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ENEGI OIL PLC

AIM ticker: 'ENEG'

OTC ticker: 'EOLPF'

20 December 2013

Enegi Oil Plc

("Enegi" or "the Company")

Results for the year ended 30 June 2013

Enegi, the independent Oil and Gas Company, today announces its results for the year ended 30 June 2013.

Highlights:

Building a portfolio of Marginal Fields:

· Creation of ABT Oil & Gas ("ABTOG"), a joint venture between Enegi and ABTechnology ("ABT")

· Strategy to focus on utilising ABTOG's suite of solutions to build a portfolio of low risk highly appraised marginal assets

· Two projects already gained:

o Enegi and ABT have agreed to farm into the Fyne oil field, central North Sea

o ABTOG have agreed to farm into the Helvick oil field and Dunmore discovery, North Celtic Sea

· Wood Group PSN contracted to carry out FEED and pre-FEED studies to facilitate the Field Development Plan on Fyne

· Exclusive agreement reached between ABT and GMC Limited ("GMC") expanding buoyant development solutions available to ABTOG

· New management team in place at ABTOG

Other Projects:

· Multi-well farm-in agreed with Black Spruce Exploration ("BSE") to accelerate development of Newfoundland assets

· Two UKCS licences awarded to Enegi in the 27th Licensing Round, each containing either a prospect or a discovery

· Interests in the exploration potential of those UKCS licences farmed out to Azimuth and work is progressing

Financial:

· Loss before tax for the year was £3,115,000 (2012: £2,375,000) increasing as a result of the Company seeking additional opportunities for the future growth of the Company.

Outlook:

Marginal Field Portfolio:

· Clear focused strategy for commercialising marginal fields

· Submission of FDP for Fyne Oil Field to the Department of Energy and Climate Change ("DECC")

· Commencement of work programme in the North Celtic Sea

· 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 multi-well drilling programme in Newfoundland with BSE

Alan Minty, CEO of Enegi, commented:

"The Company has made excellent progress in the period under review, but my belief is that 2014 could be even more significant.

The strategic emphasis going forward will continue to be on our marginal field initiative. This initiative has seen significant interest both from industry and strategic partners as referenced by the addition of projects and the option with Wood Group PSN. Whilst we progress our current projects we are also confident that further projects can be added to our portfolio.

Western Newfoundland will also see unrivalled activity in the coming year. BSE will commence their extensive drilling programme which we believe will demonstrate the full potential of the region and increase the value of our assets.

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."

Enquiries:

www.enegioil.com

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Twitter (@enegioil)

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 be able to report on the progress made by the Company over the last 18 months which has seen some significant developments take place. The main highlights are the completion of a farm-in over our assets in Newfoundland and a change in the Company's strategic emphasis to focus on the development of a marginal field initiative for which management have been laying the foundations for a considerable period of time.

From its incorporation Enegi's stated objective has been to build a portfolio of oil and gas assets incorporating each of the phases of the exploration and production life-cycle, but with a particular weighting towards appraisal and development assets that can be managed through to production. Geographically, the focus was on western Newfoundland which management and investors believed offered a significant opportunity, albeit in an undeveloped hydrocarbon basin.

At the time that the original plan was devised the financial landscape was very different and in the intervening period financial institutions have significantly curtailed investment across all sectors and projects and junior oil and gas companies, which are so reliant upon the financial markets for capital to develop frontier plays, have felt the effect more than most.

The Company has always believed that to fully develop the petroleum system in Newfoundland, additional investment would be needed. The prize in western Newfoundland is potentially very significant with data indicating that the well at the Garden Hill field alone is in contact with over 100MMBO. However, as with all major hydrocarbon plays many wells are needed to clearly delineate the reservoir and determine the most appropriate engineering solution, all of which are expensive given the frontier nature of the region. Even with a well flowing at over 1,000 bbls/day, full development would take many years as financial institutions become less willing to invest in appraisal activity in a frontier territory.

Consequently, Enegi's management spent a great deal of time and resources in "working up" the Company's assets to the point where the full nature of the opportunity could be clearly defined and communicated to potential partners. The objective was to attract a partner with the technical and financial capability to implement the plans that the Company defined at the outset. After discussions with many potential partners the Company was delighted to conclude a transaction with Black Spruce Exploration ('BSE') on 24 July 2013, whose intent is to develop the play in western Newfoundland.

Forward Strategy  

Management understands the need to diversify its portfolio and to do that at low cost; the avoidance of risk concentration is therefore a cornerstone of its strategy and this reflects the attitude of financial institutions who are less willing to provide funds for assets that have higher perceived subsurface risk. Management's plan for the development of the Company acknowledges the constraints typically associated with the financing of junior oil and gas companies and is focused on shifting the Company's attention onto assets where the subsurface risk has been mitigated or, to a large extent, removed. Furthermore, management is committed to delivering a solution which generates sufficient returns to satisfy the requirements of financial institutions and investors.

The main premise of Management's plan is the application of appropriate and proven technology towards the creation of an economic development solution for an asset. This solution, often not considered by other operators, in many instances creates unanticipated value for the asset owner; some of which can be acquired, in exchange for the provision of the solution, at a cost that is significantly cheaper than the prevailing market rates. Hence, the plan allows further reserves to be accessed - reserves which have a tangible value and provide the ability to open up other financing opportunities to develop such projects, rather than by diluting shareholders.

The first stage of the implementation of the plan for Enegi was to reach a joint venture agreement with ABTechnology to work on the application of buoy technology. This was signed on 29 May 2013 and the joint venture is now called ABT Oil & Gas ('ABTOG').

ABTOG will only consider projects that are based upon discovered hydrocarbons. This means that costly exploration risk is removed allowing capital budgets to be allocated to value creation. Additionally, the current reluctance of financial institutions to fund exploration risk suggests that the timing of the business model might be preferential to more traditional investment models.

Implementation of Strategy and Development of ABTOG

One of the key elements in the successful implementation of the business model is that ABTOG is the industry leader and has exclusive access to the technology that it advocates. This has two main benefits, firstly it creates a strong negotiating position and secondly, it allows ABTOG to be able to benefit from returns both from the hydrocarbon asset and also from application of the technology. This is particularly important in being able to construct the appropriate financial model for each development.

The strategy has been rigorously tested through consultation with the industry, where discussions are ongoing with a number of operators, and proven through the transactions that have been concluded to date. The implementation of the business model has seen three major developments take place:

· Conclusion of a transaction with Antrim Resources (N.I) Limited ("Antrim") that governs UK Central North Sea Licence P077 ("P077" or the "Licence") containing the Fyne Field ("Fyne") that allows for the development of the Fyne Field;

· Completion of an agreement to farm-in to the Helvick and Dunmore discoveries in the North Celtic Sea Basin that allows for an assessment of the commerciality of the discoveries and field development as commerciality is proved;

· An expansion of ABTOG's technology offering via an exclusive agreement with GMC Limited to utilise their self-installing buoyant offshore platform.

ABTOG is an initiative that can provide long-term value to the Company, but the extensive interest that the business model has received also opens multiple strategic options for the development of ABTOG and the Company. These options can be categorised into two main groups. The first is at an investment level where, in holding a significant interest in a rapidly expanding, value accreting venture the Company has the ability to, amongst other things, trade or leverage that interest to structure its own portfolio.

The second category of options could be considered to be at a project level. As a major shareholder in ABTOG, the Company has significant influence over the decisions that ABTOG makes with regard to the projects that it garners with all the major options that relate to project ownership including the development and sale of assets. The initial development of ABTOG has seen it generate a level of interest that allows it to have discussions with operators that Enegi would otherwise be unable to access. Ultimately, this may well present Enegi with a route to participate in opportunities of a higher quality.

Other Company Activities

The licences that the Company acquired in the 27th UKCS Licensing Round, namely Malvolio (3/23 split) and Phoenix (22/12) are progressing well due to the Company's farmout of both licences to Azimuth Ltd. Our work obligations are on course to be satisfied well in advance of our decision dates and we look forward to being able to report on the results of the work programme in the 1st half of 2014.

To a certain extent the remaining opportunities in the Company's portfolio, namely the Wadi Araba Block in Jordan and the Clare Shale in Ireland, have become peripheral in the Company's activities. This is not due to any decision taken by Management but rather as a result of external factors within the jurisdictions of those assets. In Jordan, we are still awaiting ratification of the Wadi Araba block perhaps as a result of the geopolitical pressures that currently exist in that area. In Ireland, whilst we successfully completed our work obligations, the authorities have chosen to conduct additional environmental studies before granting an Exploration Licence.

Outlook

My belief is that 2014 offers significant potential for the Company. The extensive attention that the ABTOG business model is receiving indicates that transactions such as those already completed are repeatable. The Option Agreement entered into with Wood Group PSN provides additional validation on the potential of that initiative. In addition, we expect that there will be a new UKCS Licensing Round in 2014 which, our research indicates, contains a number of assets that are ideally suited to the implementation of ABTOG's buoyant solutions.

Also in 2014, we look forward to the commencement of BSE's drilling activities in western Newfoundland and are hopeful that an extensive work programme will confirm the potential of the region that we have supported for a long time.

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

Newfoundland

During the period, Enegi's management spent a great deal of time and resources in "working up" the Company's assets to the point where the full nature of the opportunity could be clearly defined and communicated to potential partners. The objective was to attract a partner with the technical and financial capability to implement the plans that the Company defined at the outset. After discussions with many potential partners the Company was delighted to conclude a transaction with Black Spruce Exploration ('BSE') who intend to develop the play in western Newfoundland post year end.

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 Licence. 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.

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 and 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, the testing of the PAP#1-ST#3 well has continued throughout the year in conjunction with the further development of the sub-surface model for the region. Despite the difficulties experienced, the operational team was able to establish a sustained production process generating data that indicates a minimum connected volume in excess of 100 million barrels of oil. Further, the data was invaluable in complementing the sub-surface models which were interrogated by BSE prior to the completion of the farm-in agreement.

Over the coming period, BSE intend to begin a multi-well drilling campaign in Newfoundland with a new well on the Garden Hill Field ("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). SPE is also planning to drill two wells in 2014 on its adjoining lands. The Company has been in contact with SPE with a view to clarifying the timetable for this process.

EL1116

The Company continues to advance its understanding of the St. George's Bay prospect that is located within the boundaries of EL1116. During the period, the Company received the results of a Competent Person's Report ("CPR"), which was performed by Deloitte of Calgary.

The CPR was commissioned after the acquisition and interpretation by the Company's technical team of over 1,000 km of existing seismic data, as well as the logs from the previously drilled wells A-09, A-36 and PaP#1, and confirms the beliefs of the Company with regard to the St. George's Bay prospect. The structure is part of a trend that continues south west, offshore, from the Garden Hill Field 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).

Material conclusions drawn from the CPR are as follows:

· The St. George's Bay prospect offers clear potential which:

o possesses a combination trap configuration of both structure and stratigraphic elements within a gentle roll over anticline bounded by two thrust faults;

o possesses a mature source rock with migration and reservoir fully confirmed; and

o makes it viable for an exploration campaign and appraisal efforts.

· The prospect is estimated by Deloitte 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.

Ireland

Enegi was awarded the Clare Basin Licensing Option, covering some 495 sq km, 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.

The key objectives of the work programme were to procure and evaluate existing technical data and obtain and analyse new samples to develop a provisional assessment of the potential of the option area.

The Company was pleased to announce that results of the work programme indicate that, given the maturity, thickness and buried depth of the shale, the Clare Basin remains prospective for shale gas. The studies undertaken also showed an area in the centre of an existing seismic grid, consisting of 130 line kilometres of 2D seismic, as being particularly high grade, based on the thickness of the shale and lack of faulting present.

As required under the terms of the Option, Enegi submitted on the 28 November 2012 a report summarising the studies and analysis that the Company carried out to the Petroleum Affairs Division of the Department of Communications, Energy and Natural Resources ("PAD"). In order to gain a fuller understanding of the potential of the region the Company also engaged Fugro Robertson ("Fugro") to prepare an independent estimate of in place resources within the acreage covered by the Option. A number of shale gas plays were evaluated and reviewed by Fugro during this process, with the Marcellus and Woodford gas shales identified as potential analogues due to similarities in properties and recent data indicating successful production from them. Based on detailed analysis of the area within the seismic grid and comparison with the Marcellus and Woodford analogues, Fugro provided the following preliminary resource estimates:

· 3.62 trillion cubic feet ("TCF") of free gas initially in place ("GIIP") within the seismic grid coverage, based on a most likely porosity of 7%, with 1.23 TCF of that being in the area identified as high grade.

· 1.55 TCF GIIP within the seismic grid coverage for a minimum porosity case of 3%, of which 526.4 billion cubic feet falls within the high grade area.

· Corresponding estimates for the entire Option area of 13.05 TCF GIIP (most likely) and 5.59 TCF (minimum case).

· Total recoverable resource estimates for the Option area of between 1.49 TCF and 3.86 TCF.

On the basis of these resource estimates Enegi has also undertaken some preliminary economic analysis which has confirmed the viability of the proposed development project with a strong best case investment profile.

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 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.

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.

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

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 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.

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 existing assets currently under licence to other operators.

ABT - 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.

Under the terms of the JV, 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 unmanned buoy technology, the directors believe that significant returns can be generated on such 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 has agreed to 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 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 ABT's buoy technology, for submission to DECC. Upon approval of the FDP by DECC, the JV will earn a 50% 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.

Following the completion of the Fyne agreement, interest in the JV'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.

Financial review

Revenue

Revenue of £184,000 was generated during the year ended 30 June 2013 as part of the testing of the PAP#1 well at Garden Hill South (2012: £204,000).

Loss before tax

Loss before tax for the year was £3,115,000 (2012: £2,375,000). The reason for the increased expenditure during the year is that the Company has deliberately sought out additional opportunities for the future growth of the Company. The result of this additional activity has been the creation of the marginal field initiative which Management believes offers a unique opportunity to create capital value for shareholders.

Statement of Financial Position

Group net assets at 30 June 2013 were £4,675,000 (2012: £7,514,000). An increase in expenditure while seeking and establishing new opportunities is mainly responsible for decrease in Group net assets.

At 30 June 2013, the Group had cash balances of £71,000, compared to £2,116,000 at 30 June 2012. The Group had trade and other payables of £2,267,000 at 30 June 2012 (2012: £1,777,000). 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.

Cash flows

Cash outflows for the year were £2,006,000 compared to a net inflow of £1,968,000 in 2012. This is mainly as a result of the Company not undertaking any fundraising activities in the year, although that was addressed following the year end allowing the Directors to conclude that the Group and Company should be treated as a going concern.

Future funding and capital requirements

The Directors believe that the new financing secured and the execution of the farm-in agreement with BSE provides sufficient resources to enable the Group to meet its working capital obligations and bring the PAP#1 well at Garden Hill South onto commercial production.

The Group continues to review its long-term strategy for the development of its assets and opportunities as well as how the Group will become self-sustaining from a financial perspective. The successful completion of the activities contemplated by the farm-in with BSE would yield significant financial returns to the Group but management are also aware that the investment in the marginal field initiative is potentially of great value. In addition, management is always vigilant with regard to opportunities to acquire production.

CONSOLIDATED INCOME STATEMENT

For the year ended 30 June 2013

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME / (EXPENSE)

For the year ended 30 June 2013

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at 30 June 2013

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 30 June 2013

CONSOLIDATED STATEMENT OF CASH FLOWS

For the year ended 30 June 2013

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.