	4,881
Unwinding of discount on decommissioning provisions	6	10,148	7,793
Unrealised exchange losses	5(f)	8,445	3,344
Net finance costs	6	8,902	6,850
Operating profit before working capital changes		649,849	637,327
Increase in trade and other receivables		(105,088)	(1,940)
(Increase)/decrease in inventories		(3,459)	562
Increase in trade and other payables		52,610	20,383
Cash generated from operations		593,912	656,332
Decommissioning spend		(13,618)	(9,192)
Income taxes paid		(790)	(10,855)
Net cash flows from operating activities		579,504	636,285

INVESTING ACTIVITIES
Purchase of property, plant and equipment		(838,399)	(223,947)
Purchase of intangible oil and gas assets		(128,403)	(53,964)
Proceeds from farm out		124,587	-
Acquisition of available-for-sale investments		-	(808)
Interest received		787	1,834
Net cash flows used in investing activities		(841,428)	(276,885)

FINANCING ACTIVITIES
Proceeds from bank facilities		34,692	-
Shares purchased by Employee Benefit Trust		(10,274)	(13,123)
Repayment of obligations under finance leases		(89)	-
Interest paid		(632)	(1)
Other finance costs paid		(14,065)	(9,633)
Net cash flows from/(used) in financing activities		9,632	(22,757)

NET (DECREASE)/INCREASE IN CASH AND CASH EQUIVALENTS		(252,292)	336,643
Net foreign exchange on cash and cash equivalents		(2,093)	869
Cash and cash equivalents at 1 January		378,907	41,395
CASH AND CASH EQUIVALENTS AT 31 DECEMBER		124,522	378,907

The attached notes 1 to 28 form part of these Group financial statements.

1. Notes to the consolidated financial statements

The financial information for the year ended 31 December 2012 and 2011 contained in this document does not constitute statutory accounts as defined in section 435 of the Companies Act 2006. The financial information for the years ended 31 December 2012 and 2011 have been extracted from the consolidated financial statements of EnQuest plc for the year ended 31 December 2012 which have been approved by the directors on 26 March 2013 and will be delivered to the Registrar of Companies in due course. The auditor's report on those financial statements was unqualified and did not contain a statement under section 498 of the Companies Act 2006.

2. Significant accounting policies

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

The Group has adopted IAS 12 "Income Taxes" and IFRS 7 "Financial Instruments: Disclosures - Enhanced derecognition disclosure requirements" during the year. Adoption of these revised standards did not have any effect on the financial performance or position of the Group.

3. Segment information

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

All revenue is generated from sales to customers in the United Kingdom. Details of the Group's revenue components are provided in note 5(a). All crude oil revenue is received from one major customer, Shell International Trading and Shipping Company Limited and amounted to US$879,307,000 or 99% of total revenue (excluding oil hedge gains and losses) in the year ended 31 December 2012 (2011: US$954,051,000 or 98% of total revenue).

All non-current assets of the Group are located in the United Kingdom except for US$7,136,000 (2011: nil) located in Malaysia.

4. Exceptional items and depletion of fair value uplift

	2012	2011
	US$'000	US$'000
Recognised in arriving at profit/(loss) from operations before tax and finance income/(costs):
Gain on disposal of asset held for sale	-	8,644
Impairment of available for sale investments (note 14)	(4,417)	(12,497)
Impairment of oil and gas assets	(143,882)	-
Gain on disposal of property, plant and equipment	175,929	-
Well abandonment	-	8,194
Depletion of fair value uplift	(10,251)	(16,973)
	17,379	(12,632)
Tax	85,174	(62,430)
	102,553	(75,062)

Gain on disposal of asset held for sale

During the prior 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 in the year ended 31 December 2011.

Impairment of available for sale investments

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 2012 resulted in a non-cash impairment of US$4,417,000 (2011: US$12,497,000).

Impairment of oil and gas assets

As part of the annual impairment review process, impairment triggers were highlighted which has led to a US$143,882,000 impairment of the Heather and Broom hub (refer to note 10).

Gain on disposal of property, plant and equipment

On 12 October 2012, the company entered into an agreement to farm out 35% of the Alma/Galia development to KUFPEC with an effective date of 1 January 2012. To earn the 35% interest, KUFPEC agreed to pay EnQuest:

a) a total of US$113,187,000 representing 35% of certain costs incurred between 1 January 2012 and 30 September 2012;

b) a US$15,000,000 capital contribution;

c) carry EnQuest from 1 October 2012 up to a cap of US$182,000,000 after which they will revert back to paying their share of the costs (35%). This carry has been recognised in other financial assets (refer note 21) and at 31 December 2012 the carry had reduced to US$95,302,000; and

d) pay an additional amount of US$647,000 per month on top of their share of operating costs, for a period of 36 months after the date of first oil production, The present value of these payments of US$19,300,000 has been recognised as an other financial asset (refer to note 21).

At 31 December 2012, the amounts due under (a) and (b) above had been received.

A 'balancing payment' was also agreed whereby should the cost of development exceed US$1,055,000,000 then EnQuest would be required to pay 17.5% of costs up to a cap on the cost of development of US$1,153,000,000. As costs are now expected to exceed the cap EnQuest will be liable to pay these additional costs and so a liability has been recognised for US$17,150,000 in other financial liabilities.

In addition, a reserves protection mechanism was agreed to enable KUFPEC to recoup its investment to the date of first production (refer to note 24).

The gain on disposal represents the difference between the total consideration and derecognition of 35% of the development at the date of the agreement.

Well abandonment expenses

During the year ended 31 December 2011 a credit 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 Petrofac Energy Developments Limited's (PEDL) oil and gas assets on acquisition of US$10,251,000 (2011: US$16,973,000) is included within cost of sales in the statement of comprehensive income.

Tax

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

5. Revenue and expenses

(a) Revenue

	Year ended 31 December	Year ended 31 December
	2012	2011
	US$'000	US$'000

Revenue from crude oil sales	879,307	960,401
Gain/(loss) on realisation of financial instruments	53	(36,509)
Revenue from condensate sales	(137)	-
Tariff revenue	10,189	11,672
Other operating revenue	98	410
	889,510	935,974

(b) Cost of sales

	Year ended 31 December	Year ended 31 December
	2012	2011
	US$'000	US$'000

Cost of operations	228,670	233,008
Tariff and transportation expenses	40,806	43,043
Change in lifting position	(24,360)	14,631
Inventory movement (note 15)	(3,459)	875
Depletion of oil and gas assets (note 10)	216,780	217,233
	458,437	508,790

	Year ended 31 December	Year ended 31 December
	2012	2011
	US$'000	US$'000

Unsuccessful exploration expenditure written off (note 12)	6,514	-
Impairment charge (note 12)	6,583	36,962
Pre-licence costs expensed	10,060	-
	23,157	36,962

(d) General and administration expenses

	Year ended 31 December	Year ended 31 December
	2012	2011
	US$'000	US$'000

Staff costs (note 5(g))	76,861	45,177
Depreciation (note 10)	1,483	1,784
Other general and administration costs	17,570	12,523
Recharge of costs to operations and joint venture partners	(89,264)	(45,729)
	6,650	13,755

(e) Other income

	Year ended 31 December	Year ended 31 December
	2012	2011
	US$'000	US$'000

Other income	2,000	-

(f) Other expenses

	Year ended 31 December	Year ended 31 December
	2012	2011
	US$'000	US$'000

Net foreign exchange losses	5,542	3,231

(g) Staff costs

	Year ended 31 December	Year ended 31 December
	2012	2011
	US$'000	US$'000

Wages and salaries	30,069	21,279
Social security costs	4,054	3,137
Defined contribution pension costs	3,155	1,194
Expense of share-based payments (note 19)	5,163	4,881
Other staff costs	2,682	1,845
Total employee costs	45,123	32,336
Contractor costs	31,738	12,841
	76,861	45,177

The average number of persons employed by the Group during the year was 173 (2011: 112).

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 31 December
	2012	2011
	US$'000	US$'000

Fees payable to the Company's auditor for the audit of the Company's annual accounts	148	136
Fees payable to the Company's auditor and its associates for other services: The audit of the Company's subsidiaries Audit related assurance services Tax advisory services (i) Other assurance services Corporate finance services	207 67 745 5 148	127 78 913 - -
	1,320	1,254

(i) Includes costs of US$345,600 (2011: US$620,000) relating to tax advice on asset and corporate acquisitions. These have been capitalised as part of the cost of the asset.

6. Finance costs/income

	Year ended 31 December	Year ended 31 December
	2012	2011
	US$'000	US$'000

Finance costs:
Loan interest payable	668	-
Unwinding of discount on decommissioning provisions (note 22)	10,148	7,793
Cash flow hedge re-price premium	335	5,867
Fair value loss on financial instruments at fair value through profit or loss (note 21)	2,147	-
Finance charges payable under finance leases	3	-
Other financial expenses	8,307	4,938
	21,608	18,598
Less: amounts included in the cost of qualifying assets	(397)	-
	21,211	18,598
Finance income:
Bank interest receivable	686	1,808
Fair value gain on financial instruments at fair value through profit or loss (note 21)	871	2,147
Unwinding of financial asset	479	-
Other financial income	125	-
	2,161	3,955

7. Income tax

(a) Income tax

The major components of income tax expense are as follows:

	Year ended 31 December	Year ended 31 December
	2012	2011
Group statement of comprehensive income	US$'000	US$'000
Current income tax
Current income tax charge	4,860	860
Adjustments in respect of current income tax of previous years	(1,204)	807

Deferred income tax
Relating to origination and reversal of temporary differences	50,335	237,034
Adjustments in respect of changes in tax rates	10,785	68,085
Adjustments in respect of deferred income tax of previous years	(23,593)	(4,956)
Income tax expense reported in statement of comprehensive income	41,183	301,830

(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
	2012	2011
	US$'000	US$'000
Profit before tax	403,401	362,821

Statutory rate of corporation tax in the UK of 62% (2011: 59.3%)	250,109	215,168
Supplementary corporation tax non-deductible expenditure	6,552	888
Non-deductible expenditure	3,310	3,195
Deductible lease expenditure	(76,951)	-
Non-taxable gain on sale of assets	(109,076)	-
Petroleum revenue tax (net of income tax benefit)	19,081	14,465
North Sea tax reliefs	(29,894)	(6,341)
Tax in respect of non-ring fence trade	(10,837)	1,596
Deferred tax rate increase on North Sea oil and gas activities	14,675	78,149
Adjustments in respect of prior years	(24,797)	(4,149)
Overseas tax rate differences	(464)	(1,141)
Other differences	(525)	-
At the effective income tax rate of 10% (2011: 83%)	41,183	301,830

Deferred income tax relates to the following:

	Group balance sheet		Group profit and loss
	2012	2011	2012	2011
	US$'000	US$'000	US$'000	US$'000
Deferred tax liability
Accelerated capital allowances	1,050,189	775,486	274,703	222,657
Other temporary differences	99,955	46,345	53,610	39,999
	1,150,144	821,831
Deferred tax asset
Losses	(359,406)	(95,558)	(253,847)	107,284
Decommissioning liability	(116,476)	(112,368)	(4,108)	(42,314)
Other temporary differences	(65,175)	(36,512)	(32,831)	(27,463)
	(541,057)	(244,438)
Deferred tax expense			37,527	300,163
Deferred tax liabilities, net	609,087	577,393

Reflected in balance sheet as follows:
Deferred tax assets	(23,143)	(12,617)
Deferred tax liabilities	632,230	590,010
Deferred tax liabilities, net	609,087	577,393

In addition to the amount charged to the profit and loss, a deferred tax charge of US$4,167,000 (2011: credit US$4,242,000) in respect of cash flow hedges (note 21), is recognised as other comprehensive income.

(d) Tax losses

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

The Group has unused UK mainstream corporation tax losses of US$2,662,000 (2011: nil) for which no deferred tax asset has been recognised at the balance sheet date due to the uncertainty of recovery of these losses.

The Group also has pre-trading ring fence expenditure of US$54,529,000 which has arisen following the acquisition of Canamens Energy North Sea Limited in early 2012 for which no deferred tax asset has been recognised. The expenditure is likely to become deductible and available to the Group for UK ring fence taxation purposes during 2013.

The Group has unused overseas tax losses in Canada of approximately CAD$17,106,000 (2011: CAD$76,577,000) and in Holland of €1,070,000 (2011: €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 2013. The tax losses in Canada were adjusted in the 2010 submitted returns to reflect the change in control of Stratic, resulting in a reduction in losses of $47,554,000. Tax losses in Holland can be carried forward for a period up to nine years and are likely to expire in 2013.

(e) Change in legislation

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

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.

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
	2012		2011	2012	2011	2012	2011
		US$'000	US$'000	Million	Million	US$	US$

Basic		362,218	60,991	784.1	801.7	0.462	0.076
Dilutive potential of Ordinary shares granted under share-based incentive schemes		-	-	13.3	2.9	-	-
Diluted		362,218	60,991	797.4	804.6	0.454	0.076

Adjusted (excluding exceptional items)		259,665	136,053	784.1	801.7	0.331	0.170

9. Dividends paid and proposed

The Company paid no dividends during the year ended 31 December 2012 (2011: nil).At 31 December 2012 there are no proposed dividends. (2011: 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 2011	1,628,601	7,813	1,636,414
Additions	291,723	4,677	296,400

Reclassified from intangible assets (note 12)	11,204	-	11,204
Change in decommissioning provision	50,722	-	50,722
At 31 December 2011	1,982,250	12,490	1,994,740
Additions	829,463	8,859	838,322
Farm in to West Don	29,752	-	29,752
Farm out	(143,054)	-	(143,054)
Cost carry	86,698	-	86,698
Reclassified from intangible assets (note 12)	31,221	-	31,221
Change in decommissioning provision	62,239	-	62,239
At 31 December 2012	2,878,569	21,349	2,899,918

Depletion and depreciation:
At 1 January 2011	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
Impairment charge for the year	143,882	-	143,882
Charge for the year	216,780	1,483	218,263
At 31 December 2012	1,075,884	7,443	1,083,327

Net carrying amount:
At 31 December 2012	1,802,685	13,906	1,816,591

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

At 1 January 2011	1,130,612	3,637	1,134,249

A farm out agreement was entered into during the year with KUFPEC for a 35% share of the Alma/Galia development. Consideration included reimbursement of past costs (US$113,187,000), a capital contribution (US$15,000,000), a cost carry up to a cap of US$182,000,000 and future costs payable after the date of first oil production (US$23,292,000). The cost of the 35% share of assets disposed was US$143,054,000 (including the decommissioning asset).

During the year ended 31 December 2012 there was a US$143,882,000 impairment of the Heather and Broom hub following a delay in phasing of production, particularly to allow the drilling of the West Fault Block well at Thistle in 2013 and an increase in estimated capital expenditure associated with the field life extension programme. The Heather and Broom hub inherited a high net book value of US$423,000,000, reflecting the fair value uplift when Lundin acquired the Heather and Broom assets prior to the formation of EnQuest. Refer to note 11 in respect of key assumptions used in value in use calculations.

At 31 December 2012, due to the recognition of 2P reserves for the Kraken field, US$61,994,000 of costs in relation to Kraken were reclassed from intangible to property, plant and equipment. Also during the year, prior year pre-development costs in relation to Crawford and Porter (US$ 30,773,000) were transferred to intangible assets as a result of a decision to review development options.

The amount of borrowing costs capitalised during the year ended 31 December 2012 was US$397,000 and relate to the Alma/Galia development (2011: nil). The weighted average rate used to determine the amount of borrowing costs eligible for capitalisation is 0.84% (2011: nil).

The additions during the year and the resultant net book value of property, plant and equipment held under finance leases and hire purchase contracts at 31 December 2012 was US$141,000 (2011: nil).

The net book value at 31 December 2012 includes US$535,827,000 (2011: US$107,433,000) of pre-development assets and development assets under construction which are not being depreciated.

11. Goodwill

A summary of the movement in goodwill is presented below:

	2012	2011
	US$'000	US$'000

At 1 January and 31 December	107,760	107,760
At 1 January and 31 December

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

Impairment testing of goodwill

In 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 pre-tax 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 five 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$107.60 per barrel in 2013, US$102.00 per barrel in 2014, US$97.80 per barrel in 2015, US$94.30 per barrel in 2016, US$91.70 per barrel in 2017 thereafter US$90 inflated at 2% per annum from 2013. In 2011, oil prices were based on 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 thereafter US$90 inflated at 2% per annum from 2012.

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

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

WACC takes into account both debt and equity. The cost of equity is derived from the expected return on investment by the Group's investors. The cost of debt is based on its interest-bearing borrowings. Segment risk is incorporated by applying a beta factor based on publicly available market data. The pre-tax discount rate applied to the Group's pre-tax cash flow projections is 20.4% (2011: 21.3%).

Sensitivity to changes in assumptions

There are reasonably possible changes in key assumptions which could erode the estimated amount 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$71.75 per barrel, escalated at 2% per annum (2011: US$80.71 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 18.4% (2011: 24%) to cause the recoverable amount to fall below the carrying amount of the CGU.

12. Intangible oil and gas assets

		US$'000
Cost
At 1 January 2011		108,124
Additions		64,165
Write-off of relinquished licences previously impaired		(34,127)
Reclassified to property, plant and equipment (note 10)		(11,204)
Reclassified to asset held for sale (note 13)		(1,254)
At 31 December 2011		125,704
Additions		77,120
Acquisition of interests in licences		39,103
Write-off of relinquished licences previously impaired		(4,754)
Unsuccessful exploration expenditure written off		(6,514)
Reclassified to property, plant and equipment (note 10)		(31,221)
Reclassified from asset held for sale (note 13)		1,254
At 31 December 2012		200,692

Provision for impairment
At 1 January 2011		(98,522)
Impairment charge for the year		(36,962)
Write-off of relinquished licences previously impaired		34,127
At 31 December 2011		(101,357)
Impairment charge for the year		(6,583)
Write-off of relinquished licences previously impaired		4,754
At 31 December 2012		103,186

Net carrying amount:

At 31 December 2012		97,506

At 31 December 2011		24,347

At 1 January 2011		9,602

During the year ended 31 December 2012, the Group acquired a 60% interest in the Kraken oil discovery in the UKCS in various tranches. The initial 20% interest was acquired through the acquisition of two entities from Canamens Limited for US$36,103,000. These costs are included within acquisition of interests in licences. The remaining 40% is by way of development carries. In addition costs of US$3,000,000 to acquire interests in an exploration licence in Malaysia are included within acquisition of interests in licences.

During the year ended 31 December 2012, US$4,754,000 of costs relating to relinquished licences previously impaired were written off (2011: US$34,127,000).

The impairment charge for the year ended 31 December 2012 includes costs of the Tryfan exploration well which proved to be uncommercial. During the year ended 31 December 2011 costs of US$36,962,000 were impaired relating to dryhole wells or uneconomic assessment on evaluation of the assets.

13. Assets held for sale

		US$'000

At 1 January 2011		9,778
Disposals		(9,778)
Reclassified from intangible fixed assets (note 12)		1,254
At 31 December 2011		1,254
Reclassified to intangible fixed assets (note 12)		(1,254)
At 31 December 2012		-

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 were subject to a swap arrangement whereby these were to be transferred to Sterling Resources Limited for a 50% share in the Cairngorm licence Block 16/3d. This arrangement was finalised in December 2012 and therefore the costs have been reclassified to intangible fixed assets.

14. Investments

			US$'000
Cost
At 1 January 2011			-
Additions			19,231
At 31 December 2012 and 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)
Impairment charge for the year			(4,417)
At 31 December 2012			(16,914)
Net carrying amount:
At 31 December 2012			2,317

At 31 December 2011			6,734

At 1 January 2011			-

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 and a further 10,000,000 shares were purchased during 2011 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) has resulted in an additional non-cash impairment of US$4,417,000 in the year ended 31 December 2012 (2011: US$12,497,000).

15. Inventories

	2012	2011
	US$'000	US$'000

Crude oil	15,301	11,842

16. Trade and other receivables

	2012	2011
	US$'000	US$'000

Trade receivables	94,818	75,031
Joint venture receivables	100,918	33,411
Other receivables	24,645	9,313
	220,381	117,755
Prepayments and accrued income	19,341	8,799
	239,722	126,554

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 2012 no impairment provision for trade receivables was necessary (2011: nil).

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

As at 31 December 2012 and 31 December 2011 no other receivables were determined to be impaired.

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

17. Cash and cash equivalents

The carrying value of the Group's cash and cash equivalents is considered to be a reasonable approximation to their fair value. Included within the cash balance at 31 December 2012 is restricted cash of US$14,880,000 (2011: nil) relating to cash held under Performance Guarantee Agreements with suppliers.

18. Share capital

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

	2012	2011
Authorised, issued and fully paid	US$'000	US$'000

802,660,757 (2011: 802,660,757) Ordinary shares of £0.05 each	61,249	61,249
Share premium	52,184	52,184
	113,433	113,433

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

On 14 April 2011, 3,197,852 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. There were no new issues of shares during 2012.

At 31 December 2012 there were 22,966,471 shares held by the Employee Benefit Trust (2011: 18,139,465) due to the purchase of shares to satisfy awards made under the Company's share-based incentive schemes net of shares used during the year.

19. Share-based payment plans

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

Deferred Bonus Share Plan (DBSP)

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

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

Weighted average fair value per share

Trued up vesting rate

2012 awards

2011 awards

2010 awards

124p

137p

101p

86%

84%

98%

The following shows the movement in the number of share awards held under the DBSP scheme outstanding and not exercisable:

2012

Number*

2011

Number*

Outstanding at 1 January

Granted during the year

Vested during the year

Forfeited during the year

526,080

783,410

(230,743)

(60,390)

390,730

351,444

(94,292)

(121,802)

Outstanding at 31 December

1,018,357

526,080

* Includes invested and matching shares.

There were no share awards exercisable at either 31 December 2012 or 2011.

The weighted average contractual life for the share awards outstanding as at 31 December 2012 was 1.1 years (2011: 1.1 years).

The charge recognised in the 2012 statement of comprehensive income in relation to matching share awards amounted to US$701,000 (2011: US$308,000).

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, 2011 and 2012 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

2012 awards

2011 awards

2010 awards

123p

119p

104p

95%

98%

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

	2012 Number	2011 Number
Outstanding at 1 January Granted during the year Vested during the year Forfeited during the year	8,036,955 686,000 (1,782,748) (94,172)	7,926,411 829,845 (298,515) (420,786)
Outstanding at 31 December	6,846,035	8,036,955
Exercisable at 31 December	1,312,156	268,177

The weighted average contractual life for the share awards outstanding as at 31 December 2012 was 1.2 years (2011: 1.7 years).

The charge recognised in the year ended 31 December 2012 amounted to US$2,572,000 (2011: US$3,767,000).

Performance Share Plan (PSP)

Under the Performance Share Plan, the shares vest subject to performance conditions. The PSP share awards granted in 2011 and 2012 had three sets of performance conditions associated with them. One third of the award relates to Total Shareholder Return (TSR) against a comparator group of 36 oil and gas companies listed on the FTSE 350, AIM Top 100 and Stockholm NASDAQ OMX; one third relates to production growth per share, and one third relates to reserves growth per share, over the three year performance period. Awards will vest on the 3^rd anniversary.

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

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

Weighted average fair value per share

Trued up vesting rate

2012 awards

2011 awards

124p

137p

97%

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

	2012 Number	2011 Number
Outstanding at 1 January Granted during the year Forfeited during the year	1,668,522 3,021,117 (87,000)	- 1,722,022 (53,500)
Outstanding at 31 December	4,602,639	1,668,522

There were no share awards exercisable at either 31 December 2012 or 2011.

The weighted average contractual life for the share awards outstanding as at 31 December 2012 was 1.9 years (2011: 2.2 years).

The charge recognised in the year ended 31 December 2012 amounted to US$1,802,000 (2011: US$806,000).

Sharesave Plan

The Group operates an approved savings related share option scheme. The Plan is based on eligible employees being granted options and their agreement to opening a sharesave account with a nominated savings carrier and to save over a specified period, either 3 or 5 years. The right to exercise the option is at the employee's discretion at the end of the period previously chosen, for a period of six months.

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

Weighted average fair value per share

Trued up vesting rate

2012 awards

20p

93%

The following shows the movement in the number of share options held under the Sharesave plan outstanding but not exercisable:

	2012 Number	2011 Number
Granted during the year Forfeited during the year	746,880 (49,500)	- -
Outstanding at 31 December	697,380	-

There were no share options exercisable at either 31 December 2012 or 2011.

The weighted average contractual life for the share options outstanding as at 31 December 2012 was 2.9 years (2011: nil).

The charge recognised in the 2012 statement of comprehensive income amounted to US$88,000 (2011: nil).

The Company has recognised a total charge of US$5,163,000 (2011: US$4,881,000) in the statement of comprehensive income during the year, relating to the above employee share-based schemes.

20. Loans and borrowings

Revolving credit facility

At 31 December 2011, the Group had US$156,250,000 of undrawn committed borrowing facilities available which expired 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 (subject to reserves), 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 (LoC) of US$123,750,000 under the old facility have been rolled into the new facility. The drawdown of US$34,600,000 at 31 December 2012 was subsequently repaid.

Interest on the revolving credit facility is payable at US LIBOR plus a margin of 2.25% to 3.25%, dependent on specified covenant ratios. A facility non-utilisation commitment fee is payable at 40% of the interest margin.

At 31 December 2012, US$34,600,000 was drawn down under the Group's facility agreement (2011: nil) and LoC utilisation of US$123,750,000 (2011: US$123,750,000).

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

21. Other financial assets and financial liabilities

	2012	2011
	US$'000	US$'000
Financial instruments at fair value through other comprehensive income
Current liabilities
Cash flow hedges:
Forward foreign currency contracts	121	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	1,170	2,510

Current liabilities
Derivatives not designated as hedges:
Commodity forward contracts	299	363

Loans and receivables
Current assets
Other receivable	95,302	-

Non-current assets Other receivable	19,447	-

Other financial liabilities at amortised cost
Current liabilities
Other liability	17,150	-

Total current assets	96,472	2,510
Total non-current assets	19,447	-
Total assets	115,919	2,510

Total current liabilities	17,570	6,870
Total non-current liabilities	-	335
Total liabilities	17,570	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

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 oil production for approximately 3,000,000 barrels of oil in 2012 for accounting purposes. These instruments were deemed to be ineffective for hedging purposes and are therefore designated as at fair value through profit and loss (FVTPL). These derivative instruments had fully unwound by the end of December 2012 and therefore had no fair value (2011: US$2,147,000). The gains of US$2,147,000 recognised in 2011 were reversed during 2012 and are included within other finance costs.

In November 2012, the Group entered into three separate put and call options in order to hedge the changes in future cash flows from the sale of oil production for approximately 1,000,000 barrels of oil in the first quarter of 2013 for accounting purposes. These instruments were deemed to be ineffective for hedging purposes and are therefore designated as at fair value through profit and loss (FVTPL). The derivative instruments had a net asset fair value of US$871,000 (2011: nil) and gains of US$871,000 (2011: nil) were taken into profit and loss during the year and are included within other finance 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. These contracts qualified for hedge accounting. At 31 December 2012 only three of the original contracts were in place with a total fair value liability of US$121,000 (2011: US$6,842,000). The movement through other comprehensive income during the year is an unrealised gain of US$2,554,000 (2011: US$2,600,000 loss) net of a deferred tax credit of US$4,167,000 (2011: US$4,242,000 charge). The impact in profit or loss during the year was an expense of US$2,903,000 (2011: US$113,000) in respect of these contracts.

Other receivable

As disclosed in note 4, as part of the farm out to KUFPEC of 35% of the Alma/Galia development, KUFPEC will carry EnQuest up to a cap of US$182,000,000 and agreed to pay EnQuest a total of US$23,292,000 after production commences over a period of 36 months. Receivables have been recognised for both these:

· The carry element is being unwound over the period of the carry and at 31 December 2012 the remaining balance was US$95,302,000;

· A receivable has been recognised for the additional payments at its fair value of US$19,300,000. The unwinding of the discount on these future payments will be included within finance income in the income statement.

Other liability

Under the KUFPEC agreement a 'balancing payment' was also agreed whereby should the cost of development exceed US$1,055,000,000 then EnQuest would be required to pay 17.5% of costs up to a cap on the cost of development of US$1,153,000,000. As costs are now expected to exceed the cap EnQuest will be liable to pay these additional costs, resulting in the recognition of a US$17,150,000 liability.

22. Provisions

	Decommissioning
	US$'000

At 1 January 2011	140,108
Additions during the year	33,821
Changes in estimates	16,901
Unwinding of discount	7,793
Utilisation	(17,386)
At 31 December 2011	181,237
Additions during the year	37,609
Farm in to West Don	14,569
Farm out of Alma/Galia development	(7,054)
Changes in estimates	10,061
Unwinding of discount	10,148
Utilisation	(13,618)
At 31 December 2012	232,952

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% (2011: 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.

23. Trade and other payables

	2012	2011
	US$'000	US$'000

Trade payables	81,885	26,215
Accrued expenses	232,877	192,494
Other payables	14,904	15,628
	329,666	234,337

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

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

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

24. Commitments and contingencies

Commitments

(i) Operating lease commitments

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

	2012	2011
	US$'000	US$'000

Not later than one year	2,025	1,372
After one year but not more than five years Over five years	4,781 2,772	2,170 -
	9,578	3,542

Lease payments recognised as an operating lease expense during the year amounted to US$2,324,819 (2011: US$2,066,054).

Under the Dons Northern Producer Agreement a minimum notice period of twelve months exists whereby the Group expects the minimum commitment under this agreement to be approximately US$46,000,000 (2011: US47,000,000).

(ii) Finance lease commitments

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

	2012 Minimum payments		2012 Present value of payments	2011 Minimum payments	2011 Present value of payments
		US$'000	US$'000	US$'000	US$'000

Due in less than one year		37	34	-	-
Due in more than one year but not more than five years		110	107	-	-
		147	141	-	-
Less future financing charges		(6)	-	-	-
		141	141	-	-

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

(iii) Capital commitments

At 31 December 2012, the Group had capital commitments excluding the above lease commitments amounting to US$203,620,000 (2011: US$310,408,000).

Contingencies

At 31 December 2012, potential future commitments included US$45,000,000 contingent consideration due to Canamens Limited after acquisition of two of its companies, US$5,000,000 in respect of the Group's interest in Block 9/2b in the UK North Sea (Kraken) and a further potential commitment of £7,000,000 (US$11,200,000) is due in respect of back-in payments associated with the sole risk drilling undertaken by the previous operator on the Kraken 9/2b-04 appraisal and 9/2b-04z exploration sidetrack. During 2012 EnQuest acquired interests in Kraken from Nautical Petroleum plc (25%) and First Oil plc (15%). The amounts payable are US$150,000,000 to US$240,000,000 and US$90,000,000 to US$144,000,000 respectively, linked to independent reserves determination between 100MMboe and 166MMboe. All will become payable upon approval of the Kraken Field Development Plan (FDP) by the Department of Energy and Climate Change. The FDP is expected to be submitted in the first half of 2013.

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

In addition, there is contingent consideration of US$20,000,000 after the acquisition of Nio (Sabah) Limited which will be determined based on 2P reserves associated with an approved FDP on blocks SB307 and SB308 in Malaysia. An exploration/appraisal well is expected to be drilled in the area in the second half of 2013.

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

25. 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 28 to these Group financial statements.

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

All sales to and purchases from related parties are made at normal market prices and the pricing policies and terms of these transactions are approved by the Group's management. There have been no transactions with related parties who are not members of the Group during the year ended 31 December 2012 (2011: nil).

Compensation of key management personnel

The following table details remuneration of key management personnel of the Group comprising executive and non-executive directors of the Company and other senior personnel:

	2012	2011
	US$'000	US$'000

Short term employee benefits	4,306	3,849
Share-based payments	4,086	2,850
Post employment pension benefits	30	29
	8,422	6,728

26. Risk management and financial instruments

Risk management objectives and policies

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

The Group's activities expose it to various financial risks particularly associated with fluctuations in oil price, foreign currency risk, liquidity risk and credit risk. Management reviews and agrees policies for managing each of these risks, which are summarised below. Also presented below is a sensitivity analysis to indicate sensitivity to changes in market variables on the Group's financial instruments and to show the impact on profit and shareholders' equity, where applicable. The sensitivity has been prepared for periods ended 31 December 2012 and 2011 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. In November 2011, the Group entered into five separate put and call options to hedge approximately 3,000,000 barrels of oil in 2012. During November 2012, the Company entered into a further three put and call options, to hedge approximately 1,000,000 barrels of oil in the first quarter of 2013. Since the year end the Group has entered into further put and call options covering 3.6 million barrels of oil production for 2013.

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 2012	76,337	(76,323)	29,008	(29,003)
31 December 2011	70,836	(67,500)	26,918	(25,650)

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 United States dollar receipts at spot rates periodically and as required for payments in other currencies. Approximately 1% (2011: 2%) of the Group's sales and 89% (2011: 89%) of costs are denominated in currencies other than the functional currency.

During the year ended 31 December 2011, the Group had entered into 11 forward currency contracts to partially hedge the Group's exposure to fluctuations in foreign currencies, namely Sterling and Euro. At 31 December 2012 only three of these contracts remained and are due to mature in 2013. These contracts qualify for hedge accounting and have been disclosed within note 21.

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 the United States dollar to GBP Sterling exchange rate:

	Pre-tax profit		Total equity
	+10% US dollar rate increase	-10% US dollar rate decrease	+10% US dollar rate increase	-10% US dollar rate decrease
	US$'000	US$'000	US$'000	US$'000

31 December 2012 31 December 2011	(24,918) (25,056)	24,918 25,056	(9,234) 1,438	9,234 (1,438)

Credit risk

The Group trades only with recognised, international oil and gas operators and at 31 December 2012 there were no trade receivables past due (2011: nil), and US$4,078,000 of joint venture receivables past due but not impaired (2011: US$705,000). Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary.

	2012	2011
Ageing of past due but not impaired receivables	US$'000	US$'000

Less than 30 days	143	7
30-60 days	144	-
60-90 days	78	622
90-120 days	89	21
120+ days	3,624	55
	4,078	705

At 31 December 2012, the Group had one customer accounting for 87% of outstanding trade and other receivables (2011: one customer, 92%) and three joint venture partners accounting for 90% of joint venture receivables (2011: six joint venture partners, 80%).

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 2012 the Group was in compliance with all financial covenant ratios agreed with its bankers.

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 (dependent upon reserves), 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 were rolled into the new facility and have subsequently increased to US$181,500,000. 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 2012	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

Loans and borrowings	-	-	-	34,600	34,600
Obligations under finance leases	-	34	35	72	141
Accounts payable and accrued liabilities	329,666	-	-	-	329,666
Financial expenses	-	1,123	-	-	1,123
Other liability	-	17,150	-	-	17,150
	329,666	18,307	35	34,672	382,680


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

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

Year ended 31 December 2012
	On demand	Less than 3 months	3 to 12 months	1 to 2 years	>2 years	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Foreign exchange forward contracts	-	6,298	-	-	-	6,298
Foreign exchange forward contracts	-	(6,298)	-	-	-	(6,298)
	-	-	-	-	-	-

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 and 2012, the Group held commodity forward contracts for which, based on the oil price at 31 December 2011 and 2012, there were no projected contracted cash flows.

Capital management

The capital structure of the Group consists of debt, which includes the borrowings disclosed in notes 20 and 24, cash and cash equivalents and equity attributable to the equity holders of the parent, comprising issued capital, reserves, and retained earnings as in the Group Statement of Changes in Equity.

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

The Group also has approval from the Board to hedge the exchange risk on up to 70% and 50% of the non US dollar portion of the Group's annual capital budget and operating expenditure respectively, and up to 50% of annual production. This is designed to minimise the risk of adverse movements in exchange rates and prices eroding the return on the Group's projects and operations.

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

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

	2012	2011
	US$'000	US$'000
Loans and borrowings, net (A)	34,741	-
Cash and short term deposits	(124,522)	(378,907)
Net debt/(cash) (B)	(89,781)	(378,907)

Equity attributable to EnQuest PLC shareholders (C)	1,293,869	934,208

Profit for the year attributable to EnQuest PLC shareholders (D)	362,218	60,991

Profit for the year attributable to EnQuest PLC shareholders excluding exceptionals (E)	259,665	136,053

Gross gearing ratio (A/C)	0.027	n/a

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

Shareholders' return on investment (D/C)	28%	7%

Shareholders' return on investment excluding exceptionals (E/C)	20%	15%

27. Post balance sheet events

In December 2012, a Sale and Purchase Agreement was executed in respect of the sale of the P8A licence to Van Dyke Energy for an initial consideration of $3,000,000 plus a contingent payment of a further $3,000,000 payable once the field incorporating the license reaches gross sales volumes of 2.5 million barrels. The carrying value was US$45,000 at 31 December 2012. This is expected to complete in the first half of 2013.

On 21 January 2013 the Group received formal consent from the Department of Energy and Climate Change in respect of the Thistle Late Life Extension (LLX) development. The incremental reserves targeted by the development will receive Additionally Developed Oil Field Allowance in excess of £200,000,000 (US$320,000,000). This is a new field allowance announced by the Government in 2012 to help mature fields in the UKCS and will apply when the taxation legislation receives Royal Assent in 2013.

On 23 January 2013, EnQuest Britain Limited agreed with CIECO Energy (UK) Limited to acquire two of its affiliate companies which together hold a total of an 8% non-operated interest in the producing oil field Alba, in the UK Continental Shelf. The acquisition completed on 22 March 2013, with consideration, net of cash acquired, totalling £19,622,000 (US$29,700,000) plus a further deferred cash consideration of up to £500,000 (US$800,000) contingent on certain project milestones.

In February 2013, the Group issued a 5.5% Sterling Retail Bond through the Order Book for Retail Bonds of the London Stock Exchange (ORB). The Bonds raised US$145,000,000 and will pay a fixed gross rate of interest of 5.5% per annum until 2022.

28. Subsidiaries

At 31 December 2012, 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	Intermediate holding company and provision of Group manpower and contracting/procurement services	England	100%

EnQuest Dons Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%

EnQuest Dons Oceania Limited (i)	Exploration, extraction and production of hydrocarbons	Cayman Islands	100%

EnQuest Heather Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%

EnQuest Thistle Limited (i)	Extraction and production of hydrocarbons	England	100%

Stratic Energy (UK) Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%

Grove Energy Limited (i)	Intermediate holding company and exploration of hydrocarbons	Canada	100%
EnQuest ENS Limited (i)	Extraction and production of hydrocarbons	England	100%
EnQuest UKCS Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%

EnQuest Norge AS EnQuest Heather Leasing Limited (i) Nio Petroleum (Sabah) Limited (i)	Exploration, extraction and production of hydrocarbons Leasing Exploration, extraction and production of hydrocarbons	Norway England England	100% 100% 100%
(i) Held by subsidiary undertaking.

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