EnQuest Full Year Results 2010

RNS Number : 2904E

EnQuest PLC

05 April 2011

ENQUEST PLC, 5 April 2011

Full Year results, for the 12 months to 31 December 2010

Delivering Strong Growth

HIGHLIGHTS
Unless otherwise stated all figures are in US dollars.

§ Pro-forma* net 21,074 Boepd export production, a 55% increase on 2009, average realised oil price was $81.26/Boe

§ Good operational performance across producing fields and the overall 2010 drilling programme was completed ahead of schedule and under budget

§ Increased year end net 2P reserves from 80.5 MMboe to 88.5 MMboe, equates to a reserve replacement ratio of 208% and an increase in year end reserves of 10%

§ Increased 2010 pro-forma* revenue by 93% to $614.4 million, with pro-forma EBITDA^** pre-exceptionals and fair value adjustments, up from $124.8 million to $369.3 million

§ Reported cash flow from operations was $267.7 million, over four times 2009 levels

§ Completed acquisition of Stratic Energy Corporation in November 2010

§ Increased number of UK production licences from 16 to 26 during 2010, including five licences from the 26^th licensing round

* 'Pro-forma' data reflects the results for 12 calendar months of 2010 and 2009 as if the assets previously owned by Petrofac Limited and Lundin Petroleum AB were owned by EnQuest throughout the period. The results reported under IFRS reflect the related pooling of interests and acquisition accounting - see 'Detailed pro-forma note' below.

** EBITDA is calculated by taking profit/(loss) from operations before tax and finance income/(costs) and adding back depletion, depreciation and impairment and write off of tangible and intangible oil and gas assets

Amjad Bseisu, Chief Executive, said

"In our first year as a listed company, EnQuest has performed well against its key objectives; delivering strong results with significant increases in reserves and production. This performance marks a great beginning for EnQuest. It was made possible by the dedication and hard work of all of our employees. In 2010, EnQuest grew its production and its capabilities, investing in both our facilities and our people, enabling us to maintain our focus on execution and creating a company with distinctive skills.

EnQuest is setting its production target for 2011 at 26,500 Boepd, equating to a 26% increase over 2010; underpinned by our 2011 drilling programme of eight wells. Following the early success at Area E, the 2011 drilling programme will now include five production wells, two on Don Southwest and three on Thistle. We also continue to examine other areas of potential within our portfolio, expanded as it has been by the acreage we acquired through the 26^th licensing round; including a possible development opportunity at Ardmore.

EnQuest was very disappointed by the recent unexpected UK Budget decision to increase the supplementary charge levied on North Sea oil and gas production from 20% to 32%. The increase in tax rate does not create a positive climate for additional investments in the UKCS and will render some small field investments uneconomic. Nonetheless, there remains significant potential in our development and production programme and EnQuest is confident of its ability to deliver not only its 2011 targets, but also its medium and longer term growth objectives from its UKCS production and further afield.

With EnQuest's technical core competence, financial strength and the opportunities available, we are creating a substantial exploitation company. With the increased potential from our existing assets, the acquisition of Stratic and our success in the 26^th licensing round, EnQuest remains firmly on track in implementing its strategy of delivering sustainable growth in shareholder value."

OUTLOOK

§ EnQuest is targeting export production of 26,500 Boepd in 2011: a 26% increase on 2010. Saleable production is anticipated to be at a similar ratio to export meter production as in 2010

§ An active eight well drilling programme in 2011, including:

o Successful results already from the Area E well at Don Southwest (the Conrie field); scheduled to come onstream in the fourth quarter of 2011

o The Don Southwest Area 26 appraisal well which was dry

o Don Southwest producer-injector pair S8 and S9

o Three infill wells at Thistle: NWFB-P1, EFB-P1 and Dev-P1

o An exploration well at Ivy, south of Heather

§ Unit production and transportation costs anticipated to be $26-$28/Boe, using $85 oil and £1:$1.60

§ Full year capex guidance of approximately $300 million: $250 million on development drilling and facilities, $50 million on exploration and appraisal

2010 REVIEW

Production & Development

	Full twelve months Pro-forma Daily Average	Full twelve months Pro-forma Daily Average	Full twelve months Pro-forma Cumulative	Reported Cumulative
	2010	2009	2010	2010
	Net export production (Boepd)	Net export production (Boepd)	Net export production (Boe)	Net export production (Boe)
Thistle/Deveron	4,836	3,849	1,765,269	1,765,269
The Don Fields	11,660	3,358	4,255,704	3,776,897
Heather/Broom	4,578	6,406	1,671,011	1,671,011
Total	21,074	13,613	7,691,984	7,213,177

§ Pro-forma net 21,074 Boepd export production in 2010, up 55% on 2009

§ Pro-forma net 7.7 MMboe cumulative export production and reported net 7.2 MMboe cumulative export meter production

§ Notable 2010 drilling successes included:

o Don Southwest Area 22 S2Z, S5 and S6, all completed ahead of schedule, with strong positive impact on production

o West Don W4 producer, on stream in November at net initial rate of c.12,000 Boepd

o Thistle A46 well, which recommenced production in early 2010, and SFB-P1, the first new well drilled on Thistle in over 20 years

§ Disappointing results on BR7 at Broom and Area H at Don Southwest

2P Reserves

§ Year end net 2P reserves increased by 10% to 88.5 MMboe, after:

o Saleable production of 7.4 MMboe, after 4% volume adjustment from export meter volume

o An increase of 7.2 MMboe through acquisition of Stratic

o Upward revisions to previous estimates of 8.2 MMboe, including; increases for Thistle/Deveron, Don Southwest and West Don and net of a reduction due to the Broom dry well

Financial

US Dollars	Pro-forma (pre-exceptionals and fair value adjustments)		Reported (pre-exceptionals and fair value adjustments)
	2010	2009	2010	2009
Revenue ($million)	614.4	319.0	583.5	234.0
Cost of sales ($million)	(406.4)	(259.6)	(384.5)	(193.1)
Unit production & transportation costs ($/Boe)	(30.4)	(34.8)	(30.8)	(39.0)
Unit depletion of oil & gas properties ($/Boe)	(22.8)	(18.7)	(22.2)	(13.8)
Gross profit ($million)	208.0	59.4	199.0	40.9
Profit before tax & net finance costs ($million)	169.4	24.6	163.7	16.6
EBITDA ($million)	369.3	124.8	-	-
Cash flow from operations ($million)	-	-	267.7	59.9
Earnings per share (cents)	-	-	4.0	1.9
Net cash/(debt) ($million)	-	-	41.4	(126.7)

§ Reported 2010 profit from operations before tax and net finance costs was $163.7 million, compared to $16.6 million in 2009

§ $614.4 million pro-forma revenue benefitted from the strong growth in production levels:

o 2010 pro-forma revenue reflected sales volumes of 7,433 Mboe, compared to 4,738 Mboe in 2009

o In 2010 the average pro-forma realised oil price achieved was $81.26/Boe, compared to $65.14/Boe in 2009

§ 2010 pro-forma unit production and transportation costs of $30.4 per Boe, reflected the increases noted in EnQuest's November 2010 Interim Management Statement

§ Exceptional items in the second half of 2010 included a $35 million impairment in relation to Peik and Burdock

§ Pro-forma capex of $196.3 million, invested mainly in drilling on Don Southwest, West Don and Thistle, and in the pipeline augmentation project on Broom

§ Strong cash generation; reported cash flow from operations was $267.7 million, up from $59.9 million in 2009

§ Net cash at end of period of $41.4 million having repaid $88.8 million of net debt associated with the acquisition of Stratic and $29.2 million of working capital due to Petrofac and Lundin

Ends

For further information please contact:

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

Amjad Bseisu (Chief Executive)

Jonathan Swinney (Chief Financial Officer)

Michael Waring (Head of Communications & Investor Relations)

Finsbury Tel: +44 (0)20 7251 3801

Andrew Mitchell

Conor McClafferty

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 / International: +44 (0) 20 7138 0844

USA +1 212 444 0895

Notes to editors

EnQuest is the largest independent producer of oil out of 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 and OMX Nordix index. Its assets include the Thistle, Deveron, Heather, Broom, West Don and Don Southwest fields. It has interests in 26 production licences covering 34 blocks or part blocks in the UKCS, of which 21 licences are operated by EnQuest.

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

Detailed 'pro-forma' note: In April 2010 the newly incorporated independent entity EnQuest PLC acquired the demerged UK North Sea assets of Petrofac Limited and Lundin Petroleum AB respectively. This transaction has been accounted for as a pooling of interest of EnQuest and the former Lundin business (Lundin North Sea BV, 'LNS'). The result is the net assets of LNS remain at the previous carrying amounts. The acquisition of the former Petrofac business (Petrofac Energy Developments Limited, 'PEDL') is treated as an acquisition by LNS of PEDL. The full year Group statement of consolidated income published today therefore includes the trading results for LNS from the start of the 2010 calendar year with the inclusion of the PEDL trading results from 5 April 2010. In order to aid comparability of performance, the Directors have elected to also prepare a separate abridged pro-forma full year consolidated income statement for the 12 months ended 31 December 2010 and 31 December 2009. This abridged pro-forma income statement presents the trading results for both LNS and PEDL from the start of the 2010 calendar year, as though PEDL was part of the Group for the full period ended 31 December 2010 and similarly for the prior period. The Directors have also elected to present certain other data including, inter-alia, production figures, on the same pro-forma basis. Throughout this document, comments or data presented on a pro-forma basis are identified as "pro-forma".

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

CHAIRMAN'S STATEMENT

2010 was an excellent year for EnQuest PLC, following our flotation in April. EnQuest has been using its technical, operational, commercial and asset management skills to implement its differentiated strategy. Our performance delivered an impressive set of maiden results, with strong growth in production and earnings. Pro-forma daily average net production grew by 55% compared to 2009, to 21,074 Boepd in 2010 and basic earnings per share of 4.0 cents increased by 111%. Reported cash flow from operations was $267.7 million, over four times 2009 levels. I am pleased to say that our conviction of EnQuest's potential is already proving to have been well founded.

Market conditions

2010 saw the average price of Brent crude oil at $79.5/Bbl, up almost 30% on 2009 and resulted in higher realised oil prices per barrel for EnQuest; up from $65.1 to $81.3 per barrel on a pro-forma basis. During 2010, the increased level of crude oil prices reflected improving financial markets and strengthening of the overall global economy. More recent global geo-political events have increased oil price volatility and highlighted supply side constraints.

Whilst we cannot predict the short term impact of oil price movements, EnQuest is well positioned in 2011 and well placed to capitalise on opportunities which may arise. Over the long term, I firmly believe that the fundamental economics of global supply and demand for oil will inevitably result in prices that will strongly support EnQuest's strategy.

2010 was an interesting year for the UK North Sea upstream marketplace, with a number of independents leaving the UK listed sector. Many of those that remain are focused on exploration rather than exploitation and are also managing a range of geographies outside the United Kingdom Continental Shelf. Whilst recent UK government tax changes have been disappointing, nonetheless EnQuest is well positioned with its strong balance sheet and its skills and capabilities to take forward development projects. I believe that these strengths give EnQuest a competitive advantage in its marketplace.

The timely evolution of EnQuest

In 2010 EnQuest was formed from the demerged UK North Sea assets of Petrofac Limited and Lundin Petroleum AB. In April, following the IPO process, EnQuest PLC made a successful debut on both the London Stock Exchange and the Nasdaq OMX in Stockholm. EnQuest started with an initial net 2P reserves of 80.5 MMboe in the North Sea and a portfolio which included a number of undeveloped discoveries in this mature basin; clearly a compelling fit with EnQuest's 'exploitation' focused model. EnQuest's results today confirm this; these assets have been thriving within EnQuest, benefiting from the financial, technical and operational expertise and capital that is needed to optimise their development.

On formation, EnQuest's operational priorities were the immediate implementation of an effective health, safety and environment management system and the integration of the overall structures of its two predecessor organisations. During this transformation period, we placed particular emphasis on developing a distinctive EnQuest culture and on establishing the EnQuest values.

In 2010, the EnQuest team delivered; its strong production performance, its success in the 26^th licensing round and the acquisition of Stratic Energy Corporation have all reaffirmed our confidence in EnQuest's model and in its ability to achieve its growth objectives.

Investing for the future

The EnQuest Board believes that reinvesting in our core business is key to building shareholder value and that the opportunities for investment are currently such that growth is a more effective way to generate returns for investors than by paying out a dividend. This will be reassessed on a regular basis, but for the foreseeable future, cash will be invested in ongoing production operations development and exploration projects and acquisitions.

Creating a new force in integrated development

In order to help establish EnQuest, we drew together a strong Board, comprising leading industry players with the expertise and experience to take the Company forward. Our Chief Executive, Amjad Bseisu was one of the founders of Petrofac Limited, having started its highly successful Petrofac Energy Developments division, and his vision was the initial driving force in the creation of EnQuest. Both Chief Operating Officer Nigel Hares and I worked initially with BP and then went on to lead Talisman Energy, a company which we are proud to say had an excellent growth record and also a similar business model to EnQuest's. When Nigel and I saw a similarly compelling potential in EnQuest, we had little hesitation in coming on board. Our Chief Financial Officer, Jonathan Swinney has broad international mergers and acquisition expertise and all of our Non-Executive Directors bring highly relevant in depth experience of developing similar businesses.

During this critical formative period for EnQuest, it has been invaluable to have both Robin Pinchbeck and Alexandre Schneiter as Non-Executive Directors, given their knowledge of the Company's business and their experience. However their associations with Petrofac Limited and Lundin Petroleum AB mean that they are not independent, for the purposes of the Combined Code. EnQuest therefore undertook that they would both stand down from the Board before April 2012. As part of this process Robin Pinchbeck will be retiring at the EnQuest Annual General Meeting on 25 May 2011. The Board and I would like to thank him for his important contribution to the successful establishment of EnQuest. The Board plans to appoint a new independent Non-Executive Director in the near future.

The creation of EnQuest has evidently put our employees through a considerable period of change; these forces of change have generated a very positive momentum. This has enabled us to optimise our organisational structure, increase our scale and build on our integrated multi-disciplinary capabilities. Whilst EnQuest's projects are always planned rigorously and methodically, our employees also have the agility to respond swiftly and effectively to unexpected opportunities as they arise, I believe that this is a key EnQuest differentiator. After this particularly busy launch year, the Board and I would like to thank EnQuest's employees for their commitment, their enthusiasm and their support throughout.

I would also like to welcome the highly skilled new people who have been joining EnQuest. EnQuest's vision, its performance to date and its pipeline of activity, are all helping us to attract some of the best talent in the industry and this is critical to delivering our ambitious growth plans. We have successfully recruited a number of senior figures during the year, in areas where there is strong competition for resources. EnQuest is building its reputation as a dynamic and attractive place in which to work and where petroleum industry professionals can develop excellent careers.

Governance and the EnQuest Code of Conduct

The launch of EnQuest's Code of Conduct was an important step in 2010. The Code sets out the behaviour which EnQuest expects of its Directors, managers and employees, of our suppliers, contractors, agents and partners. We are committed to complying with all applicable legal requirements, to upholding the highest ethical standards and to acting with complete integrity at all times. Our employees and everyone that we work with create and support our reputation and ensure our progress and success. This Code demonstrates our commitment to ensuring that these high levels of conduct continue.

Delivering sustainable balanced growth

There are significant opportunities on the United Kingdom Continental Shelf ('UKCS'). With an estimated 15 to 24 billion Boe of projected reserves and resources remaining in the UKCS, this should be a fertile environment for EnQuest's growth. We believe that we have a good supply of development opportunities and that EnQuest is one of the few companies which can take such opportunities and turn them into operationally and economically viable projects. In the short time since it has been in existence, EnQuest's performance has given the Board increased confidence that it will be able to achieve its medium-term production growth objective.

Business Review

CHIEF EXECUTIVE'S REPORT

Delivering strong growth

Our first year has been an excellent start for EnQuest, delivering production, operational and financial results exceeding expectations. Pro-forma production rose 55% to 21,074 Boepd making EnQuest the largest independent UK producer in the UK North Sea. The increase was due to additional production from our Don fields where we drilled one injection and three production wells and to our Thistle field where we have successfully rebuilt a platform rig and drilled and worked over two wells. Our active capital programme increased EnQuest's 2P reserves by 10% to a net 88.5 MMboe, representing a reserve replacement ratio of 208% in our maiden year of operations. EnQuest's financial results were also strong, driven by the increased production levels as well as higher oil prices. Pro-forma revenues were up 93% to $614.4 million and pre-exceptionals EBITDA was up 196% to $369.3 million.

We are well on our way to building a strong technically differentiated company with over a thousand people now working for EnQuest. With safety as our first priority, we have hired new senior management and instituted new systems and a functional responsibility matrix. Our newly formed integrated subsurface and execution teams managed a capital programme totalling $196.3 million on a pro-forma basis. This included the drilling of five production and injection wells, two exploration and appraisal wells, execution of the Don to Thistle export programme, execution of the Broom to Heather improved pipeline and many other upgrade programmes. We also completed a major upgrade of the Thistle platform drilling rig.

Our active drilling programme included what we believe are record drilling times in the northern North Sea - only 41 days for the S5 well at Don Southwest.

EnQuest's differentiated strategy

EnQuest is an exploitation company focusing on discovered reserves, late life assets and near field appraisal and exploration. EnQuest aims to deliver sustainable growth in shareholder value by focusing on exploiting our existing reserves, commercialising and developing discoveries, converting our contingent resources into reserves and pursuing selective acquisitions and opportunities in new licence rounds. With EnQuest's core technical capability and its financial strength, the Company is well placed to grow and to create a substantial development and production company with strong long term prospects.

The North Sea provides a significant opportunity that fits EnQuest's strategy, with its extensive existing infrastructure and its pool of skilled labour. Our integrated team approach with focus on subsurface and operations skills, allows us to be internally focused on execution. The results of this integrated team approach were exemplified by the excellence of EnQuest's drilling work, our execution of two pipeline projects in 2010 on time and ahead of budget and completion of the Thistle rig refurbishment programme.

Health, Safety and Environment ('HSE')

HSE is our first priority and is integral to how we manage our business, with regard to our people, our installations and the environment in which we operate.

I am pleased that Norman Thomson has joined us as Head of Health, Safety, Environment and Quality ('HSEQ') to manage and further develop our HSEQ systems, policies and procedures and to provide functional safety leadership to all of our Asset Managers. HSE is a critical part of EnQuest's values and is reflected in all of our operational and development decisions. Norman will help to bring further rigour to our performance and operational HSEQ measures, allowing a proactive continuous improvement approach in all of our assets and development projects. In 2010, we had a strong HSE record with an LTA rate of 0.21, and we put in place an HSE culture and HSE systems designed to maintain and improve on our current high standards.

Operational results ahead of expectations

As noted, EnQuest had a 55% increase in pro-forma production to 21,074 Boepd, which came ahead of our 18,000 Boepd target as initially set for the year. This outperformance came primarily from the Don and Thistle fields, where EnQuest had undertaken a programme of active investment.

On the Don fields, a threefold year-on-year growth in production was achieved, with an increase in daily average pro-forma net production from 3,358 Boepd in 2009 to 11,660 Boepd in 2010; in particular reflecting the positive contribution from the Don Southwest S5 and S6 production and injection wells. On Thistle, the newly refurbished rig carried out its first drilling in over 20 years, with the new well drilled under budget and in only 47 days. Approximately $70 million has been invested in an extensive upgrade of Thistle's drilling facilities, allowing us to lower drilling costs significantly and to tap smaller reserves. At our third hub, Heather, the 2010 work programme was focused on a major subsurface review and a drilling evaluation project. This has been completed and a rig upgrade programme will start this year.

A strong financial performance

Pro-forma profit before tax and net finance costs rose to $169.4 million, compared to $24.6 million in 2009. Pre-exceptionals pro-forma EBITDA was 196% up at $369.3 million.

EnQuest also had strong production driven reported cash flow from operations of $267.7 million. During the year, on a pro-forma basis, the Group realised average oil prices per barrel of $81.3, compared with $65.1 per barrel in 2009, reflecting the increases in market prices for Brent crude. The year end balance sheet was also strong, with a net cash balance of $41.4 million, after repayment of the $88.8 million of net debt arising from the Stratic acquisition and also $29.2 million of working capital due to Petrofac and Lundin. Our borrowing facility had no cash draw downs as at the end of 2010.

Pro-forma unit cost of sales for production and transportation costs were $30.4 per Boe in 2010, driven partly by one-off workover costs on the West Don W2 well and by the higher than anticipated costs imposed on EnQuest for the maintenance and operation of the Sullom Voe Terminal, the destination for the petroleum from all three of our hubs.

Pro-forma capital expenditure of $196.3 million was less than initially anticipated, partly due to the speed and efficiency of the drilling programme and also to the rephasing of some projects that will now be implemented in 2011. For example the Thistle rig started a programme of partial well abandonments in late 2010, prior to returning to drilling the North West Fault Block, which was consequently rephased into 2011.

An active and productive business development programme

Since announcing our intention to float, EnQuest's technical and financial capabilities have continued to strengthen as we have assessed a steady stream of potential opportunities.

Just a few weeks after flotation, EnQuest submitted bids as part of the 26^th licensing round, and in October 2010, we were pleased to be offered all of the licenses we had applied for. These new EnQuest licences complement and build on the strength of our existing portfolio in the North Sea. The new licences included; Ardmore, where studies are underway to assess its redevelopment potential, Pilot, which is a heavy oil discovery close to Elke, Gorse, which is a small exploration block adjacent to Heather, and Tryfan, an exploration block immediately south east of an existing EnQuest block (3/11a).

In August 2010, we announced our first acquisition since EnQuest's IPO, that of Stratic Energy Corporation ('Stratic'); this was subsequently completed in November 2010. This acquisition was in line with our strategy to deliver sustainable growth in shareholder value through the exploitation of existing reserves and pursuit of selective acquisitions. Stratic added 7.2 MMboe to our 2P reserves, enhanced our working interest in West Don from 27.7% to 44.95% and provided a 19% interest in the Crawford field. At the time of the announcement, the acquisition purchase price, adjusted for tax, equated to US$11.2 per barrel of 2P reserves.

In 2010, we also signed a farm-in agreement with the Kuwait Foreign Petroleum Exploration Corporation ('KUFPEC'), to join us in the Elke discovery. KUFPEC is a subsidiary of the Kuwait Petroleum Company and we believe this is KUFPEC's first upstream investment in Europe.

EnQuest's main focus in acquiring Stratic was its interests in the West Don field and the undeveloped Crawford field, but we recognised that a Stratic project in Slovenia also had some potential in its own right. Following the completion of the Stratic acquisition, we announced the disposal of our 48.75% working interest in the Petisovci project in Slovenia in return for a 22.5% equity stake in Ascent Resources PLC, the operator of the Petisovci project and the owner of an existing 26% working interest. This transaction, completed in February 2011, will enable EnQuest to crystallise such value as may be realised from this asset in the future.

Reserves growth sustaining EnQuest's future production growth

EnQuest seeks to maximise reserves generation from its existing assets and through developments and selective acquisitions. In 2010, we delivered increased reserves by both of these means.

Over the course of the year, we grew our year end net 2P reserves by 10%, this equates to a reserve replacement ratio of 208%. This increase in reserves replaced the 7.4 MMboe produced during the year and in addition also added approximately the same amount again. This robust growth was achieved partly through the Stratic acquisition, but we also delivered a net 8.2 MMboe through the exploitation of our existing assets.

EnQuest increased its acreage position from 16 to 26 licences in the UKCS. These opportunities alongside external ones form the basis for continued conversion of undeveloped and unappraised discoveries to producing assets.

Building a high performance organisation

The EnQuest vision and values have been defined and enthusiastically embraced by our staff. This has greatly helped us to swiftly create one highly focused organisation, from the two heritage companies and more recently also from the Stratic acquisition. Our vision centres around three key elements:

- to become the UK's leading independent oil and gas production and development company

- to become a technical leader in integrated development

- to maximise the potential from existing fields and undeveloped discoveries in the UKCS and beyond

Summary and outlook for 2011: Delivering growth

In summary, we are pleased to report that EnQuest has exceeded its growth targets for 2010. We delivered pro-forma net production of over 21,000 Boepd, with growth of 55% on the prior year and we generated pro-forma EBIDTA of $369.3 million, with strong reported net cash flow from operations of $112.8 million after adjusting for capital expenditure of $154.9 million. In 2010, we increased our year end net 2P reserves by 10% to 88.5 MMboe, with a reserve replacement ratio of 208%. We completed our first acquisition since our IPO, providing us with a meaningful increase in our 2P reserves and increasing our equity in the West Don field. We were also pleased to be offered all of the licences we sought in the 26^th licensing round. Our business development effort has provided opportunities for new stand-alone projects and the potential for additional hubs and we have increased the number of EnQuest's UK production licences from 16 to 26.

Building on the momentum of performance in 2010 and the continuous development of our assets, EnQuest is now targeting 26,500 Boepd average net production for 2011. This equates to a 26% increase above 2010, significantly increasing our cash flow. Our 26,500 Boepd target is underpinned by our active 2011 programme of eight wells. Following the early success in 2011 at Area E, the drilling programme will include five production wells, two on Don Southwest and three on Thistle. Our guidance for full year levels of capital expenditure is that we currently anticipate approximately $300 million of capex this year; $250 million on development drilling and facilities, $50 million on exploration and appraisal.

EnQuest was disappointed by the recent unexpected UK Budget decision to increase the supplementary charge levied on North Sea oil and gas production from 20% to 32%. The increase in tax rate clearly does not create a positive climate for additional investments in the UKCS and will render some small field investments uneconomic. Nonetheless, there remains significant potential in our development and production programme and EnQuest is confident of its ability to deliver not only its 2011 targets, but also its medium and longer term growth objectives from its UKCS production and further afield.

Through its resolute focus on execution and its creation of fresh opportunities, EnQuest has delivered against its targets in its first year. This performance and today's results give me more confidence than ever in our ability to deliver sustainable growth in shareholder value through the exploitation of existing reserves, development opportunities and selective acquisitions. We have grown not only our production and reserves levels, but also our staffing, our capacities and our differentiated capabilities. EnQuest is firmly on track with its ambitious plans to become a substantial exploitation company in the North Sea and beyond.

MANAGEMENT OF RISKS AND UNCERTAINTIES

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

· exploiting its hydrocarbon reserves

· commercialising and developing discoveries

· converting its contingent resources into reserves and

· pursuing selective acquisitions

In pursuit of this strategy, EnQuest has to face and manage a variety of risks. As a result, the Board has established a risk management framework, embedding the principles of effective risk management throughout the business.

Key business risks

The Group's principal risks could lead to a significant loss of reputation or could prevent the business from executing its strategy and creating value for shareholders. These risks, along with mitigating actions are set out below:

Risk

Mitigation

Health Safety and Environment (HSE)

Oil and gas development, production and exploration activities are complex and HSE risks cover many areas including operational safety, personal health and safety, compliance with regulatory requirements and potential environmental harm.

The Group maintains, in conjunction with its core contractors, a comprehensive programme of health, safety, environmental asset integrity and assurance activities and has implemented a continuous improvement programme, promoting a culture of transparency in relation to HSE matters.

In addition, the Group has a positive, transparent relationship with the UK Health and Safety Executive.

Production

The Group's production is critical to its success and is subject to a variety of risks including uncertain geology, operating in a difficult environment with mature equipment and potential for significant unexpected shutdowns and unplanned expenditure to occur.

The Group's programme of asset integrity and assurance activities provides leading data indicators of significant potential issues which may result in unplanned shutdowns or which may in other respects have the potential to undermine asset availability and uptime. The Group continually assesses the condition of its assets and operates extensive maintenance procedures designed to minimise the risk of unplanned shutdowns and expenditure. The Group monitors both leading and lagging key performance indicators in relation to its maintenance activities.

Lower than expected reservoir performance may have a material impact on the Group's results.

Life of asset production profiles are audited by independent reserves auditors. The Group also undertakes regular internal peer reviews.

The Group instigates pro-active operational interventions, when appropriate.

The Group's forecasts of production are risked to reflect appropriate production risks.

The Group's delivery infrastructure on the UKCS is dependent on the Sullom Voe Terminal

The Sullom Voe Terminal has a good safety record and its safety and operational performance levels are regularly monitored by the Group and other Terminal owners to ensure that operational integrity is maintained.

Reserve Replacement

Failure to develop its contingent and prospective resources or secure new licences and/or asset acquisitions and realise their expected value.

The Group puts a strong emphasis on subsurface analysis and employs industry leading professionals. The Group has recruited a significant number of employees during the year in a variety of technical positions which enables it to evaluate and subsequently implement the acquisition of new assets and licences. All analysis is subject to internal, and where appropriate, external peer review.

The Group allocates resource to manage its reputation with DECC, relative to continuous improvement in safety performance, environmental performance and ultimate recovery of hydrocarbon reserves, therefore enhancing its position to be successful in applying for UK licences.

In addition, the Group has secured appropriate bank facilities to fund new licence application and asset acquisitions.

The Group has post acquisition integration procedures which include implementation plans. These implementation plans are monitored on a regular basis to ensure the Group realises its anticipated value from acquisitions.

Human Resources

The Group's success is dependent upon its ability to attract and retain key personnel.

The Group monitors its employee value proposition to support the recruitment and retention of technically qualified personnel, used in identifying and executing its commercial and technical work. Specifically, the Group regularly monitors the employment market to provide remuneration packages, bonus plans and long-term share-based incentives plans targeted to incentivise performance and loyalty to the Group.

To enable the company to meet its growth aspirations, the Group is undertaking a number of resource initiatives in 2011 and beyond which will offer significant career development and progression opportunities for the current workforce: including senior management succession planning and talent management. There has already been a high level of recruitment activity; robust recruitment and selection strategies and processes are in place. EnQuest's experienced HR department will continue to seek to recruit in line with current workforce plans and forecasts.

The Group also maintains market competitive contracts with key suppliers to support the execution of work, where the necessary skills do not exist within the group's employee base.

In addition the Group allocates resources to develop strong, supportive joint-venture partner relationships.

Reputation

The reputational and commercial exposures to a major offshore incident are significant.

Operational activities are conducted in accordance with approved policies, standards and procedures. Interface agreements are agreed with all core contractors.

The Group undertakes regular audit activities to provide assurance on compliance with established policies, standards and procedures.

Financial

Inability to fund appraisal and development work programmes.

The Group has secured appropriate bank facilities to fund its development activities, this is due to be refinanced before 6 April 2012. This funding is supported by operating cash inflow from the Group's producing assets. The Group reviews its cashflow requirements on an ongoing basis to ensure it has suitable resources for its needs.

Oil Price

A material decline in oil and gas prices may adversely affect the Group's results of operations and financial condition.

The Group monitors oil price sensitivity relative to the core economics of its business. In 2010 the Board approved a policy to hedge up to 50% of annual forecast oil production. Approximately 40% of 2011 forecast oil production has been hedged using zero-premium collars.

In order to develop its resources, the Group needs to be able to fund substantial levels of investment. The Group will therefore regularly review and implement suitable policies to hedge against the possible negative funding impacts of changes in oil prices on revenues and profits.

Political and Fiscal

Changes in the regulatory or fiscal environment affecting the Group's ability to deliver its strategy.

It is difficult for the Group to predict the timing or severity of such changes. However, the Group does engage with government and other appropriate organisations, through Oil & Gas UK and other industry associations in order ensure the Group is kept abreast of expected potential changes and takes an active role in making appropriate representations.

At a more operational level, the Group has procedures to identify impending changes in relevant regulations to ensure legislative compliance.

Joint Venture Partners

Failure by joint venture parties to fund their obligations.

Dependence on other parties where the Group is not the operator.

The Group operates regular 'cash call' arrangements with its co-venturers to mitigate the Group's credit exposure at any one point in time and keeps in regular dialogue with each of these parties to ensure payment. Risk of default is mitigated by joint operating agreements allowing the Group to take over any defaulting party's share in an operated asset.

The Group maintains regular dialogue with its partners to ensure alignment of interests and to maximise the value of joint venture assets.

Competition

The Group operates in a competitive environment across many areas including the acquisition of oil and gas assets, the marketing of oil and gas, the provision of oil and gas services and access to human resources.

The Group has a strong balance sheet which puts it in a favourable position to be able to compete effectively and move quickly when looking to acquire assets.

The Group also has strong technical and business development capabilities to ensure it is well positioned to identify potential acquisition opportunities.

The Group has good relations with oil and gas service providers and constantly keeps the market under review.

Human resources are key to the Group's success and programs outlined above are in place to ensure it can attract and retain key personnel.

Business Review

OPERATING REVIEW

Overview

EnQuest delivered a robust operational performance in 2010; with a successful drilling programme, strong production results ahead of expectations and a good reserve replacement ratio.

EnQuest's assets include interests in six producing fields situated in the North of the UKCS: Broom, Heather, Thistle, Deveron, West Don and Don Southwest. These assets generated pro-forma daily average net production of 21,074 Boepd, an increase of 55% over the 13,613 Boepd produced in 2009.

Year end net 2P reserves increased by 10% from 80.5 MMboe at year end 2009 to 88.5 MMboe at year end 2010. This equates to a 2P reserve replacement ratio of 208%, as audited by a recognised 'Competent Person', in accordance with the definitions and guidelines set out under the 2007 Petroleum Resources Management System guidelines, approved by the Society of Petroleum Engineers.

Pro-forma capital expenditure during the year was $196.3 million, which included financing the drilling of five successful production and injection wells in three different fields, and also two exploration and appraisal wells, which were dry.

Keeping EnQuest's people safe and mitigating impacts on the environment in which it operates are always EnQuest's top priorities. EnQuest has well developed policies and processes, monitored at Board level that set continuously improving targets compared with acknowledged industry benchmarks. EnQuest has established a series of both leading and lagging indicators which are monitored at each Board meeting. A long established lagging indicator which EnQuest measures is the number of 'lost time accidents'. EnQuest is committed to working towards not having any such accidents, whilst the 0.21 LTA rate recorded by EnQuest and its leading contractors in 2010 is in the upper quartile of HSE performance in the industry.

Producing Oil Fields

Thistle and Deveron
Working interest 99% in both fields

No decommissioning liabilities: remain with former owners (apart from new incremental developments since acquisition)

Pro-forma daily average net production:

2010: 4,836 Boepd (2009: 3,849 Boepd)

Summary

In 2010 the first new well in over 20 years was drilled on Thistle. It was successfully completed and came into production as planned in November. This well made a contribution to the substantial increase in Thistle and Deveron's reserves.

2010 Highlights

It was an exciting year for the Thistle field with the first new well (SFB-P1) in 20 years successfully brought on-stream at 800 Boepd. Innovative use of proven technology reduced the complexity of the drilling approach, enabling the new well to be delivered under budget. This followed a previous investment programme of approximately $70 million to upgrade the capability and integrity of the Thistle drilling rig.

A successful partial abandonment programme was completed on four wells, on behalf of the former owners. Production recommenced from well A46 at 600 Boepd following a successful workover and jet pump installation. The connection of the Dons oil and gas pipelines into Thistle brought in owned fuel gas, helping to reduce reliance on third party supplies.

2011

In 2011, we plan to drill three further infill wells; NWFB, EFB-P1 and Dev-P1. Two water injection walkovers are also planned.

During 2010 work had continued on evaluating options to improve platform uptimes and this is expected to result in further investment in 2011 and over the next few years in power generation and control systems upgrades.

The Don Fields

Working interests:

Don Southwest, 60%

West Don, 27.7% at start of 2010, increasing to 44.95% in November 2010, through the acquisition of Stratic Energy Corporation

Decommissioning liabilities: as per working interests

Pro-forma daily average net production:

2010: 11,660 Boepd (2009: 3,358 Boepd)

Summary

Pro-forma production in 2010 of 11,660 Boepd was over three times the level produced in 2009. This was due to three new production wells, the commissioning of a successful water injection system, the installation of a pipeline connecting the Dons to the Thistle field and the start up of gas lift. Faster than expected delivery of the wells drilled on the Dons was a key feature of the 2010 performance.

2010 Highlights

The start of 2010 saw the Dons fields switch from a tanker offload system to pipeline export into the Brent system via a newly commissioned pipeline to Thistle. The tanker offload system had allowed early production, but was vulnerable to interruption by bad weather. Connection to Thistle delivered a step change in production efficiency and reduced the cost of oil export. The final commissioning of the water injection system was also completed in early 2010. The production wells on both fields responded well to pressure support. These two milestones successfully brought the project phase of the Don development to a close.

Don Southwest

The S2Z sidetrack well (Area 22) started production in March 2010. Water injection to Area 5 and Area 22 also commenced in March 2010. The S5 and S6 producer injector pair were drilled and brought on-stream in record time and ahead of budget. The reservoir properties at S5 proved to be better than prognosed, and the well came online with initial net production of over 13,000 Boepd. One dry exploration well was drilled in the Dons at Area H.

West Don

West Don also benefited from the commissioning of water injection. At West Don a workover was only partially successful and production well W2 remains temporarily suspended. The third West Don production well (W4) was brought on-stream for less than budget in late November 2010, at an initial net rate of around 12,000 Boepd.

2011

Early in 2011, we drilled a successful exploration well in Area E on Don Southwest and development plans for this new discovery (the Conrie field) are now being finalised. The Don Southwest Area 26 appraisal well was dry. Further drilling plans for Don Southwest in 2011 include a producer-injector pair (wells S8 and S9) in Area 6.

Heather and Broom

Working interests:

Heather, 100%

Broom, 55%

Decommissioning liabilities:

Heather, 37.5%

Broom, 55%

Pro-forma daily average net production:

2010: 4,579 Boepd (2009: 6,406 Boepd)

Summary

In 2010 the Broom pipeline improvement to Heather was completed on schedule and on budget. The dry North West Terrace exploration well at Broom proved that there was no potential for extension to the Western area of the Broom field. An extensive project to evaluate the remaining drilling potential of the Heather field was completed. This has resulted in the development of a plan to upgrade the drilling rig, with identification of nine well locations and drilling starting in mid 2012. The rig upgrade will start in Q2 2011.

2010 Highlights

Heather

No new drilling took place on Heather during the year. A planned shutdown in 2010 was extended to bring forward maintenance and integrity work, avoiding the need for a shutdown in 2011 and helping to provide continuity in production.

Broom

The BR7 NWT well produced disappointing results and the well was suspended. As expected, 2010 saw a decrease in production over 2009 levels, due to the failure of one of the Broom pipelines from corrosion in 2009. In 2010, a new pipeline was successfully installed and production returned to full capacity. Work was also completed at the BR-2 well to remove a restriction in the gas lift supply enabling the well to be restored to full production.

2011

Following the successful Heather subsurface review in 2010, the Heather rig will be upgraded in 2011 for a drilling programme starting in 2012. An exploration well will be drilled on the Ivy prospect, south of Heather, in 2011.

OPPORTUNITIES ON OTHER ENQUEST BLOCKS

Crawford (9/28a)

The acquisition of Stratic provided a 19% interest in the Crawford field where work is being undertaken with partners to prepare development plans.

UK North Sea 26^th licensing round

Shortly after flotation in April 2010, EnQuest applied for a number of blocks as part of the UK North Sea 26^th licensing round. In October 2010, EnQuest was offered all of the licences that it had applied for.

Ardmore (26^th round, 30/24b, 24c & 25c)

Working interest: 100%

The previously abandoned Ardmore field is being reviewed and options for further redevelopment are being analysed; Ardmore has the potential to be a stand-alone field redevelopment. Seismic surveys have been purchased and evaluated and an option on a Floating Production and Storage Offloading ('FPSO') vessel has already been secured.

Peik & Burdock (9/15a & 9/10b)

Working interests: 18% and 85% respectively.

Studies to evaluate the commercial viability of these blocks will continue during 2011. In the second half of 2010, a non-cash impairment amount of $35.0 million was charged against Peik & Burdock in the accounts; this project is highly dependent upon gas prices. It is therefore uncertain if the project will meet the economic thresholds required.

Elke & Pilot (28/3a) & (26^th round, 21/27a & 28/2a)

Working interest: 70% and 100% respectively.
In 2010, KUFPEC, a subsidiary of the Kuwait Petroleum Company, farmed-in to 30% of the Elke block. During 2010, studies took place to evaluate the potential of the existing heavy oil at Elke, these included an electromagnetic survey in August and this evaluation work is ongoing. The Pilot block offered to EnQuest as part of the 26^th licensing round is also a heavy oil discovery and its proximity to Elke may improve the economic potential of both blocks.

Scolty (21/8a)

Working interest: 40%

Following initial exploration work, this field was found to be uneconomic for EnQuest to develop ahead of other developments in the area, resulting in a non-cash impairment of $25.0 million in the first half of 2010. EnQuest continues to work on potential solutions with other licence holders in the area.

Business Review

FINANCIAL REVIEW

Economic environment

In the year ended 31 December 2010, the Brent crude oil price averaged US$79.5 per barrel, up some US$18 per barrel on the average for 2009, reflecting a gradual shift to greater stability in the global economy following a period of significant economic and financial turmoil. This improvement in the stability of the financial markets, supported by increased confidence in the need to grow world oil production, provided the platform for the Company's IPO in April 2010.

The Group's financial performance in 2010 reflects strong operational performance throughout the year, with revenue up by 93% on a pro-forma basis compared with 2009 reflecting higher production volumes, higher sales prices and the acquisition of Stratic in November 2010.

The Group enters 2011 with US$41.4 million net cash having repaid US$88.8 million of Stratic debt in November 2010; as well as strong ongoing operating cash flows from its existing portfolio of assets and a US$280.0 million bank facility, of which US$206.0 million is undrawn and available for development activities and acquisition opportunities.

Income Statement

Production and revenue

Production levels, on a working interest basis, for the pro-forma 12 months to 31 December 2010 averaged 21,074 Boepd, up 55% compared with 2009. The increase primarily reflects improved production from Don Southwest and West Don fields, which commenced first production in June 2009 and April 2009 respectively, and incremental production from West Don field as a result of the Stratic acquisition. Thistle field production also increased due to well A46 being brought back on-stream and sustained high levels of power system uptime. Saleable production was approximately 4% lower than the export meter production volumes quoted above primarily as a result of the partial decommissioning of the LPG processing plant during 2010, resulting in additional volume adjustments being applied by the Sullom Voe Terminal operator.

Realised oil prices, on a pro-forma basis for the 12 months to 31 December 2010, averaged US$81.3 per barrel compared with US$65.1 per barrel in 2009, reflecting the increase in market prices for Brent crude.

Operating costs

Cost of sales for the Group are as follows:

	Pro-forma* (pre-exceptionals and fair value adjustments)		Reported (pre-exceptionals and fair value adjustments)
	Year ended 31 December		Year ended 31 December
	2010	2009	2010	2009
	US$ million	US$ million	US$ million	US$ million

Cost of sales	406.4*	259.6*	384.5	193.1

	US$	US$	US$	US$
Unit operating cost, adjusted for over/under-lift and inventory movements (per Boe):
-Production and transportation costs	30.4*	34.8*	30.8	39.0
-Depletion of oil and gas properties	22.8*	18.7*	22.2	13.8
	53.2*	53.5*	53.0	52.8

The Group's pro-forma unit operating cost for the year is broadly consistent with the previous year, with a reduction of US$0.3 per Boe (0.6%).

The reduction in the Group's average pro-forma unit production and transportation cost of US$4.4 per Boe for the year ended 31 December 2010 compared with 2009, is primarily attributable to the increase in production volume from Don Southwest.

The increase of US$4.1 per Boe in the Group's average pro-forma depletion expense is also mainly due to the impact of the increase in Don Southwest production compared with the previous year as the Don fields carry a significantly higher depletion rate per barrel compared with the Heather, Thistle and Broom fields.

Well abandonment expenses of US$8.2 million have been reported in 2010 in relation to the partial decommissioning of the Thistle field wells A40/42 and A18/55. The wells were drilled prior to May 2002 and are therefore covered by the Intervening Period and Decommissioning Liability Agreements with the previous field owners. However, the previous owners did not approve the abandonment expense and EnQuest proceeded with performing partial decommissioning of these wells following an agreed programme to perform early partial decommissioning of four other Thistle wells in 2010. As EnQuest considered the safety and integrity of the A40/42 and A18/55 wells and the safety of its personnel and the platform essential, it performed partial decommissioning work on these wells, prioritising the work ahead of drilling further in-fill production wells. Since the previous owners did not approve the work under the Decommissioning Liability Agreement, EnQuest has therefore decided to provide for these expenses but will continue to consider its options to recover these funds from the previous owners.

The Group's reported change in lifting position expense was US$3.9 million for the year ended 31 December 2010, compared with a credit of US$4.6 million in 2009. The increase in expense of US$8.5 million has arisen primarily due to over-lifting of Thistle volumes at 31 December 2010, compared to under-lifting at 31 December 2009.

The reported hydrocarbon inventory movement credit of US$2.8 million in the year ended 31 December 2010 was mainly due to the increase in shipping co-ordinator deadstock resulting from increased production through-put volumes.

Reported general and administrative expenses excluding exceptional items were US$13.8 million in the year ended 31 December 2010 compared with US$0.1 million in the previous year. The expenses primarily relate to the Group's general management and business development expenses. Prior to the IPO, all significant general and administrative expenses incurred by LNS were directly chargeable to joint ventures.

Exceptional items

Exceptional costs totalling US$97.9 million (before tax) have been disclosed separately in the year ended 31 December 2010 relating to:

· non-cash impairment of US$35.0 million in relation to the Peik and Burdock discoveries due to latest development economics being below the Group's investment hurdle rates;

· non-cash impairment of US$25.0 million in relation to the Scolty discovery resulting from EnQuest's decision to discontinue field specific development;

· additional depletion costs of US$16.3 million resulting from the fair value uplift of PEDL's oil and gas assets on acquisition;

· demerger and listing expenses of US$8.0 million relating to the Group's formation and listing on the London Stock Exchange and the Stockholm NASDAQ OMX market;

· Stratic acquisition costs of US$5.3 million, including US$4.3 million of redundancy costs; and

· well abandonment expenses of US$8.2 million, outlined above.

Finance costs

Net finance costs reported of US$10.0 million include US$5.2 million unwinding of discount on decommissioning provisions and US$4.3 million of costs associated with the Group's revolving credit facility and letter of credit utilisation during the year.

Taxation

The reported tax charge for the year of US$28.7 million represents an effective rate of 51% compared with 27% in the previous year. The Group's effective tax rate in the year results from UK Corporation tax payable at the statutory rate of 50%, petroleum revenue tax ('PRT') on the Thistle field, ring fence expenditure supplement receivable and prior year adjustments. The Group's 2009 effective tax rate was significantly lower due to prior year PRT adjustments.

Earnings per share

The Group's reported basic earnings per share were US$0.040 for the year ended 31 December 2010 compared with US$0.019 in 2009. The increase of US$0.021 is attributable to the combined impact of an increase in production volumes and realised oil price in the year ended 31 December 2010 compared with the previous year.

Cash flow and liquidity

The Group's reported cash generated from operations in 2010 increased by US$207.8 million to US$267.7 million (2009: US$59.9 million), resulting mainly from the combination of higher average reported realised oil prices in 2010 compared with 2009 and the additional production volumes from Don Southwest and West Don fields following the acquisition of PEDL and Stratic.

Pro-forma* capital expenditure is set out in the table below:

	2010	2009
	US$ million	US$ million

Expenditure on producing oil and gas assets:
- Dons hub	70.8	207.2
- Thistle hub	41.5	39.6
- Heather and Broom hub	59.1	23.9

Exploration and evaluation expenditure	17.1	2.3
Other capital expenditure	7.8	0.3
	196.3	273.3

Significant projects were undertaken during the year, including:

· drilling and completing Don Southwest S5 and S6 development wells;

· new pipeline installed on Broom field;

· Don Southwest phase one drilling programme;

· West Don W4 production well drilling programme;

· Thistle Southern Fault Block sidetrack drilling and completion;

· Thistle electric submersible pump installation;

· long lead costs incurred in preparing for Don Southwest 2011 development drilling programme;

· Thistle and Heather platform structural upgrade programme;

· Don Southwest Area E exploration well top-hole drilling;

· unsuccessful Broom North West Terrace extension well; and

· unsuccessful Area H exploration well.

Net cash at 31 December 2010 amounted to US$41.4 million compared to net indebtedness of US$126.7 million in 2009. In April 2010, prior to the corporate restructure with EnQuest, the outstanding bank loan of LNS amounting to US$156.0 million was assigned to its then parent, Lundin Petroleum AB. The resulting liability between LNS and Lundin Petroleum AB, net of a long term loan payable to LNS, was capitalised on 31 March 2010.

On 17 March 2010, in anticipation of the corporate restructuring with LNS and the acquisition of PEDL, the Group established a two year US$280.0 million Revolving Credit Facility Agreement with the Bank of Scotland and BNP Paribas. In the half year results, the Group reported an intention to extend this facility by a further US$70.0 million in preparation for the acquisition of Stratic. However, as a result of strong operating cash inflows in the second half of the year, the Group determined that an extension to the facility was not required.

The net cash position at 31 December 2010, together with unutilised committed bank facilities, provides US$247.4 million of funding available to the Group for the 2011 capital development programme and future investment opportunities.

Capital restructuring and acquisitions

The combination of LNS with EnQuest was accounted for as a corporate restructuring under the pooling of interests method. The combination of PEDL with LNS has been accounted for using the acquisition method. Both transactions were satisfied by the allotment and issuance of Ordinary shares in the Company and resulted in a Group merger reserve of US$662.9 million at 31 December 2010.

On 8 November 2010, the Group announced completion of the Stratic acquisition through the allotment and issuance of Ordinary shares in the Company. The acquisition of Stratic enhanced the Group's proven and probable oil and gas reserves in the UKCS and consolidated its position in the West Don asset, providing a further 17.25% working interest in the asset.

Balance Sheet

As a result of the combination of LNS, EnQuest and PEDL described above, the Group's total asset value has increased by US$782.2 million to US$1,439.5 million at 31 December 2010 (2009: US$657.3 million).

Property, plant and equipment

Property, plant and equipment has increased to US$1,136.4 million at 31 December 2010 from US$518.6 million at 31 December 2009. The increase of US$617.8 million is mainly due to oil and gas assets net book value of US$631.2 million added on the acquisition of PEDL and Stratic, together with oil and gas asset additions of US$148.5 million, partially offset by depletion charges of US$177.2 million in the year.

Goodwill

Goodwill of US$100.1 million and US$1.8 million has been recorded in connection with the acquisition of PEDL and Stratic respectively. The goodwill and fair values recognised on the acquisitions are provisional due to the complexity of the acquisitions and due to the inherently uncertain nature of a number of critical accounting estimates. The review of the fair value of the assets and liabilities acquired will be completed within 12 months of each acquisition, and the goodwill valuation will then be finalised.

Intangible oil and gas assets

The Group's intangible oil and gas assets value has reduced by US$59.3 million to US$12.3 million at 31 December 2010 compared with US$71.6 million in 2009. The decrease is mainly due to impairment provisions and exploration write offs recorded of $80.9 million, of which US$57.9 million associated with the Peik, Burdock and Scolty discoveries have been classified as exceptional, and the reclassification of US$18.7 million to asset held for sale at the year end relating to the Petisovci asset. This is partially offset by intangible oil and gas assets of US$22.8 million added on the acquisition of Stratic and additions during the year of US$17.4 million.

Asset held for sale

In February 2011 the Group sold its interest in the Petisovci asset in return for 150,903,958 new Ordinary shares in Ascent Resources plc ('Ascent') and a nil cost option to receive a further 29,686,000 new Ordinary shares in Ascent subject to certain criteria related to the successful development of the Petisovci asset. Costs of US$18.7 million related to this asset, which were added on the acquisition of Stratic, are reported as asset held for sale at 31 December 2010.

Trade and other receivables

Trade and other receivables have increased by US$71.7 million to US$107.5 million at 31 December 2010. US$48.7 million of this increase relates to a rise in trade receivables for oil sales and tariff income due to the improved production volumes and realised oil price in December 2010 compared with December 2009, and US$18.8 million relates to an increase in joint venture receivables in relation to Don Southwest and West Don fields.

Cash and bank

The Group has a strong liquidity position at 31 December 2010, with US$41.4 million of cash and cash equivalents despite undertaking a significant capital expenditure programme, with US$196.3 million pro-forma spend in the year, and the repayment of US$88.8 million of Stratic debt shortly after the acquisition in November 2010.

Loans and borrowings

The Group's borrowings of US$156.0 million at 31 December 2009 were cleared in full in April 2010, prior to the corporate restructure with EnQuest, when the LNS loan was assigned to its then parent, Lundin Petroleum BV.

Provisions

The Group's decommissioning provision increased by US$87.2 million to US$140.1 million at 31 December 2010 (2009: US$52.9 million). The increase is due to the combined impact of the acquisition of PEDL and Stratic which added US$66.8 million of decommissioning provisions, additions of US$10.9 million during the year resulting from the Group's drilling programme, unwinding of the discount of US$5.2 million and US$4.3 million resulting from a change in decommissioning estimates during the year.

Trade and other payables

Trade and other payables have increased to US$116.9 million at 31 December 2010 from US$33.3 million at 31 December 2009. The increase of US$83.6 million is primarily due to an increase in accrued capital expenses of US$70.0 million compared with 2009 resulting from the Group's drilling and capital project programme which was ongoing at the end of 2010.

Financial risk management

The Group is exposed to the impact of changes in Brent crude oil prices on its revenue and profits. The Group did not hedge this risk in the years ending 31 December 2010 and 2009. However, during 2010 the Board approved a policy to hedge up to a maximum of 50% of annual oil production and in Q4 2010 the Group entered into four zero-premium oil price collars to partially hedge its exposure to fluctuations in the Brent oil price. The oil price collar hedges apply to approximately 4 million barrels of oil production in 2011 and have an average floor price of US$75 per barrel and an average cap of US$100 per barrel.

EnQuest's functional currency is US dollars. Foreign currency risk arises on purchases and the translation of assets and liabilities denominated in currencies other than US dollars. During the 12 months ended 31 December 2010 the Group's exposure has been managed by the sale of US dollars on a spot basis.

Cash balances can be invested in short-term bank deposits and AAA rated liquidity funds, subject to Board approved limits and with a view to minimising counter-party credit risks.

KEY PERFORMANCE INDICATORS

	2010	2009

Lost Time Accidents (days)	0.21	0.07

2P Reserves (MMboe)	88.51	80.50

Business performance pro-forma data*:
Production (Boepd) Revenue (US$ million)	21,074* 614.4*	13,613* 319.0*
Realised oil price per barrel (US$)	81.26*	65.14*
Opex per barrel (production and transportation costs) (US$)	30.4*	34.8*
Gross profit (US$ million)	208.0*	59.4*
Capex (US$ million)	196.3*	273.3*

Reported data:
Cash flow generated from operations (US$ million)	267.7	59.9
Net cash/(debt) (US$ million)	41.4	(126.7)
Profit before tax (US$ million) Basic earnings per share (US cents)	55.8 4.0	11.0 1.9

* In April 2010 the newly incorporated independent entity EnQuest PLC acquired the demerged UK North Sea assets of Petrofac Limited and Lundin Petroleum AB respectively. This transaction has been accounted for as a capital restructuring of EnQuest and the former Lundin business (Lundin North Sea BV, 'LNS') and an acquisition of the former Petrofac business (Petrofac Energy Developments Limited, 'PEDL'). Consequently the Group statement of comprehensive income, prepared in accordance with IFRS, includes the results of LNS from the start of the 2010 calendar year but only from 5 April 2010 for PEDL. For the comparative period to 31 December 2009, the reported statement of comprehensive income includes the results of LNS only. The results of EnQuest are included from its incorporation date of 29 January 2010. The pro-forma data in the above table presents the trading results for both LNS and PEDL from the start of the 2010 calendar year, as though PEDL was part of the Group for the full 12 months ended 31 December 2010. The comparative data for the year ended 31 December 2009 is presented on the same basis.

EnQuest PLC

ABRIDGED GROUP PRO-FORMA* INCOME STATEMENT

For the year ended 31 December 2010

	2010			2009
	Business performance	Exceptional items and depletion of fair value uplift	Total for period
	US$'000	US$'000	US$'000	US$'000
	Unaudited	Unaudited	Unaudited	Unaudited
Revenue	614,357	-	614,357	318,988
Cost of sales	(406,403)	(16,319)	(422,722)	(259,570)

Gross profit/(loss)	207,954	(16,319)	191,635	59,418
Exploration and evaluation expenses Impairment of oil and gas assets Well abandonment expenses	(22,987) - -	(57,870) (2,121) (8,194)	(80,857) (2,121) (8,194)	(6,149) - -
General and administration expenses	(17,126)	(13,432)	(30,558)	(11,427)
Other income/ (expenses), net	1,546	-	1,546	(17,217)

Profit/(loss) from operations before tax and finance income/(costs)	169,387	(97,936)	71,451	24,625

EBITDA**	369,342	(21,627)	347,715	124,778

* In April 2010 the newly incorporated independent entity EnQuest PLC acquired the demerged UK North Sea assets of Petrofac Limited and Lundin Petroleum AB respectively. This transaction has been accounted for as a capital restructuring of EnQuest and the former Lundin business (Lundin North Sea, 'LNS') and an acquisition of the former Petrofac business (Petrofac Energy Developments Limited, 'PEDL'). Consequently the group statement of comprehensive income, prepared in accordance with IFRS, includes the results of LNS from the start of the 2010 calendar year but only from 5 April 2010 for PEDL. For the comparative period to 31 December 2009, the reported statement of comprehensive income includes the results of LNS only. The results of EnQuest are included from its incorporation date of 29 January 2010.

This abridged pro-forma income statement presents the trading results for both LNS and PEDL from the start of the 2010 calendar year, as though PEDL was part of the group for the full year ended 31 December 2010. The comparative data for the year ended 31 December 2009 is presented on the same basis.

** EBITDA is calculated by taking the profit/(loss) from operations before tax and finance income/(costs) and adding back depletion, depreciation and impairment and write off of tangible and intangible oil and gas assets. EBITDA is not a measure of financial performance under IFRS.

EnQuest PLC

OIL AND GAS RESERVES AND RESOURCES

At 31 December 2010

	UKCS		Other Regions	Total
	MMboe	MMboe	MMboe	MMboe

Proven and Probable Reserves (notes 1,2, 3 & 7)

At 1 January 2010		80.50	-	80.50
Revisions of previous estimates		8.22	-	8.22
Acquisitions		7.20	-	7.20
Production:
Export meter	(7.69)
Volume adjustments:
Heather, Broom and Thistle (note 5)	0.10
Dons hub (note 6)	0.18
		(7.41)	-	(7.41)
Proven and Probable Reserves at 31 December 2010		88.51	-	88.51

Contingent Resources (notes 1, 2 & 4)

At 1 January 2010		72.72	-	72.72
Revisions of previous estimates		3.77		3.77
Acquisitions (note 10)		-	8.07	8.07
Additions - UK 26^th licensing round (note 8)		25.00	-	25.00
Disposals (note 9)		(4.50)	-	(4.50)

Contingent Resources at 31 December 2010		96.99	8.07	105.06

Notes:

(1) Reserves and resources are quoted on a pro-forma working interest basis for the 12 calendar months of 2010 as if the assets previously owned by Petrofac and Lundin Petroleum were owned by EnQuest throughout the period.

(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 and guidelines set out under the 2007 Petroleum Resources Management System guidelines approved 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 most likely technical case or '2C' basis.

(5) Attributable to partial decommissioning of the Sullom Voe Terminal ('SVT') LPG processing plant during the year, resulting in Heather, Broom and Thistle light ends components delivered to the terminal being reclassified, with the propane no longer forming part of the saleable production revenue stream. Some of this propane value is now recovered by a reduced contribution to terminal fuel and flare costs.

(6) Attributable to the change from offshore loading to direct export via SVT during the year. As described in note 5, following partial decommissioning of the SVT LPG processing plant in 2010, propane and butane volumes do not form part of the saleable production revenue stream. Instead, the surplus light ends recovered offshore will contribute to increased SVT oil production and terminal fuel and flare costs.

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

(8) The values presented includesome licences offered to the Group in October 2010 which had not legally commenced as at 31 December 2010.

(9) On 10 December 2010, the Group assigned 30% of its equity in the Elke P995, Block 28/3a licence to KUFPEC under a Sale and Purchase Agreement.

(10) On 11 February 2011 the Group sold its 48.75% interest in the Slovenian Petisovci project . The Group had acquired its interest in Petisovci through its acquisition of Stratic in November 2010 and contingent resources of 12.47 MMboe related to this asset were therefore excluded from the Group's contingent resources at 31 December 2010.

EnQuest PLC

GROUP STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2010

		2010			2009
	Notes	Business performance	Exceptional items and depletion of fair value uplift (note 4)	Reported in year
		US$'000	US$'000	US$'000	US$'000

Revenue	5(a)	583,468	-	583,468	234,017
Cost of sales	5(b)	(384,485)	(16,319)	(400,804)	(193,146)

Gross profit/(loss)		198,983	(16,319)	182,664	40,871
Exploration and evaluation expenses Impairment of oil and gas assets Well abandonment expenses	5(c)	(22,987) - -	(57,870) (2,121) (8,194)	(80,857) (2,121) (8,194)	(6,149) - -
General and administration expenses	5(d)	(13,770)	(13,432)	(27,202)	(135)
Other income	5(e)	7,024	-	7,024	3,932
Other expenses	5(f)	(5,526)	-	(5,526)	(21,885)

Profit/(loss) from operations before tax and finance income/(costs)		163,724	(97,936)	65,788	16,634
Finance costs	6	(11,187)	-	(11,187)	(6,444)
Finance income	6	1,174	-	1,174	827

Profit/(loss) before tax		153,711	(97,936)	55,775	11,017

Income tax	7	(78,647)	49,948	(28,699)	(3,025)

Profit/(loss) for the year attributable to owners of the parent		75,064	(47,988)	27,076	7,992

Other comprehensive income for the year, after tax:
Cash flow hedges				-	18,122

Total comprehensive income for the year, attributable to owners of the parent				27,076	26,114

Earnings Per Share	8			US$	US$
Basic				0.040	0.019
Diluted				0.040	0.019

The comparative statement of comprehensive income has been presented as a single column as there were no exceptional items or depletion of fair value uplifts reported in the year ended 31 December 2009.

The attached notes 1 to 26 form part of these Group financial statements.

EnQuest PLC

GROUP BALANCE SHEET

As at 31 December 2010

	Notes	2010	2009
ASSETS		US$'000	US$'000
Non-current assets
Property, plant and equipment	10	1,136,449	518,558
Goodwill	12	101,918	-
Intangible oil and gas assets	13	12,302	71,641
Asset held for sale	13	18,665	-
Loan receivable from related party	23	-	21,443
Deferred tax assets	7	8,871	156
		1,278,205	611,798

Current assets
Inventories	14	12,404	1,297
Trade and other receivables	15	107,543	35,782
Due from related parties	23	-	552
Cash and cash equivalents	16	41,395	7,893
		161,342	45,524
TOTAL ASSETS		1,439,547	657,322

EQUITY AND LIABILITIES
Equity
Share capital	17	113,174	32,164
Merger reserve		662,855	50,785
Other reserves		-	83
Share-based payment reserve		2,540	-
Retained earnings		104,327	77,168
TOTAL EQUITY		882,896	160, 200


Non-current liabilities
Loans and borrowings	19	-	156,000
Provisions	20	140,108	53,198
Deferred tax liabilities	7	292,021	252,483
		432,129	461,681

Current liabilities
Trade and other payables	21	116,916	33,326
Due to related parties	23	-	497
Income tax payable		7,606	1,618
		124,522	35,441

TOTAL LIABILITIES		556,651	497,122

TOTAL EQUITY AND LIABILITIES		1,439,547	657,322

The attached notes 1 to 26 form part of these Group financial statements.

EnQuest PLC

GROUP STATEMENT OF CHANGES IN EQUITY

For the year ended 31 December 2010

	Share capital	Merger reserve	Cash flow hedge reserve	Other reserves	Share-based payments reserve	Retained earnings	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000

At 1 January 2009	32,164	50,785	(18,122)	847	-	68,412	134,086

Profit for the year	-	-	-	-	-	7,992	7,992

Other comprehensive income for the year	-	-	18,122	-	-	-	18,122
Total comprehensive income for the year	-	-	18,122	-	-	7,992	26,114
Share option programme transfer to retained earnings	-	-	-	(764)	-	764	-

At 31 December 2009	32,164	50,785	-	83	-	77,168	160,200

Total comprehensive income for the year: profit for the year	-	-	-	-	-	27,076	27,076

Issue of Ordinary shares	80,480	486,850	-	-	-	-	567,330

Capital contribution on assignment of debt on de-merger	-	125,220	-	-	-	-	125,220
Issue of shares to Employee Benefit Trust	530	-	-	-	(530)	-	-
Share-based payment charge	-	-	-	-	3,070	-	3,070
Share option programme transfer to retained earnings	-	-	-	(83)	-	83	-

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

The attached notes 1 to 26 form part of these Group financial statements.

EnQuest PLC

GROUP STATEMENT OF CASH FLOWS

For the year ended 31 December 2010


	2010	2009
	US$'000	US$'000
CASH FLOW FROM OPERATING ACTIVITIES
Profit before tax	55,775	11,017
Depreciation	845	642
Depletion	177,185	51,778
Exploration costs written off	80,857	6,149
Impairment of oil and gas assets	2,121	-
Share-based payment charge	3,070	-
Long term incentive plan	717	608
Unwinding of discount on decommissioning provisions	5,196	2,916
Unrealised exchange losses	164	2,535
Net finance costs	4,817	2,272
Operating profit before working capital changes	330,747	77,917
Trade and other receivables	8,532	10,005
Due from related parties	552	(503)
Inventories	442	(174)
Trade and other payables	(72,038)	(24,860)
Due to related parties	(497)	(2,476)
Cash generated from operations	267,738	59,909
Long term incentive plan	(1,036)	(228)
Income taxes paid	(4,093)	(1,448)
Net cash flows from operating activities	262,609	58,233

INVESTING ACTIVITIES
Purchase of property, plant and equipment	(137,494)	(63,784)
Purchase of intangible oil and gas assets	(17,374)	(2,341)
Acquisition of subsidiaries - cash	21,556	-
Interest received	35	-
Net cash flows used in investing activities	(133,277)	(66,125)

FINANCING ACTIVITIES
Long-term receivables repaid	-	29,072
Repayment of loans and borrowings	(86,251)	(15,000)
Interest paid	(3,393)	(2,794)
Other finance costs paid	(5,030)	-
Net cash flows (used in) /generated from financing activities	(94,674)	11,278

NET INCREASE IN CASH AND CASH EQUIVALENTS	34,658	3,386
Net foreign exchange on cash and cash equivalents	(1,156)	981
Cash and cash equivalents at 1 January	7,893	3,526
CASH AND CASH EQUIVALENTS AT 31 DECEMBER	41,395	7,893

The attached notes 1 to 26 form part of these Group financial statements.

EnQuest PLC

NOTES TO THE GROUP FINANCIAL STATEMENTS

1 CORPORATE INFORMATION AND PRESENTATION OF FINANCIAL INFORMATION

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

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

The Company was incorporated on 29 January 2010 as a holding Company to effect a business combination between Lundin North Sea BV ('LNS') and Petrofac Energy Developments Limited ('PEDL').

On 5 April 2010 the Company acquired 100% of the voting shares of PEDL and on 6 April 2010 acquired 100% of the voting shares of LNS. Both acquisitions were satisfied by the allotment and issuance of Ordinary shares in the Company.

On 6 April 2010, following completion of the PEDL and LNS acquisitions, the Company was admitted to the Official List and to unconditional trading on the main market for listed securities of the London Stock Exchange. On 9 April 2010, the Company was admitted to unconditional trading on the Stockholm NASDAQ OMX market, as a secondary listing.

The Group's financial statements for the year ended 31 December 2010 were authorised for issue in accordance with a resolution of the Board of Directors on 4 April 2011.

A listing of the principal Group companies is contained in note 26 to these Group financial statements.

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

The statutory accounts for the year ended 31 December 2010 have been audited, and the report of the auditors on those accounts is unqualified and will be delivered to the Registrar of Companies in due course. The comparative figures for the financial year ended 31 December 2009 are the equivalent of the Company's statutory accounts for that financial year. Those accounts, which were prepared under IFRS, have been reported on by the Company's auditors and delivered to the registrar of companies. The auditors issued an unqualified opinion on those accounts.

Copies of the 2010 Annual Report and Accounts will be posted to shareholders in advance of the Annual General Meeting which is planned to take place on 25 May 2011. Further copies will be available from the Company's headquarters, from the date of posting or request via the Company's web-site at www.enquest.com.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of preparation

The Group financial information has been prepared in accordance with International Financial Reporting Standards ('IFRS') as adopted by the European Union as they apply to the financial statements of the Group for the year ended 31 December 2010 and applied in accordance with the Companies Act 2006. The accounting policies which follow set out those policies which apply in preparing the financial statements for the year ended 31 December 2010.

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

Going concern concept

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

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Group formation

The combination of LNS with EnQuest has been accounted for as a capital restructuring under the pooling of interests method. The combination of PEDL with LNS has been accounted for using the acquisition method, with LNS identified as the acquirer.

The approach adopted has a number of consequences including that:

· the Group's financial statements are prepared on the basis that EnQuest and LNS had always been combined, with the results of LNS being included for the year ended 31 December 2010 and EnQuest results being included from its incorporation date of 29 January 2010; comparative data for the statement of comprehensive income within these Group financial statements only relates to LNS as EnQuest was not incorporated in the comparative period;

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

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

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

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

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

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

Basis of consolidation

Subsidiaries

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

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

Unincorporated jointly controlled assets

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

Business combinations

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

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

New standards and interpretations

The Group has adopted new and revised IFRS that are relevant to its operations and effective for accounting periods beginning on or after 1 January 2010. The principal effects of the adoption of these new and amended standards and interpretations are discussed below:

IFRS 2 Share-based Payment (Revised)

The IASB issued an amendment to IFRS 2 that clarified the scope and the accounting for Group cash-settled share-based payment transactions. The Group adopted this amendment as of 1 January 2010, the amendment did not have any impact on the financial position or performance of the Group.

IFRS 3 Business Combinations (Revised) and IAS 27 Consolidated and Separate Financial Statements (Amended)

IFRS 3 (Revised) introduces significant changes in the accounting for business combinations occurring after 1 January 2010. Changes affect the valuation of non-controlling interests, the accounting for transaction costs, the initial recognition and subsequent measurement of a contingent consideration and business combinations achieved in stages. The Group adopted this revised standard as of 1 January 2010. Retrospective application has been applied to 2009 equity comparatives where appropriate, however there is no impact on the financial position or performance of the Group for the year ended 31 December 2009.

IAS 27 (Amended) is effective for annual periods beginning on or after 1 July 2009 and prescribes the accounting treatment in respect of a change in ownership interest in a subsidiary, allocation of losses incurred by a subsidiary between controlling and non-controlling interests and accounting for a loss of interest in a subsidiary. This may affect the Group where there is a change in ownership interest in any of its subsidiaries. The amendment did not have any impact on the financial position or performance of the Group for the year ended 31 December 2009.

Standards issued but not yet effective

Standards issued and relevant to the Group, but not yet effective up to the date of issuance of the Group's financial statements are listed below. This listing is of standards and interpretations issued, which the Group reasonably expects to be applicable at a future date. The Group intends to adopt those standards when they become effective.

IFRS 9 Financial Instruments: Classification and Measurement

IFRS 9 as issued reflects the first phase of the IASB's work on the replacement of IAS 39 and applies to classification and measurement of financial assets as defined in IAS 39. The standard is effective for annual periods beginning on or after 1 January 2013. In subsequent phases, the IASB will address classification and measurement of financial liabilities, hedge accounting and derecognition. The completion of this project is expected in mid 2011. The adoption of IFRS 9 will have an effect on the classification and measurement of the Group's financial assets. However, the Group determined that the effect shall be quantified in conjunction with the other phases when issued to present a comprehensive picture.

Improvements to IFRS's (Issued in May 2010)

The IASB issued improvements to IFRS, an omnibus of amendments to its IFRS standards. The amendments have not been adopted as they become effective for annual periods on or after either 1 July 2010 or 1 January 2011. The Group does not expect that adoption of the amendments will have any impact on its financial position or performance.

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Critical accounting estimates and judgements

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

Estimates in oil and gas reserves

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

Estimates in impairment of assets (excluding goodwill)

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

Decommissioning provision

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

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

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

Estimates in impairment of goodwill

Determination of whether goodwill has suffered any impairment requires an estimation of the value in use of the cash-generating units ('CGU') to which goodwill has been allocated. The present value calculation requires the entity to estimate the future cash flows expected to arise from the CGU and a suitable discount rate. In calculating the present value in use of the CGU, the Group has applied an oil price assumption of US$85 per barrel, escalated at 2% per annum and discounted at a pre-tax rate of 19%.

Taxation

The UK's Corporation tax legislation is relatively complex. The Group's operations are subject to a number of specific rules which apply to UK North Sea exploration and production. In addition, the tax provision is prepared before the relevant companies have filed their UK Corporation tax and supplementary charge returns with HMRC and significantly, before these have been agreed. As a result of these factors the tax provision process necessarily involves the use of a number of estimates and judgements.

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

Foreign currencies

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

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

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Foreign currencies (continued)

assets and liabilities measured at fair value in a foreign currency are translated using the rate of exchange at the date the fair value was determined. All foreign exchange gains and losses are taken to the statement of comprehensive income.

Classification and recognition of assets and liabilities

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

Property, plant and equipment

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

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

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

Office furniture and equipment 25% - 100%

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

No depreciation is charged on land or assets under construction.

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

Capitalised costs

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

Intangible oil and gas assets

Expenditure directly associated with evaluation or appraisal activities is capitalised as an intangible asset. Such costs include the costs of acquiring an interest, appraisal well drilling costs, payments to contractors and an appropriate share of directly attributable overheads incurred during the evaluation phase. For such appraisal activity, which may require drilling of further wells, costs continue to be carried as an asset whilst related hydrocarbons are considered capable of commercial development. Such costs are subject to technical, commercial and management review to confirm the continued intent to develop, or otherwise extract value. When this is no longer the case, the costs are written-off in the statement of comprehensive income. When such assets are declared part of a commercial development, related costs are transferred to property, plant and equipment oil and gas assets. All intangible oil and gas assets are assessed for any impairment prior to transfer and any impairment loss is recognised in the statement of comprehensive income.

Oil and gas assets

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

Changes in unit-of-production factors

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

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Property, plant and equipment (continued)

Borrowing costs

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

Impairment of assets (excluding goodwill)

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

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

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

Goodwill

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

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

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

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

Derivatives

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

The Group categorises derivatives as follows:

Fair value hedge

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

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Cash flow hedge

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

Net investment hedge

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

Derivatives that do not qualify for hedge accounting

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

Trade receivables

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

Inventories

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

Under/over-lift

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

Cash and cash equivalents

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

Equity

Share capital

The balance classified as equity share capital includes the total net proceeds (both nominal value and share premium) on issue of registered share capital of the Parent Company.

The pooling of EnQuest and LNS on 6 April 2010 has resulted in the share capital of LNS being retrospectively adjusted to reflect the capital structure of EnQuest as of the beginning of the earliest comparative period presented. Share issue costs associated with the issuance of new equity are treated as a direct reduction of proceeds.

Merger reserve

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

Cash flow hedge reserve

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

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Equity (continued)

Share-based payments reserve

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

Retained earnings

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

Employee benefit trust

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

Provisions

Decommissioning

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

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

Other

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

Derecognition of financial assets and liabilities

Financial assets

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

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

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

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

Financial liabilities

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

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

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Interest-bearing loans and borrowings

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

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

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

Revenue

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

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

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

Exceptional items

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

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

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

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

Leases

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

Employee benefits

Short- term employee benefits

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

Pension obligations

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

2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Share-based payment transactions

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

Equity-settled transactions

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

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

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

Taxes

Income taxes

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

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

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries

and interests in joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

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

Production taxes

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

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

3 SEGMENT INFORMATION

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

All revenue is generated from sales to customers in the United Kingdom. Details of the Group's revenue components are provided in note 5(a). All crude oil revenue is received from one major customer and amounted to US$570,518,000 or 98% of total revenue in the year ended 31 December 2010 (2009: US$226,325,000 or 97% of total revenue).

4 EXCEPTIONAL ITEMS AND DEPLETION OF FAIR VALUE UPLIFT

	2010	2009
	US$'000	US$'000
Recognised in arriving at profit from operations before tax and finance income/ (costs):
Initial Public Offering and acquisition costs	8,143	-
Costs relating to the acquisition of Stratic	5,289	-
Impairment expenses	59,991	-
Well abandonment expenses	8,194	-
	81,617	-
Depletion of fair value uplift	16,319	-
	97,936	-

Initial Public Offering and acquisition costs

Expenses relating to the acquisition of LNS and PEDL and the Company's listing on the London Stock Exchange and Stockholm NASDAQ OMX market of US$8,143,000 (2009: nil) are included in general and administrative expenses in the statement of comprehensive income.

Costs relating to the acquisition of Stratic

Costs of US$5,289,000 (2009: nil) relating to the acquisition of Stratic Energy Corporation ('Stratic') are included in general and administrative expenses in the statement of comprehensive income.

Impairment expenses

Expenses relating to the impairment of Scolty and Peik area assets were recognised in the year (2009: nil). The impairment expense comprises US$25,034,000 relating to Scolty and US$34,957,000 relating to the Peik area, of which US$2,121,000 relates to property, plant and equipment oil and gas assets (note 10) and US$32,836,000 relates to intangible oil and gas assets (note 13).

Well abandonment expenses

Expenses of US$8,194,000 (2009: nil) relating to partial decommissioning of two wells covered by the Intervening Period and Decommissioning Liability Agreements have been recognised due to doubt over recoverability from the previous field owners arising from differences in the commercial interpretation of the Agreements.

Depletion of fair value uplift

Additional depletion charges arising from the fair value uplift of PEDL's oil and gas assets on acquisition of US$16,319,000 (2009: nil) are included within cost of sales in the statement of comprehensive income.

Tax has been included on exceptional items and depletion of fair value uplifts estimated at the Group's effective tax rate of 51%.

5 REVENUES AND EXPENSES

(a) Revenue

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000
Revenue from crude oil sales	570,518	226,325
Revenue from condensate sales	1,695	1,786
Tariff revenue	11,255	5,305
Other operating revenue	-	601
	583,468	234,017

(b) Cost of sales

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000

Cost of operations	180,903	130,615
Tariff and transportation expenses	41,661	15,411
Change in lifting position	3,864	(4,593)
Inventory movement - hydrocarbons	(2,809)	(65)
Depletion of oil and gas assets (note 10)	177,185	51,778
	400,804	193,146

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000

Unsuccessful exploration expenditure written off (note 13)	13,608	-
Impairment charge (note 13)	67,249	6,149
	80,857	6,149

(d) General and administration expenses

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000

Staff costs (note 5(g))	31,788	7,157
Depreciation (note 10)	845	642
Other general and administration costs	17,280	6,181
Recharge of costs to operations and joint venture partners	(22,711)	(13,845)
	27,202	135

5 REVENUES AND EXPENSES (continued)

(e) Other income

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000

Foreign exchange gains	4,838	3,932
Other income	2,186	-
	7,024	3,932

(f) Other expenses

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000

Foreign exchange losses	5,526	21,454
Other expenses	-	431
	5,526	21,885

(g) Staff costs

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000

Total staff costs:
Wages and salaries	12,823	5,145
Social security costs	3,177	637
Defined contribution pension costs	841	358
Expense of share-based payments (note 18)	3,070	-
Long-term incentive plan costs (note 18)	717	608
Other staff costs	651	409
Contractor costs	6,174	-
Redundancy costs	4,335	-
	31,788	7,157

Redundancy costs of US$4,335,000 were incurred by the Group in the year ended 31 December 2010 (2009: nil) as a result of the Stratic acquisition. These costs are included in 'costs relating to the acquisition of Stratic' which are reported as an exceptional item (note 4).

The average number of persons employed by the Group during the year was 60 (2009: 34).

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

5 REVENUES AND EXPENSES (continued)

(h) Auditors' remuneration

The following amounts were payable by the Group to its auditors during the year.

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000
Ernst & Young LLP:

Audit of the Group financial statements	141	-
Local statutory audits of subsidiaries	228	-
Tax services	80	-
Other services pursuant to legislation	63	-
Corporate finance services (i)	651	-
	1,163	-
PricewaterhouseCoopers LLP:

Audit of the Group financial statements	-	124
Tax services	9	-
Other services pursuant to legislation	13	-
Corporate finance services (i)	70	-
	92	124

(i) Corporate finance services relate to the IPO and are included in the Initial Public Offering and acquisition costs of $8,144,000 which are presented as an exceptional item (note 4).

6 FINANCE INCOME/ COSTS

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000

Finance costs:
Loan interest payable	1,693	3,099
Unwinding of discount on decommissioning provisions (note 20)	5,196	2,916
Other financial expenses	4,298	429
	11,187	6,444
Finance income:
Bank interest receivable	939	31
Other interest receivable Other financial income	- 235	796 -
	1,174	827

7 INCOME TAX

(a) Income tax

The major components of income tax expense are as follows:

	Year ended 31 December	Year ended 31 December
	2010	2009
Group statement of comprehensive income	US$'000	US$'000
Current income tax
Current income tax charge	4,344	8,916
Adjustments in respect of current income tax of previous years	(2,121)	(943)

Deferred income tax
Relating to origination and reversal of temporary differences	25,899	(4,948)
Adjustments in respect of deferred income tax of previous years	577	-
Income tax expense reported in statement of comprehensive income	28,699	3,025

(b) Reconciliation of total income tax charge

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

	Year ended 31 December	Year ended 31 December
	2010	2009
	US$'000	US$'000
Profit before tax	55,775	11,017

Statutory rate of Corporation tax in the UK of 50% (2009: 50%) Supplementary Corporation tax non-deductible expenditure	27,888 1,364	5,509 1,726
Non-deductible expenditure	3,682	-
Petroleum revenue tax (net of income tax benefit)	3,241	(3,140)
Ring fence expenditure supplement Tax in respect of non-ring fence trade	(6,093) 971	- (140)
Adjustments in respect of prior years	(1,544)	(943)
Overseas tax	(810)	13
At the effective income tax rate of 51% (2009: 27%)	28,699	3,025

7 INCOME TAX (continued)

Deferred income tax relates to the following:

	Group balance sheet		Group statement of comprehensive income
	2010	2009	2010	2009
	US$'000	US$'000	US$'000	US$'000
Deferred tax liability
Accelerated capital allowances	554,307	355,604	(33,290)	17,291
Other temporary differences	10,474	582	2,334	(6,586)
	564,781	356,186

Deferred tax asset
Losses	(207,100)	(77,391)	69,525	(12,502)
Decommissioning liability	(70,054)	(26,468)	(12,093)	(3,151)
Other temporary differences	(4,477)	-
	(281,631)	(103,859)


Deferred tax (expense)/income			26,476	(4,948)
Deferred tax liabilities, net	283,150	252,327

Reflected in balance sheet as follows:
Deferred tax assets	(8,871)	(156)
Deferred tax liabilities	292,021	252,483
Deferred tax liabilities, net	283,150	252,327

(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.

Deferred tax assets of US$5,149,000 (2009: nil) were recognised in 2010 on the acquisition of Stratic (note 11) in relation to unutilised tax losses. The tax losses relate to UK trading losses arising in Stratic Energy UK Limited prior to 2010, recoverability of which is dependent on future taxable trading profits in excess of those arising from the reversal of deferred tax liabilities in that company. It is anticipated that Stratic Energy UK Limited will generate taxable trading profits in the future in excess of the losses carried forward, and this company had taxable trading profits in 2010.

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. The denominators for the purposes of calculating both basic and diluted earnings per share for each period have been adjusted to reflect the capital restructure in accordance with IAS 33, 'Earnings per Share' (note 2).

8 EARNINGS PER SHARE (continued)

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
	2010	2009	2010	2009	2010	2009
	US$'000	US$'000	Million	Million	US$	US$

Basic	27,076	7,992	686.8	422.4	0.040	0.019
Dilutive potential of Ordinary shares granted under share-based incentive schemes	-	-	5.6	-	-	-
Adjusted	27,076	7,992	692.4	422.4	0.040	0.019

9 DIVIDENDS PAID AND PROPOSED

The Company paid no dividends during the year ended 31 December 2010 (2009: nil).

10 PROPERTY, PLANT AND EQUIPMENT

	Oil and gas	Office furniture	Total
	assets	and equipment
	US$'000	US$'000	US$'000
Cost:
At 1 January 2009	769,016	4,387	773,403
Additions	63,525	259	63,784
Change in decommissioning provision	3,385	-	3,385
At 31 December 2009	835,926	4,646	840,572
Additions Change in decommissioning provision Acquisition of subsidiaries	148,492 15,172 631,211	2,366 - 801	150,858 15,172 632,012
At 31 December 2010	1,630,801	7,813	1,638,614

Depletion and depreciation:
At 1 January 2009	266,905	2,689	269,594
Charge for the year	51,778	642	52,420
At 31 December 2009	318,683	3,331	322,014
Impairment charge for the year	2,121	-	2,121
Charge for the year	177,185	845	178,030
At 31 December 2010	497,989	4,176	502,165


Net carrying amounts:

At 31 December 2010	1,132,812	3,637	1,136,449

At 31 December 2009	517,243	1,315	518,558

At 1 January 2009	502,111	1,698	503,809

10 PROPERTY, PLANT AND EQUIPMENT (continued)

No interest has been capitalised within oil and gas assets during the year (2009: nil).

The net book value at 31 December 2010 includes US$5,344,000 (2009: US$2,005,000), of pre-development assets and development assets under construction which are not being depreciated.

During the year ended 31 December 2010, capitalised pre-development costs of US$2,121,000 (2009: nil) and intangible asset licence costs of US$32,836,000 (2009: nil) (note 13) associated with the Peik area were written off based on the Group's latest economic evaluation of the asset which did not support the delivery of an economic development.

11 BUSINESS COMBINATIONS

Acquisition of Stratic

On 5 November 2010, the Company acquired 100% of the issued share capital of Stratic, an oil and gas Company operating principally in the United Kingdom. The acquisition was satisfied by the issue and allotment of 24,434,983 EnQuest Ordinary shares (note 17).

The acquisition of Stratic enhanced the Group's proven and probable oil and gas reserves in the UKCS and also consolidated its position in the West Don asset, providing a further 17.25% working interest in the asset.

The provisional fair values of the identifiable assets and liabilities of Stratic, as at the date of the acquisition, are analysed below:

		Provisional fair value recognised on acquisition
		US$'000

Assets
Property, plant and equipment		131,486
Intangible oil and gas assets		22,809
Deferred tax assets		5,149
Inventories		2,215
Trade receivables		55
Other receivables and prepayments		4,506
Cash		5,421
		171,641

Liabilities
Provision - decommissioning		(10,840)
Loans and borrowings		(87,969)
Trade and other payables		(9,793)
Accrued expenses		(10,692)
		(119,294)

Total identifiable net assets at fair value		52,347

Goodwill arising on acquisition		1,816

Consideration		54,163

Purchase consideration transferred:
24,434,983 Ordinary £0.05 EnQuest shares		54,163

11 BUSINESS COMBINATIONS (continued)

Acquisition of Stratic (continued)

The fair values are provisional due to the complexity of the acquisition and due to the inherently uncertain nature of a number of the critical accounting estimates. The review of the fair value of the assets and liabilities acquired will be completed within 12 months of the acquisition.

From the date of acquisition, Stratic has contributed US$6,511,000 to revenue and US$70,000 to the net profit before tax of the Group. If the above combination had taken place at the beginning of 2010, net profit of the Group would have been US$28,767,000 and revenue would have been US$608,210,000.

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

Business combination expenses of US$5,289,000 relating to the above transaction have been expensed in the year (2009: nil).

LNS capital restructuring

On 6 April 2010, EnQuest acquired 100% of the voting rights of LNS, an oil and gas exploration and production Company operating in the UK Continental Shelf. The acquisition was satisfied by the issue and allotment of EnQuest Ordinary shares (note 17). For financial reporting purposes, the combination of LNS with EnQuest has been accounted for as a capital restructuring under the pooling of interests method.

On 6 June 2010, LNS changed its name to EnQuest North Sea BV.

Acquisition of PEDL

On 5 April 2010, EnQuest acquired 100% of the voting shares of PEDL, an oil and gas development and production Company operating in the UK Continental Shelf. The acquisition, which was satisfied by the issue and allotment of EnQuest Ordinary shares (note 17), has been accounted for using the acquisition method. The Group financial statements include the results of PEDL for the period from its acquisition date.

11 BUSINESS COMBINATIONS (continued)

Acquisition of PEDL (continued)

The provisional fair value of the identifiable assets and liabilities of PEDL as at the acquisition date was:

		Provisional fair value recognised on acquisition
		US$'000

Assets
Property, plant and equipment		500,526
Deferred income tax asset		27,310
Inventories		9,335
Trade receivables		4,884
Joint venture receivables		51,678
Other receivables and prepayments		20,051
Cash		16,135
		629,919

Liabilities
Provision - decommissioning		(55,966)
Deferred tax liabilities		(37,665)
Trade and other payables		(94,183)
Accrued expenses		(29,040)
		(216,854)

Total identifiable net assets at fair value		413,065

Goodwill arising on acquisition		100,102

Purchase consideration transferred, comprising 345,629,616 Ordinary £0.05 EnQuest shares		513,167

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

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

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

On 6 May 2010 PEDL changed its name to EnQuest Dons Limited.

Business combination expenses of US$1,733,000 relating to the above transaction have been expensed in the period (2009: nil).

12 GOODWILL

A summary of the movement in goodwill is presented below:

	2010	2009
	US$'000	US$'000

At 1 January	-	-

Acquisitions during the year (note 11):
Petrofac Energy Developments Limited	100,102	-
Stratic Energy Corporation	1,816	-

At 31 December	101,918	-

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

Impairment testing of goodwill

The Group performed its annual impairment test in the fourth quarter of 2010. In assessing whether goodwill has been impaired, the carrying amount of the CGU, including goodwill, is compared with its recoverable amount.

The recoverable amount of the CGU has been determined on a value in use basis using a discounted cash flow model comprising asset-by-asset life of field projections. The discount rate used is derived from the Group's post-tax weighted average cost of capital. 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 management's assessment of oil price using publicly available forecast commodity prices. For the purposes of calculating value in use, management has applied an oil price assumption of US$85 per barrel, escalated at 2% per annum.

Production volumes are based on life of field production profiles for each asset within the CGU. The production volumes used in the value in use calculations are supported 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 in to account both debt and equity. The cost of equity is derived from the expected return on investment by the Group's investors. The cost of debt is based on its interest-bearing borrowings. Segment risk is incorporated by applying a beta factor based on publicly available market data. The discount rate applied to the Group's pre-tax cash flow projections is 19% (2009: n/a).

12 GOODWILL (continued)

Sensitivity to changes in assumptions

There are reasonably possible changes in key assumptions which could erode the estimated amount of US$640,000,000 by which the calculated value in use exceeds the carrying value of the CGU. These are discussed below:

· oil price: management has considered the possibility of lower oil prices in the future. Revenue for the Group's future oil production is directly linked to the market price of Brent blend oil. A fall in the price for Brent blend production 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 in the order of US$65 per barrel, escalated at 2% per annum.

· production volumes: estimated production volumes are based on detailed data for the Group's portfolio of assets taking in to account asset-by-asset development plans agreed by management as part of the planning process. It is estimated that production would need to fall by 24% across all assets for the whole of the next 19 years to cause the recoverable amount to fall below the carrying amount of the CGU.

13 INTANGIBLE OIL AND GAS ASSETS

		US$'000
Cost
At 1 January 2009		100,573
Additions		2,341
At 31 December 2009		102,914
Additions		17,374
Acquisition of subsidiaries		22,809
Unsuccessful exploration expenditure written off		(13,608)
Reclassified to asset held for sale		(18,665)
At 31 December 2010		110,824

Provision for impairment
At 1 January 2009		(25,124)
Impairment charge for the year		(6,149)
At 31 December 2009		(31,273)
Impairment charge for the year		(67,249)
At 31 December 2010		(98,522)

Net carrying amount:

At 31 December 2010		12,302

At 31 December 2009		71,641

At 1 January 2009		75,449

During the year ended 31 December 2010, capitalised intangible asset licence costs of US$32,836,000 (2009: nil) and pre-development costs of US$2,121,000 (2009: nil) (note 10), associated with the Peik area were impaired based on the Group's initial economic evaluation of the asset which did not support the delivery of an economic development.

Also, during the year ended 31 December 2010, following a decision taken to discontinue field specific exploration activities on certain licences, US$48,021,000 of capitalised evaluation costs were impaired and written off (2009: US$6,149,000), including US$25,034,000 in relation to the Scolty area.

At 31 December 2010, US$18,665,000 of costs associated with the Petisovci asset (2009: nil) were reclassified to asset held for sale following the announcement that this asset was to be sold in early 2011 (note 25).

14 INVENTORIES

	2010	2009
	US$'000	US$'000

Crude oil	12,404	1,297

15 TRADE AND OTHER RECEIVABLES

	2010	2009
	US$'000	US$'000

Trade receivables	77,203	28,473
Joint venture receivables	18,768	-
Other receivables	3,865	5,546
	99,836	34,019
Prepayments and accrued income	7,707	1,763
	107,543	35,782

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 2010 no impairment provision for trade receivables was necessary (2009: nil).

Joint venture receivables relate to billings to joint venture partners and were not impaired. One joint venture receivable of US$547,000 was past due at 31 December 2010 (2009: nil) but was not impaired.

As at 31 December 2010 other receivables of US$8,194,000 (2009: nil) were determined to be impaired due to doubt over recoverability of well abandonment expenses from previous field owners incurred under Intervening Period and Decommissioning Liability Agreements (note 4).

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

16 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.

17 SHARE CAPITAL

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

	2010	2009
	US$'000	US$'000
Authorised ,issued and fully paid
799,462,905 Ordinary shares of £0.05 each (31 December 2009: 422,436,246 Ordinary shares of £0.05 each)	60,990	32,164
Share premium	52,184	-
	113,174	32,164

The comparative figure for the share capital at 31 December 2009 is adjusted to reflect the restructuring of EnQuest and LNS under the pooling of interests method (note 2).

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

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

17 ISSUED SHARE CAPITAL (continued)

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

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

On 7 April 2010, 6,962,020 Ordinary shares of £0.05 each were issued and allotted to the Company's Employee Benefit Trust to satisfy awards to be made under the Company's share-based incentive schemes.

On 8 November 2010, a further 24,434,983 Ordinary shares of £0.05 each were issued and allotted to the shareholders of Stratic in consideration for the transfer of Stratic's voting shares to the Company. Following this transaction, and at 31 December 2010, the Company had an issued share capital of 799,462,905 Ordinary shares of £0.05 each.

18 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 Performance Share Plan, a Deferred Bonus Share Plan and a Restricted Share Plan. No awards under the Performance Share Plan were granted to employees in 2010.

Deferred Bonus Share Plan (DBSP)

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

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

Weighted average fair value per share

Trued up vesting rate

2010 awards

2009 awards

101p

n/a

98%

n/a

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

2010

Number*

2009

Number*

Outstanding at 1 January

Granted during the year

Vested during the year

Forfeited during the year

390,730

Outstanding at 31 December

390,730

* Includes invested and matching shares.

18 SHARE-BASED PAYMENT PLANS (continued)

Deferred Bonus Share Plan (DBSP) (continued)

The charge recognised in the 2010 statement of comprehensive income in relation to matching share awards amounted to US$72,000 (2009: nil).

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 under the RSP will vest over periods between one and five 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

2010 awards

2009 awards

104p

n/a

98%

n/a

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

2010

Number

2009

Number

Outstanding at 1 January

Granted during the year

Vested during the year

Forfeited during the year

7,926,411

Outstanding at 31 December

7,926,411

The charge recognised in the year ended 31 December 2010 amounted to US$2,997,000 (2009: nil).

The Company has recognised a total charge of US$3,070,000 (2009: nil) in the statement of comprehensive income during the year, relating to the above employee share-based schemes.

Long-Term Incentive Plan scheme (LTIP)

Prior to the formation of EnQuest PLC, LNS participated in the Lundin Petroleum Group LTIP scheme which consisted of an annual grant of units that converted into cash payment at vesting. The cash payment was determined at the end of each vesting period by multiplying the number of units by the share price. The LTIP had a three year duration whereby the initial grant of units vested equally in three tranches; one third after two years and the final third after three years. The demerger of LNS from the Lundin Petroleum Group resulted in all LTIP awards vesting due to the change in control, resulting in total costs of US$717,000 for the year ended 31 December 2010 (2009: US$608,000).

18 SHARE-BASED PAYMENT PLANS (continued)

Share Option Programme

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

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

	2010	2010	2009	2009
	Average weighted exercise price	Number of shares	Average weighted exercise price	Number of shares
	SEK per share		SEK per share


At 1 January	78.05	118,250	89.85	534,250
Granted	-	-	-	-
Exercised	-	-	-	-
Lapsed	78.05	(118,250)	89.36	(416,000)
At 31 December	-	-	78.05	118,250

19 LOANS AND BORROWINGS

The Group had the following loans and borrowings outstanding:

	Effective interest rate	Maturity	2010	2009
	(%)		US$'000	US$'000
Non-current
Term loan (ii)	US LIBOR + 0.9%	2014	-	156,000

(i) Revolving credit facility

On 17 March 2010, in anticipation of the corporate restructuring with LNS and the acquisition of PEDL, the Group established a two year US$280,000,000 Revolving Credit Facility Agreement with Bank of Scotland and BNP Paribas which is secured on the assets of the Group. Under the terms of the facility agreement, the Group has the ability to draw loans to a maximum value of US$200,000,000 and utilise Letters of Credit ('LoC') to a maximum aggregate value of US$80,000,000.

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

At 31 December 2010 there were no borrowings under the Group's facility agreement (2009: nil) and LoC utilisation of US$74,000,000 (2009: nil)

(ii) Term loan

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

20 PROVISIONS

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

At 1 January 2009	46,633	231	46,864
Additions during the year	-	261	261
Changes in estimates	3,385	-	3,385
Unwinding of discount	2,916	-	2,916
Utilisation	-	(228)	(228)
At 31 December 2009	52,934	264	53,198


At 1 January 2010	52,934	264	53,198
Additions during the year	10,897	-	10,897
Acquisition of subsidiaries	66,806	-	66,806
Changes in estimates	4,275	-	4,275
Unwinding of discount	5,196	-	5,196
Utilisation	-	(264)	(264)
At 31 December 2010	140,108	-	140,108

Provision for decommissioning

The Group makes full provision for the future costs of decommissioning its oil production facilities and pipelines on a discounted basis.

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% (2009: 5.5%). The unwinding of the discount is classified as finance cost (note 6).

These provisions have been created based on internal 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.

21 TRADE AND OTHER PAYABLES

	2010	2009
	US$'000	US$'000

Trade creditors	11,762	1,481
Accrued expenses	101,767	31,241
Other payables	3,387	604
	116,916	33,326

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

Accrued expenses include accruals for capital and operating expenditure in relation to the producing 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.

22 COMMITMENTS AND CONTINGENCIES

Commitments

Leases

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

	2010	2009
	US$'000	US$'000

Not later than one year	1,725	711
After one year but not more than five years	3,433	1,423
	5,158	2,134

Lease payments recognised as an operating lease expense during the year amounted to US$1,163,446 (2009: US$649,000).

Capital commitments

At 31 December 2010, the Group had capital commitments excluding the above lease commitments amounting to US$78,602,000 (2009: US$24,485,000).

23 RELATED PARTY TRANSACTIONS

The Group financial statements include the financial statements of EnQuest PLC and its subsidiaries.

The following table provides the total amount of transactions which have been entered into with related parties:

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

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

2009:
Lundin Petroleum AB - current	-	-	-	179
Lundin Petroleum AB - long-term loan	-	-	21,443	-
Ultimate Parent Company	-	-	21,443	179

Lundin Petroleum BV	796	-	-	36
Parent Company	796	-	-	36

Lundin Services BV	-	-	-	282
Lundin Oil & Gas BV	-	-	438	-
Lundin Norway AS	-	-	114	-
Subsidiaries	-	-	552	282

	796	-	21,995	497

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. Following the restructuring on 6 April 2010, the entities listed in the above table ceased to be related parties.

There have been no other transactions with related parties.

23 RELATED PARTY TRANSACTIONS (continued)

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

Compensation of key management personnel

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

	2010	2009
	US$'000	US$'000

Short-term employee benefits	4,992	350
Share-based payments	2,323	-
Post employment pension benefits	38	44
	7,353	394

24 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk management objectives and policies

The Group's principal financial assets and liabilities comprise trade and other receivables, cash and short-term deposits, interest-bearing loans and borrowings 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 2010 and 2009 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 oil prices on its revenues and profits generated from sales of crude oil. The Group did not hedge this risk in the years ending 31 December 2010 and 2009.

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

	Pre-tax profit		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 2010	69,746	(69,746)	20,661	(33,478)
31 December 2009	35,790	(35,790)	14,810	(14,810)

During 2010, the Board of EnQuest approved a policy to hedge up to a maximum of 50% of annual oil production. In the fourth quarter of 2010, the Group entered into four zero premium oil price collars for 2011 to hedge, partially, its exposure to fluctuations in oil prices. Each collar will hedge the price of approximately 1,000,000 barrels of oil in 2011. These derivative instruments are designated effective cash flow hedges and had a nil fair value at 31 December 2010 (2009: nil).

Foreign currency risk

The Group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the Group's functional currency. The Group manages this risk by converting US$ receipts at spot rates periodically and as required for payments in other currencies. Approximately 6% of the Group's sales and 79% of costs are denominated in currencies other than the functional currency.

24 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (continued)

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

	Pre-tax profit		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 2010	(22,664)	22,664	(10,879)	10,879
31 December 2009	(1,752)	1,752	(876)	876

Credit risk

The Group trades only with recognised, international oil and gas operators and at 31 December 2010 there were no trade receivables past due (2009: nil), and one joint venture receivable past due of US$547,000 (2009: nil).

Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary.

At 31 December 2010, the Group had one customer accounting for 97% of outstanding trade and other receivables (2009: one customer, 83%) and three joint venture partners accounting for 82% of joint venture receivables (2009: nil).

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 counter-party 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 2010 the Group was in compliance with all financial covenant ratios agreed with its bankers.

At 31 December 2010, the Group had US$206,000,000 (2009: nil) of undrawn committed borrowing facilities available which are due to expire in March 2012 and replacement borrowing facilities are expected to be arranged during 2011.

24 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (continued)

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

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

Accounts payable and accrued liabilities	116,254	-	-	-	116,254
Financial expenses	-	3,983	1,320	-	5,303
	116,254	3,983	1,320	-	121,557

Year ended 31 December 2009
	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

Interest-bearing loans and borrowings	-	-	-	156,000	156,000
Accounts payable and accrued liabilities	33,326	-	-	-	33,326
Due to related parties	497	-	-	-	497
Financial expenses	-	1,810	1,810	5,430	9,050
	33,823	1,810	1,810	161,430	198,873

Capital management

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

The Group seeks to optimise the return on investment, by managing its capital structure to achieve capital efficiency whilst also maintaining flexibility for future acquisitions. The Group keeps under review the costs and access to debt funding to ensure it has an appropriate flexibility. Note 19 to the financial statements provides further details of the Group's financing activity.

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

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

	2010	2009
	US$'000	US$'000
Loans and borrowings, net (A)	-	(134,557)
Cash and short-term deposits	41,395	7,893
Net debt (B)	41,395	(126,664)

Equity attributable to EnQuest PLC shareholders (C)	882,896	160,200

Profit for the year attributable to EnQuest PLC shareholders (D)	27,076	7,992

Gross gearing ratio (A/C)	n/a	84%

Net gearing ratio (B/C)	n/a	79%

Shareholders' return on investment (D/C)	3%	5%

25 POST BALANCE SHEET EVENTS

On 11 February 2011 the Group sold its 48.75% interest in the Petisovci project ('Petisovci') in Slovenia in return for 150,903,958 new Ordinary shares in Ascent Resources plc ('Ascent'), representing a 22.2% equity stake in Ascent. The Group had acquired its interest in Petisovci through its acquisition of Stratic in November 2010. As part of the transaction the Group also received a nil-cost option to receive a further 29,686,000 new Ordinary shares in Ascent, subject to certain criteria related to the successful development of Petisovci.

On 23 March 2011 it was announced that supplementary corporation tax on UK oil and gas production is to be increased from 20 per cent to 32 per cent with effect from 24 March 2011, thereby increasing the combined rate of tax on UK oil and gas production from 50 per cent to 62 per cent on ring fence profits and from 65 per cent to 81 per cent for fields liable to petroleum revenue tax. The government has stated that the supplementary corporation tax rate may be reduced back to 20 per cent if oil prices stay low (below US$75 per barrel) for a sustained period, however it is not clear at this time if this will be incorporated into legislation. This change in UK tax legislation does not impact the 2010 Group financial results as these changes have not been substantively enacted at the balance sheet date, however it is likely to have a material effect on the value of the Group's deferred tax liabilities and assets and income tax charge in future reporting periods.

26 SUBSIDIARIES

At 31 December 2010, EnQuest PLC had investments in the following principal subsidiaries:

Name of Company	Principal activity	Country of incorporation	Proportion of nominal value of issued shares controlled by the Group

EnQuest North Sea BV	Intermediate holding Company	Netherlands	100%
EnQuest Britain Limited (i)	Intermediate holding Company and provision of Group manpower and contracting/procurement services	England	100%
EnQuest Dons Limited	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Dons Oceania Limited (i)	Exploration, extraction and production of hydrocarbons	Cayman Islands	100%
EnQuest Heather Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Thistle Limited (i)	Extraction and production of hydrocarbons	England	100%
Stratic Energy (UK) Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
Grove Energy Limited (i)	Intermediate holding Company and exploration of hydrocarbons	Canada	100%

(i) Held by subsidiary undertaking.

This information is provided by RNS

The company news service from the London Stock Exchange

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