Year End Results

Enegi Oil Plc

('Enegi' or 'the Company')

Results for the year ended 30 June 2011

Enegi, the western Newfoundland focused oil and gas company, today announces its results for the year ended 30 June 2011.

·; The work-over programme on the PAP#1 well began in August 2010 and after delays due to disputes with the farm-in partner the Company has received approval from the regulator to commence the final stage

·; The Company was awarded an onshore petroleum licensing option, ON11/1, covering an area of approximately 495 km2 within the Clare Basin in County Clare, Ireland

·; The Company's operating subsidiary, PDI Production Inc. (PDIP), terminated the farm-in agreement over PL2002-01 and now holds a 100% interest in that lease

·; The Company has adopted, and continues to implement, a strategy that seeks to avoid risk concentration on western Newfoundland by seeking to expand its investments and opportunities

·; The Company raised £1.4m during the year and realised £456,000 from the sale of non-core assets

·; The Company has de-listed from the Bourse de Luxembourg

·; The Company converted £1.5m of outstanding balances due to related parties to equity during the year

·; Net assets for the group has increased from £4,525,000 to £6,118,000

·; The Company created an Advisory Board to provide independent judgement on the value assessment and the monetisation process that should be adopted by the Board

CHAIRMAN'S STATEMENT

I am pleased to report on the progress made by Enegi Oil plc. ("Enegi Oil" or the "Company" together with its subsidiaries (the "Group")) for the year ended 30 June 2011 and to provide an update on those activities that have occurred since the financial year end.

There are two main themes that have governed our activities over the last year. The first is the conclusion of the workover on Garden Hill South in Newfoundland, Canada and the second is the implementation of the strategy to seek to reduce the Company's risk concentration through the Clare Basin and buoy technology.

This time last year we were involved in a farm-in on lease PL2002-01 and the workover had been commenced with encouraging results from the initial stages of the programme. After the initial stages, progress stalled and the Company spent considerable time in discussions with our farm-in partner to advance the work programme. Eventually we were left with little alternative but to terminate the farm-in agreement that governed PL2002-01 and to seek to advance the programme ourselves.

We believe that the termination of the farm-in agreement will, in the longer term, generate significant additional value for shareholders because self-financing the next phase of activity will result in a greater attribution of value from the PAP#1-ST3 well to the Company and its shareholders. That is, any dilution necessary to raise finance to complete the workover will be significantly less than the 40% of the value that would have been allocated to the farm-in partner on completion of their farm in obligations.

After terminating the farm-in agreements the Company raised over CAD1.5m through Canadian investors to undertake the remainder of the work programme. These funds were raised through an exciting opportunity via the Canadian markets where resource exploration activities in Canada allowed the Company's shares to qualify as 'flow-through shares' under the Income Tax Act (Canada). Flow-through shares are a tax-assisted investment vehicle for Canadian investors. The shares are issued pursuant to an agreement in writing under which the Company agrees to expend the funds raised on certain resource exploration activities. Expenses can then be renounced to the purchasers of the shares who can deduct up to an amount equal to the price they paid for the shares in computing their Canadian income tax liabilities. The renounced expenses allowed the Company to raise funds at a premium to its share price and it is an innovative approach for a UK company.

As in prior years, subject to any further fundraising, the company is reliant upon achieving commercial production in the foreseeable future. Achievement of commercial production will allow us to further develop the opportunities noted below. A key step in the process of achieving such production is the carrying out of the work over programme on the PAP #1 well following approval from the regulator. Approval from the regulator was received on 21 December 2011.

The second theme in our year has been the search for opportunities that will allow the Company to reduce its risk concentration on western Newfoundland. Two main opportunities arose through the year, the acquisition of petroleum rights in western Ireland and the investment in buoy technology.

In February 2011, Enegi Oil was informed by the Department of Communications, Energy and Natural Resources in Ireland that it had been awarded an onshore petroleum licensing option, ON11/1. ON11/1 covers an area of approximately 495 km2 within the Clare Basin in County Clare, Ireland. The Clare Basin is within the same fault system trend as the Company's prospect/leads and discovery in Newfoundland. ON11/1 contains the Clare Shale, an organically rich source rock that may contain shale gas. Work has commenced on this project and will continue in a manner that is consistent with the Company's financial position.

The award of ON11/1 grants Enegi Oil exclusive rights to undertake a defined programme of work, on areas of interest within the Clare Basin, within the two year option period, which expires on 28 February 2013. There are various elements in the work programme, including the delineation of prospective areas, the quantification of their gas potential, the identification of potential drilling targets and the identification of optimal well design. Depending on the results of the programme of work, an application may be made for an Exploration License over all or part of the areas covered by ON11/1 for the right to conduct drilling activities.

Finally, we come to buoy technology. In May 2011, the Company announced that it had secured a zero cost option to acquire the share capital of Advanced Buoy Technology (ABtechnology) Ltd ("ABT"). ABT has developed the ability to offer an innovative approach to developing proven oil and gas assets where the current estimates of recoverable reserves and extraction costs would cause the assets to be classified as marginal or sub-economic. The premise behind this innovative approach is the use of an unmanned buoy, which sits just below the surface, housing production and processing equipment. This contrasts with more traditional solutions where a fixed or floating production platform might be utilised. The impact of this technology is to significantly lower capital and operational costs for these developments allowing previously marginal fields to be economic.

The opportunity presented by ABT was identified over 2 years ago and, whilst the board believed it represented a potential platform to allow Enegi to execute its strategy of reducing risk concentration by providing the Company with a solution that can be leveraged with partners or on a standalone basis to extract value from assets previously considered to have limited value, unfortunately Enegi was not in a position to invest in the opportunity at that time.

While the workover on Garden Hill South is incomplete, that still remains the case and the option to acquire ABT expired in September 2011. Nevertheless, the Company remains excited about the prospect of a strategic partnership with ABT and, in particular, the opportunity to facilitate the expansion of the Company's existing asset portfolio and provide an alternative revenue source independent of the Company's existing assets. In the interim, the Company is pleased that ABT has agreed to continue to work exclusively with the Company.

To assist the Company in realising value from its opportunities an Advisory Board has been created. The purpose of the Advisory Board will be to provide the Company with access to a number of highly respected industry professionals across a broad range of disciplines that will be able to advise the Company as it implements its plans both in terms of buoy technology and its hydrocarbon assets.

The Advisory Board will operate in an analogous way to duties of non-executive directors. The major function would be to provide independent judgement on the value assessment and the monetisation process that should be adopted by the Board to maintain and optimise shareholder value.

The first appointment to the Advisory Board is Barath Rajgopaul an ex-Director of the Company who retired from his executive position in October 2011. The Company is in negotiations with a number of suitable candidates and will announce the first appointments in due course.

In summary, I am excited about the prospects for the coming year; the workover results from Garden Hill South are eagerly anticipated; we will commence work on a new exciting lead in Ireland and we continue to work with ABT with the aim of expanding further Enegi Oil's portfolio.

Finally, I would like to take this opportunity to thank all the staff for their contributions during the year.

Alan Minty

Chairman

OPERATIONAL AND FINANCIAL REVIEW

Enegi Oil's principal business activities include the development and operation of hydrocarbon assets, with its focus being on Atlantic Canada and western Ireland. The Company holds the hydrocarbon rights to an onshore petroleum lease, PL 2002-01 (the "lease"), and two offshore exploration licences, EL1070 and EL1116 (the "licences"), in western Newfoundland. The working interest in Ireland is held through an onshore petroleum licensing option, ON11/1 (the "option"). The Company was established to exploit prospects identified within the lease and licences and its portfolio has been increased by the option.

The lease was issued in April 2002 and has been extended until August 2012 upon the satisfaction of certain conditions, those which have fallen due to date having all been met. The lease covers an area of approximately 160km2 and contains the discovered field, Garden Hill South, as well as two other leads, Garden Hill Central and Garden Hill North.

The licence EL1070 was issued in January 2002 for a total period of nine years and covers an area of approximately 1,000km2. The licence contains the Shoal Point prospect and an unmapped lead, Lourdes. EL1070 continues to exist while our partners in the licence are diligently pursuing their current activities.

The licence EL1116 was issued in January 2009 for a total period of nine years and covers an area of approximately 2,120km2.

In February 2011, Enegi was informed by the Department of Communications, Energy and Natural Resources in Ireland that it had been awarded an onshore petroleum licensing option, ON11/1. ON11/1 covers an area of approximately 495 km2 within the Clare Basin in County Clare, Ireland. The Clare Basin is within the same fault system trend as the Company's prospect/leads and discovery in Newfoundland.

Garden Hill South

PDI Production Inc. ('PDIP'), the Company's wholly owned Canadian operating subsidiary, took delivery of Nabors Rig 45 after it had drilled a well at Shoal Point and commenced the re-entry of the PAP#1 well in August 2008, the main objective being the completion of a horizontal sidetrack.

During the drilling, which lasted into December 2008, both oil and gas were encountered. PDIP commenced a flow test on the PAP#1-ST#3 well at Garden Hill South on 21 January 2009 and during the drilling of the well and the subsequent flow test, 6,146 barrels of high quality crude oil (and 3,100 boe of associated gas) were produced. The Board however concluded, from the preliminary results of the flow test, that the well was sub-economic at that time and it was shut in on an extended well test. In November 2009 the well was reopened and initially flowed at 580 to 600 bopd plus associated gas.

The Company has further examined the flow and shut in test data to determine various options for improving the flow rate of the well. The data gained indicates that the well will produce on an interval basis; whereby the well may be flowed then shut-in, allowing it to recharge the in-contact reservoir pressure, before repeating the process. The period between each interval and the expected production is currently not known. The Company also reviewed the potential for re-entering the sidetrack to physically stimulate the well; an option which is thought to provide a solution.

Consequently, PDIP entered into a farm-in agreement for the PAP#1 well. Under the terms of the agreement, the farm-in partner was expected to gain a 30% interest in the well for a maximum expenditure of C$2.5 million (Canadian Dollars). The expenditure was expected to be used to initially log the well and then conduct a foam/acid fraccing operation which is anticipated to improve the production profile of the well. The original farm-out agreement was amended to provide the farm-in partner with a 40% interest in the well after completion of the workover as part of an overall regional development plan which incorporated additional activity on the remainder of PL2002-01. The work-over programme commenced in the autumn of 2010 and results from the initial stages indicated that with other components of the programme yet to be implemented the well was able to produce at a sustainable rate of 200bopd.

After the initial stages of the workover progress stalled and following lengthy discussions with the farm-in partner the Company decided that it was in the best interest of shareholders to terminate all farm-in agreements covering PL2002-01 and raise the funds for the completion of the workover itself. To that end the Company raised over CAD1.5m in June 2011 and has recommenced the workover.

Garden Hill Central and North

Garden Hill Central and North are 100% owned and operated by PDIP. TRACS International has estimated that Garden Hill Central and North have net mean unrisked resources of 24.6 mmboe and 8.3 mmboe respectively.

In August 2007, the Company commenced preparations for a 2D seismic programme covering the Garden Hill Central and Garden Hill North structures. This survey will provide additional information to better understand the two structures and determine initial drilling targets. Due to its size, Garden Hill Central is likely to be the first of these two structures to be drilled.

Although this survey was originally scheduled to take place in the fourth quarter of 2008, weather and technical delays have pushed the programme back. As part of the larger review which the Company is currently undertaking, the timing of this seismic work is now being reconsidered.

EL1116

In December 2008, PDIP was informed that it had been awarded further hydrocarbon exploration rights in the 2008 Call for Bids offered by the Canada - Newfoundland Offshore Petroleum Board (C-NLOPB). The successful bid was for an offshore parcel comprising 211,985 hectares which is adjacent to PL 2002-01 which PDIP currently holds.

The successful bid was based upon the Company committing to expenditure of C$600,000 in exploring the parcel during the initial five-year period of a nine-year Exploration Licence. PDIP has lodged a deposit equal to 25% of this work commitment with the C-NLOPB which will be offset against future expenditure. If significant quantities of petroleum resources are discovered as a result of exploration work, PDIP may then seek a Significant Discovery Licence from the C-NLOPB. Any Significant Discovery Licences issued in respect of lands resulting from the Exploration Licence will be subject to rentals which will escalate over time.

As stated in Enegi's Competent Persons Report at the time of the IPO, TRACS International believes that two of the structures that it has identified under Petroleum Lease 2002-01, Garden Hill South and Garden Hill Central, extend offshore. Management are currently considering the best way to advance the development of EL1116 and will update shareholders once the plan has been determined.

Shoal Point

In November 2009, the Group's operating subsidiary, PDIP, entered into an interest swap agreement with Canadian Imperial Venture Corporation and Shoal Point Energy on EL1070. Under the agreement, PDIP acquired a 100% interest in the more conventional St. George's Group play in exchange for its interest in the less conventional, shallower shale play.

In August 2010, PDIP agreed to enter into a farm-out agreement on Shoal Point. Under the terms of the agreement, the farm-in partner will commence a seismic programme that will cover the prospective areas of EL1070. The intention is for a minimum of 40% of the seismic to be shot in 3D, although this will be subject to environmental considerations and permitting issues. The farm-in partner will also drill a new well to test the productivity of the Aguathuna Formation located offshore, which contains the conventional Shoal Point prospect, assuming 100% of the total cost, risk and expense associated with the seismic programme and the drilling of the new well in return for a 70% interest in EL1070.

EL1070 was due to expire in January 2011 but will remain in force until such time as the drilling of a well is being diligently pursued and for so long afterward as may be necessary to determine the existence of a significant discovery based on the results of that well. Our partners in EL1070 commenced the drilling of a well before the expiry of the licence and management believe that the well will provide the necessary data to ensure that a Significant Discovery Licence ('SDL') will be awarded that covers the St. George's Group play in general and Shoal Point in particular.

ON11/1

In February 2011, Enegi was informed by the Department of Communications, Energy and Natural Resources in Ireland that it had been awarded an onshore petroleum licensing option, ON11/1. ON11/1 covers an area of approximately 495 km2 within the Clare Basin in County Clare, Ireland. The Clare Basin is within the same fault system trend as the Company's prospect/leads and discovery in Newfoundland.

The award of ON11/1 grants Enegi exclusive rights to undertake a defined programme of work, on areas of interest within the Clare Basin, within the two year option period, which expires on 28 February 2013. There are various elements in the work programme, including the delineation of prospective areas, the quantification of their gas potential, the identification of potential drilling targets and the identification of optimal well design. Depending on the results of the programme of work, an application may be made for an Exploration License over all or part of the areas covered by ON11/1 for the right to conduct drilling activities.

ON11/1 contains the Clare Shale, an organically rich source rock that may contain shale gas. Work has commenced on this project and will continue in a manner that is consistent with the Company's financial position.

Financial Highlights

No revenue was generated during the year ended 30th June 2011 (2010: £107,000).

Losses before tax for the year were £1,454,000 (2010: £1,256,000). The main reason for the slight increase in the loss in 2011 is that net revenue of £89,000 was realised during 2010 and administrative expenses have increased as the Company has sought to implement its strategy of avoiding risk concentration.

Group net assets at 30 June 2011 were £6,118,000 (2010: £4,525,000). The raising of funds and conversion of related party balances totalling £2,917,000 is mainly responsible for this movement offsetting the loss for the year.

CONSOLIDATED INCOME STATEMENT

For the year ended 30 June 2011

CONSOLIDATED STATEMENT OF RECOGNISED INCOME AND EXPENSE

For the year ended 30 June 2011

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at 30 June 2011

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 30 June 2011

CONSOLIDATED CASH FLOW STATEMENT

For the year ended 30 June 2011

Basis of presentation

The attached 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"), IFRIC interpretations and the Companies Act 2006 applicable to Companies reporting under IFRS. The attached consolidated financial statements have been prepared under the historical cost convention.

Basis of consolidation

On 18 March 2008, Enegi acquired PDIP via a share for share exchange. Under IFRS 3 'Business Combinations', this acquisition has been accounted for as a reverse acquisition, whereby PDIP is treated as the acquirer of Enegi. Arising from this treatment was the reverse acquisition reserve within consolidated shareholders' equity and the merger relief reserve within the legal parent Company's shareholders' equity.

The attached consolidated financial statements, therefore, represent the consolidated financial statements of PDIP combined with Enegi.

The financial statements of the subsidiaries are prepared for the same reporting year as the parent company, using consistent accounting policies. All intra-group balances, transactions, revenues, expenses and gains and losses resulting from intra-group transactions that are recognised in assets, have been eliminated on consolidation.

Subsidiaries are entities controlled by the Group. Control exists when the Group has the power, directly or indirectly, to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that are currently exercisable or convertible are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.