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ENEGI OIL PLC

AIM ticker: 'ENEG'

OTC ticker: 'EOLPF'

31 March 2014

Enegi Oil Plc

("Enegi" or "the Company")

Interim Results for the six months ended 31 December 2013

Enegi, the independent Oil and Gas Company today announces its interim results for the six months ended 31 December 2013.

Highlights:

· Farmed out western Newfoundland assets to Black Spruce Exploration ('BSE')

· Development costs of a work programme that may include as many as 12 wells to be funded by BSE

· Enegi continues to focus on the development of ABT Oil and Gas, ('ABTOG') its marginal field initiative with ABTechnology Ltd.

· Focus of the Company's resources has been on developing the foundations on which the marginal field initiative can be successfully implemented and delivered

· Foundations include:

o Project Acquisition: Leveraging solutions to gain interests in projects with two secured (Fyne Field, UKCS and Helvick and Dunmore, North Celtic Sea)

o Delivery Capability: ABTOG range of solutions increased through strategic partnership with GMC Ltd for the Self-Installing Floating Tower

o Industry Endorsement: Completed transactions provide element of endorsement but expect to enhance through future activity

o Project Delivery: Fyne project advancing; environmental statement submitted to DECC. The intent is to submit final FDP late summer.

Outlook:

· Focus remains on development of marginal fields initiative through ABTOG

· Commencement of drilling programme in western Newfoundland

· Negotiations ongoing with further marginal field studies/projects anticipated to be added to portfolio

· ABTOG applying for further assets in the 28th Seaward Licensing Round for the UKCS

· Continue to investigate opportunities to acquire production assets

· Fyne field FDP to be submitted to DECC in late Summer

Alan Minty CEO of Enegi commented:

"Having farmed out the development of our assets in western Newfoundland to BSE, the Company has focused on the development of the marginal field initiative through ABTOG. Our belief is that ABTOG will create a new sector of the oil and gas upstream market in which stranded or marginal hydrocarbon accumulations, previously considered to have little or no value, will be subject to large increases in value because of the solutions that ABTOG provides.

We have expended considerable effort in laying the foundations for ABTOG's development and the business model is generating a lot of interest and gaining considerable traction. The scale of the opportunity should not be underestimated but considerable work will be required to access it.

That is not to say that we do not believe that western Newfoundland still provides a significant opportunity only that, in terms of our efforts and the potential returns for Enegi shareholders, we consider the marginal field initiative to offer greater potential."

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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

I am pleased to report on the progress made by the Company during the six months ending 31 December 2013. Having farmed out the development of its assets in western Newfoundland to Black Spruce Exploration ('BSE'), the Company has continued to focus on the development of the marginal field initiative through ABT Oil and Gas ('ABTOG'), its joint venture with ABTechnology Ltd. ('ABT').

My statement focusses on the development of ABTOG as the resources for the development of western Newfoundland are being supplied by BSE. That is not to say that we do not believe that western Newfoundland still provides a significant opportunity, it is just that we believe that, in terms of our efforts and the potential returns for Enegi shareholders, the marginal field initiative offers greater potential.

The objective of our work over the period has been to continue to develop the foundations on which the marginal field business model can be implemented to demonstrate to the industry, financiers and shareholders that ABTOG is capable of delivering its plans.

Those foundations can be categorised as follows and the Company continues to advance them to the point where we are satisfied that we can demonstrate the potential of the venture:

· Project Acquisition: Demonstrating that one of the fundamental assumptions of the business model, that marginal field solutions can be leveraged to generate interests in projects, is achievable;

· Delivery Capability: Demonstrating that the venture is capable of delivering the solution for projects in which it participates both in terms of engineering expertise and access to personnel;

· Industry Endorsement: Demonstrating that industry partners believe sufficiently in the project to become integral to its success; and

· Project Delivery:The completion of a project to 'First Oil'.

Our belief is that ABTOG is creating a new sector of the oil and gas upstream market in which stranded or marginal hydrocarbon accumulations, previously considered to have little or no value, are subject to a large increase in value because of the solutions that ABTOG provides, such increase in value being attributable to the significant decreases in capital and operational expenditures provided by the solutions.

In addition to the foundations that we are laying there is much circumstantial evidence to support our belief in the potential of the business model. Not least amongst that evidence is the recently delivered report, UKCS Maximising Recovery Review, which highlights several areas in which the UKCS commercial environment should be improved to maximise the economic recovery of the region's hydrocarbons. The commissioning of the report in itself demonstrates that a drive to enhance hydrocarbon recovery is underway.

The adoption of solutions to generate value from marginal and stranded fields clearly is imperative if the drive to maximise economic recovery is to be successful. We believe that, as one of the most mature basins in the world, the way the UKCS is managed will become an area of great interest for other governments and regulators as the results of the policies adopted for its future development are seen.

Overall, the marginal field initiative is advancing as I had hoped and great strides have been taken in progressing the venture. The scale of the opportunity should not be underestimated nor the work that will be required to achieve it.

Project Acquisition

During the period ABTOG reached agreement to participate in two projects, the development of the Fyne Field ('Fyne') with Antrim Resources (N.I) Limited ('Antrim') and the agreement to farm into the Helvick and Dunmore discoveries in the North Celtic Sea Basin, offshore Ireland. Discussions continue with other operators with respect to expanding the project portfolio.

Delivery Capability

To consolidate its position in the market, ABTOG has been extending the range of buoyant solutions available to the joint venture, whilst retaining the core principles and attributes of lower capex, lower opex due to normally unattended operation and redeployability. In addition to the production buoy solution significant effort was expended on successfully ensuring the suitability of the Self-Installing Floating Tower ('SIFT') in North Sea conditions in conjunction with GMC Ltd., a strategic partner of ABT.

Whilst the expansion of our portfolio provides further credibility to our ability to deliver appropriate solutions, it is our belief that credibility in this area has been evident for some time through the engineering strategic partnerships that have already been secured.

Industry Endorsement

We consider industry endorsement to be a continual process in which project stakeholders are seen to commit to projects through the application of their own resources. The application of resources can take a number of commercial forms but they will generally involve the commitment of some form of capital to a particular project or the venture in general.

In truth, this foundation has not yet been totally satisfied although the completed project acquisition activities provide significant endorsement. Discussions are underway to enhance this and we look forward to updating shareholders in due course.

Project Delivery

The nature of oil and gas development projects means that project delivery can take a long time and ABTOG must be able to develop a project through to 'First Oil'. The main project advancing presently is the development of Fyne. With Antrim the completed Environmental Statement for Fyne has been submitted to the Department of Energy and Climate Change ('DECC'). Following this, and once the Environmental Statement has been cleared, the final form of the Field Development Plan ('FDP') for Fyne is then expected to be submitted to DECC in late summer 2014. At the time of submission of the final FDP, any technical issues must be resolved, the environmental statement must be approved, evidence of suitable financing must be provided and Antrim must be approved as a Production Operator. First production is anticipated prior to 25 November 2016. This timeline has been agreed with DECC.

Outlook for the remainder of 2014

As I indicated in December, the Company has made excellent progress in the last year but I believe that 2014 could be even more significant, not least as a result of the drilling programme that BSE will be undertaking, which we expect to start to realise the full potential of our Newfoundland assets and justify our long standing commitment to the region.

The management's strategic focus remains on the development of marginal fields, through our involvement in ABTOG, and we plan to leverage the technology available to us to access interests in low risk, well appraised and in some cases developed fields that can provide production in short order. In the meantime, we are also investigating other opportunities to acquire production, which will provide revenue and improve our access to finance going forward.

In addition to the continuing development of its project portfolio, ABTOG is also currently identifying and evaluating assets available in the 28th Seaward Licensing Round for the UKCS where conventional development solutions may not be economically feasible and which are suitable for development using buoyant solutions. As previously, our focus in selecting opportunities is on well-appraised assets where there is a clear indication of the presence of hydrocarbons, remoteness from available infrastructure which favours a small, standalone development solution, and a physical environment that will allow successful implementation.

Alan Minty

Chairman

Operational Review

Newfoundland

During the period we entered into a farm-in agreement with Black Spruce Exploration ('BSE') in relation to our Newfoundland assets, PL2002-01(A), EL1116 and EL1070 (together 'the Assets').

The Farm-In will be completed in two phases:

· Phase 1: BSE will drill four new wells and rework PAP#1-ST#3. The four new wells will consist of one exploration well on EL1116, one exploration well on EL1070, and two appraisal wells in PL2002-01(A). Subject to securing necessary regulatory approvals, BSE is required under the Farm-In to spud each Phase 1 well within six months of completion of the previous Phase 1 well. Upon drilling an exploration well in each of the Exploration Licences, BSE will earn a 50% interest in that respective Exploration License. BSE will be required to drill the two appraisal wells on PL2002-01(A) and rework PAP#1-ST#3 before earning a 50% interest in PL2002-01(A).

· Phase 2: BSE will be required to drill seven further wells to increase its interest by a further 10%, to earn a 60.0% working interest in all the lease and licences held by Enegi. Three of these well locations will be identified by Enegi and the remaining four by BSE.

The Company continues to work closely with BSE to ensure that all technical and regulatory issues relating to the upcoming programme are appropriately addressed. We are also, with BSE, currently reviewing and confirming the schedule for drilling of the first well at Garden Hill, in light of the work required to ensure that BSE's rig is suitably equipped for all the anticipated wells and also taking into account the particularly harsh winter conditions that have been experienced in western Newfoundland this winter.

Garden Hill Field

The lease covering the Garden Hill Field ('GHF'), 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. 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 at the Garden Hill site, which had been suspended for a period following the unfortunate sudden death last year, from natural causes, of the Garden Hill Site Operations Manager. During the suspension we had to plan for the future on site, and we took the appropriate time and care to recruit and train a Wellsite Supervisor who is now overseeing the continuation of the ongoing testing of the PAP#1-ST#3 well ('the Well'). We also took the opportunity to ensure that the site and facilities were in the best possible condition for the upcoming drilling programme as well as for ongoing testing activities.

Good pressure recovery was observed over the period during which the Well was shut in. Initial pressure recovery following production periods has so far also been extremely encouraging, allowing the Well to flow freely at high rates for short intervals in line with the sustained production process that was established last year. 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.

Over the coming period, BSE intend to begin a multi-well drilling campaign in Newfoundland with a new well on the GHF, provisionally called PAP#4. Subject to receiving the appropriate regulatory approvals, PAP#4 will be drilled to appraise the conventional, proven oil bearing Aguathuna Formation. The targeted trend represents a zone of greater reservoir quality and connectivity within the Aguathuna Formation, the presence of which has been substantiated by test data obtained from flowing the existing PAP#1-ST#3 well.

EL1070

Further to the farm-out agreement with BSE, a well is required to be drilled on EL1070, most likely targeting the Shoal Point lead. 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 an SDL 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. SPE confirmed, in their announcement on 16 August 2012 that it is proceeding with its plans to drill a sidetrack well on the licence to test the hydrocarbon reservoir potential of the Green Point Shale (following issues experienced during drilling of the original 3K-39 well).

EL1116

EL1116 contains the St. George's Bay prospect. The structure is part of a trend that continues south west, offshore, from GHF in the Ordovician Carbonate platform, providing strong evidence of a regional petroleum trend that stretches south west from EL1070 (which contains the Shoal point lead).

A recently commissioned Competent Person's Report estimates the St. George's Bay prospect to contain:

It is anticipated that the well required to be drilled on EL1116 under the farm-in agreement with BSE will target the St. George's Bay prospect. A drilling deposit of $250,000 was paid by BSE to the Canada-Newfoundland Offshore Petroleum Board ('C-NLOPB'). This has extended the initial five year licence period (Period I), which was due to expire in January 2014 by a further 12 months.

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 KGEC.

The Dead Sea and Wadi Araba block is approximately 6,800 km2 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.

An initial work programme for the area is being developed, which will involve the evaluation of technical data and the acquisition of new geophysical data. It is also expected that at least three exploration wells will be drilled within four years on the block. Enegi, as Duty Holder, will provide all the technical and operational expertise into the development of the area. KGEC has also secured access to US$100 million and will provide the funding required to explore, appraise and develop this block.

The licence for the block is expected to be fully approved by the Council of Ministers and ratified by Parliament in the coming months.

North Sea

The Company was awarded two licences in the 27th Seaward Licensing Round for the UKCS by the UK Department of Energy and Climate Change ('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 buoy technology. The Company believes that both licences are in the optimum operating envelope for ABT's buoy technology and that this technology offers the best chance of commercialising these assets. Whilst conventional development solutions may not be economically feasible on these licences, appropriate technology such as that offered by ABT changes the economics significantly.

Block 3/23 is 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 Malvolio prospect is in water depth of 397 ft and is some 48 km from the nearest existing infrastructure and as such is considered to be isolated; however the STOIIP, as supplied by DECC, is between 153 and 326 MMBBL with a minimum and maximum unrisked recoverable range between 44 and 97 MMBBL.

The Company subsequently reached an agreement with Azimuth Ltd ('Azimuth') under which a 50% interest in the area that is not considered to contain the Malvolio prospect was farmed out to Azimuth 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.

Block 22/12b is 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. Internal estimates of unrisked STOIIP range between 15 and 99 MMBBL, with unrisked recoverable resources of between 9 and 51 MMBBL. DECC have classified the Phoenix field as a Significant Discovery, meaning that the field could have achieved flow rates in excess of 1,000 BOPD.

The Company subsequently reached an agreement with Azimuth Ltd ('Azimuth') under which a 50% interest in the area that is not considered to contain the Pheonix discovery was farmed out to Azimuth 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 Company is also continuing to evaluate with its partners other suitable assets in the North Sea that may become available through future licensing rounds or are currently under licence to other operators.

ABTOG - Marginal Field Development

Following the initial success of the strategic partnership between Enegi and Advanced Buoy Technology (ABTechnology) Ltd ('ABT'), under which successful licensing applications were made to DECC in the 27th Seaward Licensing Round for the UKCS, the Company entered into a formal Joint Venture agreement ('JV') with ABT, subsequently named ABT Oil and Gas ('ABTOG').

Through ABTOG, Enegi and ABT will work together globally to secure and develop interests in stranded, offshore oil reserves which can be accessed utilising ABT's technology. By using ABT's buoyant technology, the directors believe that significant returns can be generated on marginal and otherwise uneconomic fields. Accordingly, it is expected that the technology will allow the JV partners to secure reserves, which would otherwise not be available to farminees, at a cost which is substantially below the cost of accessing reserves which can be developed using conventional methodologies.

Following the commencement of the JV, the partners secured a further technology, GMC's self-installing, buoyant offshore platform, which it intends to utilise in the same manner as ABT's buoy technology. The solution provides a harsh environment, highly stable platform upon which to host modular drilling and production facilities as a cost effective alternative to other conventional development solutions. The system can also provide storage for produced oil either on the sea bed or within the buoyant structure, or have the facilities to export produced oil and gas to nearby infrastructure.

The system takes advantage of standard and repeatable low cost manufacturing techniques, is self-installing and where possible can be operated unattended during the production phase of a project. These advantages create a significant cost reduction and therefore provide a commercial solution to develop small and isolated oil and gas fields. The system is also highly flexible and can be easily redeployed with alternative topside modules installed in order to meet the operating requirements of follow-on fields.

After conclusion of the agreement with GMC, the JV now exclusively possesses a second solution which may be used to develop smaller oil and gas assets and has expanded the operating envelope for its solutions.

Fyne Field

As part of the first phase of implementing the JV's business model, that being the utilisation of proven and appropriate technology to acquire interests in well appraised fields, 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') containing the Fyne Field ('Fyne').

Fyne is an extensively appraised oil field located in Licence P077 which covers Block 21/28a in the Central North Sea. 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.

Under the terms of the agreement, Enegi and ABT will be responsible for the costs associated with preparing an amended Field Development Plan for Fyne (the 'FDP'), based on using ABTOG's buoyant technologies, for submission to DECC. Upon approval of the FDP by DECC, the JV will earn a 50% beneficial interest in the development of Fyne. A FDP has been previously prepared for Fyne and much of this work can be integrated into the new FDP.

A completed Environmental Statement for Fyne has been submitted to the Department of Energy and Climate Change ('DECC') as expected. Following this, and once the Environmental Statement has been cleared, the final form of the FDP for Fyne is then expected to be submitted to DECC in late summer 2014. At the time of submission of the final FDP, any technical issues must be resolved, the environmental statement must be approved, evidence of suitable financing must be provided and Antrim must be approved as a Production Operator. First production is anticipated prior to 25 November 2016. This timeline has been agreed with DECC.

Following the completion of the Fyne agreement, interest in the ABTOG's business model has been high and discussions with a number of operators have identified a number of strong, unlicensed targets. Management anticipates sustained growth in the value of the Company as projects and solutions are added and progressed and as risks associated with a number of projects are reduced once the first field reaches production.

North Celtic Sea Basin

Following the agreement to participate in the development of the Fyne field, the venture 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.

Upon award of each Lease Undertaking, the venture will be assigned a 10% interest in each Discovery with a further 20% interest upon award of the Petroleum Lease and following the completion of the second phase and another 20% following the approval of the Plan of Development by the Irish Government and completion of the third phase. Upon completion of the entire work programme, an aggregate 50% interest in the Discoveries will have been earned. Each assignment of equity will be subject to Ministerial approval.

Financials

The accounts for the period have been prepared in accordance with the International Financial Reporting Standards as adopted by the European Union using accounting policies that are consistent with those stated in the 2013 Annual Report and Accounts.

The Company reports a loss of £1,281,000 for the period, a decrease of £173,000 over the corresponding period in 2012. This is primarily due to the Company reducing its activities in developing new opportunities now that management has taken the strategic decision to focus its resources on the marginal field initiative.

The Company received no revenue during the period (2012: £84,000) mainly due to the suspension of activities on the Garden Hill Field following the unfortunate sudden death last year of the Garden Hill Site Operations Manager.

The Company secured additional financing through the placement of shares and through a loan, which realised £825,000 and £960,000 respectively, net of expenses. These funds have primarily been used for the advancement of the marginal field initiative and to facilitate the repurchase of 12,325,378 shares from BSE. These shares have been taken into Treasury.

In February 2014, the Company further secured its financial position through the placement of shares to raise £2,005,000 to continue the development of the marginal field initiative.

To facilitate the Company's participation in the 28th Seaward Licensing Round for the UKCS, the Equity Line Facility ("ELF") entered into with Dutchess Opportunity Cayman Fund ("Dutchess"), as announced on 19th May 2011, has been extended for a further two years with the Line Amount increased to £35 million. In consideration for extending the period of the ELF and increasing the line amount, Enegi has agreed to pay Dutchess a Commitment Fee of £100,000 in Ordinary Shares, equating to 1,428,571 Ordinary Shares. The Ordinary Shares will be issued on 1st April 2014 and it is expected that Admission of these shares will take place at 8.00am on 7th April 2014. Following Admission the Company will have 185,664,713 Ordinary Shares in issue. The extension of the ELF is an integral part of successful licence applications and therefore critical in the development of the marginal field initiative.

Group net assets as at 31st December 2013 were £4,173,000 (2012: £6,014,000) which is largely explained by the losses that the Company has realised over the following period.

CONSOLIDATED INCOME STATEMENT

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

CONSOLIDATED STATEMENT OF CASH FLOW

NOTE: These statements have been prepared under International Financial Reporting Standards as adopted by the European Union using accounting policies consistent with those in the last Annual Report.