Enegi Oil : Interim Results for the six months ended 31 December 2014

ENEGI OIL PLC AIM ticker: 'ENEG' OTC ticker: 'EOLPF'

31 March 2015

Enegi, the independent Oil and Gas Company today announces its interim results for the six months ended 31
December 2014.

Key points:

 Strategy focused on utilising redeployable engineering solutions that reduce Opex and Capex to build a portfolio of low risk highly appraised marginal assets
 Continuing focus on the development of portfolio through ABT Oil and Gas Ltd. ("ABTOG").
 Building a consortium of "like-minded" major industry players to take forward the Company's Marginal Field Initiative - completion of ongoing discussions expected to lead to a dramatic upturn in activity
 New approach for development of western Newfoundland assets based upon an incremental investment
plan centered on an Early Field Development ("EFD")
 Increasing industry focus on cost reduction expected to drive operators to consider alternative approaches to field development - ABTOG's solutions and methods are appropriate for this
 Further projects expected to be added to portfolio
 Lower oil price environment increases the number and size of projects that can be potentially developed using our low Opex / Capex solutions
 Lower oil price environment increases the attractiveness of our solutions for projects, with returns significantly increasing as oil price strengthens
 Implementation of the business plan will require an injection of new capital into the business - the value that it is able to generate should significantly exceed the effect of any potential shareholder dilution

Alan Minty CEO of Enegi commented:

"The significant opportunities afforded by marginal fields, particularly in the current climate, remains the Company's focus. Dialogue with the market and, in particular, asset owners continually reinforces the need for delivery capability to be demonstrable. Our offering requires expertise across a broad spectrum of disciplines and, as such, we are looking to build a consortium of established industry partners, with discussions well advanced in a number of cases, to deliver this.

We consider that the completion of the appropriate agreements will provide a very strong endorsement to our marginal field initiative, complementing the substantial engineering work that has already been undertaken, facilitating a firm upturn in activity and the realisation of the vision in which all at the Company strongly believe."

Enegi Oil Tel: + 44 161 817 7460

Alan Minty, CEO
Nick Elwes, Director of Communications

Cenkos Securities

Neil McDonald Tel: + 44 131 220 9771
Derrick Lee Tel: + 44 131 220 6939

www.enegioil.com Facebook (Enegi Oil PLC) 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.

The six month period under review has been extremely challenging for the industry and is one that has seen wholesale changes being carried out following the dramatic fall in the oil price from the highs of June last year. This rapid decline in the oil price over the last six months of last year has seen many investment and development programs being put on hold or cancelled due to high development costs and lower revenues as a result of falling oil prices. In addition, operators are currently considering how to manage some current existing projects that are running at a loss.
While the industry is undoubtedly still coming to terms with a lower oil price environment, we have continued to establish and progress the foundations of our marginal field business. The business provides a way of developing projects utilising development solutions that have the ability to reduce Opex and Capex - a strategy that could be seen to have considerable prescience given the current oil price and focus on cost reduction across the industry. This environment also provides significant opportunities for us as oil and gas companies look for ways to preserve their cash whilst still needing to move their projects forward. Our business model of acquiring interests in projects, taking them to field development plan and then developing them using our solutions is a low risk, low cost and faster development solution for operators - creating what we believe is a very significant window of opportunity for us as lower oil prices persist.
As we look to progress our strategy of building a portfolio of assets that can be developed utilising these solutions, we remain in discussions with a number of major industry players in order to build a consortium of like-minded partners who will provide services and expertise to ensure the delivery of our Marginal Field Initiative. These are the foundations which we are looking to build and which, upon completion we believe that these potential partners will not only allow for a dramatic upturn in activity, but also provide further considerable industry endorsement of the venture. Whilst the time frame to setting up and completing this phase of our initiative has been frustrating, it is essential to ensure that we bring together the right team of partners and also ensure that we continue to retain an appropriate level of upside for the Company and our shareholders. Completing an inappropriate transaction that stifles the venture is as bad, if not worse, than not completing a transaction at all.
We believe that our lower cost solutions have a very significant competitive advantage with our solutions being suitable for the development of small fields between 16 mmbbls and 22 mmbbls even at these oil prices, projects which traditional solutions are currently unable to develop economically. With the cancellation of projects on fields with as much as 30 mmbbls, which were marginally economic with higher oil prices, an even more significant opportunity is now available to us as these larger and often more highly appraised fields are now no longer economic using traditional solutions; increasing the number of fields available to us as well as the potential size of each project.
Whilst lower oil prices have also undoubtedly impacted financiers appetite for investing in oil and gas projects given the potential returns from traditional solutions, we believe our business model and flexible approach for financiers will still be attractive in the current climate. In fact, the opportunities that we are presenting which are economic and provide solid returns for investors at the current prices, will provide very significantly improved returns should the oil price recover even to $85 per barrel. Ironically, what we have seen is that the lower oil price has increased the attractiveness of our offering due to the excellent economics of developing projects using our solutions given the significant increases in potential returns that can be gained when the oil price increases, something we are confident of given the cyclical nature of the oil and gas industry. Give n this we remain confident that we will be able to add further projects to our portfolio which we believe will be attractive to the industry and investors alike.

During the period we also announced a new approach to developing our assets in western Newfoundland based upon some of the lessons we have learned in developing the Marginal Field Initiative. This new approach will see us developing an incremental investment plan centred on our assets in western Newfound 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. We are already in discussions with a number of potential partners with a view to commencing an EFD plan and will provide further updates as they are agreed.
The Company continues to manage its cashflow carefully and a number of actions have been implemented during the period, and since its end, to reduce expenditures. Even allowing for these measures the implementation of our business plan will require an injection of new capital. The Board is also very mindful of the wishes of its shareholders on seeking to avoid dilution at lower prices and whilst new capital will be required the Board will, in line with shareholders requests, endeavour to try and ensure that this does not happen until further milestones have been met.
Allowing for this we have a very attractive and appropriate business plan and believe that our marginal field initiative offers us a very significant opportunity and that the value that any additional capital that is raised should generate should significantly exceed the effect of any potential shareholder dilution. We have also been vigilant to ensure that as a company we are not overburdened by excessive debt. This is a philosophy that we will continue as in the current climate we are already seeing a number of oil and gas companies struggling with their debt burdens to the detriment of their shareholders.
Whilst the current challenges facing our industry, especially in the UKCS, are substantial, through our strategy of focussing on reducing Opex and Capex it is my belief that we have a highly appropriate venture that has a very significant opportunity to grow in the current climate. What we are undertaking has the potential to be a truly global initiative and we would also not have attracted the interest we have if others within the industry did not feel the same. We are confident, allowing for some potential hurdles that a lower oil price environment brings, that our solutions, strategy and model are highly attractive to the industry and provide an exciting future for the Company.
Alan Minty
Chairman

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. This 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 continues to be to acquire interests in and build a portfolio of well appraised hydrocarbon discoveries that are undervalued, generally due to their size and lack of proximity to infrastructure, and through the application of our appropriate re-deployable solutions which allow strong returns to be generated, enable the discoveries to be developed. Our 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. Highly appropriate solutions given the current climate and focus on costs throughout the industry.
Whilst we have continued to establish and progress the foundations of the business; in order to provide additional confirmation in our ability to deliver the business model it is imperative that asset owners have the confidence that the solutions can be delivered. To that extent, ABTOG is looking to build up a consortium of like-minded major industry players who will provide services and expertise to ensure the delivery of our Marginal Field Initiative. These dialogues remain ongoing and the Company is confident that upon completion these partners will provide endorsement for the Marginal Field Initiative and have the potential to significantly increase this venture's activity. The Company expects that negotiations will be concluded within weeks and will make an announcement accordingly.
On the Fyne Field, we have, during the period, undertaken work which has considerably advanced the design and engineering of the SIFT solution for greater capex reduction and the requirements for 'Normally Unattended' operations to reduce opex in light of the oil price 'fall' providing deeper understanding of its potential applications in the UKCS and beyond. As a result of such work and most importantly, we are able to demonstrate that the solutions are economic at current oil prices on projects that would normally be relinquished. The solution proposed for Fyne has proven to provide a robust economic case for the development of the field but in the context of a wider regional development 'play' rather than as a 'stand-alone' project. This is the impact of the lower oil price; marginal fields become larger so there is a change of focus to opp ortunities that provide better returns for investment.
In conjunction with Antrim Ventures, ('AEV'), the Company was offered a production licence on Block 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.
On Block 22/12b, awarded to the Company in the 27th Seaward Licensing Round, the work programme has been completed as agreed under the farm-in agreement with Azinor. The programme has confirmed that oil bearing sands at the Phoenix Discovery ("Phoenix") are contained within a simple and relatively low risk four way dip closed structure and the advanced technical work 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. Again and as with Fyne, the impact of the lower oil price has to be recognised; the Company's view is that Phoenix remains a suitable candidate for development, but as part of a wider marginal field initiative 'play'. The Company is in discussions with DECC with respect to the most suitable manner in which to advance the licence.

ABTOG has also previously secured a further significant opportunity by reaching agreement to farm into the Helvick and Dunmore discoveries (the "Discoveries") in the North Celtic Sea Basin, offshore Ireland with Providence Resources. In return for the opportunity to acquire an aggregate 50% interest in the Discoveries a phased, three stage work programme will be conducted. 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, which the Company is currently awaiting.

Western Newfoundland

In Western Newfoundland Enegi has formulated the EFD plan which is a logical response to lower oil prices and what appears to be a change in investors' risk appetite regarding the uncertainty of larger 'plays'. A key characteristic of this plan is the reduction of risk by incremental project development. Furthermore, 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 - a highly appropriate strategy for such a frontier region such as western Newfoundland. This new approach will see us developing an incremental investment plan centered on our assets in western Newfound 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. The Company is already in discussions with a number of potential partners with a view to commencing an EFD plan.
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.
During the period the Company also updated its subsurface evaluation of its western Newfoundland assets. 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 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.

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. This further endorses the rationale for the Company's EFD
model and strategy.
Operationally on PL2002-01(A), the Company has 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. The Group also continues to believe that the area covered by the lease renewal, as granted in August 2012 reflects the view of the Department of Natural Resources ('DNR') of the Provincial Government of Newfoundland and Labrador, 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. This process is currently still ongoing.
On 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.

Non-core Assets

In Ireland we have previously successfully completed our work obligations under the Claire Basin Licencing Option and have applied for an exploration licence, however the authorities have chosen to conduct additional environmental studies before granting an exploration licence.
In Jordan the Company continues to be involved in a project aimed at developing the Dead Sea and Wadi Araba block with Korean Global Energy Corp. The Company is currently waiting for the licence for the block to be fully approved by the Council of Ministers and ratified by Parliament.

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 2014 Annual Report and Accounts.
The Company reports a loss of £1,083,000 for the period, a decrease of £198,000 over the corresponding period in 2013. This is primarily due to the Company reducing its overheads as it resolves the financial and corporate structure required to implement its strategy. Additionally, the result for the period includes a charge of £140,000 with respect to the loan from Shard Capital Management explained more fully below.
The Company received revenue of £27,000 during the period (2013: nil). 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. Data collected from the PAP#1-ST#3 well confirms the Company's view that the asset remains valuable.
Group net assets as at 31st December 2014 were £1,385,000 (2013: £4,173,000) the reduction in which is largely explained by the losses that the Company has realised over the following periods.

Extension of Loan Agreement

At 31 December 2014 the Group had cash balances of £17,000, compared to £299,000 at 31 December 2013. 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 for an additional cost of £20,000. The aggregate total of £1,540,000 is repayable to Shard Capital Management within six months of the period end. 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 entered 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.

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 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.

Unaudited 6 months ended 31

December

2013

£'000

Audited 12 months ended 30

June

2014

£'000

Cost of sales - - -

Administrative expenses (1,110) (1,281) (4,603)

Finance costs - - (301)

Taxation - - -

Basic (0.6p) (0.8p) (2.9p) Diluted (0.6p) (0.8p) (2.9p)

Unaudited

As at 31

December

2013

£'000

Audited

As at

30 June

2014

£'000

Tangible fixed assets 4,830 6,007 4,828

Intangible assets 1,157 725 1,155

Other long term assets 543 558 538

Trade and other receivables 619 398 680

Cash and cash equivalents 17 299 232

Trade and other payables (3,737) (2,826) (3,220) Due to related parties (1,594) (523) (1,329) (5,331) (3,349) (4,549)

Provisions (450) (465) (448) Total liabilities (5,781) (3,814) (4,997) Net assets 1,385 4,173 2,436

Ordinary share capital 1,857 1,569 1,857

Share premium account 26,137 24,459 26,137

Reverse acquisition reserve 9,364 9,364 9,364

Other reserves (2,487) (2,496) (2,487) Warrant reserve 355 355 355

Accumulated losses (33,841) (29,078) (32,790)

Unaudited

6 months ended 31

December

2013

£'000

Audited 12 months ended 30

June

2014

£'000

Cash used in operations (203) (1,453) (2,512)

Expenditure on tangible assets (-) (273) (899)

Proceeds from Loan - 1,000 1,000

Fees paid to secure Loan - (40) (40) Funds placed in an Equity Swap - - (500) Share capital issued for cash - 825 2,730

Cash and cash equivalents at the start of the year

Exchange (losses) / gains (12) 169 382

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.

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