Final Results

RNS Number : 8480H

EnQuest PLC

19 March 2015

ENQUEST PLC, 19 March 2015. Results for the year ended 31 December 2014*.
2014 production up 15%, substantial 25 MMboe reserves increase
Production of between 33,000 Boepd and 36,000 Boepd for 2015, up c.24%

Highlights

§ Production averaged 27,895 Boepd, up 15.2%, over 2013. This was due to very good operational performance, with an excellent HSE performance, excellent production efficiency and with a 3,459 Boepd contribution from EnQuest's first international production.

§ Net 2P reserves of 220.0 MMboe as at end 2014, up 25.2 MMboe on prior year, reserves replacement ratio of c.350%. Net contingent resources of 170.6 MMboe at end of 2014, up 49.2 MMboe.

§ Revenue of $1,010 million, EBITDA^** of $581 million, reflecting the strong operational performance.

§ The Floating Production, Storage and Offloading ('FPSO') vessel for the Alma/Galia development has now left the yard on schedule and the project is on track for first oil in mid-2015.

§ Kraken continues to be on budget and is on schedule for first oil in 2017. The drilling of an appraisal well in Kraken West has confirmed the presence of oil, with potential for upside. Further evaluation is ongoing.

§ Cost reduction action across the board; confirming 2015 cash capex target of c.$600 million, also a unit opex reduction target of c.10% over 2014, to an average of c.$38/bbl in 2015.

§ Hedging already in place for 2015 and now also for 2016, currently with 10 million barrels hedged in 2016, through puts averaging c.$68 per barrel in 2016.

§ Non-cash post-tax impairments of $335.3 million, due to lower near term oil price assumptions.

§ Net debt at the year end, was $932.8 million.

§ Production guidance for the full year 2015 is for an average of between 33,000 Boepd and 36,000 Boepd, representing a 24% annual increase at the mid-point of the range.

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

	2014		2013	Change %
Production (Boepd)		27,895	24,222	15.2
Revenue ($m)		1,009.9	961.2	5.1
Realised oil price $/bbl		100.6	109.7	(8.3)
Gross profit ($m)		355.8	434.9	(18.2)
Profit before tax & net finance costs ($m)		362.5	374.8	(3.3)
EBITDA ** ($m)		581.0	621.3	(6.5)
Cash generated from operations ($m)		637.1	562.7	13.2
Reported basic earnings per share (cents)		(22.8)	24.4	-
Net (debt)/cash ^*** ($m)		(932.8)	(381.1)	-

**EBITDA is calculated on a business performance basis, and is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion, depreciation and foreign exchange movements. *** Net (debt)/cash represents cash and cash equivalents less borrowings as at the reported cash flow statement date of 31 December.

EnQuest CEO Amjad Bseisu said:

"EnQuest delivered a strong operational performance in 2014, with production up 15%, EBITDA of $581 million and a 25 MMboe increase in reserves. Our two major development projects are both progressing well; the EnQuest Producer has now left the yard and the Alma/Galia development is on track for first oil in mid-2015, Kraken is on budget and on schedule for first oil in 2017.

During the latter part of 2014, EnQuest acted quickly to counter lower oil prices, implementing a new hedging programme, significantly cutting 2015 cash capital expenditure and taking action across the board to reduce operating costs materially. Consequently this year, EnQuest expects to deliver unit opex of c.$38/bbl, a reduction of c.10% on 2014. Reducing cost and increasing efficiency are core to the EnQuest business model.

EnQuest is also set to benefit from the material increases in production from both Alma/Galia and Kraken in the next two years, delivering significant additional cash flow. Despite the uncertain markets, we are well placed for the future."

Summary of 2015 year to date and outlook

EnQuest has performed well at the start of 2015; production efficiency for the North Sea has again been very strong and the focus on operational efficiencies in PM8/Seligi has been delivering excellent daily gross production.

In 2015, the focus is on bringing Alma/Galia to production and delivering the Kraken project on track. The drilling programme has also been rationalised significantly.

EnQuest remains on course for six producing operated hubs in the UK and achieving annual net production from the UK North Sea of approximately 50,000 Boepd. The PM8/Seligi fields in Malaysia, have the capacity to increase international production.

Production guidance: Average production guidance for the full year 2015 is between 33,000 Boepd and 36,000 Boepd, with Alma coming on stream in mid-2015.

Drilling programme: The rationalised 2015 drilling programme includes a production well on Galia, three new production wells on Thistle and the H66 well completion on Heather. The first Ythan development well will also be completed.

Exploration and appraisal: The drilling of an appraisal well and sidetrack to the west of the Kraken field has confirmed the presence of oil. Preliminary analysis indicates that the primary well (Tyrone) found oil bearing reservoir with a net vertical thickness of approximately 25 feet. The sidetrack (Tiree) also confirmed oil bearing reservoir, with net vertical thickness of approximately 83 feet. Further evaluation is ongoing.

Development opportunities: Following Front End Engineering Design ('FEED') studies, submission of a Field Development Plan ('FDP') is anticipated in 2015 for the development of Scolty/Crathes. The Tanjong Baram field development is proceeding according to plan, with first oil targeted by the end of H1 2015.

Capital expenditure: In 2015, cash capital expenditure on current projects is expected to be approximately $600 million, including around $350 million being invested in the Kraken development and about $100 million in Alma/Galia. Capex reductions have been achieved both from development projects and from existing fields.

Operating expenditure: EnQuest achieved unit opex of $42.1/bbl in 2014 and is targeting a reduction target of c.10% in 2015, to c.$38/bbl. This is being achieved through lower cost barrels coming onstream and through substantial direct cost savings.

Further cost savings are being targeted across the business, through the supply chain and by improving efficiencies in operations, through maximising production and minimising waste. Limited company contractor rates have been cut and headcount reduced in the UK and logistics costs are down significantly.

Depletion and depreciation: In 2015, the depletion and depreciation charge is anticipated to be slightly higher than in 2014.

Tax: In the current oil price environment, EnQuest does not anticipate paying material UK cash tax before 2025.

Hedging: EnQuest has put hedging in place for 2016, currently with 10 million barrels hedged through puts averaging c.$68 per barrel. For 2015, EnQuest has restructured the hedging programme, realising a gain of $100 million. EnQuest now has 10 million barrels hedged in 2015 at c.$65 per barrel.

Financing: EnQuest successfully negotiated a relaxation of covenants to its revolving credit facility and ongoing continued compliance with its covenants is a priority for 2015 and beyond.

By Production and Development Asset

UK North Sea

Thistle/Deveron

§ Drilling will recommence at Thistle in 2015, with three new production wells being brought onstream, one in the middle of the year and two more in H2 2015.

Don fields

§ A phased development of the Ythan field is planned, with drilling operations on the first well continuing through Q1 2015 and first production from the field by mid-2015. The drilling of the Ythan AA injector well is planned for around the end of 2015. Other areas to increase production in the Dons area will be reviewed, however, as expected, natural rates of decline will continue in 2015.

Heather/Broom

§ There will be no further drilling on Heather in 2015 beyond the completion of the Heather H66 production well.

Greater Kittiwake Area ('GKA')

§ Following the success of the Mallard workover, a Gadwall sidetrack is expected in mid-2015.

Alma/Galia

§ The EnQuest Producer vessel left the yard in Newcastle and has now successfully completed marine performance trials in deeper water nearby. Alma/Galia is on course for first oil in mid-2015, with five wells now available to come onstream. A phased start up is planned, with one well coming onstream per week for the first month. Drilling on the Galia production well is to be completed and tied in during H2 2015.

§ EnQuest's net 2P reserves for Alma/Galia increased slightly to c.26MMboe at the start of 2015, following the positive results from the wells which have been drilled.

Kraken

§ The Kraken programme for 2015 includes the installation of subsea hardware, including the manifolds for the first drill centre which connect to the templates already installed, two templates for the second drill centre, installation of the mooring system for the FPSO and commencement of the development drilling programme. The new drilling rig is expected on location at Kraken in H2 2015 to commence the Kraken batch top-hole drilling programme.

§ The FPSO programme also continues, with a dry docking scheduled to be undertaken to install the FPSO turret infrastructure by the end of Q1 2015.

International

Malaysia

§ Development of the Tanjong Baram field continues, with first oil scheduled by the end of H1 2015.

§ The 2015 PM8/Seligi work programme is focused on well interventions activities and improvements to the field infrastructure, including work on gas compressors, pipelines and generators.

Tunisia

In February 2015, EnQuest announced that it had exited from its small investment in Tunisia, retention of which had been subject to conditions which were not satisfied within the relevant timeframe. Consideration of $22 million had been kept in escrow and was duly returned to EnQuest.

Summary review of 2014

Financial

§ In 2014, EnQuest generated EBITDA of $581.0 million, benefiting from action taken on costs in H2 2014. EBITDA was lower than in 2013 mainly due to lower oil prices and to higher tariff and transportation costs. Cash generated from operations was $637.1 million compared to $562.7 million, mainly due to increases in trade payables, accrued payables and an overlift position compared to an underlift in 2013.

§ 2014 revenue of $1,009.9 million was 5.1% higher than in 2013, mainly due to the 15.2% increase in production offset by the 8.3% decrease in the realised price per barrel of oil sold. The increase in revenue was also due to an overlift of $8.2 million in 2014 compared with an overlift of $2.6 million in 2013. Within revenue in 2014 there is $31.7 million of realised income relating to oil commodity hedges and call options.

§ Profit from operations before tax and net finance costs was $362.5 million, down 3.3% on the prior year. This reflects cost of sales of $654.1 million for 2014 compared with $526.3 million in 2013. An increase of $85.3 million was due to increased costs relating to the GKA and PM8/Seligi acquisitions and an increase of $34.0 million was due to increased transportation costs. That increase was partly due to increased volumes, but mainly due to an increase in the costs per barrel at the Sullom Voe Terminal (SVT). Total full year 2014 unit operating costs of $42.1/bbl reflected the initial benefit of cost reduction initiatives taken in H2 2014 and the lower exchange rate and generally a year of good operational performance and strong control of direct costs.

§ Profit after tax and net finance costs was $137.4 million, down on last year, reflecting increased interest costs following the 2014 bond issuance.

§ EnQuest's funding facilities include c.$900 million of bonds and a committed credit facility of $1.2 billion plus an accordion of up to a further $500 million. 2014 year end net debt was $932.8 million, with $217.6 million drawn on the credit facility utilisation before taking into account cash balances. The net debt position was after cash outflow of $1,060.3 million on capital expenditure.

§ Non-cash post-tax impairments of $335.3 million, due to lower near term oil price assumptions.

§ As a result of the continued capital investment, UK corporate tax losses at the end of the year increased to approximately $1,818 million.

Production, Development & Reserves

	Net daily average 1 Jan' 2014 to 31 Dec' 2014	Net daily average 1 Jan' 2013 to 31 Dec' 2013
	(Boepd)	(Boepd)
Thistle/Deveron	9,025	7,925
Dons	8,835	11,014
Heather/Broom	4,081	4,339
Kittiwake	1,281¹	-
Alba	1,214	922²
Total UKCS	24,436	24,222
PM8/Seligi (Malaysia)	3,459³	-
Total EnQuest	27,895	24,222

¹ Net production since the completion of the acquisition at the start of Mar' 2014, averaged over the twelve months to end of Dec' 2014.
² Net production since the completion of the acquisition at the end of Mar' 2013, averaged over the twelve months to end of Dec' 2013.
³ Net production since the completion of the acquisitions at the end of June 2014, averaged over the twelve months to end of Dec' 2014.

Note: Production from PM8/Seligi was 2,078 Boepd on an entitlement basis.

UK North Sea

Thistle/Deveron

§ In 2014, Thistle delivered 14% production growth year on year, reflecting continuing benefit from new production wells brought onstream during the course of H2 2013 and the programme of investment in the Thistle life extension project. In 2014, the A57 and A60 wells continued to outperform expectations, with watercut rising slower than anticipated. The investment programme in Thistle delivered a stepped improvement in production efficiency.

Don fields

§ In 2014, production optimising projects were implemented to address the natural decline in the Don fields. Production efficiency remained very strong, at 89%, with high levels of water injection efficiency supporting production. Production from Area 22 of Don Southwest was boosted by a successful acid stimulation treatment on Well S2z and by the completion in August of a new production well. The new production well TJ delivered initial rates in line with expectations. On West Don, the W4 well suffered from scale build up and was shut-in in November awaiting remedial measures, scheduled for 2015.

Heather/Broom

§ Production at Heather/Broom delivered 4,081 Boepd in 2014. This was down slightly after a strong performance in 2013. Following the completion of the 2013 rig reactivation project, rig operations in Q1 2014 commenced with a workover of the H56 well, which was brought onstream in May and has continued to deliver planned levels of production. This was followed by the sidetrack of shut-in well H44 as a new injection well in the B2 block. H64 was brought on in July, which resulted in an increase from the nearby production well, H62Y. Crestal production well, H47, was sidetracked in place of the planned workover, and was brought onstream in November, delivering an initial rate significantly above expectation. High levels of operational uptimes and a production efficiency of over 90% have been achieved.

Greater Kittiwake Area

§ EnQuest took over as the operator at the end of Q1 2014; the initial focus was on integration and delivering an early workover programme on Mallard.

§ The Mallard workover was successfully completed and was brought online at the end of Q3 2014, GKA production peaked at 7,300 Boepd, shortly after. Since acquiring GKA, EnQuest has improved operational efficiency and with the benefit of the workover, production has increased from just over 2,500 Boepd gross in the first few months, to over 5,500 Boepd gross in October. The Grouse well now benefits from stable gas-lift supply.

Alma/Galia

§ At the end of 2014, the Alma/Galia development project was on track for first oil in mid-2015.

§ Systems required for first oil were mechanically complete, with commissioning well underway. Control systems (marine, subsea, electrical submersible pumps) had been installed and commissioned. Five production wells were fully completed and ready for the FPSO tie-in. The drilling programme for the production wells was successfully completed; five wells were drilled with results meeting or exceeding expectations. All subsea well tie-ins were complete. The subsea infrastructure was in place, with risers and mooring systems wet-stored awaiting the arrival of the FPSO.

Kraken

§ During 2014, the Kraken project progressed well, on budget and on schedule.

§ In Q2 2014, the Kraken FPSO donor vessel arrived at the shipyard in Singapore for conversion scope to commence.

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

International

PM8/Seligi. Malaysia.

§ Following the acquisition at the end of June 2014, EnQuest assumed offshore field operations in October, and the overall transition completed in December 2014, with strong production from the fields. EnQuest intends to enhance production through well interventions, facilities rectification and upgrades, and subsurface programmes that will lead to new wells in 2016.

Tanjong Baram. Malaysia.

§ In March 2014, EnQuest signed a contract for the development of the Tanjong Baram field, offshore Sarawak. Tanjong Baram is being developed as an unmanned platform with production tied back to the Petronas Carigali operated West Lutong A complex. The development plan is based on a two well programme, with capacity for one additional well in the facilities design.

Reserves

§ Audited net 2P reserves at the start of 2015 were 220.0 MMboe, a 13.0% increase on the start of 2014; reflecting a reserves replacement ratio of c.350% and a reserve life of over 20 years. The increase resulted partly from positive revisions to reserve estimates from infill drilling and an improved knowledge of the reservoirs. Approval of the Ythan discovery for development, and the promotion of the Scolty and Crathes discoveries following development planning, also contributed to the increase in EnQuest's reserve base. Further additions arose from 2014 acquisitions, including interests in the Greater Kittiwake Area ('GKA') and PM8/Seligi in Malaysia.

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)

Tulchan Communications	Tel: +44 (0)20 7353 4200
Martin Robinson
Martin Pengelley

Presentation to Analysts and Investors

A presentation to analysts and investors will be held at 09:00 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 09:00 on the following numbers:

Conference call details:

UK: +44(0)20 3427 1918

USA: +1646 254 3364

Confirmation Code: EnQuest

Notes to editors

EnQuest is the largest UK independent producer in the UK North Sea. EnQuest PLC trades on both the London Stock Exchange and the NASDAQ OMX Stockholm. Its operated assets include the Thistle, Deveron, Heather, Broom, West Don, Don Southwest, Conrie, Kittiwake, Mallard, Gadwall, Goosander and Grouse producing fields and the Alma/Galia, Kraken and Ythan developments; EnQuest also has an interest in the non-operated Alba producing oil field. EnQuest had 34 UK production licences at the start of 2015, covering 45 blocks or part blocks, and was the operator of 29 of these licences. This increases to 38 production licences including the 28th round awards awarded in Q1 2015, covering 54 blocks or part blocks in the UKCS, 33 of the licences are operated by EnQuest.

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

EnQuest has begun replicating its existing model in the UKCS by targeting previously underdeveloped assets in a small number of other maturing regions; complementing our operations and utilising our deep skills in the UK North Sea. In which context, EnQuest has interests in Malaysia where its operated assets include the PM8/Seligi Production Sharing Contract ('PSC') and the Tanjong Baram development, EnQuest also has an interest in the non-operated SB307/SB308 blocks.

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

STRATEGIC REPORT

CHAIRMAN'S STATEMENT

EnQuest's performance
During 2014, EnQuest delivered a strong operational performance and reacted swiftly to the oil price declines witnessed in the second half of the year. The Company has a significant capital programme associated with its Kraken investment in 2015 and 2016 and looks forward to 2017, when Kraken is planned to be onstream.

Despite the recent downturn in the oil price, since EnQuest's inception five years ago, we have grown our original net 2P reserve base by over 173%, representing a replacement ratio of 514%. Consequently, EnQuest started 2015, with a reserve life of over 20 years. During these first five years, EnQuest generated c.$2.7 billion in cash flow from operations.

Industry background
From the outset, EnQuest has worked closely with the industry and the UK Government to bring about structural changes to the business environment in the North Sea, which we believe are essential to the future of the industry. The North Sea needs a stable and incentivising fiscal regime with regulation that encourages new development activity and promotes greater collaboration between operators, leading to a lower cost base. The steep decline in oil prices during the latter part of 2014 has acted as a catalyst for action.

EnQuest's response to lower oil prices
In response to declining oil prices, EnQuest took action to protect against further oil price falls and to maximise cost reduction. EnQuest accelerated its oil price hedging programme and worked closely with the supply chain to reduce operating and capital expenditure. While we remain confident about the long term prospects for the oil price, we are managing our business so as to allow us to withstand a more prolonged period of lower oil prices.

EnQuest's funding facilities include a $1.2 billion committed credit facility, with a $500 million accordion. EnQuest renegotiated covenants with its lending banks and these have been relaxed until mid-2017. Ongoing continued compliance with its covenants is a priority for 2015 and beyond. With its credit facility and a long dated debt maturity profile, the financial position of the Company remains resilient.

At the same time, EnQuest delivered very good operational performance in 2014, with strong production growth and industry leading levels of production efficiency. The Alma/Galia development project recovered from delays in the first half of 2014, and since then it has remained on schedule. Since its sanction at the end of 2013, the Kraken development project has consistently been on schedule and on budget.

The EnQuest Board
The composition of the Board remained constant during 2014. The Directors assess and evolve EnQuest's strategy, taking key decisions on its implementation. In 2014 these included the acquisition of EnQuest's first producing assets outside the North Sea, and in 2015 the Board also took measured actions in light of the lower oil price environment, in terms of setting the new business plans for 2015 and beyond.

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

Governance
In 2014, EnQuest complied in full with the 2012 UK Corporate Governance Code. In September 2014, the Financial Reporting Council published the revised 2014 UK Corporate Governance Code, compliance with which will continue to be reported annually by EnQuest. We are well advanced in implementing our responses to the changes brought in by the 2014 UK Corporate Governance Code.

Corporate Governance for EnQuest is not merely following a set of rules, but embedding a framework which supports our core values and, provides structure for how we are organised, how we manage risk, how we behave and how we provide assurance in respect of performance. In 2014, the Board strengthened a number of areas of corporate governance including the risk management framework and corporate responsibility. We work to ensure that all elements of corporate governance are part of our corporate culture and we have developed an environment which nurtures, develops and maintains our approach.

The Board reviewed the Company's corporate responsibility model. We ensured that we have strong relevant policies in place, covering the areas of Health and Safety, People, Business Environment, Business Conduct and Community. We will be working towards monitoring the impact and progress of these areas in the coming period. Our UK Health and Safety policy has now also been implemented in our international projects in Malaysia, with supplemental policies as required by local legislation.

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

Delivering sustainable growth
We are managing our business to withstand a prolonged period of low oil prices and I am confident that EnQuest will emerge from this down cycle in even better shape to implement our strategy successfully. The life of the Alma/Galia field is over ten years and the Kraken field has a twenty five year life, this is a long term business.

STRATEGIC REPORT

CHIEF EXECUTIVE'S REPORT

EnQuest's performance, business model and strategy
EnQuest's core competency in controlling costs and managing operations efficiently is particularly important in the current climate of low oil prices. Despite challenging macro conditions, EnQuest delivered a strong operational performance in 2014, with production of 27,895 Boepd, whilst EBITDA was $581 million. 2014 was a record year for production and was up 15% on the prior year. The acquisition of the Seligi and PM8 oil fields in Malaysia provided EnQuest with its first contribution from outside the North Sea, countering the impact of delay to the Alma/Galia project.

EnQuest delivered an increase in its net 2P reserve base, up by 25.2 to 220.0 MMboe, reflecting a reserve replacement ratio of approximately 350% for 2014. The increase resulted partly from positive revisions to reserve estimates from infill drilling and an improved knowledge of the reservoirs. Approval of the Ythan discovery for development, and the promotion of the Scolty and Crathes discoveries following development planning, also contributed to the increase in EnQuest's reserve base. Further additions arose from 2014 acquisitions, including interests in the Greater Kittiwake Area ('GKA') and PM8/Seligi in Malaysia.

During the latter part of 2014, EnQuest acted quickly to counter the impact of a rapid decline in oil prices, increasing the hedging programme and significantly cutting 2015 cash capital expenditure to c.$600 million, with reductions from both developments and existing fields. We are targeting a reduction in EnQuest's operating cost per barrel of c.10%, from $42.1/boe in 2014 to an average of c.$38/boe in 2015. This is being achieved through lower cost barrels coming onstream, reducing opex per barrel in newly acquired fields, and through substantial direct cost savings. We are targeting cost savings across the business, through the supply chain and by improving efficiencies in our operations, through maximising production and minimising waste. We have cut limited company contractor rates and reduced our headcount in the UK and logistics costs are down significantly. This agile focused approach enabled EnQuest to hold unit operating costs flat during its first five years, while average costs in the North Sea doubled. EnQuest continues to work with the supply chain and contractors to achieve further cost savings and optimisation.

Given the low oil price environment, EnQuest negotiated a relaxation of covenants to its revolving credit facility until mid-2017. This continued commitment from our lenders recognises the cash flow generation of EnQuest's business and in particular the expected increases in cash flow from the Alma/Galia and Kraken developments.

EnQuest has achieved a 173% increase in net oil reserves over the last five years, having converted more than half of the original reserves into flowing barrels. Despite the reductions to the investment programme, EnQuest remains on course to achieve annual net production from the UK North Sea of 50,000 Boepd, with six operated producing hubs in the UK. In Malaysia, PM8/Seligi has the potential to increase international production significantly over the coming years.

Health, safety, environment and assurance ('HSE&A')
In 2014, EnQuest met its commitment to deliver safe results, with the best HSE performance since formation in April 2010. EnQuest achieved a Lost-Time Incident Frequency Rate ('LTIFR') of zero and a Recordable Incident Frequency Rate ('RIFR') below the industry average. There were no High Potential Incidents ('HIPO's): the last recorded HIPO was in April 2013.

In addition, the producing northern North Sea assets achieved a total of 11 years without a Lost-Time Incident ('LTI') and 11 million man hours LTI-free. Health and Safety Executive inspections were performed on all the assets, and no major issues were identified. These results are a testament to the focus given to HSE&A.

North Sea operations
In 2014, EnQuest delivered good production of 24,436 Boepd in the UK, marginally ahead of the 24,222 Boepd in 2013. This reflects the continuing strength of field reservoir performance and high production efficiency from EnQuest's existing UK assets. With production efficiency from existing assets averaging 88% in 2014, EnQuest is likely to have further improved its position in the Oil & Gas UK's rankings.

EnQuest delivered 12 wells in 2014, including successful wells at Heather and Don South West. At the Dons, the Ythan development in Don North East, moved from licence award, through Field Development Plan submission and approval, to spudding of the first well in less than 12 months. The Thistle life extension project continued to improve production levels in 2014. Thistle produced over three million barrels of oil for the first time since 1997. The Greater Kittiwake Area ('GKA') assets were acquired early in 2014. Subsequent to the acquisition of GKA, the discovery of Avalon further enhanced the potential of GKA.

North Sea developments

Alma/Galia
During 2014, both the subsea and the drilling programmes for the Alma/Galia project were delivered on time. By the end of the year, five production wells were fully completed and ready for tie-in and the subsea infrastructure was in place. However, delays to the programme for the Floating Production, Storage and Offloading vessel ('FPSO', the 'EnQuest Producer') had moved the earliest possible 'sailaway' date into the winter months. This would have significantly increased the operational risks and costs of waiting for appropriate weather conditions. Sailaway and first oil were therefore rescheduled to spring 2015 and to mid-2015 respectively. Since August 2014, the FPSO construction has remained on track and following first oil, initial net peak production of c.13,000 Boepd is expected, significantly increasing EnQuest's production profile. Plateau unit operating cost is expected to be approximately $15/bbl to $20/bbl.

Delays and cost increases for the EnQuest Producer initially stemmed from changes to the implementation of safety codes, such as for moorings and also other regulatory imposed scope changes. The extent of work required on the vessel was also greater than anticipated.

The FPSO is essentially now a new vessel with all the topsides having been replaced. Ownership of the vessel at first oil provides EnQuest with a range of additional funding options, such as a potential sale and leaseback.

EnQuest's net 2P reserves for Alma/Galia increased slightly to c.26 MMboe at the start of 2015, following the positive results from the wells which have been drilled.

Kraken
During 2014, the Kraken project progressed well, on budget and on schedule.

In Q2 2014, the FPSO donor vessel arrived at the shipyard in Singapore and its conversion scope commenced. In H2 2014, EnQuest commenced installation of the subsea structures at the first drill centre, where the initial wells for the development will be drilled. Detailed engineering, procurement and manufacture for all equipment relating to wells, subsea infrastructure and the FPSO continued throughout 2014.

With the Kraken project on budget, its anticipated net capital expenditure estimate is unchanged at $1.4 billion to first oil. The full cycle breakeven cost for the project continues to be in the region of $55/bbl. In addition, with $512 million invested to the end of 2014, the forward economics of the 25 year life project are strong with an internal rate of return in the mid thirties per cent, net to EnQuest using the forward curve in early March 2015.

North Sea acquisitions
In Q1 2014, EnQuest applied for and was offered an 'out of round' licence in the Don North East area ('Don NE') for blocks 211/18e and 211/19c. This included the Area 23 and Area 24 discovered oil accumulations and an undrilled extension to the Don NE field. Following the award of this licence a Field Development Plan for 'Ythan' was submitted and approved.

In Q1 2014, EnQuest announced the acquisition of the Greater Kittiwake Area assets. The acquisition fits within the goals of managing mature fields and of exploiting nearby discoveries and near field exploration opportunities. The Scolty and Crathes discoveries are within the GKA area, with potential to benefit from a tie-back to Kittiwake. The combination of these opportunities also facilitates the extension of the GKA field life itself.

The base consideration for the acquisition was $39.9 million, which following working capital and other adjustments resulted in the payment of a cash consideration of $30.3 million. When the acquisition was announced, the additional net 2P reserves were recorded as 4.7 MMboe as at the economic date of 1 January 2013. Following GKA post acquisition production of a net 0.5 million barrels of oil in 2014, EnQuest recorded net 2P reserves of c.8 MMbbls in GKA as at the end of 2014. Reasons for the net increase included not only the addition of Scolty/Crathes, but also improved performance and the lengthening of the field life.

In Q4 2014, EnQuest was offered and accepted eight licences as part of the UK 28^th North Sea licensing round.

International
2014 was a transformational year for EnQuest's international business, particularly with the acquisition of the PM8/Seligi fields, delivering our first production from outside the North Sea.

In Q2 2014, EnQuest announced the signing of a small field risk service contract with Petroliam Nasional Berhad ('Petronas'), the national oil company for Malaysia, for the development and production of petroleum from the Tanjong Baram field offshore Sarawak, Malaysia. Start-up is expected in mid-2015. Separately, the Kitabu prospect, was drilled in Q1 2014, however the well failed to encounter hydrocarbons; this was in the SB307/SB308 contract area where EnQuest has a non-operated interest.

Later in Q2 2014, EnQuest announced a significant expansion of its footprint in Malaysia, through the acquisition the PM8 Production Sharing Contract ('PSC') fields and the Seligi oil field, from ExxonMobil Exploration and Production Malaysia Inc; both EnQuest and Petronas Carigali Sdn Bhd to hold participating interests. EnQuest also signed an agreement with Petronas to extend the term of the PSC, comprising PM8 PSC assets and the Seligi oil field to 2033 (formally 'PM8 PSC (Extension)' or simply 'PM8/Seligi'). This acquisition has a good strategic fit and offers considerable potential for EnQuest to use its core skills in enhancing value from maturing fields.

The base consideration for the acquisition was $67.0 million, which following interim period adjustments resulted in the payment of a cash consideration of $24.7 million. Following strong production of a net 0.8 million barrels of oil in 2014, EnQuest recorded net 2P reserves of c.15 MMbbls in PM8/Seligi as at the end of 2014. In December 2014, following a short transition period, EnQuest took over operatorship and is working on an ongoing programme to target further efficiency improvements and to maximise recovery. Production in the last six months of 2014 was approximately 7,000 Boepd net, on a working interest basis and this continued to improve into 2015.

In 2014, EnQuest was offered and accepted 2 licences as part of the 2014 Awards in Pre-Defined Areas ('APA') Norwegian Licensing Round.

Financial performance

In 2014, EnQuest generated EBITDA of $581 million, benefiting from further action taken on costs in H2 2014 and also from its full year currency hedging programme.

Following the delays to the Alma/Galia project in early 2014, EnQuest's net capex cost for the first phase of the project is expected to be c.$55/bbl.

EnQuest's funding facilities include c.$900 million of bonds and a committed credit facility of $1.2 billion plus an accordion of up to a further $500 million. 2014 year end net debt was $933 million, with $218 million drawn on the credit facility utilisation before taking into account cash balances.

Total full year 2014 unit operating costs of $42.1 per barrel reflected the initial benefit of cost reduction initiatives taken in H2 2014 and the lower exchange rate and generally a year of good operational performance and strong control of direct costs.

There were non-cash post-tax impairments of $335.3 million, due to lower near term oil price assumptions.

2015 year to date

EnQuest has performed well at the start of 2015; production efficiency has again been very strong on our North Sea assets and our focus on operational efficiencies in PM8/Seligi has been delivering excellent daily production.

The EnQuest Producer programme is proceeding according to schedule in Q1 2015; the boilers were ignited and fired, notice was given to moor and hook up the vessel in the field. The FPSO recently left the yard in Newcastle, and has successfully completed marine performance trials in deeper water nearby, on schedule for first oil from Alma/Galia in the middle of this year.

The drilling of an appraisal well in Kraken West has confirmed the presence of oil, with potential for upside. Further evaluation is ongoing.

Hedging for 2015 was already in place and hedging is now also in place for 2016, currently with 10 million barrels hedged through puts averaging c.$68 per barrel in 2016.

Outlook for the rest of 2015 and beyond

EnQuest is focused on performance and execution. Safety will always be a priority and we are focused on operational efficiency and further reducing costs. Alma/Galia is on track for first production in the middle of the year. Production for 2015 is expected to be an average of between 33,000 Boepd and 36,000 Boepd, a 24% increase over 2014 at the mid-point of the range. With unit operating expenditure of approximately $15/bbl to $20/bbl during the period of initial net peak volumes, Alma/Galia will also contribute towards a reduction in EnQuest's 2015 unit operating costs of c.10% over 2014.

2015 priorities also include delivering the $600 million cash capital expenditure programme, focused on the Kraken development project. The drilling programme has been rationalised to existing commitments and to projects with high margin barrels, including the drilling of three low cost near field production wells on Thistle, a Gadwall sidetrack and bringing Alma/Galia onstream.

In Malaysia, the 2015 work programme on PM8/Seligi will be focused on well intervention activities and improving the field infrastructure. For Tanjong Baram, the implementation of our development plan is well underway, with first oil targeted by the end of H1 2015.

In Q1 2015, covenants of the credit facility were relaxed giving significant flexibility in a lower oil price environment. EnQuest's focus in 2015 will be on near term profitable cash flow and optimising the long term value of the business. If the low oil price environment continues, then beyond existing development commitments, capital expenditure will continue to be rationalised.

The speed and size of changes made to the business in response to deteriorating energy market conditions was achieved through the agility and focus inherent in EnQuest's business model. EnQuest delivers material improvements to mature fields and we will continue doing so in 2015 and beyond.

STRATEGIC REPORT

OPERATING REVIEW

NORTH SEA OPERATIONS
TOP QUARTILE PRODUCTION EFFICIENCY
Overview
In 2014, EnQuest had its best Health, Safety & Environment ('HSE') performance since it was formed in April 2010, with its focus on HSE culture and performance. Good HSE performance drives good business performance, and the Production Efficiency ('PE') has been excellent. In 2014, EnQuest achieved an overall UK production efficiency of 88% excluding the new GKA assets, or of 86% including GKA. This, together with the delivery of successful wells at Heather and Don South West, enabled production of 24,436 Boepd in the North Sea in 2014.

Looking forward to 2015, with Alma/Galia on track for first oil in the middle of the year, the North Sea operations team is ready to take control of the development as it is handed over by the projects team. With net peak production of c13,000 Boepd, Alma/Galia is set to increase daily UK production levels by over 50%. The Gadwall sidetrack and other barrel adding activities will continue on the existing hubs. Work to finalise the best development solution for Scolty/Crathes will also continue.

On Heather, the return to drilling programme was completed in Q1 and drilling operations have been continuous throughout the year with production from the platform peaking at more than 7,000 Boepd (gross) in November, the first time such levels have been reached since January 2013. Heather achieved high levels of operational uptime, with an exceptional run of 136 continuous days without a production trip, due to the focus of the operations teams onshore and offshore.

Substantial progress has also been made on Kittiwake. The return of the Mallard field to production following its workover in the summer added 3,000 Boepd, increasing overall Greater Kittiwake Area field rates to around 5,500 Boepd, less than six months after acquisition.

On the Don fields, high levels of water injection were achieved and the drilling of the TJ production well and the scale dissolver programme at Don Southwest were delivered. The Don North East located Ythan field has progressed from open acreage to development in six months, with the well spudded ahead of schedule.

Thistle/Deveron achieved year on year production growth of 14%. The Thistle life extension project itself made further progress in 2014 and a major industry award highlighted recognition of this project as a proven template for successfully extending the life of ageing assets.

On exploration, the Avalon well was drilled faster than scheduled and was under budget, and the Cairngorm appraisal well yielded positive initial results. In the 28^th licensing round EnQuest was awarded acreage it had applied for around its hubs.

At the end of 2014, EnQuest started the process for the return of 32% of its interests in Crawford to the previous owner, following which EnQuest will hold a 19% working interest.

Thistle/Deveron

Working interest at end 2014: 99%
Decommissioning liabilities: Remain with former owner
Fixed steel platform
Daily average net production:
2014: 9,024 Boepd
2013: 7,925 Boepd

2014

In 2014, Thistle delivered 14% production growth year on year, reflecting continuing benefit from new production wells brought onstream during the course of H2 2013 and the programme of investment in the Thistle life extension project. The A57 and A60 wells continued to outperform expectations with water cut rising slower than anticipated. The commissioning of the 'D' turbine on gas and the reinstatement of the refurbished 'B' turbine gave improved power stability and improved water injection efficiency in the second half of the year. The second of two new cranes was fully installed and made operational in Q3 2014, reducing risk and operating expenditure. These elements of the life extension investment programme, alongside EnQuest's focused operating strategy, have continued to improve production efficiency at Thistle.

2015 and beyond

Drilling will restart at Thistle in 2015, with three new production wells being brought onstream, one in the middle of the year and two more in H2 2015. The Thistle life extension project will be mechanically complete during 2015, with full completion scheduled for 2016. A planned maintenance shutdown of the Sullom Voe Terminal ('SVT') will stop export from Thistle for three weeks at the end of H1 2015; EnQuest has scheduled its own maintenance programme for the same dates and will additionally use it for some extra life extension works.

The Don fields

Working interest at end 2014:
- Don Southwest, 60%
- Conrie, 60%
- West Don, 63.45%
- Don North East, 60%
Decommissioning liabilities: As per working interests
Floating production unit with subsea wells
Daily average net production:
2014: 8,835 Boepd
2013: 11,014 Boepd

2014

Production efficiency remained very strong, at almost 90%, with high levels of water injection efficiency supporting production. Production from Area 22 of Don Southwest was boosted by a successful acid stimulation treatment on Well S2z and by the completion in August of a new production well. The new production well, TJ, delivered initial rates in line with expectations but production chemistry issues prevented successful gas lift, and medium term rates were below expectation. The acid stimulation and scale inhibition programme also benefitted Don SW wells S11 and S10Y. An upgrade of the water injection system is underway which will allow better operability and increased injection rates. On West Don, the W4 well suffered from scale build up and was shut-in in November awaiting a remedial acid treatment. Bad weather delayed this work into Q1 2015. In Q1 2014, EnQuest applied for and was offered an 'out of round' licence (P.2137) in the Don North East area for blocks 211/18e and 211/19c, including the Area 23 and Area 24 discovered oil accumulations and an undrilled extension to the Don North East field. The Area 24 discovery which lies adjacent to the Don Southwestfield, progressed rapidly to development with the Field Development Plan, for the renamed 'Ythan' field approved by DECC and the first well spudded in November.

2015 and beyond

A phased development of the Ythan field is planned, with drilling operations on the first well continuing through Q1 2015 and first production from the field by mid-2015. The drilling of the Ythan AA injector well is planned for around the end of 2015. Following W4 scale build up in winter it was brought back online in Q1 2015 and is performing well. The SVT shutdown will similarly be used for planned EnQuest maintenance on the Northern Producer.

During 2015, the natural rates of decline will reduce production.

Heather/Broom

Working interest at end 2014:
- Heather, 100%
- Broom, 63%
Decommissioning liabilities:
- Heather, 37.5%
- Broom, 63%
Fixed steel platform
Daily average net production:
2014: 4,081 Boepd
2013: 4,339 Boepd

2014

Production at Heather/Broom delivered 4,081 Boepd in 2014. This was down slightly after a strong performance in 2013. Following the completion of the 2013 rig reactivation project, rig operations in Q1 2014 commenced with a workover of the H56 well, which was brought onstream in May and has continued to deliver planned levels of oil production. This was followed by the sidetrack of shut-in well H44 as a new injection well in the B2 block. The H64 injector was brought on in July, which resulted in an increase from the nearby producer, H62Y, over the following months. Crestal producer, H47, was sidetracked in place of the planned workover, and was brought onstream in November, delivering an initial rate significantly above expectation. New producer H66, a sidetrack of suspended well H48, was being drilled at year end.

High levels of operational uptimes and a production efficiency of over 90% have been achieved and 136 consecutive days without any production interruptions were achieved in H2 2014. The Broom water injection flowline failed at the end of August; replacement options were assessed and a contract awarded for the design, procurement and installation of a replacement line.

2015 and beyond

Beyond the completion of the Heather H48 sidetrack as the H66 production well, there will be no further drilling on Heather in 2015. Broom injection will be reinstated by the middle of 2015. The SVT shutdown will similarly be used for planned EnQuest maintenance on Heather/Broom.

Greater Kittiwake Area ('GKA')

Acquisition completed in Q1 2014
Working interest 50% in each of:
- Kittiwake
- Grouse
- Mallard
- Gadwall
- Goosander
Decommissioning liabilities:
Kittiwake 25%
Mallard 30.5%
Grouse, Gadwall and Goosander 50%
Fixed steel platform
100% interest in export pipeline from GKA to Forties Unity platform
Daily average net production:
2014: 1,281 Boepd
This is based on the net production since the acquisition at the start of March 2014, as averaged over the full year.

Post acquisition programme in 2014
EnQuest took over as the operator at the end of Q1 2014 with the duty holder remaining in place. The focus was on integrating GKA and delivering an early work over programme on Mallard, which has led to a near doubling of production. Next steps will include progressing the proposed Field Development Plan ('FDP') submission for the nearby Scolty/Crathes discoveries, with a tie-back to GKA with potential exploration of nearby prospects.

The Mallard workover was successfully completed and was brought online at the end of Q3 2014, GKA production peaked at 7,300 Boepd, shortly after. Following inspection and routine testing the existing tree was reinstalled, which reduced expenditure and allowed early production from Mallard. Since acquiring GKA, EnQuest has been applying its proven skills for managing mature fields. Improved operational efficiency and the benefit of the workover, has production from just over 2,500 Boepd gross in the first few months, to over 5,500 Boepd gross in October. The Mallard workover also facilitated the opportunity for an accelerated Gadwall workover. Production from Gadwall will be reinstated mid-2015, following the sidetracking of the existing well in H2 2014. The Grouse well now benefits from stable gas-lift supply.

EnQuest made substantial improvements in operating efficiency, with opex per barrel significantly reduced from pre-acquisition levels. Front End Engineering Design ('FEED') studies were being completed on the proposed development of Scolty/Crathes.

2015 and beyond

Goosander, Grouse and Mallard will all be online in 2015 and production from Gadwall is expected to be reinstated in mid-2015.

We are conducting studies on future development scenarios for Avalon, and have considered options for Avalon in FEED engineering on Scolty/Crathes.

Further reductions in GKA unit opex are anticipated during 2015.

Alma/Galia
Working interest at end 2014:
- 65% in both fields
Decommissioning liabilities: As per working interest
Floating, production storage and offloading unit with subsea wells
First oil expected in mid-2015
- Net peak production to be in excess of 13,000 Boepd

2014

At the end of 2014, the Alma/Galia development project was on track for first oil in mid-2015. Systems required for first oil were mechanically complete, with commissioning well underway.

Control systems (marine, subsea, electronic submersible pumps) had been installed and commissioned. Five production wells were fully completed and ready for FPSO tie-in. The pre-first oil drilling programme for the production wells was successfully completed, with five wells meeting or exceeding expectations. The subsea infrastructure was in place, with risers and mooring systems wet-stored awaiting the arrival of the FPSO.

2015

In January the EnQuest Producer boilers were lit, one of the final steps ahead of completing onshore commissioning. The FPSO recently left the yard in Newcastle and has successfully completed marine performance trials in deeper water nearby, on schedule for first oil in the middle of the year. Oil tank commissioning is undertaken in the field, just ahead of commercial production coming onstream. Alma/Galia is on course for first oil in mid-2015. Five wells are now available to come onstream in mid-2015; a phased start up is planned, with one well coming onstream per week, for the first month. Drilling on the Galia production well is to be completed and tied in during H2 2015.

Alba (non-operated)

Working interest at end of 2014: 8%
Decommissioning liabilities: As per working interest
Fixed steel platform
2014: 1,214 Boepd
2013: 922^* Boepd

(*) Net production since the completion of the acquisition at the end of March 2013, averaged over the full year.

Field production was stable in 2014. The Alba oil field is operated by Chevron.

In 2014, operations included the drilling of two production wells, with the second well coming onstream in September 2014. A new 4D seismic survey was also acquired, which is key for maturing future drilling targets.

2015 and beyond

Infill drilling will continue in 2015, with a new production well (S11) and a water injection pipeline scheduled to be online in Q3 2015. There will be a planned maintenance shutdown for approximately three weeks in 2015.

STRATEGIC REPORT

OPERATING REVIEW

MAJOR PROJECTS
KRAKEN CONTINUES ON SCHEDULE AND ON BUDGET FOR FIRST OIL IN 2017

Overview
2014 was a year of significant progress for EnQuest's Kraken development in the northern North Sea, with material advances across the key areas of the project; all key supplier contracts are in place on a fixed price, milestone basis.

During 2014, the work that was required to prepare the donor tanker for conversion to FPSO was largely completed; hull and deck modifications began, alongside other workscopes, including accommodation upgrades and helideck fabrication. All the principal contracts have now been placed for individual modules, including the power, water injection and electrical units.

Kraken

Working interest at end 2014: 60%
Decommissioning liabilities: As per working interest
Floating Production Storage and Offloading unit with subsea wells
First Oil expected 2017
- Net peak production to be c.30,000 Boepd

2014

During 2014, the Kraken project progressed well, on budget and on schedule.

In Q2 2014, the FPSO donor vessel arrived at the shipyard in Singapore for the conversion scope to commence. The programme of conversion work continued throughout the rest of the year. The initial focus was on the hull conversion and the marine system refurbishment. Fabrication progressed for key elements of the FPSO, including the topside modules, accommodation and the helideck.

In H2 2014, EnQuest conducted the installation of two integrated templates (subsea structures) at the first drill centre, where the initial wells for the development will be drilled. A survey vessel successfully completed coring work at the FPSO mooring anchor locations. Delivery of the hydraulic submersible pumps ('HSP') used to provide the artificial lift commenced in Q3 2014. Detailed engineering, procurement and manufacture for all equipment relating to wells, subsea infrastructure and the FPSO continued throughout 2014.

Further appraisal drilling was undertaken to the west of the Kraken field in H2 2014, to assess potential there.

2015 and beyond

The Kraken programme for 2015 includes the installation of subsea hardware, including the manifolds for the first drill centre which connect to the templates already installed and two templates for the second drill centre and six subsea trees. The mooring system for the FPSO and the batch drilling programme will also commence.

The drilling of an appraisal well and sidetrack in to the west of the Kraken Field has confirmed the presence of oil. Preliminary analysis indicates that the primary well (Tyrone) found oil bearing reservoir with a net vertical thickness of approximately 25 feet. The sidetrack (Tiree) also confirmed oil bearing reservoir, with net vertical thickness of approximately 83 feet. Further evaluation is ongoing.

The new drilling rig is expected on location at Kraken by Q3 2015, to commence the Kraken batch drilling programme.

The FPSO programme also continues, with a dry docking scheduled to install the FPSO turret by the end of Q1 2015.

STRATEGIC REPORT

OPERATING REVIEW

INTERNATIONAL
OPERATIONS

Our Production Sharing Contract ('PSC') for PM8/Seligi in Malaysia includes the Seligi oil field, once the largest oil field off Peninsular Malaysia. PM8/Seligi combined has over 200 wells. This is a substantial opportunity for EnQuest to replicate the success of its strategy on Thistle, potentially on a considerably larger scale, significantly increasing production, extending PM8/Seligi's field life and increasing reserves.

Malaysia

PM8/Seligi has already materially increased EnQuest's overall production levels and by Q4 2014, the new fields were producing approximately 15,000 Boepd gross. Having taken over operatorship, EnQuest is focused on an ongoing programme to target efficiency improvements and to maximise recovery.

PM8/Seligi

Working interest at end 2014: 50%
Decommissioning liabilities:

· PM8, 50%

· Seligi, 50% of partial liability allocated based on ratio remaining oil reserves and to estimated ultimate recovery

In addition to the main production platform and separate gas compression platform, there are eleven minimum facility satellite platforms tied back to the main platform
Daily average net production:
2014: 3,459 Boepd (working interest)
2014: 2,078 Boepd (entitlement)
Reflects net production from June 2014 to December 2014, averaged over the full year.

2014

EnQuest assumed offshore field operations in October, while the overall transition completed in December 2014. Production from the fields has been strong and continues to increase. Going forward, EnQuest intends to enhance production through well interventions, facilities rectification and upgrades, and subsurface programmes that will lead to new wells.

2015 and beyond

The work programme is focused on well interventions and improving the field infrastructure, including gas compressors, power generators and ongoing integrity management of topside facilities and pipelines.

Tanjong Baram

Working interest at end 2014: 70%
Decommissioning liabilities: None

2014

In March 2014, EnQuest signed a Small Field Risk Service Contract with PETRONAS for the development of the Tanjong Baram field, offshore Sarawak. Tanjong Baram is being developed as an unmanned platform with production tied back to the Petronas Carigali operated West Lutong A complex. The development plan is based on a two well programme, with capacity for one additional well in the facilities design. Work on the development of the project is proceeding according to plan.

2015 and beyond

Development of field is underway, with first oil targeted by end of H1 2015, to be followed by steady state operations.

risks and uncertainties

Management of risks and uncertainties

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

exploiting its hydrocarbon reserves;

commercialising and developing discoveries;

converting its contingent resources into reserves; and

pursuing selective acquisitions.

In pursuit of this strategy, EnQuest has to face and manage a variety of risks. Accordingly, the Board has established a risk management framework to enhance effective risk management within the following overarching statement of risk appetite approved by the Board:

•We aim to deliver consistently above median investment performance

•We will manage the investment portfolio against agreed key performance indicators

•We seek to avoid reputational risk by ensuring that our operational processes and practices reduce the potential for error as far as practical

•We seek to embed a risk culture within our organisation which does not encourage excessive risk taking activities and is in line with overall risk appetite

•We seek to manage operational risk by means of a variety of controls to prevent or mitigate occurrence

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

A Risk Committee periodically reviews and updates the Group Risk Register based on the individual risk registers of its members. The Group Risk Register, along with an assurance mapping exercise and a risk report (focused on the most critical risks and emerging and changing risk profiles), is periodically reviewed by the Board (with senior management), to ensure that key issues are being adequately identified and actively managed. In addition, a system of risk reviews has been established to provide oversight in respect of prospective significant commitments.

Key business risks

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

Set out below are the principal risks and the mitigations together with an estimate of the potential impact and likelihood of occurrence after the mitigation actions and how these have changed in the past year.

	Risk		Mitigation
	Health, safety and environment (HSE) Oil and gas development, production and exploration activities are complex and HSE risks cover many areas including major accident hazards, personal health and safety, compliance with regulatory requirements and potential environmental harm. Potential impact - Medium (2013 Medium) Likelihood - Low (2013 Low) There has been no material change in the potential impact or likelihood and the Group's overall record on HSE remains robust.		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 continual improvement programme, promoting a culture of transparency in relation to HSE matters. The Group has established a Corporate HSE committee which meets quarterly. HSE performance is discussed at each board meeting. In addition, the Group has a positive, transparent relationship with the UK Health and Safety Executive and Department of Energy & Climate Change. EnQuest's HSE&A Policy and Principles are now fully integrated across our operated sites and this has enabled an increased focus on Health, Safety and the Environment. There is a strong assurance programme in place to ensure EnQuest complies with its Policy and Principles and regulatory commitments.
	Production The Group's production is critical to its success and is subject to a variety of risks including subsurface uncertainties, operating in a mature field environment and potential for significant unexpected shutdowns and unplanned expenditure to occur (particularly where remediation may be dependent on suitable weather conditions offshore). Lower than expected reservoir performance may have a material impact on the Group's results. The Group's delivery infrastructure in the UKCS is mostly dependent on the Sullom Voe Terminal. Longer term production is threatened if low oil prices bring forward decommissioning timelines. Potential impact - High (2013 High) Likelihood - Low (2013 Low) There has been no material change in the potential impact or likelihood.		The Group's programme of asset integrity and assurance activities provides leading indicators of significant potential issues which may result in unplanned shutdowns or which may in other respects have the potential to undermine asset availability and uptime. The Group continually assesses the condition of its assets and operates extensive maintenance and inspection procedures designed to minimise the risk of unplanned shutdowns and expenditure. The Group monitors both leading and lagging KPIs in relation to its maintenance activities and liaises closely with its downstream operators to minimise pipeline and terminal production impacts. Production efficiency is continually monitored and identified remedial and improvement opportunities undertaken as required. A continual, rigorous cost focus is also maintained. Life of asset production profiles are audited by independent reserves auditors. The Group also undertakes regular internal reviews. The Group's forecasts of production are risked to reflect appropriate production risks. The Sullom Voe Terminal has a good safety record and its safety and operational performance levels are regularly monitored and challenged by the Group and other terminal owners and users to ensure that operational integrity is maintained. Nevertheless, the Group actively continues to explore the potential of alternative transport options and developing hubs that may provide cost savings.
	Project execution The Group's success will be dependent upon bringing new developments, such as Alma/Galia (which was not delivered to schedule or budget) and Kraken, to production on budget and on schedule. To be successful, the Group must ensure that project implementation is both timely and on budget. Failure to do so may have a material negative impact on the Group's performance. Potential impact - High (2013 High) Likelihood - Medium (2013 Medium) The likelihood of occurrence of an event impacting project execution will have increased to an extent by virtue of the commencement of the capital works on Kraken, as at 13 March 2015. However, It should be noted that project execution risk on Alma/Galia is diminishing as the project enters its final stages, with Hook-up and Commissioning (HUC) of the FPSO now underway (as at 13 March 2015). All wells required for first oil are already drilled, completed and tied in.		The Group has project teams which are responsible for the planning and execution of new projects with a dedicated team for each development. The Group has detailed controls, systems and monitoring processes in place to ensure that deadlines are met, costs are controlled and that design concepts and Field Development Plans are adhered to and implemented. These are modified when circumstances require and only through a controlled management of change process and with the necessary internal and external authorisation and communication. The Group also engages third party assurance experts to review, challenge and, where appropriate, make recommendations to improve the processes for project management, cost control and governance of major projects. EnQuest ensures that responsibility for delivering time-critical supplier obligations and lead times are fully understood, acknowledged and proactively managed by the most senior levels within supplier organisations. The Kraken development was sanctioned by DECC and EnQuest's partners in November 2013. First oil production is scheduled for 2017. The development involves the drilling of 25 new subsea horizontal wells which will be connected to an FPSO. Prior to sanction, EnQuest identified and optimised the development plan using EnQuest's pre-investment assurance processes. Six appraisal wells have been drilled in the area, new seismic data was completed, considerable subsurface modelling was undertaken and front end engineering and design (FEED) studies were carried out for the FPSO and subsea integrated equipment. The first two subsea template structures were successfully installed on schedule in September 2014. In order to reduce project cost risk, more than 75% of the capital expenditure has been defined by actual tendering and placing of contracts. The FPSO involves conversion of an existing tanker which will be under a leased contracting arrangement for a fixed price.
	Reserve replacement Failure to develop its contingent and prospective resources or secure new licences and/or asset acquisitions and realise their expected value. Potential impact - High (2013 High) Likelihood - Medium (2013 Low) The likelihood has increased as oil price volatility limits business development activity. Low oil prices can potentially affect development of contingent and prospective resources and can also affect reserve certifications.		The Group puts a strong emphasis on subsurface analysis and employs industry leading professionals. The Group continues to recruit in a variety of technical positions which enables it to manage existing assets and evaluate the acquisition of new assets and licences. All analysis is subject to internal and, where appropriate, external review. All reserves are currently externally audited by a Competent Person. In addition, EnQuest has active business development teams both in the UK and internationally developing a range of opportunities and liaising with vendors/government.

	Financial Inability to fund financial commitments. The Group's revolving credit facility and retail bond contain certain financial covenants (each containing covenants based on the ratio of net indebtedness to EBITDA and finance charges to EBITDA) and in the case of the revolving credit facility, a requirement for liquidity testing. Prolonged low oil prices, cost increases and production delays or outages could threaten the Group's ability to comply with relevant covenants. . Potential impact - High (2013 High) Likelihood - Medium (2013 Medium) Low oil prices have impacted cash-flow adversely, increasing the potential impact and likelihood. However it is considered that the risk is being appropriately mitigated and remains controlled. Further information is contained in the Going Concern paragraph in the Financial Review.		During the year, the Group issued a $650m High Yield Bond which can be used to fund its development activities, and agreed a commercial loan of £31.8m in order to fund its Aberdeen office development. This funding is supported by operating cash inflow from the Group's producing assets. The Group reviews its cash flow requirements on an ongoing basis to ensure it has suitable resources for its needs. Post year-end, the Group renegotiated certain financial covenants under its revolving credit facility to provide greater flexibility for its capital investment programme. The net debt / EBITDA covenant has been increased to 5 times and the ratio of financial charges to EBITDA is reduced to 3 times, both until mid-2017. Ongoing compliance with the financial covenants under all of the group's lending arrangements (including the $650m High Yield Bonds and £155m Retail Bonds) is actively monitored and reviewed. The Group is maintaining a focus on costs through supplier renegotiations, cost-cutting and rationalization. Where costs are incurred by external service providers, e.g. at Sullom Voe Terminal, the group actively challenges operating costs.
	Human resources The Group's success is dependent upon its ability to attract and retain key personnel and develop organisational capability to deliver strategic growth. Industrial action across the sector could also impact on the operations of the Group. Potential impact - Low (2013 Medium) Likelihood - Low (2013 Low) There has been a reduction in the potential impact due to low oil prices impacting the buoyancy of the employment market.		The Group has established a competent employee base to execute its principal activities. In addition to this, the Group, which seeks to maintain good relationships with its employees and contractor companies, and regularly monitors the employment market to provide remuneration packages, bonus plans and long term share-based incentive plans that incentivise performance and long-term commitment from our employees to the Group. EnQuest is undertaking a number of human resource initiatives. These initiatives are part of the overall People and Organisation strategy and have specific themes relating to Organisation, People, Performance and Culture. It is a Board-level priority that the Executive and senior management have the right mix of skills and experience. The Group also maintains market-competitive contracts with key suppliers to support the execution of work where the necessary skills do not exist within the Group's employee base. The focus on Executive and senior management retention, succession planning and development remains an important priority for the Board and an increasing emphasis will continue to be placed on this.
	Reputation The reputational and commercial exposures to a major offshore incident are significant. Potential impact - High (2013 High) Likelihood - Low (2013 Low) There has been no material change in the potential impact or likelihood.		Operational activities are conducted in accordance with approved policies, standards and procedures. Interface agreements are agreed with all core contractors. The Group undertakes regular audit activities to provide assurance on compliance with established policies, standards and procedures.
	Oil price A material decline in oil and gas prices adversely affects the Group's operations and financial condition. Potential impact - High (2013 High) Likelihood - High (2013 Low) The potential likelihood has increased due to declining and volatile oil prices.		This risk is being mitigated by a number of measures including hedging production, renegotiating supplier contracts and lending arrangements and reducing costs and commitments. The Group monitors oil price sensitivity relative to its capital commitments and has a policy which allows hedging of its production. The Group has hedged significant amounts of its production in 2015 and 2016 using puts and calls. This ensures that the Group will receive a minimum oil price for its production. In order to develop its resources, the Group needs to be able to fund substantial levels of investment. The Group will therefore regularly review and implement suitable policies to hedge against the possible negative funding impacts of changes in oil prices whilst remaining within the limits set by its revolving credit facility. The Group has established an in-house trading and marketing function to enable it to enhance its ability to mitigate the exposure to volatility in oil prices.
	Political and fiscal Unanticipated changes in the regulatory or fiscal environment can affect the Group's ability to deliver its strategy and potentially impact revenue and future developments. Potential impact - High (2013 High) Likelihood - Medium (2013 Medium) Although the referendum on Scottish independence has taken place, there is a general election in May 2015. Whilst it appears unlikely that a new UK government will unexpectedly burden the industry in the current low oil price environment, the outcome of the general election is still uncertain.		It is difficult for the Group to predict the timing or severity of such changes. However, through Oil & Gas UK and other industry associations the Group does engage with government and other appropriate organisations in order to ensure the Group is kept abreast of expected potential changes and takes an active role in making appropriate representations. All business development or investment activities recognise potential tax implications and the group maintains relevant internal tax expertise. 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. Potential impact - Medium (2013 Medium) Likelihood - Medium (2013 Medium) There has been no material change in the potential impact or likelihood.		The Group operates regular cash call and billing arrangements with its co-venturers to mitigate the Group's credit exposure at any one point in time and keeps in regular dialogue with each of these parties to ensure payment. Risk of default is mitigated by joint operating agreements allowing the Group to take over any defaulting party's share in an operated asset and rigorous and continual assessment of the financial situation of partners. The Group generally prefers to be the operator. The Group maintains regular dialogue with its partners to ensure alignment of interests and to maximise the value of joint venture assets.
	Competition The Group operates in a competitive environment across many areas including the acquisition of oil and gas assets, the marketing of oil and gas, the procurement of oil and gas services and access to human resources. Potential impact - Medium (2013 Medium) Likelihood - Medium (2013 Low) There has been an increase in the perceived potential likelihood, due to recent emergence of new competitors for acquisitions (e.g. private equity) and the increased leverage of the Group.		The Group endeavours to have a resilient balance sheet, which puts it in a 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 and execute potential acquisition opportunities. The Group maintains good relations with oil and gas service providers and constantly keeps the market under review.
Portfolio Concentration The Group's assets are concentrated in the UK North Sea around a limited number of infrastructure hubs and existing production (which is principally only oil) is from mature fields. This amplifies exposure to key infrastructure, political/fiscal and oil price movements. Potential impact - Medium (2013 Medium) Likelihood - Medium (2013 Low)		This risk is mitigated in part through acquisitions. For all acquisitions, the Group uses a number of business development resources to evaluate and transact acquisitions in a commercially sensitive matter. This includes performing extensive due diligence (using in-house and external personnel) and actively involving executive management in reviewing commercial, technical and other business risks together with mitigation measures. During 2014, EnQuest acquired the PM8/Seligi producing asset in Malaysia as well as the Greater Kittiwake Area. The Group also constantly keeps its portfolio under rigorous review and accordingly, actively considers the potential for making disposals, executing development projects (Alma/Galia, Kraken), making international acquisitions and expanding hubs.
International business Whilst the majority of the Group's activities and assets are in the UK, the international business is becoming more material. The Group's international business is subject to the same risks as the UK business (e.g. HSE, production and project execution); however, there are additional risks that the Group faces including security of staff and assets, political, foreign exchange and currency control, taxation, legal and regulatory, cultural and language barriers and corruption. Potential impact - Medium (2013 Medium) Likelihood - Medium (2013 Low) The expanded international business has increased the likelihood of the overall risk. In addition, oil price uncertainty has increased the potential impact and likelihood of a slowdown in international growth plans.		Prior to entering into a new country, EnQuest evaluates the host country to assess whether there is an adequate and established legal and political framework in place to protect and safeguard first its expatriate and local staff and, second, any investment within the country in question. When evaluating international business risks, executive management reviews commercial, technical and other business risks together with mitigation and how risks can be managed by the business on an ongoing basis. EnQuest looks to employ suitably qualified host country staff and work with good quality local advisers to ensure it complies within national legislation, business practices and cultural norms whilst at all times ensuring that staff, contractors and advisers comply with EnQuest's business principles, including those on financial control, cost management, fraud and corruption. Where appropriate, the risks may be mitigated by entering a joint venture with partners with local knowledge and experience. After country entry, EnQuest maintains a dialogue with local and regional government, particularly with those responsible for oil, energy and fiscal matters, and may obtain support from appropriate risk consultancies. When there is a significant change in the risk to people or assets within a country, the Group takes appropriate action to safeguard people and assets.

STRATEGIC REPORT

FINANCIAL REVIEW

Financial Overview

The Group has delivered a strong operational performance in 2014 against a backdrop of falling oil prices and general industry cost pressures. Significant capital investment in growth projects continued throughout the year.

In the year ended 31 December 2014, the Brent crude oil price averaged $98.9 per barrel compared to $108.7 per barrel for 2013. Total production volumes were 15% higher for the year ended 31 December 2014 which resulted in revenue of $1,009.9 million compared with $961.2 million in 2013.

	Business performance
	2014	2013
	$ million	$ million

Profit from operations before tax and finance income/(costs)	362.5	374.8
Depletion and depreciation	245.1	224.0
Intangible impairments and write-offs	0.6	2.0
Net foreign exchange (gains)/losses	(27.2)	20.5
EBITDA	581.0	621.3

EBITDA for the year ended 31 December 2014 was $581.0 million compared with $621.3 million in 2013. The lower EBITDA is mainly due to lower oil prices in H2 2014 and higher tariff and transportation costs.

In H1 2014 the Group successfully raised a $650 million high yield bond. The 8 year bond further diversified the Company's capital base and gives long term maturities for its debt profile. At the year end $217.6 million was drawn on the $1.2 billion Revolving Credit Facility (RCF) before taking into account cash balances of $176.8 million. In addition, during the year, the Group also entered a £31.8 million 2 year development loan facility to finance the construction of the Group's Aberdeen office building.

Following receipt of the bond proceeds EnQuest entered into a number of foreign exchange transactions to swap $550 million of the US Dollar proceeds into Sterling to enable it to repay Sterling drawings under the RCF. The transactions required EnQuest to swap Sterling back into US Dollars between October and December 2014 at a fixed rate. In early October 2014 the transactions were closed out realising a gain of $46.7 million.

	Net debt/(cash)
	2014	2013
	$ million	$ million

Bond¹	882.6	254.5
Multi-currency revolving credit facility¹	193.5	199.4
Property Loan¹	33.5	-
Cash and cash equivalents	(176.8)	(72.8)
	932.8	381.1

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

Through these facilities, EnQuest has a diversified and long term funding base providing financing for current projects.

As a result of the continued capital investment, UK corporate tax losses at the end of the year increased to approximately $1,818 million. The effective tax rate for the year excluding exceptional items is 43.5% which reflects the blend of UK and international assets. In the current environment, no material corporation tax or supplementary corporation tax is expected to be paid on UK operational activities before 2025. The Group paid cash corporate income tax on assets acquired in Malaysia and this is expected to continue throughout the life of the production sharing contract (PSC).

Income Statement

Production and revenue

Production levels, on a working interest basis, for the year ended 31 December 2014 averaged 27,895 Boepd compared with 24,222 Boepd in 2013. The increase reflects a substantial initial contribution from PM8/Seligi in Malaysia, higher production in the Thistle field which has been experiencing high production efficiency and ten months of production from the newly acquired Greater Kittiwake Area (GKA) assets. This was partially offset by the expected natural decline in the Don fields.

The Group's blended average realised price per barrel of oil sold was $100.6 for the year ended 31 December 2014, below the $109.7 per barrel received for 2013, reflecting the decline in the oil price in Q4 2014. Revenue is predominantly derived from crude oil sales and for the year ended 31 December 2014 crude oil sales totalled $970.5 million compared with $953.8 million in 2013. The increase in revenue was due to the higher production and an overlift of $8.2 million in 2014 compared with an overlift of $2.6 million in 2013 and partly offset by a reduction in the oil price. Within revenue in 2014 there is $31.7 million of realised income relating to oil commodity hedges and call options.

Operating costs

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

	Reported	Reported
	year ended 31 December	year ended 31 December
	2014	2013
	$ million	$ million

Cost of sales	654.1	526.3

	$	$
Unit operating cost, adjusted for over/underlift and inventory movements (per barrel):
-Production costs	31.5	27.2
-Tariff and Transportation costs	10.6	8.3
-Operating costs	42.1	35.5

-Depletion of oil and gas properties	24.6	24.6
	66.7	60.1

Cost of sales pre-exceptionals and depletion of fair value adjustments was $654.1 million for the year ended 31 December 2014 compared with $526.3 million in 2013. An increase of $85.3 million was due to costs relating to the GKA and PM8/Seligi acquisitions and an increase of $34.0 million was due to increased transportation costs. The significant increase in the latter was partly due to increased volumes, but mainly due to an increase in the costs per barrel at the Sullom Voe Terminal (SVT). This has been partially offset by an overall gain relating to the bond proceeds currency transactions and realised mark to market valuations on foreign exchange trades.

The Group's operating costs comprise production costs and tariff and transportation costs which were $436.5 million for the year ended 31 December 2014 compared with $308.0 million in 2013. Transportation costs increased from $73.5 million to $140.0 million for the year ended 31 December 2014 mainly due to significantly higher unit costs per barrel at SVT. Production costs increased by $61.7 million to $296.2 million for the year ended 31 December 2014, partly attributable to the acquisition of the GKA asset on 1 March 2014 and the PM8/Seligi Malaysian asset acquired at the end of June. In the other producing assets, higher costs in Thistle and Heather related to diesel usage and increased logistics and maintenance costs.

There has been a significant increase in SVT tariff costs. Costs are $28.9 million higher than prior year due to a higher base level of costs incurred by the operator and also EnQuest being allocated a higher proportion of SVT costs in 2014. This reflects EnQuest's increased production and therefore higher share of throughput at SVT. In addition, the exceptional items include a charge of $32.8 million in respect of 2012 and 2013 costs which were only notified to EnQuest by the operator in 2014. Working collaboratively with the SVT operator and co-owners, gross costs are expected to be reduced going forward and also a lower proportion of these will accrue to EnQuest. The project to define the medium to long term future is maturing in its definition and we expect the SVT operator to define the project fully in 2015. Finally, the unit operating cost per barrel has been adjusted for a 40% allocation of the gain from the bond proceeds currency transactions, which reflects the approximate ratio of operational expenditure to capital expenditure for the year.

Due to the above factors, the Group's average unit production and transportation cost has increased by $6.6 per barrel.

The Group's depletion expense per barrel for the year is consistent with the previous year with a higher rate in Heather and Thistle as a consequence of a higher capex profile offset by lower production in the Don fields.

The Group's change in lifting position was an $8.2 million expense for the year ended 31 December 2014, compared with an expense of $2.6 million in 2013. The net overlift during 2014 has increased mainly due to the UK operated assets being in an overlift position offset with an underlift in Alba and Malaysia.

Exploration and evaluation expenses

Exploration and evaluation expenses were $4.0 million in the year compared with $8.6 million reported in the previous year. The expenses in 2014 primarily relate to South West Heather, Norway's pre-licence costs and costs relating to the 28^th Licence Round in the UK.

General and administrative expenses

General and administrative expenses were $16.5 million in the year ended 31 December 2014 compared with $25.0 million reported in the previous year. A reduction in business development specific costs and higher Parent Company Overhead (PCO) recovery accounts for the majority of the movement.

Other income and expenses

Other income is comprised of net foreign exchange gains of $27.2 million in the year ended 31 December 2014 relating to exchange rate fluctuations relating to the retail bond and bank loans.

Taxation

The tax charge for the year of $105.8 million, excluding exceptional items, represents an effective tax rate of 43.5% compared with 43% in the previous year. The small increase in the Group's effective tax rate for the year is due primarily to foreign exchange losses relieved at the mainstream tax rate, partly offset by an increase in the Ring Fence Expenditure Supplement on UK activities.

Exceptional items and depletion of fair value uplift

Exceptional losses totalling $821.9 million before tax have been disclosed separately in the year ended 31 December 2014. Tangible oil and gas assets have been impaired by $678.8 million relating to the Don fields and Alma/Galia. The impairment is primarily due to the significant fall in the oil price in the latter part of 2014.

Exceptional items also includes an impairment of $152.0 million to intangible costs for the year ended 31 December 2014. The majority of the costs relate to the Crawford, Porter, Kildrummy and Cairngorm licences and some GKA acreage in the UK. In current market conditions some of these interests do not merit sufficient funds to progress them to economic development. The impairment also includes costs on the unsuccessful exploration well in the SB307/308 block in Malaysia.

The remaining balance is made up of SVT costs of $32.8 million invoiced by the operator in 2014, but relating to 2012 and 2013 production, $6.9 million of depletion on the fair value uplift on acquisitions and $19.2 million unrealised mark to market losses on derivative contracts offset by negative goodwill of $28.6 million relating to the acquisition of PM8/Seligi in Malaysia.

The tax impact of the exceptional items is a tax credit of $508.1 million, resulting in an overall tax credit for the year of $402.3 million and an overall effective tax rate of 69.5%.

Finance costs

Finance costs of $121.1 million include $52.1 million of bond and loan interest payable, $12.1 million unwinding of discount on decommissioning provisions, $41.4 million relating to the time value of the closed out puts. Other financial expenses of $18.5 million are primarily commitment and letter of credit fees of $11.6 million as well as arrangement fee amortisation relating to the bank facilities and bonds of $6.8 million. The Group capitalised interest of $3.2 million for the year ended 31 December 2014 in relation to the interest payable on borrowing costs on its capital development projects.

Finance income

Finance income of $1.8 million includes $0.3 million of bank interest receivable, $0.4 million VAT interest received and $0.9 million unwinding on the financial asset created in 2012 as part of the consideration for the farm out of the Alma/Galia development to KUFPEC.

Earnings per share

The Group's reported basic earnings per share was (22.8) cents for the year ended 31 December 2014 compared with 24.4 cents in 2013. The decrease of 47.2 cents was attributable to higher operating, finance and exceptional impairment costs offset slightly by a lower tax charge for 2014. The Group's reported diluted earnings per share excluding exceptional items was 17.8 cents for the year ended 31 December 2014 compared with 24.0 cents in 2013. The decrease of 6.2 cents was mainly attributable to lower gross profit and higher finance costs offset by a lower effective income tax rate.

Cash flow and liquidity

The Group's reported cash generated from operations in 2014 was $637.1 million compared with $562.7 million in 2013. The reported cash flow from operations per share was 82.3 cents per share compared with 72.3 cents per share in 2013. The increase is mainly due to a decrease in trade receivables and joint venture debtors, an increase in trade payables, accrued payables and a decrease in the opening underlift position .

During the year ended 31 December 2014, $2.1 million was received in relation to an exploration refund for EnQuest Norge AS's activities in Norway. In addition, $7.9 million was paid during the year ended 31 December 2014 in relation to EnQuest Group's UK tax liabilities for non-operational activities and petroleum revenue tax (PRT). $6.6 million was paid in relation to the Group's operations in Malaysia.

It is anticipated that the underlying effective tax rate for 2015 will be materially below the UK statutory tax rate of 60%, excluding one-off exceptional tax items, mainly due to the impact of Ring Fence Expenditure Supplement. In the current environment and with the investment in the North Sea, the Group does not expect a material cash outflow for UK corporation tax on operational activities before 2025. This is due to the projected level of capital expenditure, which benefits from tax deductible first year capital allowances in the UK, available field allowances and accumulated tax losses which are largely attributable to the Group's capital investment programme to date.

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


	2014	2013
	$ million	$ million

Expenditure on producing oil and gas assets	318.0	294.5
Development expenditure	628.1	632.0
Exploration and evaluation capital expenditure	69.7	36.6
Other capital expenditure	44.5	21.2
	1,060.3	984.3

Significant projects were undertaken during the year, including:

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

· the Kraken development;

· the Thistle life extension programme;

· the Dons drilling programme on the TJ production well and the scale dissolver programme at Don Southwest;

· Ythan JT well;

· the acquisition of GKA and successful workover of Mallard;

· the Heather/Broom drilling programme was completed and drilling programmes on H44, H47 and H56; and

· PM8/Seligi acquisition.

Net debt at 31 December 2014 amounted to $932.8 million compared with net debt of $381.1 million in 2013.

In H1 2014, the Group successfully issued a $650 million high yield bond, with a 7% coupon and a 2022 maturity.

In 2015, the Group renegotiated financial covenants under its RCF to provide greater flexibility for its capital investment programme. The net debt/EBITDA covenant has been increased to 5 times and the ratio of financial charges to EBITDA is reduced to 3 times, both until mid-2017. Compliance with ongoing covenants continues to be a priority for the Group.

Balance Sheet

The Group's total asset value has increased by $545.4 million to $4,095.9 million at 31 December 2014 (2013: $3,550.5 million).

Property, plant and equipment

Property, plant and equipment (PP&E) has increased to $3,116.4 million at 31 December 2014 from $2,871.2 million at 31 December 2013. The increase of $245.2 million is mainly due to oil and gas asset capital additions of $839.5 million. The main spend relates to Kraken ($112.7 million) and Alma/Galia ($415.8 million). There was also $82.1 million in relation to changes in estimates on the decommissioning provisions and $206.1 million of acquisition costs mainly relating to GKA ($55.0 million) and Malaysia ($150.9 million). Depletion and depreciation charges of $252.0 million were incurred as well as an impairment charge of $678.8 million.

The oil and gas asset capital additions, including carry arrangements, during the year are set out in the table below:
	2014
	$ million

Dons hub	53.1
Thistle hub	79.8
Heather and Broom hub	96.4
Alma/Galia	415.8
Kraken	112.7
Alba	4.5
GKA	95.7
PM8/Seligi	160.8
Tanjong Baram	22.1
Other	4.8
	1,045.7

On 1 March 2014, EnQuest completed the acquisition of the GKA assets including an interest in the Kittiwake to Forties oil export pipeline. In June 2014, EnQuest completed the acquisition of the Seligi oil field and the PM8 PSC, located offshore Malaysia.

Intangible oil and gas assets

Intangible oil and gas assets decreased by $65.2 million to $65.7 million at 31 December 2014. The decrease mainly relates to impairments on the Crawford, Porter, Kildrummy and Cairngorm licenses and some GKA acreage in the UK.

Investments

The Group holds an investment of 160,903,958 new ordinary shares in Ascent Resources plc which is valued at $0.7 million based on the quoted bid price as at 31 December 2014.

Inventory

Inventory increased by $42.6 million, the increase relates to the purchase of christmas trees of $22 million and drilling and operational inventory.

Trade and other receivables

Trade and other receivables have increased by $19.0 million to $286.2 million at 31 December 2014 compared with $267.2 million in 2013. Prepayments and accrued income include the initial payment of $100 million to Armada Kraken PTE Limited for the lease of an FPSO vessel for the Kraken field. Trade receivables and joint venture receivables have both decreased in line with normal business activity.

Cash and bank

The Group had $176.8 million of cash and cash equivalents at 31 December 2014 and $217.6 million was drawn down on the $1.2 billion RCF.

Provisions

The Group's decommissioning provision increased by $221.3 million to $449.7 million at 31 December 2014 (2013: $228.4 million). The acquisition of GKA and PM8/Seligi have an associated provision of $124.3 million. EnQuest has a 50% interest in the GKA area, but is only responsible for approximately 25% of the decommissioning liability for the platform. The decommissioning provision for GKA is $77.6 million. For the PM8 PSC, EnQuest's estimated share of decommissioning provision is approximately $46.7 million, for which the PSC contractors are required to make annual cost recoverable contributions into a sinking fund based on a pro-rata production basis.

The Group has re-evaluated the discount rate to be used when discounting the Group's decommissioning liabilities. The liability is discounted at 3% (2013: 5%) and this is included as a change in estimate, resulting in an increase of $77.4 million. The underlying costs for the UK assets remain consistent with the third party report that was commissioned in 2013 to complete the detailed triennial study to review decommissioning cost estimates for the operated producing hubs.

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

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

Income tax

The Group had no UK corporation tax or supplementary corporation tax liability at 31 December 2014, which remains unchanged from the prior year. The Group had PRT recoverable of $4.4m at 31 December 2014 compared with a $4.0 million liability at 31 December 2013. The decrease is due to over paid PRT instalments on Alba in the second half of 2014. The income tax asset at 31 December 2014 represents the expected refund on exploration activities undertaken in Norway, a pre-acquisition corporate income tax overpayment in Malaysia, and the expected PRT refund.

Deferred tax liability

The Group's deferred tax liability (net of deferred tax assets) has decreased by $283.7 million to $462.6 million at 31 December 2014 from $746.3 million in 2013. The decrease is mainly due to the impairment charge, partly offset by the capital expenditure programme undertaken by the Group during the year which provides the Group with 100% first year capital allowance claims as well as an increase in ring fence taxation losses carried forward and deferred tax liabilities arising on the acquisition of assets in Malaysia. Total UK tax losses carried forward at the year end amount to approximately $1,818 million.

Trade and other payables

Trade and other payables have increased to $429.1 million at 31 December 2014 from $363.3 million at 31 December 2013. The increase of $65.8 million is due to an increase in trade payables of $57.8 million in line with increased activity in the year and an increase in the overlift position of $13.1 million.

Other financial liabilities

Other current liabilities have decreased by $68.4 million to $101.5 million. The decrease relates to the Kraken 'firm' carry which has reduced throughout the year, amounting to $99.0 million. This is offset by an increase relating to commodity forward contracts and forward foreign currency contracts of $29.6 million.

Other non-current financial liabilities have increased by $22.9 million. The balance is made up of commodity forward contracts of $18.0 million that expire in 2016 and $5.7 million relating to a carry liability with respect to PM8.

Financial Risk Management

The Group is exposed to the impact of changes in Brent crude oil prices on its revenue and profits. EnQuest's policy is to manage the impact of commodity prices and during 2013 the Company entered into commodity hedging contracts to hedge partially the exposure to fluctuations in the Brent oil price during 2014. A total of 3.6 million barrels of puts (300,000 barrels per month) were bought at a price of $106 per barrel and 7.2 million barrels of calls were sold at a price of $106 per barrel, which would only be triggered if the monthly average price of Brent exceeded a fixed price for the given month (ranging from $119 to $124 per barrel).

During Q1 2014, the Company swapped an additional 1 million barrels in Q2 at prices of approximately $109 per barrel. An additional 1 million barrels were swapped in Q2 at a price of $105/bbl.

In Q4 2014, the Company bought puts covering 8 million barrels to hedge 2015 production at an average price of $87.3/bbl. In addition, the Company sold calls covering 8 million barrels maturing in 2015 and 7.5 million barrels maturing in 2016. The put position was closed in Q4 2014, with the Company purchasing new puts covering 10 million barrels of 2015 production priced at $65/bbl and selling a further 2.25 million barrels of 2015 calls. In return, for closing out the $87.3/bbl puts and purchasing the lower priced puts and selling the additional calls, the Company received cash of $100 million. Gains of $119.1 million in respect of the 8 million barrels of puts closed in December, which were designated as hedges of 2015 production, have been deferred in equity, and will be recognised during 2015.

After the year end the Group hedged 10 million barrels of production for 2016, through the purchase of puts with an average strike price of $68.2/bbl on a pro rata basis throughout 2016. In addition, the Group sold further calls maturing in mid-2015 and through 2016. In total, as at the date of this report, the Group has sold 11.8 million barrels of 2015 calls with an average strike price of $80.55/bbl, and 13.5 million barrels of 2016 calls with an average strike price of $88.53/bbl.

The total premiums received or receivable through the sale of calls to date totals $115.0 million. This premium will be realised in the income statement over the life of the options. In total $6.8 million was realised in 2014, with a further $82.4 million and $25.8 million to be realised in 2015 and 2016 respectively. Unrealised mark to market movements in these options will be recognised as an exceptional item in line with the Company's accounting policy.

EnQuest's functional currency is US Dollars. Foreign currency risk arises on purchases and the translation of assets and liabilities denominated in currencies other than US Dollars. To mitigate the risks of large fluctuations in the currency markets, the hedging policy agreed by the Board allows for up to 70% of the non-US Dollar portion of the Group's annual capital budget and operating expenditure to be hedged. For specific contracted capital expenditure projects, up to 100% can be hedged. During the first half of 2013, the Group entered into a structured product to hedge a portion of its Sterling, and Norwegian Krone exposure throughout 2013 and 2014. During 2014, a total of £182 million of Sterling exposure was hedged using this structured product with an average strike price of $1.46:£1. If the spot rate at expiry of the contracts was above $1.64:£1 then there was no trade and the Group funded its Sterling requirement through the spot market or drew Sterling on the bank facility. Between $1.64:£1 and $1.33:£1, EnQuest traded at the lower of $1.46:£1 and the spot rate, and below $1.33:£1, EnQuest traded a higher volume of currency at $1.46:£1.

The same structure was also used to hedge the Group's Norwegian Krone (NOK) exposure arising as part of the Kraken development project. In 2014, a total of NOK367 million was hedged.

During 2014 the Company entered into several foreign exchange swap contracts when Sterling was trading above $1.66:£1. The realised impact of $46.7 million has been recognised in the income statement within cost of sales.

EnQuest continually reviews its currency exposures and when appropriate looks at opportunities to enter into foreign exchange hedging contracts.

Surplus cash balances are deposited as cash collateral against in-place letters of credit as a way of reducing interest costs. Otherwise cash balances can be invested in short term bank deposits and AAA-rated liquidity funds, subject to Board approved limits and with a view to minimising counterparty credit risks.

Going Concern

The Group closely monitors and manages its liquidity risk throughout the year, including monitoring forecast covenant results. Cash forecasts are regularly produced and sensitivities considered for, but not limited to, changes in crude oil prices (adjusted for hedging undertaken by the Group), production rates and development project timing and costs. These forecasts and sensitivity analyses allow management to mitigate any liquidity or covenant compliance risks in a timely manner.

Following the significant decline in oil prices, management has taken action to implement certain cost saving programmes, to reduce planned operational expenditure, general and administrative spend and capital expenditure in 2015 and 2016. Management also successfully renegotiated certain covenants contained within the Revolving Credit Facility.

At year end, the Group had significant headroom on its borrowing facilities and related financial covenants under both the Revolving Credit Facility and the Retail Bond. The Group's forecasts and projections take into account the actions described in the preceding paragraph, and reflect the assumption that the Group's major projects remain on track. These forecasts indicate that the Company will be able to operate within the requirements of its existing borrowing facilities for 12 months from the date of approval of the Annual Report and Accounts. Forecasts therefore indicate that the Group's liquidity will remain strong. Furthermore, if there were further sustained falls in the oil price or the benefits of planned initiatives are not realised, management has a number of options available to it to maintain strong liquidity, including asset sales, new financings or amendment of covenants under the existing financing arrangements (including the Retail Bond) and may do so as a precautionary measure should it determine that it is appropriate or prudent to do so. The directors therefore continue to adopt the going concern basis in preparing the financial statements.

KEY PERFORMANCE INDICATORS

	2014	2013

Lost Time Incident Frequency (LTIF)	0.00	1.36

2P reserves (MMboe)	220.0	194.8

Business performance data:
Production (Boepd)	27,895	24,222
Revenue ($ million)	1,009.9	961.2
Realised blended average oil price per barrel ($)	100.6	109.7
Opex per barrel (production and transportation costs) ($)	42.1	35.5
Gross profit excluding exceptional items ($ million)	355.8	434.9
Cash capex on property, plant and equipment oil and gas assets($ million)	1,060.3	984.3

Reported data:
Cash generated from operations ($ million)	637.1	562.7
Net debt ($ million)	(932.8)	(381.1)
Profit before tax excluding exceptional items ($ million)	243.3	338.0
Basic earnings per share (cents)	(22.8)	24.4
EBITDA ($ million)	581.0	621.3

EnQuest PLC

Abridged Group Income Statement

For the year ended 31 December 2014

2014

2013

Business Performance

US$'000

Exceptional items and depletion of fair value uplift

US$'000

Total for period

US$'000

Business Performance

US$'000

Exceptional items and depletion of fair value uplift

US$'000

Total for period

US$'000

Revenue

1,009,884

18,611

1,028,495

961,199

(5,954)

955,245

Cost of sales

(654,061)

(57,797)

(711,858)

(526,321)

(822)

(527,143)

Gross profit/(loss)

355,823

(39,186)

316,637

434,878

(6,776)

428,102

Exploration and evaluation expenses

(4,033)

(151,982)

(156,015)

(8,641)

Impairment on available for sale assets

(1,316)

(312)

Impairment of oil and gas assets

(678,801)

Negative goodwill

28,630

Gain on disposal of intangible oil and gas assets

2,019

General and administration expenses

(16,464)

(25,024)

Other (expenses)/income, net

27,176

(20,452)

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

362,502

(840,636)

(478,134)

374,823

(7,088)

367,735

EBITDA*

580,993

(32,316)

548,677

621,300

1,733

623,033

Notes:

* EBITDA is calculated on a business performance basis, and is calculated by taking profit/loss from operations before tax and finance income/(costs) and adding back depletion, depreciation and foreign exchange movements. EBITDA is not a measure of financial performance under IFRS.

EnQuest PLC

OIL AND GAS RESERVES AND RESOURCES

At 31 December 2014

	UKCS		Other Regions		Total
	MMboe	MMboe	MMboe	MMboe	MMboe

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

At 1 January 2013		194.76	-	-	194.76
Revisions of previous estimates		5.33	-	-	5.33
Discoveries, extensions and additions (note 7)		7.25	-	-	7.25
Acquisitions and disposals (note 8, 9)		6.21	-	16.54	22.75
Production:
Export meter	(8.92)		(1.30)
Volume adjustments (note 5)	0.14		-
		(8.78)		(1.30)	(10.08)
Proven and Probable Reserves at 31 December 2014 (note 10)		204.76		15.24	220.00

Contingent Resources (notes 1, 2 & 4)

At 1 January 2013		117.00		4.40	121.40
Revisions of previous estimates		6.12		-	6.12
Discoveries, extensions and additions		2.53		-	2.53
Acquisitions (note 8)		20.61		52.27	72.88
Disposals (note 9)		(14.28)		(4.40)	(18.68)
Promoted to reserves (note 7)		(13.62)		-	(13.62)
Contingent Resources at 31 December 2014		118.36		52.27	170.63

Notes:

(1) Reserves are quoted on a net entitlement basis, resources are quoted on a net working interest basis.

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

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

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

(5) Correction of export to sales volumes.

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

(7) Contingent Resources previously allocated to Scolty Crathes have been classified as reserves following development planning. Ythan resources have been classified as reserves due to the approval for development.

(8) Seligi and PM8 assets in Malaysia were acquired in June 2014. Greater Kittiwake Area assets were acquired in March 2014. West and east Torphins, Avalon and Shelterstone acquired.

(9) Cairngorm appraised and farmed down, Peik relinquished in January 2014 and Horizon West sold in November 2014.

(10) The above Proven and Probable Reserves include 10.5 MMboe that will be consumed as lease fuel on the Kraken and Alma FPSOs.

(11) The above table excludes Tanjong Baram in Malaysia.

EnQuest PLC

GROUP STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 December 2014

			2014		2013
	Notes	Business performance	Depletion of fair value uplift, re-measurements, impairments and other exceptional items (note 4)	Reported in year	Business performance	Depletion of fair value uplift, re-measurements, impairments and other exceptional items (note 4)	Reported in year
		US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Revenue and other operating income	5(a)	1,009,884	18,611	1,028,495	961,199	(5,954)	955,245
Cost of sales	5(b)	(654,061)	(57,797)	(711,858)	(526,321)	(822)	(527,143)

Gross profit/(loss)		355,823	(39,186)	316,637	434,878	(6,776)	428,102
Exploration and evaluation expenses	5(c)	(4,033)	(151,982)	(156,015)	(8,641)	-	(8,641)
Impairment of investments	4	-	(1,316)	(1,316)	-	(312)	(312)
Impairment of oil and gas assets	4	-	(678,801)	(678,801)	-	-	-
Negative goodwill	13	-	28,630	28,630	-	-	-
Gain on disposal of intangible oil and gas assets	12	-	2,019	2,019	-	-	-
General and administration expenses	5(d)	(16,464)	-	(16,464)	(25,024)	-	(25,024)
Other income	5(e)	27,176	-	27,176	-	-	-
Other expenses	5(f)	-	-	-	(26,390)	-	(26,390)

Profit/(loss) from operations before tax and finance income/(costs)		362,502	(840,636)	(478,134)	374,823	(7,088)	367,735

Finance costs	6	(121,066)	18,698	(102,368)	(38,830)	-	(38,830)
Finance income	6	1,814	-	1,814	2,030	-	2,030

Profit/(loss) before tax		243,250	(821,938)	(578,688)	338,023	(7,088)	330,935

Income tax	7	(105,841)	508,120	402,279	(146,607)	5,276	(141,331)

Profit/(loss) for the year attributable to owners of the parent		137,409	(313,818)	(176,409)	191,416	(1,812)	189,604

Other comprehensive income for the year, after tax:
Cash flow hedges: may be reclassified subsequently to profit or loss Deferred tax on gain on cash flow hedges Available for sale financial assets	21 7 14			156,281 (96,894) (398)			46 - 398
Total comprehensive income for the year, attributable to owners of the parent				(117,420)			190,048

Earnings per share	8	US$		US$	US$		US$
Basic		0.178		(0.228)	0.246		0.244
Diluted		0.178		(0.228)	0.240		0.238

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

EnQuest PLC

GROUP BALANCE SHEET

At 31 December 2014

	Notes	2014	2013
ASSETS		US$'000	US$'000
Non-current assets
Property, plant and equipment	10	3,116,405	2,871,229
Goodwill	11	189,317	107,760
Intangible oil and gas assets	12	65,710	130,874
Investments	14	689	2,403
Deferred tax assets	7	40,401	14,731
Other financial assets	21	18,809	21,928
		3,431,331	3,148,925

Current assets
Inventories	15	89,397	46,814
Trade and other receivables	16	286,227	267,180
Current tax receivable		11,199	6,275
Cash and cash equivalents	17	176,791	72,809
Other financial assets	21	100,932	8,455
		664,546	401,533
TOTAL ASSETS		4,095,877	3,550,458

EQUITY AND LIABILITIES
Equity
Share capital	18	113,433	113,433
Merger reserve		662,855	662,855
Cash flow hedge reserve		59,387	-
Available-for-sale reserve		-	398
Share-based payment reserve		(17,696)	(10,280)
Retained earnings		541,894	718,303
TOTAL EQUITY		1,359,873	1,484,709

Non-current liabilities
Borrowings	20	227,035	199,396
Bond	20	882,561	254,500
Obligations under finance leases	25	36	72
Provisions	23	556,368	308,426
Other financial liabilities	21	23,694	839
Deferred tax liabilities	7	503,037	760,993
		2,192,731	1,524,226

Current liabilities
Bond	20	12,689	4,291
Trade and other payables	24	429,070	363,310
Obligations under finance leases	25	36	35
Other financial liabilities	21	101,478	169,891
Current tax payable		-	3,996
		543,273	541,523

TOTAL LIABILITIES		2,736,004	2,065,749

TOTAL EQUITY AND LIABILITIES		4,095,877	3,550,458

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

The financial statements on pages 81 to 116 were approved by the Board of Directors on 18 March 2015 and signed on its behalf by:

Jonathan Swinney

Chief Financial Officer

EnQuest PLC

GROUP STATEMENT OF CHANGES IN EQUITY

At 31 December 2014

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

At 1 January 2013	113,433	662,855	(46)	-	(11,072)	528,699	1,293,869

Profit for the year	-	-	-	-	-	189,604	189,604
Other comprehensive income	-	-	46	398	-	-	444
Total comprehensive income for the year	-	-	46	398	-	189,604	190,048

Share-based payment charge	-	-	-	-	8,193	-	8,193
Shares purchased on behalf of Employee Benefit Trust	-	-	-	-	(7,401)	-	(7,401)

At 31 December 2013	113,433	662,855	-	398	(10,280)	718,303	1,484,709

Loss for the year	-	-	-	-	-	(176,409)	(176,409)
Other comprehensive income	-	-	59,387	(398)	-	-	58,989
Total comprehensive income for the year	-	-	59,387	(398)	-	(176,409)	(117,420)

Share-based payment charge	-	-	-	-	8,468	-	8,468
Shares purchased on behalf of Employee Benefit Trust	-	-	-	-	(15,884)	-	(15,884)

At 31 December 2014	113,433	662,855	59,387	-	(17,696)	541,894	1,359,873

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

EnQuest PLC

GROUP STATEMENT OF CASH FLOWS

For the year ended 31 December 2014

		2014	2013
	Notes	US$'000	US$'000
CASH FLOW FROM OPERATING ACTIVITIES
(Loss)/profit before tax		(578,688)	330,935
Depreciation	5(d)	7,438	6,914
Depletion	5(b)	244,531	225,654
Exploration costs impaired and written off	5(c)	152,550	1,966
Impairment of oil and gas assets	4	678,801	-
Gain on disposal of intangible oil and gas assets	4	(2,019)	-
Impairment on available-for-sale investments	4	1,316	312
Negative goodwill	4	(28,630)	-
Share-based payment charge	5(g)	8,468	8,193
Unwinding of discount on decommissioning provisions	6	12,094	12,588
Unrealised losses on financial instruments	5(a)(b)	(1,447)	(5,938)
Unrealised exchange (gains)/losses	5(e)(f)	(27,176)	26,390
Net finance costs	6	88,461	22,479
Operating profit before working capital changes		555,699	629,493
Decrease/(increase) in trade and other receivables		96,243	(30,828)
Increase in inventories		(41,748)	(30,849)
Increase/(decrease) in trade and other payables		26,876	(5,126)
Cash generated from operations		637,070	562,690
Cash received on sale of financial instruments		100,126	-
Decommissioning spend		(7,177)	-
Income taxes paid		(12,503)	(11,278)
Net cash flows from operating activities		717,516	551,412
INVESTING ACTIVITIES
Purchase of property, plant and equipment		(990,563)	(950,326)
Purchase of intangible oil and gas assets		(69,749)	(36,593)
Proceeds from disposal of intangible oil and gas assets		2,162	-
Acquisitions		(58,233)	-
Prepayment of finance lease		(100,000)	-
Proceeds from farm-out		-	2,648
Interest received		936	583
Net cash flows used in investing activities		(1,215,447)	(983,688)
FINANCING ACTIVITIES
Proceeds from bank facilities		42,034	182,731
Proceeds from bond issue		650,000	246,345
Shares purchased by Employee Benefit Trust		(15,884)	(7,401)
Repayment of obligations under finance leases		(35)	(35)
Interest paid		(43,582)	(9,025)
Other finance costs paid		(23,049)	(35,712)
Net cash flows from financing activities		609,484	376,903

NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS		111,553	(55,373)
Net foreign exchange on cash and cash equivalents		(7,571)	3,660
Cash and cash equivalents at 1 January		72,809	124,522
CASH AND CASH EQUIVALENTS AT 31 DECEMBER		176,791	72,809

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

EnQuest PLC

NOTES TO THE GROUP FINANCIAL STATEMENTS

For the year ended 31 December 2014

1. Notes to the consolidated financial statements

The financial information for the year ended 31 December 2014 and 2013 contained in this document does not constitute statutory accounts as defined in section 435 of the Companies Act 2006. The financial information for the years ended 31 December 2014 and 2013 have been extracted from the consolidated financial statements of EnQuest plc for the year ended 31 December 2014 which have been approved by the directors on 18 March 2015 and will be delivered to the Registrar of Companies in due course. The auditor's report on those financial statements was unqualified and did not contain a statement under section 498 of the Companies Act 2006.

2. Significant accounting policies

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

The Group has adopted IFRS 10 Consolidated Financial Statements / IAS 27 (Revised) - Separate Financial Statements, IFRS 11 Joint Arrangements, IAS 28 (Revised) - Investments in Associates and Joint Ventures and IFRS 12 Disclosure of Interests in Other Entities. Adoption of these revised standards did not have any effect on the financial performance or position of the Group.

Going concern concept

The Directors assessment of going concern concludes that the use of the going concern basis is appropriate and there are no material uncertainties that may cast significant doubt about the ability of the Group to continue as a going concern. See page 42 in the Financial Review for further details.

3. Segment information

Management have considered the requirements of IFRS 8, in regard to the determination of operating segments and concluded that the Group has only one significant operating segment, being the exploration for, extraction and production of hydrocarbons. Operations are located and managed into the following two business units, North Sea and Malaysia therefore all information is being presented for geographical segments. The information reported to the Chief Operating Decision Maker does not include an analysis of assets and liabilities and accordingly IFRS 8 does not require this information to be presented.

Year ended 31 December 2014	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations	Consolidated
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Revenue:
External customers	956,549	53,335	-	1,009,884	18,611	1,028,495

Total group revenue	956,549	53,335	-	1,009,884	18,611	1,028,495

Income/(expenses)
Depreciation and depletion	234,382	17,586	-	251,968	-	251,968
Impairment of investments	(1,316)	-	-	(1,316)	-	(1,316)
Exploration write offs and impairments	(127,006)	(21,932)	(3,613)	(152,551)	-	(152,551)
Gain on disposal of assets	2,019	-	-	2,019	-	2,019
Impairment of oil and gas assets	(678,801)	-	-	(678,801)	-	(678,801)
Negative goodwill	-	28,630	-	28,630	-	28,630

Segment profit/(loss)	(581,609)	22,121	(6,193)	(565,681)	(13,007)	(578,688)


Other disclosures:
Capital expenditure	985,636	192,319	2,763	1,180,718	-	1,180,718

All other adjustments are part of the detailed reconciliations presented further below.

Year ended 31 December 2013	North Sea	Malaysia	All other segments	Total segments	Adjustments and eliminations	Consolidated
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Revenue:
External customers	961,199	-	-	961,199	(5,954)	955,245

Total group revenue	961,199	-	-	961,199	(5,954)	955,245

Income/(expenses)
Depreciation and depletion	232,568	-	-	232,568	-	232,568
Impairment of investments	(312)	-	-	(312)	-	(312)
Exploration write offs and impairments	(1,966)	-	-	(1,966)	-	(1,966)

Segment profit	365,907	(1,435)	1,530	366,002	(35,067)	330,935


Other disclosures:
Capital expenditure	1,358,183	6,249	5,526	1,369,958	-	1,369,958

Adjustments and eliminations

Finance income and costs and gains and losses on derivatives are not allocated to individual segments as the underlying instruments are managed on a group basis.

Capital expenditure consists of property, plant and equipment and intangible assets including assets from the acquisition of subsidiaries.

Inter-segment revenues are eliminated on consolidation.

Reconciliation of profit

	2014	2013
Reconciliation of profit	US$'000	US$'000
Segment (loss)/profit	(565,681)	366,002
Finance income	1,814	2,030
Finance expense	(79,713)	(38,830)
Gains and losses on derivatives	64,892	1,733
Profit before tax	(578,688)	330,935

Revenue from two customers (2013: one customer) each exceed 10% of the Group's consolidated revenue and amounted respectively to US$472,729,000 and US$347,900,000 arising from sales of crude oil above (2013: US$901,936,000) in the North Sea operating segment.

All non-current assets of the Group are located in the United Kingdom except for US$170,948,000 (2013: US$13,414,000) located in Malaysia and US$4,823,000 (2013: US$5,526,000) located in Egypt.

4. Exceptional items and depletion of fair value uplift

	2014	2013
	US$'000	US$'000
Recognised in arriving at profit/(loss) from operations before tax:
Unrealised mark-to-market gains of derivatives	(19,225)	(1,733)
Impairment of available-for-sale investments (note 14)	1,316	312
Impairment of oil and gas assets (note 10)	678,801	-
Impairment of exploration and evaluation assets (note 12)	151,982	-
Gain on disposal of intangible oil and gas assets (note 12)	(2,019)	-
Depletion of fair value uplift	6,870	8,509
SVT tariff operator reconciliation	32,843	-
Negative goodwill	(28,630)	-
	821,938	7,088
Tax	(508,120)	(5,276)
	(313,818)	1,812

Unrealised mark-to-market gains and losses of derivatives

These include unrealised mark-to-market gains and losses on commodity and foreign exchange instruments which are included within revenue (note 5(a)), costs of sales (note 5(b)) and finance expenses (note (6)). The separate presentation of these items best reflects the underlying performance of the business as it distinguishes between the temporary timing differences associated with re-measurement under IAS39 rules and actual realised gains and losses.

Impairment of available-for-sale investments

As consideration for the disposal of the held for sale Petisovci asset in 2011, the Group received an investment in Ascent. The accounting valuation of this shareholding at 31 December 2014 resulted in a non-cash impairment of US$1,714,000, of which US$1,316,000 was recognised in the income statement (2013: US$312,000). As there was a reversal of an impairment in 2013, which was taken to the available-for-sale reserve then, a portion of the current year impairment must be taken to the reserve, as the income statement impact cannot exceed the cumulative decline in the value of the investment.

Impairment of oil and gas assets

As part of the annual impairment review process, impairment triggers were highlighted which has led to a US$678,801,000 impairment of Alma Galia and Don fields (refer to note 10).

Impairment of exploration and evaluation assets

Exploration and evaluation assets were reviewed and this has led to an impairment primarily of Kildrummy, Cairngorm, Crawford Porter and some GKA acreage in the UK, SB307 and SB308 blocks in Malaysia and the North West October block in Egypt (refer to note 12).

Gain on disposal of intangible oil and gas assets

In November 2014 the Group disposed of its Dutch asset P8a for US$2,162,000 resulting in a gain of US$2,019,000.

Depletion of fair value uplift

Additional depletion arising from the fair value uplift of Petrofac Energy Developments Limited's (PEDL) oil and gas assets on acquisition of US$6,870,000 (2013: US$8,509,000) is included within cost of sales in the statement of comprehensive income.

Operator SVT tariff reconciliation

SVT terminal operating costs are allocated to East of Shetland users based on each user's delivered production throughput, as a percentage of the total terminal throughput. Costs are further allocated, based on a user's share of two associated services - Stabilised Crude Oil processing (SCO) & Liquified Petroleum Gas processing (LPG). SVT costs incurred during each month are provisionally allocated and charged to users based on a user's estimated share of costs (based on estimated throughput volumes per service). At year end, a process occurs whereby the terminal operator reconciles each user's estimated share of costs against its actual share (based on the actual total spend and actual terminal throughput for that given year).

In 2013, as a direct result of EnQuest's strong production performance versus other SVT users' lower than expected throughput in 2013, EnQuest's actual share of SCO/LPG throughput at year end was greater than estimated. This factor combined with a higher base level cost at SVT contributed to the exceptional value arising from the 2013 reconciliation. In addition, EnQuest also incurred a small excess capacity charge due to the use of terminal capacity in excess of its ownership share entitlement. The charge recognised in the year ended 31 December 2014 in relation to the 2013 reconciliation process was $32,843,000.

The Terminal Operator (BP) has undertaken a number of technical studies to map out the various operational and investment cases required to facilitate the terminal life to 2025, and beyond. These technical studies are now complete and will be presented to the terminal owners at the end of Q1/2015.

The next steps will be for the Terminal Owners to make a number of key decisions relating to what investments are necessary to facilitiate a terminal life to 2025 and/or 2040.

Negative goodwill

During the year ended 31 December 2014, the Group acquired the PM8/Seligi assets in Malaysia. The assets and liabilities on acquisition have been fair valued and as the fair value is greater than the deemed consideration then a gain of US$28,630,000 has been recognised. (refer to note 13).

Tax

The tax impact on the exceptional items is calculated based on the tax rate applicable to each exceptional item.

5. Revenue and expenses

(a) Revenue and other operating income

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000

Revenue from crude oil sales (i)	1,002,210	953,752
Unrealised gains and losses on commodity derivative contracts (i)	18,611	(5,954)
Tariff revenue	7,564	7,445
Other operating revenue	110	2
	1,028,495	955,245

(i) Included within revenue and other operating income are realised gains of US$31,749,000 (2013: nil) and unrealised gains of US$18,611,000 on the Group's commodity derivatives contracts (2013: losses of US$5,954,000) which are either ineffective for hedge accounting purposes or held for trading purposes.

(b) Cost of sales

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000

Cost of operations (i)	296,211	234,501
Tariff and transportation expenses	140,339	73,452
Unrealised gains and losses on foreign exchange derivative contracts (i)	18,085	(7,687)
Change in lifting position	8,157	2,649
Crude oil inventory movement (note 15)	4,535	(1,426)
Depletion of oil and gas assets (note 10)	244,531	225,654
	711,858	527,143

(i) Included within cost of operations are realised gains of US$55,273,000 (2013: US$7,339,000) and unrealised losses of US$18,085,000 (2013: gains of US$7,687,000) on foreign exchange derivative contracts ineffective for hedge accounting.

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000

Unsuccessful exploration expenditure written off (note 12)	568	704
Impairment charge (note 12)	151,982	1,262
Pre-licence costs expensed	3,465	6,675
	156,015	8,641

(d) General and administration expenses

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000

Staff costs (note 5(g))	107,476	108,226
Depreciation (note 10)	7,438	6,914
Other general and administration costs	26,624	21,450
Recharge of costs to operations and joint venture partners	(125,074)	(111,566)
	16,464	25,024

(e) Other income

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000

Net foreign exchange gains	27,176	-

(f) Other expenses

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000

Net foreign exchange losses	-	26,390

(g) Staff costs

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000

Wages and salaries	46,203	44,790
Social security costs	3,540	5,128
Defined contribution pension costs	3,366	3,267
Expense of share-based payments (note 19)	8,468	8,193
Other staff costs	3,622	3,645
Total employee costs	65,199	65,023
Contractor costs	42,277	43,203
	107,476	108,226

The average number of persons employed by the Group during the year was 356 (2013: 245).

Details of remuneration, pension entitlement and incentive arrangements for each Director are set out in the Remuneration Report on pages 59 to 72.

(h) Auditors' remuneration

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

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000

Fees payable to the Group's auditors for the audit of the Group's annual accounts	326	336
Fees payable to the Group's auditors and its associates for other services: The audit of the Group's subsidiaries Audit related assurance services (interim review) Tax advisory services (1) Other assurance services	246 69 159 137	272 73 318 43
	611	706
	937	1,042

(1) No costs were capitalised in the current year.

6. Finance costs/income

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000

Finance costs:
Loan interest payable	5,915	2,954
Bond interest payable	46,200	10,360
Unwinding of discount on decommissioning provisions (note 23)	12,093	12,588
Unwinding of discount on financial liability (note 21)	132	-
Fair value loss on financial instruments at fair value through profit or loss (note 21)	22,656	-
Finance charges payable under finance leases	2	2
Amortisation of finance fees	6,771	7,700
Other financial expenses	11,768	6,467
	105,537	40,071
Less: amounts included in the cost of qualifying assets	(3,169)	(1,241)
	102,368	38,830
Finance income:
Bank interest receivable	304	429
Unwinding of discount on financial asset (note 21)	877	1,447
Other financial income	633	154
	1,814	2,030

Fair value gains and losses on financial instruments at fair value through profit or loss relate to the movement in the time value portion of the fair value of commodity put option contracts where the intrinsic value has been designated as an effective hedge of production.

7. Income tax

(a) Income tax

The major components of income tax expense are as follows:

	Year ended 31 December	Year ended 31 December
	2014	2013
Group statement of comprehensive income	US$'000	US$'000
Current income tax
Current income tax charge	4,684	14,462
Adjustments in respect of current income tax of previous years	(6,540)	(2,075)

Overseas income tax
Current income tax charge	5,355	(3,379)
Adjustments in respect of current income tax of previous years	2,640	703
Total current income tax	6,139	9,711

Deferred income tax
Relating to origination and reversal of temporary differences	(410,422)	133,314
Adjustments in respect of changes in tax rates	-	409
Adjustments in respect of deferred income tax of previous years	2,606	(2,112)

Overseas income tax
Relating to origination and reversal of temporary differences	1,685	9
Adjustments in respect of deferred income tax of previous years	(2,287)	-
Total deferred income tax	(408,418)	131,620

Income tax expense reported in statement of comprehensive income	(402,279)	141,331

(b) Reconciliation of total income tax charge

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

	Year ended 31 December	Year ended 31 December
	2014	2013
	US$'000	US$'000
(Loss)/profit before tax	(578,688)	330,935

Statutory rate of corporation tax in the UK of 62% (2013: 62%)	(358,787)	205,179
Supplementary corporation tax non-deductible expenditure	(11,612)	15,250
Non-deductible expenditure	(12,805)	508
Deductible lease expenditure	-	(38,097)
Petroleum revenue tax (net of income tax benefit)	20,190	21,948
North Sea tax reliefs	(93,726)	(55,034)
Tax in respect of non-ring fence trade	44,160	(5,184)
Deferred tax rate decrease	-	409
North Sea oil and gas decommissioning rate restriction	5,323	2,824
Adjustments in respect of prior years	(3,581)	(3,482)
Overseas tax rate differences	1,162	(2,171)
Share based payments	5,336	(225)
Other differences	2,061	(593)
At the effective income tax rate of 70% (2013: 43%)	(402,279)	141,331

Deferred income tax relates to the following:

	Group balance sheet			Group profit and loss account
	2014	2013		2014	2013
	US$'000	US$'000		US$'000	US$'000
Deferred tax liability
Accelerated capital allowances	1,589,226	1,456,498		35,246	387,107
Deferred PRT	287,874	151,825		43,116	47,910
	1,877,100	1,608,323
Deferred tax asset
Losses	(1,078,095)	(647,228)		(430,867)	(287,822)
Decommissioning liability	(203,496)	(114,113)		(30,986)	16,057
Other temporary differences	(132,873)	(100,720)		(24,926)	(31,632)
	(1,414,464)	(862,061)
Deferred tax expense				(408,417)	131,620
Deferred tax liabilities, net	462,636	746,262

Reflected in balance sheet as follows:
Deferred tax assets	(40,401)	(14,731)
Deferred tax liabilities	503,037	760,993
Deferred tax liabilities, net	462,636	746,262
Reconciliation of deferred tax liabilities, net				2014	2013
				US$'000	US$'000
At 1 January 2014			(746,262)		(609,087)
Tax expense during the period recognised in profit or loss			408,419		(131,620)
Tax expense during the period recognised in other comprehensive income			(96,894)		(75)
Deferred taxes acquired			(27,899)		(5,480)
At 31 December 2014			(462,636)		(746,262)

(d) Tax losses

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

The Group has unused UK mainstream corporation tax losses of US$16,635,000 (2013: US$2,481,000) for which no deferred tax asset has been recognised at the balance sheet date due to the uncertainty of recovery of these losses.

The Group has unused overseas tax losses in Canada of approximately CAD$12,735,000 (2013: CAD$14,880,000) and in Holland of nil (2013: €1,070,000) for which no deferred tax asset has been recognised at the balance sheet date. The tax losses in Canada have expiry periods of between seven and 20 years, none of which expire in 2015 and which arose following the change in control of the UK Stratic Group in 2010. Tax losses in Holland can be carried forward for a period of up to nine years.

The Group has pre-trading expenditure incurred in Malaysia on licences SB307 and SB308 of approximately US$29,700,000 for which no deferred tax asset has been recognised at the balance sheet date. The Group also has unrecognised pre-trading expenditure in Egypt at the end of 2014 of US$3,300,000.

No deferred tax has been provided on unremitted earnings of overseas subsidiaries. Finance Act 2009 exempted foreign dividends from the scope of UK corporation tax where certain conditions are satisfied.

(e) Change in legislation

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

8. Earnings per share

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

In 2014, potentially issuable ordinary shares are excluded from the diluted earnings per ordinary share calculation, as their inclusion would decrease the loss per ordinary share.

Basic and diluted earnings per share are calculated as follows:

			Profit after tax		Weighted average number of Ordinary shares		Earnings per share
			Year ended 31 December		Year ended 31 December		Year ended 31 December
		2014		2013	2014	2013	2014	2013
	US$'000			US$'000	Million	Million	US$	US$

Basic	(176,409)			189,604	774.1	778.2	(0.228)	0.244
Dilutive potential of Ordinary shares granted under share-based incentive schemes	-			-	-	18.1	-	(0.006)
Diluted	(176,409)			189,604	774.1	796.3	(0.228)	0.238

Adjusted (excluding exceptional items)	137,409			191,416	774.1	778.2	0.178	0.246

Diluted (excluding exceptional items)	137,409			191,416	774.1	796.3	0.178	0.240

9. Dividends paid and proposed

The Company paid no dividends during the year ended 31 December 2014 (2013: nil).At 31 December 2014 there are no proposed dividends (2013: nil).

10. Property, plant and equipment

	Land and buildings	Oil and gas assets	Office furniture and equipment	Total
	US$'000	US$'000	US$'000	US$'000
Cost:
At 1 January 2013	-	2,878,569	21,349	2,899,918
Additions	17,272	840,665	6,491	864,428
Acquired	-	52,541	-	52,541
Cost carry	-	415,300	-	415,300
Reclassified to intangible assets (note 12)	-	(448)	-	(448)
Change in decommissioning provision	-	(44,615)	-	(44,615)
At 31 December 2013	17,272	4,142,012	27,840	4,187,124
Additions	42,665	839,514	5,429	887,679
Acquired	-	206,215	-	206,144
Change in decommissioning provision	-	82,123	-	82,123
At 31 December 2014	59,937	5,269,864	33,269	5,363,070

Depletion and depreciation:
At 1 January 2013	-	1,075,884	7,443	1,083,327
Charge for the year	-	225,654	6,914	232,568
At 31 December 2013	-	1,301,538	14,357	1,315,895
Charge for the year	110	244,531	7,328	251,969
Impairment charge for the year	-	678,801	-	678,801
At 31 December 2014	110	2,224,870	21,685	2,246,665

Net carrying amount:
At 31 December 2014	59,827	3,044,994	11,584	3,116,405

At 31 December 2013	17,272	2,840,474	13,483	2,871,229

At 1 January 2013	-	1,802,685	13,906	1,816,591

In March 2014, the Group completed the acquisition of Centrica North Sea Oil Limited (Centrica's) share of the UKCS Greater Kittiwake Area (GKA) assets as well as its 100% interest in the Kittiwake to Forties oil export pipeline. In June 2014, EnQuest completed the acquisition of ExxonMobil Exploration and Production Malaysia Inc's (ExxonMobil's) interest in the Seligi oil field and the PM8 PSC, located offshore Malaysia. The costs relating to these acquisitions are included within 'Acquired' costs.

Included within 'Acquired' costs in the year ended 31 December 2013 is the acquisition of a non-operated interest in the producing oil field Alba, in the UK Continental Shelf, which has been accounted for as an asset acquisition.

In the prior year, included within the 'cost carry' costs is the portion of the consideration payable to Nautical Petroleum plc and First Oil plc for 40% of the Kraken field which was through development carries, split between a US$240,000,000 'firm' carry (payable on FDP approval) and a 'contingent' carry (payable up to US$144,000,000 subject to reserves determination). US$320,000,000 was included and the remaining US$164,176,000 balance of the 'firm' carry and US$80,000,000 of the 'contingent' carry were provided within financial liabilities (note 21) and provisions (note 23) respectively as at 31 December 2013.

Under the 2012 farm-out agreement with KUFPEC for a 35% share of the Alma/Galia development, KUFPEC were required to carry the Company for US$182,000,000. This amount was initially recognised as an 'other receivable' (note 21) and then transferred to PP&E as the carry was exhausted. During the year ended 31 December 2013, KUFPEC carried the Company for US$98,300,000 under this carry arrangement.

During the year ended 31 December 2014, there have been impairments in the Alma Galia and Don fields of US$678,801,000 (US$256,896,000 on a post tax basis). The impairment is principally due to the significant fall in the oil price in the latter part of 2014. Other factors contributing to the impairment include delays in first oil and cost increases in the case of Alma/Galia, together with the impact of cutting the capital programme, in response to the changing economic conditions. There was no impairment in the year ended 31 December 2013.

The net book value at 31 December 2014 includes US$1,504,172,000 (2013: US$1,581,847,000) of pre-development assets and development assets under construction which are not being depreciated. Also US$49,132,000 (2013: US$7,130,000) of costs relating to the construction of the Group's new Aberdeen office has not been depreciated.

The amount of borrowing costs capitalised during the year ended 31 December 2014 was US$3,169,000 (2013: US$1,241,000) and relate to the Alma/Galia and Kraken development projects as well as the construction of the new office building. The weighted average rate used to determine the amount of borrowing costs eligible for capitalisation is 1.54% (2013: 0.95%).

The net book value of property, plant and equipment held under finance leases and hire purchase contracts at 31 December 2014 was US$141,000 (2013: US$141,000) of oil and gas assets. The net book value of US$10,695,000 (2012: US$10,695,000) for land is held under a long lease.

11. Goodwill

A summary of goodwill is presented below:

	2014	2013
	US$'000	US$'000
Cost
At 1 January Additions (note 13) At 31 December	107,760	107,760
	81,557	-
	189,317	107,760

The balance at 31 December 2013 represents goodwill acquired on the acquisition of Stratic and PEDL in 2010. The additions during the year represent the acquisition of the Greater Kittiwake Area asset.

Goodwill acquired through business combinations has been allocated to a single cash-generating unit (CGU), the UKCS, and therefore the lowest level that goodwill is reviewed.

Impairment testing of goodwill

In accordance with IAS 36 Impairment of Assets, goodwill has been reviewed for impairment at the year end. In assessing whether goodwill has been impaired, the carrying amount of the CGU, including goodwill, is compared with its recoverable amount. In the prior year the Group used the detailed calculation performed in 2012 as the basis for the tests as allowed under IAS 36.

The recoverable amount of the CGU has been determined on a fair value less costs to sell basis using a discounted cash flow model comprising asset-by-asset life of field projections. The cashflows have been modelled on a post-tax and post-decommissioning basis discounted at 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 calculations

The key assumptions required for the calculation of the CGU are:

· oil prices

· production volumes

· discount rates

· opex, capex and decommissioning costs

· taxation.

Oil prices are based on forward price curves for the first three years and thereafter at US$85 per barrel inflated at 2% per annum from 2015.

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

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

WACC takes into account both debt and equity. The cost of equity is derived from the expected return on investment by the Group's investors. The cost of debt is based on its interest-bearing borrowings. Segment risk is incorporated by applying a beta factor based on publicly available market data. The post-tax discount rate applied to the Group's post-tax cash flow projections was 8.8%.

Sensitivity to changes in assumptions

The Group's value is highly sensitive, inter alia, to oil price achieved and production volumes. The recoverable amount (NPV) of the CGU would be equal to the carrying amount of goodwill if either the oil price or production volumes (on a CGU weighted average basis) were to fall by 14% from the prices outline above. Goodwill would need to be fully impaired if the oil price or production volumes (on a CGU weighted average basis) were to fall by 17% from the prices outlined above. The above sensitivities have flexed revenues and tax cash flows, but operating costs and capital expenditures have been kept constant. In reality, management would be highly likely to take steps to mitigate the value impact of further falls in the oil price by cutting supply chain costs.

12. Intangible oil and gas assets

		US$'000
Cost
At 1 January 2013		200,692
Additions		30,852
Farm-out		(2,648)
Acquisition of interests in licences		6,837
Write-off of relinquished licences previously impaired		(6,553)
Unsuccessful exploration expenditure written off		(704)
Change in decommissioning provision		(155)
Reclassified from property, plant and equipment (note 10)		448
At 31 December 2013		228,769
Additions		67,095
Acquisition of interests in licences		19,800
Write-off of relinquished licences previously impaired		(8,423)
Disposals		(143)
Unsuccessful exploration expenditure written off		(568)
Change in decommissioning provision		634
At 31 December 2014		307,164

Provision for impairment
At 1 January 2013		(103,186)
Impairment charge for the year		(1,262)
Write-off of relinquished licences previously impaired		6,553
At 31 December 2013		(97,895)
Impairment charge for the year		(151,982)
Write-off of relinquished licences previously impaired		8,423
At 31 December 2014		(241,454)

Net carrying amount:

At 31 December 2014		65,710

At 31 December 2013		130,874

At 1 January 2013		97,506

Included within the acquisition of the GKA assets are exploration licences and an allocation of the fair value is included in acquisition of interests above for the year ended 31 December 2014.

Included within 'Acquisition of interests in licences' in 2013 is US$1,310,000 relating to a farm-in to a 50% non-operated interest in exploration licence P2006 Block 21/6b (Avalon). Also included is the Group's 50% interest in the North West October (NWO) block in Egypt, acquired from Arabian Oil Company Limited (AOC).

During the year the Group disposed of its Dutch asset P8a for US$2,162,000 resulting in a gain of US$2,019,000.

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

During the year ended 31 December 2014, US$8,423,000 of costs relating to relinquished licences previously impaired were written off (2013: US$6,553,000).

The impairment charge for the year ended 31 December 2014 includes costs relating to Crawford Porter, Kildrummy Cairngorm and some GKA acreage in the UK. In current market conditions some of those interests do not merit sufficient funds to progress them to economic development. In addition, costs relating to the SB307 and SB308 blocks in Malaysia (due to the unsuccessful exploration well) and costs incurred since acquisition on the NWO block in Egypt were impaired. The costs relating to the South West Heather licence which is in the process of being relinquished have also been impaired. The year ended 31 December 2013 included the impairment charge for the Peik licence which was relinquished in 2014.

13. Business combinations

Acquisition of GKA assets

On 1 March 2014, the Group completed the acquisition of Centrica North Sea Oil Limited (Centrica) 50% share of the UKCS GKA assets as well as Centrica's 100% interest in the Kittiwake to Forties oil export pipeline. Base consideration was US$39,900,000 which was subject to certain working capital and other interim period adjustments from the economic date of 1 January 2013, resulting in a cash consideration of US$30,322,000. The Group acquired the GKA assets partly due to its proximity to the Scolty/Crathes field and the potential for a tie-back. In addition, the Group saw significant potential to improve production through infill drilling.

The fair value was provisional at 30 June 2014 and has been reviewed in accordance with the provisions of IFRS 3 Business Combinations (Revised). The initial fair values of assets and liabilities recognised on acquisition have been updated to reflect the finalisation of working capital adjustments and decommissioning provisions.

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

	Revised fair values	Initial fair value recognised on acquisition	(Decrease)/increase to the fair value recognised on acquisition
	US$'000	US$'000	US$'000
Assets
Property, plant and equipment Intangible assets Inventory Receivables	55,360 19,800 3,258 20,310	55,360 19,800 3,258 -	- - - 20,310
Liabilities
Accruals	(40,669)	-	(40,669)
Decommissioning provision	(78,318)	(73,234)	(5,084)
Deferred tax liability	(4,276)	(6,976)	2,700
Total identifiable net liabilities at fair value	(24,535)	(1,792)	(22,743)
Goodwill arising on acquisition (Note 11)	81,557	58,814	22,743
Purchase consideration transferred	57,022	57,022	-

Purchase consideration:
Cash paid and payable			30,322
Deferred and contingent consideration			26,700
			57,022

The goodwill of US$81,557,000 comprises the value of expected synergies arising from the acquisition. None of the goodwill recognised is expected to be deductible for income tax purposes.

From the date of acquisition, GKA has contributed US$61,647,000 to revenue and US$9,866,000 to the profit before tax from continuing operations of the Group. If the combination had taken place at the beginning of the year, revenue from continuing operations would have been US$61,647,000 and the loss before tax from continuing operations for the Group would have been US$3,044,000.

The Group will pay deferred consideration of US$30,000,000 contingent on regulatory approval of a Field Development Plan (FDP) for the Scolty field and/or the Crathes field. The fair value of US$18,000,000 has been determined at the date of acquisition using the then best estimate of the likelihood of FDP approval.

In addition, contingent consideration up to a maximum of US$100,000,000 may be payable subject to future exploration success. The fair value of US$8,700,000 is based on a discounted cashflow method and the best current estimate of the chance of exploration success.

Acquisition of Seligi oil field and PM8 PSC

On 27 June 2014, the Group completed the acquisition of ExxonMobil Exploration and Production Malaysia Inc's 50% operated interest in the Seligi oil field and an 80% participating interest in the PM8 PSC, located offshore Malaysia. The PM8 PSC (extension) was agreed to include the Seligi oil field and with effect from 1 July 2014, EnQuest holds a 50% interest in PM8/Seligi. Base consideration was US$67,000,000 subject to interim period adjustments since the economic date of 1 January 2014, resulting in a cash consideration payable of US$24,744,000.

The Group acquired the assets to use its extensive experience in creating value from late stage maturing assets in the North Sea to enhance recovery from these Malaysian assets.

The changes to the fair value of the identifiable assets and liabilities of PM8/Seligi are as follows:

	Revised fair values	Initial fair value recognised on acquisition	(Decrease)/increase to the fair value recognised on acquisition
	US$'000	US$'000	US$'000
Assets
Property, plant and equipment	150,855	156,398	(5,543)
Current tax	2,759	-	2,759
Liabilities
Over-lift position	(6,959)	(9,400)	2,441
Accrued expenses	(3,681)	-	(3,681)
Financial liability	(5,247)	(5,700)	453
Decommissioning provision	(55,251)	(101,265)	46,014
Deferred tax liability	(29,102)	(11,821)	(17,281)
Total identifiable net assets at fair value	53,374	28,212	25,162
Negative goodwill	(28,630)	-	(28,630)
Purchase consideration transferred	24,744	28,212	(3,468)

The acquired financial liability relates to an agreement by the Group to carry Petronas Carigali SDN BHD (Carigali) for its share of exploration or appraisal well commitments. The fair value of US$5,247,000 has been calculated using a discounted cashflow method.

From the date of acquisition, PM8 has contributed US$53,335,000 to revenue and US$21,844,000 to the profit before tax from continuing operations of the Group. If the combination had taken place at the beginning of the year, revenue from continuing operations would have been US$155,319,000 and the profit before tax from continuing operations for the Group would have been US$91,449,000.

The negative goodwill has been recognised in the income statement in the year ended 31 December 2014. The transaction resulted in a gain as EnQuest has the capability to utilise its skills to enhance value of mature assets such as PM8. Therefore, we believe the fair value of the assets is greater than the consideration.

14. Investments

			US$'000
Cost
At 1 January 2013, 31 December 2013 and 31 December 2014			19,231


Provision for impairment
At 1 January 2013			(16,914)
Impairment charge for the year			(312)
Reversal of impairment loss			398
At 31 December 2013			(16,828)
Impairment charge for the year (i)			(1,714)
At 31 December 2014			(18,542)
Net carrying amount:
At 31 December 2014			689

At 31 December 2013			2,403

At 1 January 2013			2,317

(i) US$1,316,000 has been recognised in the income statement and US$398,000 reversing the available-for-sale reserve.

The investment relates to 160,903,958 new ordinary shares in Ascent acquired in 2011. The accounting valuation of the Group's shareholding (based on the quoted share price of Ascent) resulted in an additional non-cash impairment of US$1,714,000 in the year to 31 December 2014.

In the prior year, the accounting valuation for the period ended 30 June 2013 resulted in a non-cash impairment of US$312,000 and by 31 December 2013 the share price had increased, resulting in a reversal of the impairment, which was recognised in the available-for-sale reserve.

15. Inventories

	2014	2013
	US$'000	US$'000

Crude oil	11,695	16,273
Well Supplies	77,702	30,541
	89,397	46,814

16. Trade and other receivables

	2014	2013
	US$'000	US$'000

Trade receivables	53,812	93,252
Joint venture receivables	61,000	116,341
Under-lift position	15,010	17,248
VAT receivable	20,818	16,751
Other receivables	18,716	15,055
	169,356	258,647
Prepayments and accrued income	116,871	8,533
	286,227	267,180

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 2014 no impairment provision for trade receivables was necessary (2013: nil).

Joint venture receivables relate to billings to joint venture partners and were not impaired.

Under-lift is valued at net realisable value being the lower of cost and net realisable value.

As at 31 December 2014 and 31 December 2013 no other receivables were determined to be impaired.

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

17. Cash and cash equivalents

The carrying value of the Group's cash and cash equivalents is considered to be a reasonable approximation to their fair value due to their short-term maturities. Included within the cash balance at 31 December 2014 is restricted cash of US$27,183,000 (2013: US$nil). US$22,324,000 of this relates to cash held in escrow in respect of the unwound acquisition of the Tunisian assets of PA Resources and the remainder relates to cash collateral held to issue bank guarantees in Malaysia.

18. Share capital

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

	2014	2013
Authorised, issued and fully paid	US$'000	US$'000

802,660,757 (2013: 802,660,757) Ordinary shares of £0.05 each	61,249	61,249
Share premium	52,184	52,184
	113,433	113,433

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

There were no new issues of shares during 2014 or 2013.

At 31 December 2014 there were 29,691,691 shares held by the Employee Benefit Trust (2013: 25,510,520), the increase is due to the purchase of shares to satisfy awards made under the Company's share-based incentive schemes net of shares used during the year.

19. Share-based payment plans

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

Deferred Bonus Share Plan (DBSP)

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

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

Weighted average fair value per share

Trued up vesting rate

2014 award

2013 awards

2012 awards

127p

124p

91%

96%

94%

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

2014

Number*

2013

Number*

Outstanding at 1 January

Granted during the year

Exercised during the year

Forfeited during the year

1,484,001

1,021,538

(741,856)

(162,048)

1,018,357

848,922

(359,077)

(24,201)

Outstanding at 31 December

1,601,635

1,484,001

* Includes invested and matching shares.

There were no share awards exercisable at either 31 December 2014 or 2013.

The weighted average contractual life for the share awards outstanding as at 31 December 2014 was 0.9 years (2013: 1.0 years).

The charge recognised in the 2014 statement of comprehensive income in relation to matching share awards amounted to US$2,095,000 (2012: US$1,058,000).

Restricted Share Plan (RSP)

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

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

Weighted average fair value per share

Trued up vesting rate

2014 awards

2013 awards

2012 awards

2011 awards

125p

127p

123p

119p

100%

84%

70%

91%

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

	2014 Number	2013 Number
Outstanding at 1 January Granted during the year Exercised during the year Forfeited during the year	8,379,718 288,862 (2,703,374) (637,866)	8,158,207 1,567,800 (1,055,827) (290,462)
Outstanding at 31 December	5,327,340	8,379,718
Exercisable at 31 December	3,058,629	2,191,424

The weighted average contractual life for the share awards outstanding as at 31 December 2014 was 1.3 years (2013: 1.0 years).

The charge recognised in the year ended 31 December 2014 amounted to US$1,637,000 (2013: US$3,007,000).

Performance Share Plan (PSP)

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

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

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

Weighted average fair value per share

Trued up vesting rate

2014 awards

2013 awards

2012 awards

127p

124p

93%

87%

83%

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

	2014 Number	2013 Number
Outstanding at 1 January Granted during the year Exercised during the year Forfeited during the year	8,299,026 4,905,547 (480,636) (1,780,533)	4,602,639 3,936,000 - (239,613)
Outstanding at 31 December	10,943,404	8,299,026
Exercisable at 31 December	457,963	-

The weighted average contractual life for the share awards outstanding as at 31 December 2014 was 1.6 years (2013: 1.5 years).

The charge recognised in the year ended 31 December 2014 amounted to US$4,711,000 (2013: US$4,066,000).

Sharesave plan

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

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

Weighted average fair value per share

Trued up vesting rate

2014 awards

2013 awards

2012 awards

38.7p

20p

71%

55%

46%

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

	2014 Number	2013 Number
Outstanding at 1 January Granted during the year Exercised during the year Forfeited during the year	1,086,120 1,017,570 (13,000) (774,935)	697,380 464,460 - (75,720)
Outstanding at 31 December	1,315,755	1,086,120

There were no share options exercisable at either 31 December 2014 or 2013.

The weighted average contractual life for the share options outstanding as at 31 December 2014 was 2.6 years (2013: 2.5 years).

The charge recognised in the 2014 statement of comprehensive income amounted to US$25,000 (2013: S$62,000).

The Group has recognised a total charge of US$8,468,000 (2013: US$8,193,000) in the statement of comprehensive income during the year, relating to the above employee share-based schemes.

20. Loans and borrowings

Revolving credit facility

At 31 December 2014, the Group had a six year US$1,700,000,000 multi-currency revolving credit facility, comprising of a committed amount of US$1,200,000,000 with a further US$500,000,000 available through an accordion structure.

Interest on the revolving credit facility is payable at LIBOR plus a margin of 2.50% to 3.75%, dependent on specified covenant ratios.

At 31 December 2014, US$217,649,000 was drawn down under the Group's facility agreement (2013: US$225,809,000) and LoC utilisation was US$149,395,000 (2013: US$181,543,000). Unamortised facility fees of US$24,168,000 have been netted off against the drawdowns in the balance sheet (2013: US$26,413,000).

Property loan facility

During the year the Group entered a £31,800,000 2 year development facility with Abbey National Treasury Services PLC in relation to the construction of the Group's Aberdeen office building. The facility terminates on 28 March 2016.

Interest of LIBOR plus a margin of 1.5% is payable. At 31 December 2014, £21,934,000 (US$34,199,000) was drawn down under the development facility. Unamortised facility fees of US$645,000 have been netted off against the drawdowns in the balance sheet.

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

Bonds

In April 2014, the Group issued a US$650,000,000 high yield bond which matures in 2022 and pays a coupon of 7% payable bi-annually in April and October. The bond is carried at its amortised cost of US$651,077,000 (2013: nil).

At 31 December 2014, the Group had a 5.5% Sterling Retail Bond of £155,245,000. The original bond raised £145,000,000 with an additional £10,245,000 issued in November 2013. The bond pays a coupon of 5.5% payable bi-annually in February and August and matures in 2022. The bond had a fair value of US$169,010,000 (2013: US$263,498,000) but is carried at its amortised cost of US$244,173,000 (2013: US$258,791,000). The fair value of the Sterling Retail Bond has been determined by reference to the price available from the market on which the bond is traded.

21. Other financial assets and financial liabilities

	2014	2013
	US$'000	US$'000
Financial instruments at fair value through other comprehensive income
Current assets
Cash flow hedges:
Commodity contracts	87,299	-

Financial instruments at fair value through profit or loss
Current assets
Derivatives not designated as hedges:
Commodity contracts	7,930	-
Forward foreign currency contracts	2,409	8,455
	10,339	8,455

Non-current assets
Derivatives not designated as hedges:
Forward foreign currency contracts	-	702

Current liabilities
Derivatives not designated as hedges:
Commodity contracts	22,445	5,084
Forward foreign currency contracts	12,805	631
	35,250	5,715

Non-current liabilities
Derivatives not designated as hedges:
Commodity contracts	18,041	839

Loans and receivables
Current assets
Other receivable	3,294	-

Non-current assets Other receivable	18,809	21,226

Other financial liabilities at amortised cost
Current liabilities
Other liability	66,228	164,176
Non current liabilities Other liability	5,653	-


Total current assets	100,932	8,455
Total non-current assets	18,809	21,928
Total assets	119,741	30,383

Total current liabilities	101,478	169,891
Total non-current liabilities	23,694	839
Total liabilities	125,172	170,730

Commodity contracts

During the year ended 31 December 2014, the Group entered into various put option contracts in order to hedge the exposure to changes in future cashflows from the sale of oil production in 2015. Put options over approximately 8,000,000 barrels of oil in 2015 were purchased with an average strike price of US$87 per barrel. These options were subsequently closed in December 2014. A gain on the intrinsic value of the options (the portion designated into the hedging relationship) of $119,055,000 was deferred in equity and will be recognised in revenue during 2015. The realised loss on the time value potion of $38,815,000 was recognised in finance costs. Put options over a further 10,000,000 barrels maturing in 2015 were purchased, and remain open at year-end. These options have an average strike price of $65 per barrel, and were deemed effective for hedge accounting purposes. Intrinsic value gains of $37,226,000 have been deferred in equity and will be recognised in revenue during 2015. The increase of $16,200,000 in the time value portion above the premium paid for the options has been recognised in finance costs. The fair value of these open puts at 31 December 2014 was US$87,299,000.

The Group also sold call options during 2014. At 31 December 2014 call options over 17,744,000 notional barrels had been sold, of which 10,246,150 maturing in 2015 with an average strike price of $93.94 per barrel, and 7,498,199 maturing in 2016 with an average strike price of $99.36 per barrel. These call options are designated as 'At fair value through profit and loss' (FVTPL). These contracts had a net liability fair value of US$36,227,000 at 31 December 2014, representing a gain over the premium received of $16,653,000. This gain has been recognised in revenue.

In August and September 2013, the Group entered into five options in order to hedge the exposure to changes in future cash flows from the sale of oil production for approximately 3,600,000 barrels of oil in 2014. These instruments were deemed to be ineffective for hedge accounting purposes and were designated as at FVTPL. These contracts matured during 2014 and had a nil fair value (2013: US$5,084,000 (loss)).

During the year, the Group also entered a series of commodity swaps. These contracts had a net fair value of US$3,670,000.

Forward foreign currency contracts

During the year ended 31 December 2013, the Group entered into various forward currency contracts, namely Sterling, Euro and Norwegian Krone which were due to expire in 2014 and 2015. These contracts did not qualify for hedge accounting. Of those outstanding at 31 December 2014, the net fair value was US$10,396,000 liability (2013: US$7,688,000 asset).

Foreign exchange swap contracts

During 2014, the Group entered several foreign exchange swap contracts when Sterling was trading above $1.66:£1. The swap contracts were closed early in October 2014 realising a gain of US$46,756,000 which has been recognised in the income statement within cost of sales.

The income statement impact of all commodity and currency derivatives are as follows:

	Revenue		Cost of sales		Finance income/(expenses)
Year ended 31 December 2014	Realised US$'000	Unrealised US$'000	Realised US$'000	Unrealised US$'000	Realised US$'000	Unrealised US$'000

Call options	8,785	9,857	-	-	-	-
Put options	920	-	-	-	(41,353)	18,697
Commodity swaps	(11,522)	3,670	-	-	-	-
Foreign exchange swap contracts	-	-	46,756	-	-	-
Other forward currency contracts	-	-	8,517	(18,085)	-	-
Prior year commodity contracts	33,566	5,084	-	-	-	-
	31,749	18,611	55,273	(18,085)	(41,353)	18,697


	Revenue		Cost of sales		Finance income/(expenses)
Year ended 31 December 2013	Realised US$'000	Unrealised US$'000	Realised US$'000	Unrealised US$'000	Realised US$'000	Unrealised US$'000

Commodity contracts	-	(5,954)	-	-	-	-
Forward currency contracts	-	-	7,339	7,687	-	-
	-	(5,954)	7,339	7,687	-	-

Other receivable

As part of the 2012 farm-out to KUFPEC of 35% of the Alma/Galia development, KUFPEC agreed to pay EnQuest a total of US$23,292,000 after production commences over a period of 36 months, the fair value of which was US$19,300,000. Receivables were recognised at 31 December 2012. The unwinding of discount of US$877,000 is included within finance income for the year ended 31 December 2014 (2013: US$1,447,000).

Other liability

The consideration for the acquisition of 40% of the Kraken field from Nautical and First Oil in 2012 was through development carries. These were split into a 'firm' carry and a 'contingent' carry dependent upon reserves determination. A financial liability is recognised at 31 December 2014 for the remainder of the 'firm' carry amounting to US$66,502,000 (2013: US$164,176,000). This is expected to expire early in 2015. The 'contingent' carry has been accounted for as a provision (note 23).

On Kraken FDP approval, commitments of US$11,200,000 due in respect of back-in payments associated with the sole risk drilling undertaken by the previous operator were due to be paid. These have now been added to the carry arrangement.

As part of the agreement to acquire the PM8 assets in Malaysia, the Group agreed to carry Petronas Carigali for its share of exploration or appraisal well commitments. The discounted value of US$5,379,000 has been disclosed as a financial liability (31 December 2013: nil). The unwinding of discount of US$132,000 is included within finance expense for the year ended 31 December 2014 (2013: nil).

	Other liability	Other receivable
	US$'000	US$'000

At 1 January 2013	17,150	115,081
Additions during the year	240,000	-
Utilised during the year	(92,974)	(95,302)
Unwinding of discount	-	1,447
At 31 December 2013	164,176	21,226
Additions during the year	5,247	-
Utilised during the year	(97,674)	-
Unwinding of discount	132	877
At 31 December 2014	71,881	22,103

22. Fair value measurement

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

	Date of valuation	Total US$'000	Quoted prices in active markets (Level 1) US$'000	Significant observable inputs (Level 2) US$'000	Significant unobservable inputs (Level 3) US$'000
Assets measured at fair value:
Derivative financial assets
Commodity contracts	31 December 2014	95,229	-	95,229	-
Forward foreign currency contracts	31 December 2014	2,409	-	2,409	-
Other financial assets
Available-for-sale financial investments
Quoted equity shares	31 December 2014	689	689	-	-
Loans and receivables
Other receivable	31 December 2014	22,103	-	-	22,103
Liabilities measured at fair value:
Derivative financial liabilities
Forward foreign currency contracts	31 December 2014	12,805	-	12,805	-
Commodity contracts	31 December 2014	40,486	-	40,486	-
Other liability
Other liability	31 December 2014	71,881	-	-	71,881
Liabilities for which fair values are disclosed (notes 20 and 25)
Interest bearing loans and borrowings	31 December 2014	227,035	-	227,035	-
Obligations under finance leases	31 December 2014	36	-	36	-
Sterling retail bond	31 December 2014	169,010	-	169,010	-
High yield bond	31 December 2014	651,077	-	651,077	-

There have been no transfers between Level 1 and Level 2 during the period. The forward foreign currency and the commodity forward contracts were valued externally by the respective banks and have been reviewed internally.

23. Provisions

	Decommissioning provision	Carry provision	Contingent Consideration	Total
	US$'000	US$'000	US$'000	US$'000

At 1 January 2013	232,952	-	-	232,952
Additions during the year	3,941	80,000	-	83,941
Acquisition	27,341	-	-	27,341
Changes in estimates	(48,711)	-	-	(48,711)
Unwinding of discount	12,588	-	-	12,588
Utilisation	315	-	-	315
At 31 December 2013	228,426	80,000	-	308,426
Additions during the year	7,622	-	-	7,622
Acquisition	133,569	-	26,700	160,269
Changes in estimates	75,135	-	-	75,135
Unwinding of discount	12,093	-	-	12,093
Utilisation	(7,177)	-	-	(7,177)
At 31 December 2014	449,668	80,000	26,700	556,368

Provision for decommissioning

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

The provision represents the present value of decommissioning costs which are expected to be incurred up to 2032 assuming no further development of the Group's assets. The liability is discounted at a rate of 3.0% (2013: 5.0%). The unwinding of the discount is classified as a finance cost (note 6).

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

Carry provision

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

Contingent consideration

As part of the purchase agreement with the previous owner of the GKA assets, a contingent consideration has been agreed. (See note 13.)

24. Trade and other payables

	2014	2013
	US$'000	US$'000

Trade payables	189,257	131,526
Accrued expenses	220,723	231,295
Over-lift position	13,108	-
Other payables	5,982	489
	435,725	363,310

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

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

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

25. Commitments and contingencies

Commitments

(i) Operating lease commitments

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

	2014	2013
	US$'000	US$'000

Not later than one year	2,031	2,703
After one year but not more than five years Over five years	3,733 1,335	3,267 2,235
	7,099	8,205

Lease payments recognised as an operating lease expense during the year amounted to US$3,086,000 (2013: US$2,676,000).

Under the Dons Northern Producer Agreement a minimum notice period of 12 months exists whereby the Group expects the minimum commitment under this agreement to be approximately US$13,976,000 (2013: US$24,363,000).

(ii) Finance lease commitments

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

	2014 Minimum payments		2014 Present value of payments	2013 Minimum payments	2013 Present value of payments
		US$'000	US$'000	US$'000	US$'000

Due in less than one year		37	36	36	35
Due in more than one year but not more than five years		37	36	74	72
		74	72	110	107
Less future financing charges		(2)	-	(3)	-
		72	72	107	107

The leases are fixed rate leases with an effective borrowing rate of 2.37% (2013: 2.37%) and have an average remaining life of one year (2013: two years).

On 20 December 2013, the Group entered into a bareboat charter with Armada Kraken PTE Limited (Armada) for the lease of an FPSO vessel for the Kraken field. The lease will commence on the date of first production which is currently targeted to come onstream by 2017. Armada will construct the vessel and the Group incurred an initial payment of US$100,000,000 which was paid during 2014.

(iii) Capital commitments

At 31 December 2014, the Group had capital commitments excluding the above lease commitments amounting to US$788,259,000 (2013: US$447,293,000).

Contingencies

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

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

There is also deferred consideration of US$3,000,000 dependent on FDP approval in relation to the 20% interest in Kildrummy acquired from ENI UK Limited during the year ended 31 December 2012, the costs of this well were impaired in 2014.

In the ordinary course of business there is a risk of disputes with partners, suppliers or customers relating to matters such as cost overruns, service provision or contractual terms. Should disputes emerge and become subject to formal legal proceedings the Group could face liabilities in the event of adverse determinations. As at the date of this report there are no material court or arbitration proceedings affecting the Group.

26. Related party transactions

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

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

All sales to and purchases from related parties are made at normal market prices and the pricing policies and terms of these transactions are approved by the Group's management. There have been no transactions with related parties who are not members of the Group during the year ended 31 December 2014 (2013: nil).

Compensation of key management personnel

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

	2014	2013
	US$'000	US$'000

Short term employee benefits	4,789	3,775
Share-based payments	3,375	4,314
Post employment pension benefits	42	31
	8,206	8,120

27. Risk management and financial instruments

Risk management objectives and policies

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

The Group's activities expose it to various financial risks particularly associated with fluctuations in oil price, foreign currency risk, liquidity risk and credit risk. Management reviews and agrees policies for managing each of these risks, which are summarised below. Also presented below is a sensitivity analysis to indicate sensitivity to changes in market variables on the Group's financial instruments and to show the impact on profit and shareholders' equity, where applicable. The sensitivity has been prepared for periods ended 31 December 2014 and 2013 using the amounts of debt and other financial assets and liabilities held at those reporting dates.

Commodity price risk - oil prices

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

The Group's policy is to have the ability to hedge oil prices up to a maximum of 75% of the next 12 months production on a rolling annual basis, up to 60% in the following 12 month period and 50% in the subsequent 12 month period.

Details of the commodity derivative contracts entered into during, and on had at the end of 2014, are disclosed in note 21.

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

	Pre-tax profit		Total equity
	+US$10/Bbl increase	-US$10/Bbl decrease	+US$10/Bbl increase	-US$10/Bbl decrease
	US$'000	US$'000	US$'000	US$'000

31 December 2014	-	-	(14,495)	37,910
31 December 2013	(76,379)	52,541	(29,024)	19,966

Foreign currency risk

The Group has transactional currency exposures. Such exposure arises from sales or purchases in currencies other than the Group's functional currency and the bond which is denominated in Sterling. To mitigate the risks of large fluctuations in the currency markets, the hedging policy agreed by the Board allows for up to 70% of non-US Dollar portion of the Group's annual capital budget and operating expenditure to be hedged. For specific contracted capital expenditure projects, up to 100% can be hedged. Approximately 1% (2013: 1%) of the Group's sales and 91% (2013: 91%) of costs are denominated in currencies other than the functional currency.

During the first half of 2013, the Group entered into a series of forward contracts and structured products to hedge a portion of its Sterling, Euro and Norwegian Krone exposure throughout 2013 and 2014. In 2014, a total of £182,000,000 of sterling exposure was hedged using this structured product with an average strike price of US$1.46:£1. If the spot rate at expiry of the contracts was above US$1.64:£1 then there was no trade and the Group funded its Sterling requirement through the spot market or drew Sterling on the bank facility. Between US$1.64:£1 and US$1.33:£1, EnQuest traded at the lower of US$1.46:£1 and the spot rate and below US$1.33:£1, EnQuest traded a higher volume of currency at US$1.46:£1.

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

During 2014, EnQuest entered several foreign exchange swap contracts when Sterling was trading above $1.66:£1. The realised impact of $46,756,000 has been recognised in the income statement within cost of sales.

The following table summarises the sensitivity to a reasonably possible change in the United States Dollar to Sterling foreign exchange rate, with all other variables held constant, of the Group's profit before tax due to changes in the carrying value of monetary assets and liabilities at the reporting date. The impact in equity is the same as the impact on profit before tax. The Group's exposure to foreign currency changes for all other currencies is not material:

	Pre-tax profit
	Year ended 31 December 2014	Year ended 31 December 2013
Change in United States Dollar rate	US$'000	US$'000
+10% -10%	(75,962) 75,962	(68,931) 68,931

Credit risk

The Group trades only with recognised international oil and gas operators and at 31 December 2014 there were no trade receivables past due (2013: nil), US$490,000 of joint venture receivables past due (2013: US$1,981,000) and US$1,955,000 (2013: nil) of other receivables past due but not impaired. Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary.

	2014	2013
Ageing of past due but not impaired receivables	US$'000	US$'000

Less than 30 days	183	4
30-60 days	-	-
60-90 days	5	-
90-120 days	2	-
120+ days	2,255	1,977
	2,445	1,981

At 31 December 2014, the Group had three customers accounting for 89% of outstanding trade and other receivables (2013: two customer, 72%) and three joint venture partners accounting for 95% of joint venture receivables (2013: three joint venture partners, 99%).

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

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

Liquidity risk

The Group monitors its risk to a shortage of funds by reviewing its cash flow requirements on a regular basis relative to its existing bank facilities and the maturity profile of these facilities. Specifically the Group's policy is to ensure that sufficient liquidity or committed facilities exist within the Group to meet its operational funding requirements and to ensure the Group can service its debt and adhere to its financial covenants. During 2014 the Group performed within the financial ratios applicable (and forecast for) that period as allowed for by its revolving credit facility. In light of recent low oil prices and in order to provide flexibility for EnQuest's capital investment programme, the revolving credit facility lending banks have agreed to relax existing credit facility covenants subsequent to the year end. The net debt / EBITDA covenant has been increased to 5 times and the ratio of financial charges to EBITDA is reduced to 3 times, both until mid-2017.

At 31 December 2014, the Group held a six year US$1,700,000,000 multi-currency revolving credit facility, comprising of a committed amount of US$1,200,000,000 with a further US$500,000,000 available through an accordion structure.

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


Year ended 31 December 2014		On demand		Up to 1 year		1 to 2 years		2 to 5 years		Over 5 years		Total
		US$'000		US$'000		US$'000		US$'000		US$'000		US$'000

Loans and borrowings		-		27,100		65,959		52,210		217,649		362,918
Bond		-		58,813		58,813		176,439		1,017,266		1,311,331
Obligations under finance leases		-		37		37		-		-		74
Accounts payable and accrued liabilities		429,070		-		-		-		-		429,070
Other liability		-		66,228		5,653		-		-		71,881
Carry provision		-		-		80,000		-		-		80,000
		429,070		152,178		210,462		228,649		1,234,915		2,255,274

Year ended 31 December 2013	On demand		Up to 1 year		1 to 2 years		2 to 5 years		Over 5 years		Total
	US$'000		US$'000		US$'000		US$'000		US$'000		US$'000

Loans and borrowings	-		26,100		21,580		38,310		255,809		341,799
Bond	-		14,140		14,140		42,418		299,502		370,200
Obligations under finance leases	-		35		36		36		-		107
Accounts payable and accrued liabilities	363,310		-		-		-		-		363,310
Other liability	-		164,176		-		-		-		164,176
Carry provision	-		-		80,000		-		-		80,000
	363,310		204,451		115,756		80,764		555,311		1,319,592

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

Year ended 31 December 2014
	On demand	Less than 3 months	3 to 12 months	1 to 2 years	>2 years	Total
	US$'000	US$'000	US$'000	US$'000	US$'000	US$'000
Commodity derivative contracts	-	24,374	24,052	-	-	48,426
Commodity derivative contracts	-	-	(6,130)	-	-	(6,130)
Foreign exchange forward contracts	-	78,313	48,514	-	-	126,827
Foreign exchange forward contracts	-	(78,893)	(56,296)	-	-	(135,189)
	-	23,794	10,140	-	-	33,934

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

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

Capital management

The capital structure of the Group consists of debt, which includes the borrowings disclosed in note 20, cash and cash equivalents and equity attributable to the equity holders of the parent, comprising issued capital, reserves and retained earnings as in the Group Statement of Changes in Equity on page 83.

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

The Group has approval from the Board to hedge the exchange risk on up to 70% of the non US Dollar portion of the Group's annual capital budget and operating expenditure. For specific contracted capex projects, up to 100% can be hedged. In addition there is approval from the Board to hedge up to 75% of annual production in year 1, 60% in year 2 and 50% in year 3. This is designed to minimise the risk of adverse movements in exchange rates and prices eroding the return on the Group's projects and operations.

The Board regularly reassesses the existing dividend policy to ensure that shareholder value is maximised. Any future payment of dividends is expected to depend on the earnings and financial condition of the Company and such other factors as the Board considers appropriate.

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

	2014	2013
	US$'000	US$'000
Loans, borrowings and bond net (A)	1,109,596	453,896
Cash and short term deposits	(176,791)	(72,809)
Net debt/(cash) (B)	932,805	381,087

Equity attributable to EnQuest PLC shareholders (C)	1,359,873	1,484,709

Profit for the year attributable to EnQuest PLC shareholders (D)	(176,409)	189,604

Profit for the year attributable to EnQuest PLC shareholders excluding exceptionals (E)	137,409	191,416

Gross gearing ratio (A/C)	0.816	0.306

Net gearing ratio (B/C)	0.686	0.257

Shareholders' return on investment (D/C)	(13%)	13%

Shareholders' return on investment excluding exceptionals (E/C)	10%	13%

28. Post balance sheet events

In February 2015, EnQuest announced that it had exited from its small investment in Tunisia. The transaction had been conditional on an appropriate response from the Tunisian authorities and with the backstop date for the transaction having passed without the required response, the parties elected not to extend. Potential consideration of $22 million had been kept in escrow, this was duly returned to EnQuest after the year end.

In 2015, the Group renegotiated financial convenants under its RCF to provide greater flexibility for its capital investment programme. The net debt/EBITDA covenant has been increased to 5 times and the ratio of financial charges to EBITDA is reduced to 3 times, both until mid-2017.

29. Subsidiaries

At 31 December 2014, EnQuest PLC had investments in the following subsidiaries:

Name of company	Principal activity	Country of incorporation	Proportion of nominal value of issued shares controlled by the Group
EnQuest Britain Limited	Intermediate holding company and provision of Group manpower and contracting/procurement services	England	100%

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

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

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

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

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

Stratic UK (Holdings) Limited (i)	Intermediate holding company	England	100%

Grove Energy Limited	Intermediate holding company and exploration of hydrocarbons	Canada	100%
EnQuest ENS Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest UKCS Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Norge AS (i) EnQuest Heather Leasing Limited (i) EQ Petroleum Sabah Limited (i) EnQuest Dons Leasing Limited (i)	Exploration, extraction and production of hydrocarbons Leasing Exploration, extraction and production of hydrocarbons Dormant	Norway England England England	100% 100% 100% 100%
EQ Property Limited (i)	Property development	England	100%
EnQuest Energy Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Production Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EnQuest Global Limited (i)	Intermediate holding company	England	100%
EnQuest NWO Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
EQ Petroleum Production Malaysia Limited (i)	Exploration, extraction and production of hydrocarbons	England	100%
NSIP (GKA) Limited	Construction, ownership and operation of an oil pipeline	Scotland	100%
EnQuest Global Services Limited	Provision of Group manpower and contracting/procurement services for the International business	England	100%
EnQuest Marketing and Trading Limited	Marketing and trading of crude oil	England	100%
NorthWestOctober Limited	Dormant	England	100%
EnQuest UK Limited (i)	Dormant	England	100%
EnQuest ED Limited (i)	Dormant	England	100%
EQ Petroleum Developments Malaysia SDN. BHD (i)	Exploration, extraction and production of hydrocarbons	Malaysia	100%
(i) Held by subsidiary undertaking.

This information is provided by RNS

The company news service from the London Stock Exchange

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