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ENEGI OIL PLC

AIM ticker: 'ENEG'

OTC ticker: 'EOLPF'

24 December 2014

Enegi Oil Plc

("Enegi" or "the Company")

Results for the year ended 30 June 2014

Enegi, the independent Oil and Gas Company, today announces its results for the year ended 30 June 2014.

HIGHLIGHTS

Building a portfolio of Marginal Fields:

· Continuing focus on the development of the Marginal Field Initiative through ABT Oil and Gas Ltd. ("ABTOG") in which Enegi holds a 50% interest.

· Strategy focused on utilising engineering solutions that reduce Capex, Opex and are redeployable to build a portfolio of low risk highly appraised marginal assets

· Continued development of the engineering solution for the Fyne field which shows that the SIFT solution is technically suitable and can provide necessary returns

· Engineering work on the Fyne field shows both of the solutions utilised in the Marginal Field Initiative have wider applicability to other projects

· Memorandum of Understanding agreed between ABTOG and Wood Group PSN to establish a dedicated marginal field engineering services company.

· Work completed on the Phoenix discovery, contained in UKCS Block 22/12b, indicates that Phoenix has strong potential to be a technically and economically viable project.

· Offered a 50% interest in Block 21/28b in the UKCS 28th Seaward Licensing Round. The award of this licence potentially allows for two further discoveries to be incorporated into a Development Plan for Fyne

Other Projects:

· Mutually agreed with Black Spruce Exploration Corp. to terminate the farm-in agreement governing the Company's western Newfoundland assets.

· EL1116 has been relinquished as it would not make economic sense to apply for a one year drilling extension.

· The Company has embarked upon an incremental investment plan centred on an Early Field Development ("EFD") plan that invites E&P companies and oilfield service companies to share a portion of phased development costs and risk in exchange for information, license equity and guaranteed services

Financial:

· Loss before tax for the year was £4,859,000 (2013: £3,115,000). The main area of expense has been the continuing development of the Marginal Field Initiative.

· The loss for the year includes £301,000 of finance costs associated with concluding financing arrangements with Dutchess Capital and Shard Capital Management as well as an exceptional charge of £1,150,000 (including the effect of foreign exchange) for an impairment against the carrying value of the Group's Canadian assets. This was deemed necessary due to the recent movement in the oil price. 

· The loss also includes a charge of £491,000 which represents the current fair value of the equity swap with YA Global at the current share price. Should the share price improve in the future the value realised by the Company will increase.

· Intangible fixed assets included additions of £899,000 that related to development work performed on the engineering solutions that form part of the Marginal Field Initiative.

· In December 2014, the Company agreed with Shard Capital Management to extend the period of repayment for the loan that was agreed in 2013, for a further 6 months.

· The arrangement for the extension of the loan included an addition to the principal of £200,000 which the Company will use over the coming months and the issuance to Shard Capital Management of 10,000,000 warrants, exercisable at a price of 2.3p over the next 24 months.

OUTLOOK

Marginal Field Portfolio:

· Clear focused strategy for commercialising marginal fields

· Negotiations continuing towards a definitive agreement between ABTOG and Wood Group PSN, conclusion of which is expected to accelerate the development of the Marginal Field Initiative

· Negotiations continuing to add further marginal field assets to our portfolio

· Significant marginal field opportunities with some 261 undeveloped fields in the UKCS alone, containing a combined 5,085MMBO reserves (IHS)

Other Projects:

· Commencement of Early Field Development plan in Newfoundland

Alan Minty, CEO of Enegi, commented:

"The period under review has undeniably been challenging for the Company. However, there is no doubt that the potential scale of our marginal field initiative is very significant. Whilst it has taken time and considerable effort to establish the foundations of this venture we are very confident that we are nearing the end of that phase and that we will see a considerable upturn in activity once it is completed.

As a company we are pursuing a strategy which we believe is highly appropriate at this time in light of market conditions and industry sentiment and believe the outlook for the Company remains very good.

I would like to thank management and shareholders alike for their continued support and look forward to realising the rewards from the opportunities that we have created."

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Qualified Persons

The information in this release has been reviewed by Barath Rajgopaul MSc (Mech. Eng.) C. Eng, a member of the Advisory Panel of Enegi. Mr. Rajgopaul has over 30 years' experience in the petroleum industry.

Chairman's Statement

There is no doubt that the period on which we are reporting on has been challenging. However, we have initiated a series of actions that allow us to maintain greater control of the outcomes and hence of our own destiny. It is my belief that the (marginal field) enterprise that we have chosen to launch can be truly global in its application but, as with all ventures of potential scale, it takes time and considerable effort to establish the foundations. We are nearing the end of that phase and we believe completion of the transaction with Wood Group PSN ('Wood Group'), with whom we are still concluding arrangements, will allow for a dramatic upturn in activity. The offering needs to be carefully moulded to take advantage of, and be positioned in, the market conditions.

The evidence that supports our belief in the Marginal Field Initiative continues to be accumulated. A new regulator in the North Sea charged with encouraging asset development, a downturn in activity in the UKCS shown by a reduction in drilling commitments in the 28th Licencing Round, as well as a reduction in current drilling activity and even the reduction in oil price, show that the business model is appropriate and timely. More fields are becoming marginal and marginal fields need to be developed to support the overall production rate in the UKCS and other jurisdictions. The solutions that we offer provide a way to develop those marginal fields through the overall reduction in Capex, and the adoption of the resultant operating and engineering philosophies provide a significant reduction on Opex.

The Fyne field has been the project on which we have targeted the majority of our resources during the period with the effect that we have honed the engineering on our solutions to allow additional projects to be advanced technically on the back of much of that work. Whilst the planned submission date for the Field Development Plan was not met, we retain a high degree of confidence that we have the technical solution that allows the project to develop.

While I am hugely encouraged by the progress we have made on marginal fields, we have been disappointed that it has not been possible to complete the objectives of the farm out with Black Spruce Exploration Corp ('BSE'). This time last year we had great hopes for the development of our assets in Canada and after recognising the problems of concluding investment for large scale plans in the current climate we have agreed with BSE to terminate the farm out agreement and for each party to proceed with different plans.

Earlier this month, we announced a new approach to developing the assets in western Newfoundland based upon some of the lessons we have learned in developing the Marginal Field Initiative, where existing data is re-assessed to determine both its current value and the investment necessary to advance a project to another phase. This incremental investment reduces the huge uncertainty that permeates exploration projects, which creates delays in activity and in approval of decisions and which contributes hugely to the cost escalation which is such a feature of the oil and gas sector. The simple principle that underpins the Early Field Development plan, as we have termed it, is to utilise the licence and existing knowledge to create the value on which further investment is sought. The incremental investment is determined by the success, or otherwise, of the preceding phase and is targeted at improving the underlying knowledge base and value rather than being focused on a long term objective where the risks cannot be accurately calculated at the outset. Consequently, each phase of investment is carefully formulated to understand the risks associated with the funds being directly applied to that project phase.

The new plan is a direct response to the current state of the financial markets in which small E&P companies, especially those with assets in frontier locations like western Newfoundland, have limited ability to raise funds for projects. That is why we, as a Board and Management Team, decided to enter into the marginal field initiative. It is a way in which we will always be able to identify and pursue projects because there will always be marginal fields (their typical size being dependent upon macroeconomic factors such as oil price) and with the building blocks that we have put in place, we will possess expertise in the philosophies, engineering or otherwise, that need to be adopted to develop them. In addition, in the early stages of the development of the project we will be able to clearly differentiate ourselves when competing for capital.

I would be being disingenuous if I did not provide shareholders with my views on the financial position of the Company. Implementation of the business plan will require an injection of new capital into the business, but the value that additional capital is able to generate should significantly exceed the effect of any potential shareholder dilution. The Directors and I continue to believe that the Company has developed a very attractive and unique business model in choosing to participate in the development of the Marginal Field Initiative and that additional finance will be available to Enegi upon completion of certain aspects of its plans.

Details of the specific activities on our assets can be seen in the Operational Review but it is my belief that we have established a venture that has the potential to be a global initiative and we would not have attracted the interest we have if others within the industry did not feel the same. The outlook, allowing for some potential hurdles in the current climate, is very good and as a final thought, I would like to thank management and shareholders alike for their continued support and look forward to realising the rewards from the opportunities that have been created over the last couple of years.

Alan Minty

Chairman

Operational and Financial Review

Marginal Field Initiative - ABT Oil and Gas Ltd.

The Marginal Field Initiative remains the Company's focus and it is our belief that its success offers a huge opportunity for the development and growth of the Company. The Marginal Field Initiative is embodied by ABT Oil and Gas Ltd. ('ABTOG') which is a joint venture ('JV') between the Company and Advanced Buoy Technology (ABTechnology) Ltd ("ABT").

The business model adopted in undertaking the marginal field initiative involves the identification of well appraised hydrocarbon discoveries that are undervalued, generally due to their size and lack of proximity to infrastructure, and through applying appropriate engineering solutions to allow strong returns to be generated thus enabling the discoveries to be developed. The engineering solutions offer a reduction in Capex, allow for the application of operating philosophies that significantly reduce Opex and are re-deployable in a cost effective way so that the disparity between the production life of the field and useful economic life of the engineering solution can be managed such that smaller fields are not disproportionately burdened with Capex.

The aim is for Enegi to utilise the business model to acquire interests in smaller discoveries at a discount to the prevailing market rates as it is able to establish the development solution as well as provide access to solutions that can be utilised to achieve the required returns.

On a strategic level the marginal field initiative provides a way for the Company to differentiate itself from other organisations in the oil and gas sector particularly important at a time when the sector appears depressed and companies that have adopted more traditional strategies are finding it difficult to get recognition for otherwise viable opportunities. Further, the market for the application of the business model is global to such an extent that ABTOG is protected from strong competition in the short to medium term.

Memorandum of Understanding with Wood Group PSN

To provide additional credibility to our ability to deliver the business model it is imperative that asset owners have the confidence that the solutions can be delivered should they engage with ABTOG. To that extent, ABTOG entered into a non-binding Memorandum of Understanding ("MoU") with Wood Group PSN ("WGPSN"). The MoU defines the terms under which it is proposed that WGPSN will subscribe for a 50% shareholding in an engineering solutions company defined as an upstream energy, oil and gas technology, project management and engineering company whose services are dedicated to the provision of solutions that will allow the technical development of stranded and marginal hydrocarbon fields. The entity will be the exclusive provider of engineering services to ABTOG projects and will not hold field equity with any such equity being held by ABTOG under its nominated structure.

It is also proposed that WGPSN will initially invest specific engineering services aimed at completion of the engineering of both of ABTOG's proprietary solutions, the Unmanned Production Buoy and Self Installing Floating Tower ( SIFT ), to the point where the solutions on a generic level are capable of satisfying the engineering requirements for the completion of a Field Development Plan ("FDP"). In addition, it is proposed that, as a shareholder, WGPSN will proportionally contribute to working capital and will, for projects that satisfy pre-agreed parameters, provide engineering services up to £5,000,000 on a deferred payment basis allowing the completion of FDPs for projects in which ABTOG participates. Together, these arrangements provide ABTOG with a strong base from which to implement its business plan, ensuring that the solutions are ready and resources are in place to develop projects quickly.

WGPSN, which is the largest provider of brownfield services to the energy, oil and gas industry, is the ideal partner and investor. This enables services to be provided throughout the entire asset lifecycle, from project management, concept, appraisal and FEED studies to detailed design, construction, installation and commissioning, dutyholder, operations & maintenance and, eventually, redeployment and decommissioning.

While not concluded yet, discussions continue with WGPSN and the Board fully expects a successful conclusion to negotiations in due course.

Fyne Field

As part of the first phase of implementing the JV's business model the JV agreed a farm-in with Antrim Resources (N.I.) Limited ("Antrim") that governs UK Central North Sea Licence P077 ("P077" or the "Licence"), which covers Block 21/28a, containing the Fyne Field ("Fyne").

Fyne is an extensively appraised oil field. The field is on a sand-filled channel linking the Pilot Field (250 mmbbls STOIIP) to the Guillemot complex (> 60 mmbbls recoverable reserves). The field has 2P reserves of 9.9 million barrels with an oil API of 25o. Five wells have been successfully drilled into the field with free flow test rates of up to 4,000 bopd.

The work carried out on Fyne has considerably advanced the engineering of the SIFT solution, which has provided a deeper understanding of its potential applications in the UKCS and beyond. With specific reference to Fyne, the solution proposed has proven to provide a robust economic case for the development of the field and Antrim Energy (Ventures) Ltd. ("AEV"), has been alerted to that effect. In order to arrive at that conclusion significant work has been undertaken including topsides design and engineering, structural and foundation design, installation methodologies and operating philosophies. All of these not only go to show that the SIFT is a viable solution for Fyne but confirm our belief in the solution as part of the broader Marginal Field Initiative.

The objective for Fyne was to submit a FDP to the Department of Energy and Climate Change ("DECC") by 31 August. Despite the considerable progress that had been made towards that goal the FDP was not submitted on time. However, we have been informed by AEV that they are in discussions with DECC about the next steps for the Fyne licence.

UKCS Block 21/28b

In conjunction with AEV, the Company was offered Licence 21/28b in the UKCS 28th Seaward Licensing Round. The offer of this licence allows for two further discoveries to be incorporated into the Fyne Development Plan and the Company will update on its implications in due course.

Additional North Sea Opportunities

The Company was awarded two licences in the 27th Seaward Licensing Round for the UKCS by DECC. Applications for the two licences that Enegi has been offered were made based on a thorough identification and evaluation of assets that, in the Company's opinion, were suitable for development using buoyant technology. The Company believed that both licences were in the optimum operating envelope for ABT's buoyant technology and that this technology offers the best chance of commercialising these assets.

Block 3/23is located in the south-west margin of the East Shetland basin and contains the Malvolio prospect. This is a Paleocene appraisal opportunity within the upper Montrose Group sand. The Company subsequently reached an agreement with Azinor Petroleum Ltd ("Azinor") under which a 50% interest in the area that is not considered to contain the Malvolio prospect was farmed out to Azinor in exchange for the completion of an agreed work programme that includes certain geological, geophysical and reservoir analysis utilising existing seismic and well data in respect of the whole Block. The work programme on this asset has been completed but did not provide the assurances that were required to advance to the next stage of the development path and so the Company has decided to relinquish the licence.

Block 22/12bis located in the Forties-Montrose High area of the Central North Sea and contains the Phoenix discovery. A discovery well was originally drilled by Shell and showed a 30 ft oil column in the Forties Sandstone Member, a proven producer in nearby fields such as Forties, Nelson and Montrose. The discovery is a low relief dip closed structure in water depths of 295 ft.

The Company subsequently reached an agreement with Azinor under which a 50% interest in the area that is not considered to contain the Phoenix discovery was farmed out to Azinor in exchange for the completion of an agreed work programme that includes certain geological, geophysical and reservoir analysis utilising existing seismic and well data in respect of the whole Block.

The completed work programme has confirmed that the oil bearing sands at Phoenix are contained within a simple and relatively low risk four way dip closed structure and the advanced technical work carried out by licence partner, Azinor, has successfully characterized and isolated these oil bearing sands from their surroundings. Using the new information, the subsurface model has been updated, revealing that the base case STOIIP for Phoenix is likely to be in excess of 16MMBO. This provides further confidence to the Company's view that Phoenix is a suitable candidate for development as part of the Company's marginal field initiative.

The Company is in discussions with DECC with respect to the most suitable manner in which to advance the licence.

North Celtic Sea Basin

Following the agreement to participate in the development of the Fyne field, ABTOG was able to secure a second significant opportunity by reaching agreement to farm into the Helvick and Dunmore discoveries (the "Discoveries") in the North Celtic Sea Basin, offshore Ireland. In return for the opportunity to acquire an aggregate 50% interest in the Discoveries a phased, three stage work programme will be conducted. The first phase requires the determination of commerciality over Dunmore and Helvick. Phase two is to prepare and apply for a Petroleum Lease, with Phase three culminating in the submission of a formal Plan of Development to first oil, using low cost development solutions. The farm-in is subject to the approval of the Minister of State at the Department of Communications, Energy and Natural Resources (the "Minister") granting a Lease Undertaking in respect of each Discovery.

Western Newfoundland

The Company has agreed a mutual termination of the farm-in agreement with Black Spruce Exploration Corp.

Nevertheless, western Newfoundland contains a variety of plays and prospects, but suffers with a lack of significant activity owing to its remote location and relative lack of infrastructure and services. This has stunted its potential for growth and has created a challenging environment in which to operate.

To address this Enegi has formulated the Early Field Development ('EFD') plan after discussions with a number of parties, some of which the Company anticipate could be partners. The plan is based upon principles incorporated in the marginal field initiative where existing prior information is assessed as to its value now and to the investment necessary to advance a project to another phase. This incremental investment reduces the huge uncertainty that permeates exploration projects, which creates delays in activity and in approval of decisions and which contributes hugely to the cost escalation which is such a feature of the oil and gas sector. The simple principle that underpins the EFD concept is to utilise the licence and existing knowledge to create the value on which further investment is sought. However, that investment is targeted at improving the underlying knowledge base and value rather than being focused on a long term objective where the risks at the outset cannot rationally be calculated. Consequently, each phase of investment is carefully formulated to understand the risks with the funds being directly applied to that project phase.

The Directors believe that the benefit for Enegi is significant. By selling knowledge and equity in existing licences to other parties on the basis that the Company is carried for prior and future investment, what is actually being delivered is not only an incremental and faster farm-in model, but also one that reduces the risks to the farmee hugely. In this way, the Company expect both service and existing E&P companies to subscribe to the EFD plan

Enegi's primary intent and key to the success of the region is delineating and developing the discovered Garden Hill Field Trend with this phased approach, which is expected to act as a catalyst for increased oil and gas activity in Western Newfoundland, before expanding operations to look at wider prospects.

Western Newfoundland Subsurface Evaluation

The west coast of Newfoundland is on the margin of the Anticosti Basin and the Company believes it to be one of the remaining frontier areas containing significant hydrocarbon potential. Enegi, through its involvement in the region for the past eight years, has identified a number of significant exploration plays, both conventional and unconventional, alongside the discovered "Garden Hill Field Trend" that extends on-to-off shore, using the results gathered from its own investment and utilising data from previous operators.

Enegi has integrated and analysed subsurface data from across the region, including seismic, well, and production data from PAP#1 ST#3 ("ST#3"). The most recent internal subsurface model revision estimates that 406mmbbl may be contained within the mapped Garden Hill Field Trend, of which approximately 85mmbbl could be recoverable in the P50 case. The table below shows the STOIIP and recoverable resources associated with the Garden Hill Field Trend that is contained in the acreage currently held by Enegi.

Employing modern techniques and incorporating ST#3 production data, Enegi has developed a revised model that accounts for previous results, and indicates a large discovered trend that also has considerable surrounding upside. The Company has integrated and interpreted c. 2,500 line km of 2D seismic data around and over the Port-au-Port Peninsula, and has completed a refined structural depth model that extends across PL2002-01(A), into EL1116 to the southwest, and also into the disputed acreage to the northeast (formerly held by Enegi under PL2002-01 and subject to judicial review following the DNR's decision in 2012 to limit the extent of the renewal).

The analysis suggests that the reservoir around ST#3 is continually recharged due to its location on the margin of a hydrothermal dolomite ("HTD") reservoir trend, where greater productivity wells can be placed in future. This is consistent with field trends such as Albion-Scipio and Lima-Indiana, which share similarly aged and altered reservoirs and lie along the Appalachian structural front, in the United States. Combined, these two proliferous field trends have recovered over 600mmbbls and have much in common to the Garden Hill Field Trend.

As well as defining the presence and extent of the Garden Hill Field Trend, a number of similar prospects have been identified along parallel and adjacent structural features - as experienced in areas where the analogous play models exist (i.e. the Albion-Scipio Field Trend). Such observations, once established, have the potential to build significantly upon the upside around the Port au Port ("PAP") region, and similarly along the west coast of Newfoundland where this play concept is present.

PL2002-01(A)

The lease covering the onshore element of the Garden Hill Field Trend, PL2002-01, expired in August 2012. The determination of a renewal of the lease is subject to the Petroleum Regulations under Newfoundland Labrador's Petroleum and Natural Gas Act. Under the Petroleum Regulations an Operator, on expiry of a lease, is required to relinquish all quadrants of a lease area that, based upon existing data, are not lying in whole or in part over a petroleum pool; or are not required for the drilling of injection wells or for the efficient development, conservation and production of a petroleum pool that is in production.

Further to the Petroleum Regulations, the Group was awarded a new licence, PL2002-01(A), that covers an area of 16km2 rather than the 158.8km2 covered by the original lease. This reflects the view of the Department of Natural Resources ('DNR') of the Provincial Government of Newfoundland and Labrador that the petroleum pool in contact with ST#3 is limited to the area governed by PL2002-01(A). It is the Group's view, however, that the area covered by the lease renewal is inconsistent with the model that best reflects the geology of the original lease. Consequently, the Group has issued proceedings to understand the DNR's determination and challenge that determination as appropriate.

Operationally, we have now reinstated production activities at the Garden Hill site, which had been suspended for a period due to unforeseen mechanical issues. Good pressure recovery was observed over the period during which the Well was shut in. The lack of observed pressure depletion continues to reinforce the Company's confidence in the potential of the Garden Hill Field with data indicating a minimum connected volume in excess of 100 million barrels of oil.

EL1070

The Group has continued to monitor the work programme currently being undertaken by Shoal Point Energy ("SPE") which, it is hoped, will result in an application for a Significant Discovery Licence over EL1070. EL1070 was due to expire in January 2011, but has remained in force due to the fact that SPE commenced the drilling of the 3K-39 well prior to the expiry date. The 3K-39 well requires hydraulic fracturing techniques to recognise and fully assess the potential of its target and at this time the Province of Newfoundland is conducting a review on these techniques.

EL1116

The Company has chosen not to extend further Period 1 of EL1116 in western Newfoundland. The licence will now expire on 15 January 2015. EL1116 contains a portion of the Garden Hill Field Trend (St. George's Bay prospect when viewed in isolation) that continues south west, offshore in the Cambro-Ordovician carbonate platform. Recent work provides strong evidence for this regional petroleum trend that also stretches to the north east into EL1070 (which contains the Shoal point lead).

The Company could have extended the licence for a further period of one year under the Canada-Newfoundland and Labrador Offshore Petroleum Board Land Tenure System by placing a deposit for $5,000,000. Instead the Company has chosen to focus its efforts on the Early Field Development ('EFD') plan. A successful reapplication at some time in the future would allow a greater time period in which to develop the licence area presently governed by EL1116 with a deposit significantly lower than $5,000,000.

The only definitive target identified within EL1116 is the St. George's Bay Prospect, being the offshore extension of the Garden Hill Field Trend. The true commercial potential of the trend will be established via the planned onshore work and should this warrant offshore activity the Company and its partners retain sole access to the information required to assess these developments.

Ireland

Enegi was awarded the Clare Basin Licensing Option, covering some 495 km2, on 14 February 2011. The work programme associated with the Option was completed in late 2012 and an application for an exploration licence was subsequently submitted in February 2013, prior to the expiry of the Option. Whilst we successfully completed our work obligations, the authorities have chosen to conduct additional environmental studies before granting an exploration licence.

Jordan

The Company continues to be involved in a project aimed at developing the Dead Sea and Wadi Araba block in Jordan with Korean Global Energy Corp.

The Dead Sea and Wadi Araba block is approximately 6,800 sq km in size and is on trend with the oil and gas fairway that runs across Saudi Arabia and has predominantly been explored to date by the majors or larger oil and gas companies.

The Company is waiting for the licence for the block to be fully approved by the Council of Ministers and ratified by Parliament.

Financial review

Revenue

Revenue of £45,000 was generated during the year ended 30 June 2014 as part of the testing of the PAP#1 well at Garden Hill site (2013: £184,000). A series of mechanical delays and uncertainty over the status of the now terminated farm-in agreement with Black Spruce Exploration Corp. contributed significantly to activity during the period. The PAP#1-ST3 well is now operational again and the data collected to date confirms the Company's view that the asset remains valuable.

Loss before tax

Loss before tax for the year was £4,859,000 (2013: £3,115,000). The main area of expense has been the continuing development of the foundations for the marginal field initiative. The loss for the year includes an exceptional charge of £1,150,000 for the impairment of the Group's Canadian assets and which was deemed necessary to reflect the current fall in the price of oil. In the event that the oil price recovers in future periods, this impairment can be reversed. The loss also includes £301,000 (2013: £78,000) of finance costs associated with concluding the loan with Dutchess Capital and with the loan from Shard Capital Management and a charge of £491,000 which represents the current fair value of the equity swap with YA Global at the current share price. Should the share price improve in the future the value realised by the Company will increase.

Statement of Financial Position

Group net assets at 30 June 2014 were £2,436,000 (2013: £4,675,000). The decrease in net assets is as expected when the impairment for the Canadian assets and the loan to Shard Capital Management are considered. Group net assets included intangible fixed assets additions of £899,000 that related to development work performed on the engineering solutions that form part of the Marginal Field Initiative.

At 30 June 2014, the Group had cash balances of £232,000, compared to £71,000 at 30 June 2013. The Group had trade and other payables of £3,220,000 at 30 June 2014 (2013: £2,267,000). These cash balances when considered with the additional information provided in Note 1 to the financial statements allow the Directors to conclude that the Group and Company should be treated as a going concern. The increase in trade and other payables is mainly due to the loan provided by Shard Capital Management.

Extension of Loan Agreement

In December 2014, the Company agreed to extend the loan with Shard Capital Management for a further six months for an additional cost of £120,000. The new terms included the Company taking out an additional loan amount of £200,000 which will be utilised over the coming months for an additional cost of £20,000. The aggregate total of £1,540,000 is repayable to Shard Capital Management within six months. The loan is repayable in cash or shares in the Company at the discretion of the Company.

As part of the terms of the loan extension Enegi has agreed to enter into a warrant agreement with Shard Capital Management to subscribe for up to 10 million Ordinary Shares, such warrants to be exercisable at a price of 2.3 pence per share, being a 31 per cent premium to the Company's market closing price on 22 December 2014 and to be exercisable at any time prior to the expiry of 24 months following the date of the loan extension.

Shard Capital Management will also retain the right to subscribe for further warrants in the future at a price to be agreed between Enegi and Shard Capital Management in order to retain a warrant holding of 5.4% of the total issued and outstanding shares in Enegi.

Cash flows

Cash outflows for the year were £221,000 compared to a net outflow of £2,006,000 in 2013. The cash outflow is as expected when fundraising and the funds expended during the year are taken into account.

Future funding and capital requirements

The Directors believe that the Company has developed a very attractive business model in choosing to participate in the development of the Marginal Field Initiative. Upon conclusion of the necessary foundations, its global potential will see an upturn in activity in 2015 and the Company will seek to utilise the offering to increase its project portfolio. Implementation of the business plan will require an injection of new capital into the business but the value that it is able to generate should significantly exceed the effect of any potential shareholder dilution.

CONSOLIDATED INCOME STATEMENT

For the year ended 30 June 2014

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME / (EXPENSE)

For the year ended 30 June 2014

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at 30 June 2014

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 30 June 2014

CONSOLIDATED STATEMENT OF CASH FLOWS

For the year ended 30 June 2014

Basis of presentation

The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union (IFRSs as adopted by the EU), the Companies Act 2006 that applies to companies reporting under IFRS, and IFRIC interpretations. The consolidated financial statements have been prepared under the historical cost convention.

Basis of consolidation

The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The Group recognises any non-controlling interest in the acquiree on an acquisition-by-acquisition basis, either at fair value or at the non-controlling interest's proportionate share of the recognised amounts of acquiree's identifiable net assets.