ZOE.L Regulatory News (ZOE)

21 June 2017

Highlands Natural Resources plc ('Highlands' or 'the Company')

Final Results

Highlands, the London listed natural resources company, is pleased to provide its Final Results for the period ended 31 March 2017.

Highlights

· Bolstered portfolio with acquisition of two new projects in line with 80:20 strategy (near-term production/exploration) - independently valued with combined valuation range of US$441.8 million to US$600.1 million

· Portfolio now consists of three core projects:

· East Denver Niobrara Project - shale oil and gas in Colorado:

o Secured farm-in agreements and prime acreage acquisition with ConocoPhilips and Renegade Oil & Gas enabling Highlands to drill as many wells as possible until YE 2018

o NPV10 value ranging between US$23.4 million and US$124.6 million for 6-24 well programme

o Currently in negotiations regarding funding

· Helios Two Project - helium and methane in Montana

o Drilled first production well into Muddy Formation

o Dewatering process confirmed helium and methane content

o CPR by RPS indicates "best estimate success case" NPV10 of US$341 million for the natural gas development alone

· DT Ultravert - parent well protection and re-fracking technology

o Significant progress in commercialisation with first patent received post-period end

o Two successful tests completed in Piceance Basin

o Identified two potential applications: as a re-fracking agent; parent well protection

o Secured Calfrac Licence Agreement and extended Schlumberger agreement

Highlands Chairman Robert Price said, "This has been an incredibly exciting year for Highlands which has seen us expand our asset base to provide our shareholders with exposure to a diverse portfolio of high potential resource projects. With our three core projects all having company-making potential, we are eager to continue progressing them with a focus on our East Denver Niobrara drilling programme with a view to achieving near term cash flows and potential profitability."

Chairman's Statement

I am pleased to report that Highlands has been extremely active this year and has significantly expanded its asset base and enhanced its opportunities for the future. In particular, the Group acquired its "East Denver" and "Helios Two" projects during the year, both of which have the ability to transform the Group alongside its existing DT Ultravert technology.

The Board has stated its strategy is to establish a portfolio where 80% of the Group's portfolio should be comprised of production assets capable of providing a stable income, with the balancing 20% of the portfolio providing significant potential upside, albeit at a higher risk, through oil and gas exploration. The East Denver project fits into the 80% category whilst, at present, the DT Ultravert and Helios Two projects form part of the 20% category. It is the view of the Board that the Company's portfolio of projects provides numerous opportunities to realise substantial value for Shareholders.

The Group's core portfolio consists of:

· the East Denver Niobrara Project ('East Denver');

· the Helios Two Project ('Helios Two'); and

· its patent-granted and patent-pending DT Ultravert technology.

East Denver

The Group has farm-out agreements in Arapahoe County, Colorado with Renegade and ConocoPhillips, which collectively allow Highlands to drill as many wells as possible (up to Highlands' determination of optimal well spacing) until the end of 2018 in acreage highly prospective for the Niobrara shale formation.

In July 2016, Highlands completed a farm-out agreement with Renegade in Colorado to drill up to six lateral wells in acreage prospective for the Niobrara Shale Formation, located in the Denver Julesburg ('DJ') Basin. An independent engineering report published on 29 August 2016 by McCartney Engineering ('McCartney') indicated a probable category NPV10 of US$21.5 million for the first six extended lateral wells with an IRR of 92 per cent.

Given the compelling economics highlighted by the initial engineering report, in December 2016 the Board made the decision to extend the Group's contiguous acreage to a total of 3,840 acres via an additional farm-out with ConocoPhillips and lease acquisition from Renegade. Under the terms of the ConocoPhillips farm-out agreement, Highlands has the opportunity to drill and complete as many wells as possible (up to the level determined to be optimal well spacing and subject to certain required approvals). Highlands' land position is located in close proximity to numerous wells that have produced in excess of 100,000 barrels of oil in their first six months of production.

The Group commissioned a further report on the East Denver prospect from engineering firm RPS. This demonstrated an "1P" Proved NPV10 range for six wells of US$13.2 million to US$17.4, increasing to an "1P" Proved NPV10 between US$56.3 million and US$73.4 million for a proposed 24 well development programme. This validated the Group's decision to extend its acreage and the Directors believe that this further confirms the potential of near-term cash flow from East Denver.

To date the Group has invested approximately US$3.2 million in its East Denver assets.

Following the announcement of the farm-out agreement with ConocoPhillips, the Board initiated a competitive fundraising process with the support of the speciality energy investment banking firm Petrie Partners Securities, LLC. The Group has presented the East Denver project to more than 20 investment firms specialised in energy investment and has received a very positive and encouraging level of response. Highlands is currently working through a process of negotiating, selecting and finalising definitive agreements with its preferred investors. Any such investment, if finalised, would take a direct share of the East Denver project and not in the share capital of the Group. The advantage to Shareholders of these arrangements (if finalised) is that the investor would be obliged to pay a significant share of the costs of the project in order to earn their equity share in it.

A 24-well drilling programme may cost in the region of US$120 million or more and the Group's primary objective for the third party funding will be for an investor or group of investors to fund a majority of the capital costs of the East Denver project, with the Group covering the remainder. This funding may be staged over multiple tranches, with Highlands paying for a larger share of initial wells and the project investors covering more or all of the capital costs of later tranches of wells once the first tranche "de-risks" the project. Additionally, the Group may engage more than one investor with varying levels of risk tolerance in order to use lower-cost capital on later stages of development once investors perceive lower risk levels as a result of potentially successful early drilling efforts.

DT Ultravert

The Group has remained focused on the commercialisation of its DT Ultravert parent-well protection and refracking technology. The Group has now identified two potential applications for the technology, which could present very significant revenue streams in the future. In a separate report on the DT Ultravert technology, RPS identified an indicative success case value (NPV10) for DT Ultravert at US$58.3 million in a report dated 15 December 2015. This figure was increased by a new report in January 2017 to between US$78 million and US$135 million subject to further successful testing and commercialisation as a well refracturing and anti-bashing technology.

The first application for DT Ultravert is as a re-fracking agent, which could dramatically increase production from already stimulated horizontal and vertical wells. The Group presented the technology to a number of E&P companies and service providers, and in recognising the technical and practical merit of DT Ultravert, in 2015 the Group entered into an indicative terms agreement with Schlumberger to test DT Ultravert in the Piceance Basin in Colorado, which was extended in September 2016.

Highlands has also secured a licence agreement with Calfrac, a leading pressure-pumping provider in the US, in relation to DT Ultravert. Calfrac has licensed DT Ultravert on a shared exclusivity basis for use in connection with its commercial hydraulic fracturing operations, activities and services in seven US states. The licence agreement has an initial term of two years and will then automatically renew for consecutive one year periods, unless and until terminated. Additionally, Highlands has the exclusive right to market nitrogen gas to Calfrac at current market rates for all fracking operations undertaken by Calfac using DT Ultravert throughout the term of the licence agreement. Highlands and Diversion are collectively entitled to a 2 per cent royalty based on the revenue received by Calfrac from each fracking operation during the term of the licence agreement which uses the DT Ultravert re-fracking technology.

Throughout the year the Group has promoted the DT Ultravert concept and technology across the industry and has brought in additional staff to assist in the technical and marketing process. Following this, the Group signed its first commercial agreement for use of DT Ultravert in a vertical well re-frack with a prominent operator in the Denver Julesburg Basin, with an expectation to identify an initial well and commence operations in the near-term. That test was subsequently postponed due to a change in the operator's plans for its wellfield operations and logistics. However, the Group continues to communicate with the operator regularly in anticipation of re-initiating the project in the near-term. More generally, the Group accelerated its marketing efforts for DT Ultravert throughout the first quarter of 2017 in order to demonstrate the technical merit of DT Ultravert and secure additional commercial opportunities for DT Ultravert.

When the Group acquired its interest in DT Ultravert in 2015, the Board's initial plan was to seek to licence the technology to third parties in return for a royalty. The advantage of this strategy was primarily the low capital cost that Highlands would incur. With licences with Schlumberger and Calfrac secured, Highlands has investigated other methods of monetising its investment in DT Ultravert. One area of focus is a new business model whereby the Group would invest 100 per cent of the cost of the re-frack in exchange for 90 per cent of the incremental "wedge production" achieved from the re-frack, until such as time as the Group recovers a 200 per cent return of its costs (cost recovery plus 100 per cent). Beyond this 200 per cent mark, all incremental wedge production reverts to the operator. As well as providing Highlands with a potential financial return, this type of transaction will also bring the added benefit of showcasing the capabilities of DT Ultravert. This strategy would be initially cash intensive for the Group but, if successful, the payback on each investment would be rapid and this business model may allow the Group to quickly commercialise and scale DT Ultravert with partners across the oil and gas industry.

A second application was identified during the planning process for testing DT Ultravert as a re-fracking technology in the Piceance Basin in Colorado. 'Bashing' (which occurs when new wells are fracked near existing parent wells, often resulting in parent well damage and frac fluid infiltration), is a growing problem in the US oil and gas industry and the opportunity to test DT Ultravert as a way of protecting parent wells from this presented itself. The Group refers to this application as "Parent Well Protection". With shale providing thousands of candidates for this process, this has the potential to provide a significant opportunity for the Group. In September, the Group carried out its first field trial of the technology in the Piceance Basin with positive results, not only illustrating that DT Ultravert accomplished Parent Well Protection and prevented bashing but also demonstrated that new wells experienced production performance similar to fracks in virgin rock. The result highlighted that DT Ultravert can mitigate the risk of poor production in new wells, which is a growing concern in the oil and gas industry.

Due to the nature of the Group's stake in this technology, all technical, marketing and testing costs for the project are charged directly to the Income Statement. The direct testing costs and the cost of pursuing the patents during the year amounted to approximately US$0.5 million.

Positive test results to date have opened the door to additional potential Parent Well Protection applications in several major shale basins across the United States, and the Highlands team continues to advance discussions with multiple potential hosts. This marketing drive is being led by Domingo Mata, who joined the Group from Schlumberger where he was a senior engineer. Having presented it to a number of E&P companies and service providers, the Board is currently in discussions with regards to finalising a commercial Denver Julesburg Basin re-frack in the near term. In the meantime, the Group is advancing discussions with operators in the Permian, Williston, DJ and other major shale basins.

Post period end, the U.S. Patent Office issued Highlands' first DT Ultravert patent for Parent Well Protection. This is a major milestone for the Company and the grant represents the first issued patent among Highlands' portfolio of pending patent applications related to parent well protection and re-fracking. Based on the review and approval process for the Issued Patent, the Company is optimistic that additional patent applications may be approved and issued in due course.

Helios Two

In June 2016, the Group acquired exploration licences covering approximately 59,033 acres within the Custer, Carter and Fallon Counties in Montana, representing a potential natural gas and helium prospect, "Helios Two". The Directors believe that Helios Two is an attractive prospect, presenting numerous gas shows observed throughout the region where historic gas analysis indicated biogenic methane (natural gas) concentrations and 0.36 per cent helium content, similar to the Hugoton helium field, the largest natural accumulation of helium in the US. According to the 2017 U.S. Geologic Survey's "Mineral Commodity Report on Helium," the largest single consumer of helium is the magnetic resonance imaging (MRI) industry (equating to ~30 per cent of consumption in the US), and with the mandated decommissioning of the US Bureau of Land Management ('BLM') Cliffside Field by 2021, which historically has accounted for 30 per cent of global helium production (US Senate Energy Committee testimony by Walter Nelson on May 7, 2013), there are increasing concerns regarding helium supply reliability. As a result, US BLM auction prices (Bureau of Land Management Crude Helium Price, www.blm.com, 17 May, 2017) have exceeded US$100 per thousand cubic feet ('mcf') of crude helium in the past two years - a price that dwarfs benchmark pricing of natural gas, which lies in the US$2.00 to US$3.00 per mcf range. A significant helium discovery could therefore reduce helium costs and, as a result, reduce health imaging costs.

A Competent Person's Report for Helios Two was commissioned and published on 24 June 2016, in which RPS indicated a "best estimate success case" NPV10 of US$341 million for the natural gas development project alone from only a 69,120 acre area. Shareholders should note that this NPV10 figure represents RPS's evaluation of the statistical mean or average expected economic value assuming that the proposed de-watering processes succeeds on a technical basis. In other words, RPS has not discounted this value assessment based on the technical or process-related risks, and has provided a valuation figure for a successful outcome scenario. Following the publication of the initial RPS CPR, Highlands subsequently acquired further licences bringing Helios Two to a total of 105,444 acres in the project area. The Group commenced drilling of the Helios Well 5-52-16-22 in September 2016, targeting the Muddy Formation (the 'Muddy Well'). The initial drill results provided encouraging data enabling de-watering to commence, which entails a period of pumping and de-pressurisation of the reservoir in order to facilitate gas expansion and changes in relative permeability.

The Group optimised the de-watering process by installing a new electric submersible pump operated by Schlumberger into the Muddy Well, and obtained a permit for a disposal well as a long-term water disposal solution. Following the publication of an updated CPR in January 2017 which confirmed RPS' earlier findings, the Group reported that gas analysis at two independent gas laboratories confirmed the presence of 0.31 per cent to 0.33 per cent helium at Helios Two, providing conclusive evidence that helium is present in elevated concentrations at Helios Two and validating one of the primary considerations in Highlands's investment in the project. The Group is now focused on understanding the commerciality of this, drilling a disposal well, and accelerating the de-watering process to assess full-scale gas production rates and economics.

If full-scale de-watering is successful, the Directors believe that the Group will have substantially de-risked Helios Two from a scientific, technical and operational standpoint.

The costs to date in respect of the Helios Two project recognised as part of the Group's Exploration and Evaluation Assets amount to US$2.2 million.

Unfortunately, the Montana operations also suffered the Group's only setback in the year. Along with the "Muddy" well, the Group also drilled a second well, the "Eagle" well during the year. The aim was to use a different drilling technique and target a different shale formation. The primary goal of the exercise was achieved and the Eagle formation did produce natural gas in sufficient quantities to achieve intermittent surface flares, although without a stimulation treatment the flow rate was "too small to measure" using flow testing equipment. Importantly, Highlands drilled through approximately 800 feet of the formation without encountering significant saturation of water. Disappointingly, after logging the Eagle Well with a standard logging tool used in open holes, the Group's contractor dropped the tool back into the hole. Despite several retrieval efforts made by the contractor, the logging tool remained unrecovered. The Board, concerned by a risk of potential natural gas accumulations at surface during retrieval operations, decided to plug and abandon the well with the approval of Montana regulators. Therefore, although useful results were obtained, that well has now been closed and the costs of that particular operation, of approximately US$0.5 million have been charged directly to the Income Statement.

All of the reports referred to above from RPS are available on the Group's website and I recommend that shareholders review those reports along with other information provided.

Non-Core Portfolio

Outside of its core portfolio, the Group has other assets that it believes are value accretive and could provide significant upside potential. Whilst these are not currently viewed by the Board as forming part of the Group's core portfolio, these additional assets present future upside potential.

The Group acquired approximately 3,952 acres of land targeting the Niobrara and Muddy formations in Emmons County, North Dakota, which includes the shallow natural gas prospect, "Gravity".

Additionally, the Group acquired approximately 1,384 acres in Grand County, Utah which presents it with an in-situ uranium mining opportunity. The Group is currently in discussions with technical organisations to commission a CPR for this opportunity (although, as stated above, this is not currently a priority for Highlands).

Further details of these assets was provided in last year's Strategic Report.

Financial review

Funding

The Group is funded through investment from its shareholders. During the year, the Group successfully raised approximately £8.0 million through the issue of shares and the exercise of warrants (2016: approximately £1.9 million).

Revenue

The Group has generated no revenue from its operations in the year. The transactions undertaken so far have focussed on the acquisition of assets and rights that will be capable of generating revenue for the Group in future years and the evaluation of those assets.

Expenditure

The Group has invested a further £4.4m in its Exploration and Evaluation Assets during the year, a mixture of initial acquisition costs plus follow on evaluation expenditure, of which £0.9 million was settled by the issue of shares rather than in cash.

Total costs for the year charged to the Income Statement amounted to £3,370,000 (2016: £1,818,000), including non-cash charges of £220,448 (2016: £636,000) in respect of the options issued during the period. With the expansion of the Group's activities, the costs in both administrative and exploration areas have risen sharply. The recruitment of key staff into our Denver operations drove an increase in payroll costs from £107,000 to £605,000, in addition to which we incurred sub-contract costs of £214,000 for these personnel before they joined the Group as employees. The costs also include drilling, testing and consultancy costs charged directly to the profit and loss account of £684,000. These were principally the costs of the "Eagle" well which was drilled and then shut in during the year following a mistake by a subcontractor, plus the costs of testing the DT Ultravert technology. The Group incurs significant legal, professional, regulatory and consultancy costs both in its Denver operations and in connection with its listing on the London Stock Exchange. Whilst the costs are constrained as far as is possible, the Group has been active in its pursuit of opportunities and in building up its portfolio of projects and complying with all relevant regulations. The loss for the year includes costs of approximately £808,000 in these areas.

Liquidity, cash and cash equivalents

At 31 March 2017, the Group held £1,934,000 (2016: £717,000) which is now held primarily in US Dollar denominated accounts to match the predominance of the Group's US cost base.

Outlook

Highlands benefits from a strong and committed management team and exposure to a range of assets which we believe have the potential to deliver value to Highlands and its shareholders.

In pursuit of its 80:20 strategy, the Directors have determined primarily to focus the Group's resources on developing the East Denver Niobrara project, which the Directors believe is both one of the lower risk opportunities within the portfolio as well as a project which could be capable of delivering positive cash flows and profits to the Group within 24 months, along with pursuing the commercialisation of DT Ultravert and continuing to "prove" the Helios Two prospect.

The Group will need access to additional funds to enable it to capitalise on these opportunities and the Board is exploring a number of different avenues to accessing such funds. In essence, these centre around access to third party funding based on third party participation in the East Denver prospect and additional shareholder funding through the issue of more shares. The final choice on timing and mix of these funds will depend not just upon the availability of such funds but also the relative dilution suffered by existing shareholders, either through the increase in share capital or the decrease in stake in the East Denver prospect.

With the additional finance to hand, the Board believes that the Group has an exciting future.

Over the past year, the Group has recruited a strong and committed team in the USA to work alongside the Board in developing the Group's strategy and assets and I would like to take this opportunity to thank them, our advisers and you, our shareholders, for the effort and support throughout the year.

Robert Brooks Price

Executive Chairman

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

FOR THE YEAZR ENDED 31 MARCH 2017

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

AT 31 MARCH 2017

COMPANY STATEMENT OF FINANCIAL POSITION

AT 31 MARCH 2017

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEAR

COMPANY STATEMENT OF CHANGES IN EQUITY FOR THE YEAR

CONSOLIDATED CASHFLOW STATEEMNT FOR THE YEAR ENDED 31 MARCH 2017

COMPANY CASHFLOW STATEEMNT FOR THE YEAR ENDED 31 MARCH 2017

NOTES TO THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 MARCH 2017

1 GENERAL INFORMATION

1.1 Group

Highlands Natural Resources plc ("Highlands Natural Resources" or "the Company") and its subsidiary (together "the Group") are primarily involved in the oil and gas sector. Highlands Natural Resources plc, a public limited company incorporated and domiciled in England and Wales, is the Group's ultimate parent company. The Company was incorporated on 13 November 2014 with Company Registration Number 09309241 and its registered office and principal place of business is 9 Limes Road, Beckenham, Kent BR3 6NS. The comparative period covers the period from 13 November 2014 to 31 March 2016.

1.2 Company income statement

The Company has taken advantage of Section 408 of the Companies Act 2006 and has not included its own profit and loss account in these financial statements. The loss for the financial period dealt with in the accounts of the Company, including provision against the loans to subsidiary companies, amounted to £1,318,689 (2016: loss £1,827,186).

2. PRINCIPAL ACCOUNTING POLICIES

2.1 Basis of preparation

The Consolidated Financial Statements of the Group have been prepared in accordance with International Financial Reporting Standards (IFRS) and IFRS Interpretations Committee (IFRS IC) as adopted by the European Union and the Companies Act 2006 applicable to companies reporting under IFRS. The Consolidated Financial Statements have been prepared under the historical cost convention. The principal accounting policies are set out below and have, unless otherwise stated, been applied consistently for all periods presented in these Consolidated Financial Statements. The financial statements are prepared in pounds sterling and presented to the nearest pound.

2.2 Basis of consolidation

The Group financial information incorporates the financial information of the Company and its controlled subsidiary undertakings, drawn up to 31 March 2017. Control is achieved where the Company:

· has power of the investee;

· is exposed, or has rights, to variable return from its involvement with the investee; and

· has the ability to use its power to affect its returns.

Consolidation of a subsidiary begins when the Company obtains control over the subsidiary and ceases when the Company loses control of the subsidiary.

Where necessary, adjustments are made to the financial information of subsidiaries to bring accounting policies into line with those used for reporting the operations of the Group. All intra-group transactions, balances, income and expenses are eliminated on consolidation.

2.3 Going concern

The financial statements have been prepared on a going concern basis which assumes that the Group will continue in operational existence for the foreseeable future.

The Group is still in its early development stage and has as yet no revenues. The Group is financed through the investment by its shareholders and during the year the Group raised £8.9 million, net of costs, from the exercise of warrants and the issue of shares. The Group made a loss for the year of £3.1 million before taxation and foreign exchange adjustments, and, taking into account non-cash items and other changes in working capital, the net cash outflow from operating activities was £2.85 million. In addition, the Group invested a further £4.4 million in its core projects. This resulted in the Group holding bank balances of £1.9 million at the year end. The Group has continued to develop its projects since the year end and will need to access further finances for the coming year.

The Board is in discussion with a number of parties concerning their possible involvement in, and financing of, the Group's East Denver oil and gas prospect. Such third party involvement would provide the Group with the funds necessary to commence drilling at East Denver which should produce short term revenues and cash inflows for the Group. The Board is also considering other financing opportunities, which may involve further shareholder investment as an adjunct or replacement for such third party participation.

The Directors have reviewed the working capital requirements of the Group for the next 12 months and are confident that these can be met. The Directors have a reasonable expectation that further finances will become available during the course of the year through royalties and exploitation income relating to either new or existing agreements and the issue of further shares either through investor placings or the exercise of warrants. The Directors note that whilst there is an uncertainty as to the exact timing and source of these funds, and that the failure to receive sufficient funding from these sources would cast doubt on the Group's ability to continue as a going concern, nonetheless the Directors are cautiously confident that such funds can be obtained.

The Directors consider that the continued adoption of the going concern basis is appropriate and the accounts do not reflect any adjustments that would be required if they were to be prepared on any other basis.

2.4 Business combinations

There were no Business Combinations as defined by IFRS 3 (revised) during the period.

The acquisition of subsidiaries is accounted for using the purchase method. The cost of the acquisition is measured at the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed, and equity instruments issued by the Group in exchange for control of the acquiree, plus any costs directly attributable to the business combination. The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 are recognised at their fair values at the acquisition date.

In arriving at the cost of acquisition, the fair value of the shares issued by the Company is taken to be the mid-market price of those shares at the date of issue. Where this figure exceeds the nominal value of the shares, the excess amount is treated as an addition to the share premium account.

2.5 Revenue recognition

The Group has received no revenue during the period.

The Group's future income could consist of licence fees, milestone and option payments. Income is measured at the fair value of the consideration received or receivable.

Licence fees, option and milestone payments are recognised in full on the date that they are contractually receivable in those circumstances where:

• the amounts are not refundable;

• the licencee has unrestricted rights to exploit the technology within the terms set by the licence; and

• the Group has no further contractual duty to perform any future services.

Where such fees or receipts require future performance or financial commitments on behalf of the Group, the revenue is recognised pro rata to the services or commitments being performed. Funds received that have not been recognised are treated as deferred revenue and recognised in trade and other payables.

Revenues from work or other research and testing carried out for third parties are recognised when the work to which they relate has been performed.

2.6 Foreign currency translation

Highlands Natural Resources' consolidated financial statements are presented in Sterling (£), which is also the functional currency of the parent company. The individual financial statements of each group entity are presented in the currency of the primary economic environment in which the entity operates (its functional currency).

In preparing the financial statements of the individual entities, transactions in currencies other than the entity's functional currency (foreign currencies) are recorded at the rates of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary items denominated in foreign currencies are retranslated at the rates prevailing on the balance sheet date. Non-monetary items carried at fair value that are denominated in foreign currencies are retranslated at the rates prevailing on the date when the fair value was determined.

Exchange differences arising on the settlement of monetary items, and on the retranslation of monetary items, are included in the income statement for the period. When a gain or loss on a non-monetary item is recognised directly in equity, any exchange component of that gain or loss is also recognised directly in equity. When a gain or loss on a non-monetary item is recognised in the income statement, any exchange component of that gain or loss is also recognised in the income statement.

For the purpose of presenting consolidated financial statements, the assets and liabilities of the Group's foreign operations (including comparatives) are expressed in Sterling using exchange rates prevailing on the balance sheet date. Income and expense items (including comparatives) are translated at the average exchange rates for the period. Exchange differences arising, if any, are recognised in equity. Cumulative translation differences are recognised in profit or loss in the period in which the foreign operation is disposed of.

Goodwill and fair value adjustments arising on the acquisition of a foreign operation are treated as assets and liabilities of the foreign operation and translated at the closing rate.

2.7 Defined contribution pension funds

From time to time the Group may pay contributions related to salary to certain UK employees' individual pension schemes. The pension cost charged against profits represents the amount of the contributions payable to the schemes in respect of the accounting period. No separate provision is made in respect of non-UK employees.

2.8 Investment in subsidiaries

Investment in subsidiaries comprises shares in the subsidiaries stated at cost less provisions for impairment.

2.9 Financial instruments

Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group becomes a party to the contractual provisions of the instrument.

Financial assets can be divided into the following categories: loans and receivables, financial assets at fair value through profit or loss, available-for-sale financial assets and held-to-maturity investments. Financial assets are assigned to the different categories by management on initial recognition, depending on the purpose for which the instruments were acquired. The designation of financial assets is re-evaluated at every reporting date at which a choice of classification or accounting treatment is available.

Derecognition of financial instruments occurs when the rights to receive cash flows from investments expire or are transferred and substantially all of the risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at least at each balance sheet date whether or not there is objective evidence that a financial asset or a group of financial assets is impaired.

Trade receivables

Trade receivables are measured at initial recognition at fair value plus, if appropriate, directly attributable transaction costs and are subsequently measured at amortised cost using the effective interest method. Appropriate allowances for estimated irrecoverable amounts are recognised in the income statement when there is objective evidence that the asset is impaired. The allowance recognised is measured as the difference between the asset's carrying amount and the present value of estimated future cash flows discounted at an effective interest rate computed at initial recognition.

Loans receivable

Loans receivable are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They arise when the Group or Company provides money directly to a debtor with no intention of trading the receivables. Loans receivable are measured at initial recognition at fair value plus, if appropriate, directly attributable transaction costs and are subsequently measured at amortised cost using the effective interest method, less provision for impairment. Any change in their value is recognised in the income statement.

Cash and cash equivalents

Cash and cash equivalents comprise cash on hand and demand deposits that are readily convertible to a known amount of cash and are subject to an insignificant risk of change in value.

Financial liabilities and equity

Financial liabilities and equity instruments issued by the Group are classified according to the substance of the contractual arrangements entered into and the definitions of a financial liability and an equity instrument. A financial liability is a contractual obligation to either deliver cash or another financial asset to another entity or to exchange a financial asset or financial liability with another entity, including obligations which may be settled by the Group using its equity instruments. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities. The accounting policies adopted for specific financial liabilities and equity instruments are set out below.

Financial liabilities

At initial recognition, financial liabilities are measured at their fair value plus, if appropriate, any transaction costs that are directly attributable to the issue of the financial liability. After initial recognition, all financial liabilities are measured at amortised cost using the effective interest method.

Equity instruments

Equity instruments issued by the Group are recorded at the proceeds received net of direct issue costs.

2.10 Property, plant and equipment

The Group holds no property assets.

All plant and machinery is stated in the accounts at its cost of acquisition less a provision for depreciation.

Depreciation is charged to write off the cost less estimated residual values of plant and equipment on a straight line basis over their estimated useful lives. Estimated useful lives and residual values are reviewed each year and amended if necessary.

The principle rate of depreciation used is 25% per annum.

2.11 Intangible assets

Patent rights

Intangible assets include acquired intellectual property in the form of patent rights used in oil and gas operations. These assets are stated at cost less amortisation.

Intellectual property rights acquired during the period are capitalised on the basis of the fair value of equity instruments issued to acquire the specific rights.

Costs associated with prosecuting and maintaining these intellectual property rights are treated as an expense in the period in which they are incurred.

Amortisation is applied to write off the cost less residual value of the intangible assets on a straight line basis over their estimated useful life. The principal rate used is 10% per annum.

Exploration and evaluation assets

The Group has acquired numerous leases and mineral rights from third parties on which it has expended further sums in evaluating the assets for technical feasibility and commercial viability. These costs are treated as "exploration and evaluation assets" and are initially recognised at cost, being the purchase cost plus further exploration and evaluation expenditure in accordance with IFRS6.

Subsequent to initial recognition, each asset is assessed for impairment. An impairment provision is made where the carrying value exceeds the assets recoverable amount.

Development costs are excluded from that treatment and are taken directly to the profit and loss account.

2.12 Impairment testing of intangible assets and property, plant and equipment

At each balance sheet date, the Group assesses whether there is any indication that the carrying value of any asset may be impaired. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs.

In the case of goodwill and any intangible asset with either an indefinite useful life or which is not yet ready for use, the Group tests for impairment at each balance sheet date.

For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units). Goodwill is allocated to those cash-generating units that are expected to benefit from synergies of the related business combination and represent the lowest level within the Group at which management controls the related cash flows.

Individual assets or cash-generating units that include goodwill and other intangible assets with an indefinite useful life, or those not yet available for use, are tested for impairment at least annually. All other individual assets or cash-generating units are tested for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

An impairment loss is recognised for the amount by which the asset's or cash-generating unit's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of fair value, reflecting market conditions less costs to sell, and value in use, based on an internal discounted cash flow evaluation. Impairment losses recognised for cash-generating units to which goodwill has been allocated are credited initially to the carrying amount of goodwill. Any remaining impairment loss is charged pro rata to the other assets in the cash generating unit.

2.13 Operating leases

Leases where substantially all the risks and rewards of ownership remain with the lessor are accounted for as operating leases and are accounted for on a straight line basis over the term of the lease and charged to the income statement.

2.14 Equity

Share capital is determined using the nominal value of shares that have been issued.

The Share premium account includes any premiums received on the initial issuing of the share capital. Any transaction costs associated with the issuing of shares are deducted from the Share premium account, net of any related income tax benefits.

Equity-settled share-based payments are credited to a Share-based payment reserve as a component of equity until related options or warrants are exercised.

Retained loss includes all current and prior period results as disclosed in the income statement.

2.15 Share-based payments

The Group issued warrants to the initial investors and certain counterparties and advisers in the previous period and has issued share options to its US based staff during the current year.

Equity-settled share-based payments are measured at fair value (excluding the effect of non market-based vesting conditions) at the date of grant. The fair value so determined is expensed on a straight-line basis over the vesting period, based on the Group's estimate of the number of shares that will eventually vest and adjusted for the effect of non market-based vesting conditions.

Fair value is measured using a Black Scholes pricing model. The key assumptions used in the model have been adjusted, based on management's best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.

2.16 Taxation

Tax currently payable is based on taxable profit for the period. Taxable profit differs from profit as reported in the income statement because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.

Deferred tax is recognised on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from initial recognition of goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset realised. Deferred tax is charged or credited to profit or loss, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Group intends to settle its current tax assets and liabilities on a net basis.

2.17 Critical accounting judgements and key sources of estimation uncertainty

In the process of applying the entity's accounting policies, management makes estimates and assumptions that have an effect on the amounts recognised in the financial information. Although these estimates are based on management's best knowledge of current events and actions, actual results may ultimately differ from those estimates. The key assumptions concerning the future, and other key sources of estimation uncertainty at the balance sheet date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial period, are those relating to:

• the ability of the Group to operate as a "going concern";

• the carrying value of the Group's investment in intellectual property and patent rights;

· the estimation of the fair value of the shares and warrants issued during the period;

· the carrying value of the investment in the subsidiary.

Going concern

As explained in Note 2.3 above, the financial information is drawn up on the going concern basis which assumes that the Group will be able to access sufficient funds to continue to operate for the foreseeable future. The key assumptions are around the forecast of working capital required for, primarily, the exploitation and commercialisation of the Group's exploration and development assets, intellectual property and patent rights and the methods of funding those requirements. The Directors have reviewed the forecasts for the coming 18 months and consider that the Group's existing working capital and sources of finance are adequate for its purposes. If the financial information was to be drawn up on the basis that this assumption was not valid then there could be material changes to the carrying values of both assets and liabilities.

Carrying value of intangible assets

The Group holds certain patent rights together with lease and mining rights, as set out in Note 11 below. The key assumptions concerning the carrying value, or otherwise, for the intangible assets relate to the continuing progress of the Group's exploitation programmes, which are subject to risks common to all oil and gas businesses. These risks include the impact of competition in the specific areas of intellectual property, the potential failure of the projects in development or testing stages and the possible inability to progress projects due to regulatory, manufacturing or intellectual property issues or the lack of available funds or other resources. Furthermore, the crystallisation of any of these risks could have a significant impact on the assessment of the value of the intangible assets. The carrying value is stated at cost incurred, including the fair value of the shares and warrants issued in respect of the acquisition, see below.

Estimation of fair value of warrants and options issued in the period

The fair value of the warrants and options issued during the period have been calculated using a Black Scholes model which requires a number of assumptions and inputs, see Note 19 below.

Carrying value of investment in subsidiary and loan to group undertaking

The Company has invested in and made loans to the subsidiary companies which are not yet profitable or cash generative. The Company has made provision against the loans made to the subsidiaries equivalent to the full amount of the loan, which is repayable within one year. No provision has been made against the investment or possible future costs or losses of the subsidiaries, see Note 12 below.

2.18 Standards, amendments and interpretations to existing standards that are not yet effective and have not been early adopted by the Group

During the financial year, the Group has adopted the following new IFRSs (including amendments thereto) and IFRIC interpretations that became effective for the first time.

*\* The European commission has decided not to launch the endorsement process of this interim standard but to wait for the final standard.

Their adoption has not had any material impact on the disclosures or amounts reported in the financial statements.

At the date of authorisation of these financial statements, the following standards and interpretations relevant to the Group and which have not been applied in these financial statements, were in issue but which were not yet effective. In some cases these standards and guidance have not been endorsed for use in the European Union.

The Directors are evaluating the impact that these standards will have on the financial statements of the Group.

2.19 Segmental reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker.

The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as Robert Price.

All operations and information are reviewed together so that at present there is only one reportable operating segment.

3. REVENUE

There was no revenue generated in the period.

4. SEGMENT REPORTING

In the opinion of the Directors, during the period ended 31 March 2017 the Group only operated in the single business segment of oil and gas development.