RPT.L Regulatory News (RPT)

21 September 2018

REGAL PETROLEUM PLC

2018 INTERIM RESULTS

Regal Petroleum plc (the "Company", and with its subsidiaries, the "Group"), the AIM-quoted (RPT) oil and gas exploration and production group with assets in Ukraine, today announces its unaudited results for the six month period ended 30 June 2018.

Highlights

Operations

Financial

Outlook

This announcement contains inside information for the purposes of Article 7 of EU Regulation 596/2014.

For further information, please contact:

Philip Frank, PhD Geology, Chartered Geologist, FGS, PESGB, Director of the Company, has reviewed and approved the technical information contained within this press release in his capacity as a qualified person, as required under the AIM Rules for Companies.

Chairman's Statement

During the first half of 2018, the Group has continued to make very promising progress in the development of its MEX-GOL, SV and VAS gas and condensate fields in north-eastern Ukraine, with a vastly improved financial performance during the period. As announced on 31 July 2018, a reassessment of reserves and resources at the MEX-GOL and SV fields as at 31 December 2017 resulted in a significant reserves upgrade, and led to a reversal of an impairment of the Group's oil and gas production assets of $36.1 million.

At the MEX-GOL and SV fields, production was stable during the first half of 2018, with significantly higher production volumes compared with the same period last year following completion of the MEX-109 and SV-2 wells in June and August 2017 respectively. In July 2018, the workover of the SV-12 well was successfully completed and the well was put on production, with the well now producing at approximately 945 boepd, thereby providing a further significant boost to production from the field. In addition, the VAS field has continued to produce consistently during the period.

Aggregate daily production from the MEX-GOL, SV and VAS fields during the first half of 2018 was approximately 2,790 boepd, which compares with an aggregate daily production rate of approximately 1,750 boepd during the same period in 2017, an increase of around 60%.

The fiscal and economic situation in Ukraine has continued to improve during 2018, with a better economic outlook, GDP growth, reduced inflation and reasonable stability in the Ukrainian Hryvnia exchange rates. Nevertheless, there continues to be economic stress and weakness in the Ukrainian banking sector.

The Ukrainian Government has implemented a number of reforms in the oil and gas sector in recent years, which include the deregulation of the gas supply market in late 2015, and more recently, reductions in the subsoil tax rates relating to oil and gas production and a simplification of the regulatory procedures applicable to oil and gas exploration and production activities in Ukraine.

The deregulation of the gas supply market, supported by electronic gas trading platforms and improved pricing transparency, has meant that the market gas prices in Ukraine now broadly correlate with the imported gas prices. During the first half of 2018, gas prices were reasonably stable, allowing for some seasonal variation, and were higher than in the first half of 2017. Furthermore, condensate and LPG prices were also higher by comparison with the same period last year.

I am pleased to report that the Group's financial performance in the six months ended 30 June 2018 was significantly improved, with the Group reporting a net profit of $38.9 million (1H 2017: $0.3 million loss), predominantly as a result of improved revenues of $24.6 million (1H 2017: $12.4 million) from higher production volumes and hydrocarbon prices, and a significant reversal of an impairment of the Group's oil and gas production assets of $36.1 million, which was a one-off item. As a result, gross profits were higher at $11.9 million (1H 2017: $3.2 million) and cash generated from operations during the period was also higher at $13.1 million (1H 2017: $5.5 million).

Board and Management Changes

With effect from the end of September 2018, there will be a number of changes to the management and Board of Directors of the Company. Yevhen (Gene) Palyenka will be leaving his position as Chief Financial Officer to pursue another opportunity, Phil Frank will be stepping down from the Board and Dmitry Sazonenko will be joining the Board as Non-Executive Director. Further details of these changes are set out in the announcement made earlier this morning and the process to recruit a new Chief Financial Officer is underway.

On behalf of the Board, I would like to thank both Gene and Phil for their valued contributions during their respective tenures with the Company, and to welcome Dmitry to the Board.

Outlook

Whilst there are still challenges in the business environment in Ukraine, the situation is improving and the Group is continuing to progress the development of its Ukrainian fields. After the operational successes during the first half of 2018 and the increased production output during July 2018, we are looking forward to achieving further successes in the development activities planned for the remainder of 2018 and delivering a steadily increasing production and revenue stream in the future.

In conclusion, on behalf of the Board, I would like to thank all of our staff for the continued dedication and support they have shown during the year.

Chris Hopkinson

Chairman

20 September 2018

Chief Executive Officer's Statement

Introduction

The Group has made good progress at its Ukrainian fields during 2018, with the increase in development activity at the MEX-GOL and SV fields resulting in the success of the SV-12 well, which came on production in July 2018, providing a significant boost to production rates.

During the first half of 2018, the Group continued its work on the subsurface of the MEX-GOL and SV fields, utilising the results of P.D.F Limited's comprehensive re-evaluation study to plan additional development of these fields. Other work during this period included interpretation of the reprocessed existing 3D seismic data and the workover of the SV-12 well, as well as the upgrading of the gas processing facilities and pipeline network, and undertaking remedial work on existing wells.

At the VAS field, the acquisition of new 3D seismic over the field is underway, although the seismic contractor is experiencing some local access issues, which is delaying the acquisition work. In addition, the VAS-10 well was drilled and completed in July 2018, and is now undergoing production testing.

Production

Average daily production from the MEX-GOL and SV fields over the six months ended 30 June 2018 was 275,772 m³/d of gas, 54 m³/d of condensate and 29 m³/d of LPG (2,183 boepd in aggregate) (1H 2017: 133,951 m3/d of gas, 36 m3/d of condensate and 19 m³/d of LPG (1,140 boepd in aggregate). Production rates were significantly higher in the first half of 2018 when compared with the corresponding period in 2017 predominantly due to the contributions from the MEX-109 and SV-2 wells, which came into production in June and August 2017 respectively. Production rates have also improved significantly following the commencement of production from the SV-12 well in July 2018.

Average daily production of gas and condensate from the VAS field over the six months ended 30 June 2018 was 86,491 m3/d of gas and 6 m3/d of condensate (607 boepd in aggregate) (1H 2107: 86,770 m3/d of gas and 7 m3/d of condensate (612 boepd in aggregate)), contributing material volumes to the Group's production output.

The Group's average production for the period from 1 July 2018 to 19 September 2018 from the MEX-GOL and SV field was 387,441 m³/d of gas, 81 m³/d of condensate and 40 m³/d of LPG (3,097 boepd in aggregate) and from the VAS field was 94,993 m³/d of gas and 10 m³/d of condensate (687 boepd in aggregate).

Operations

The improving geopolitical situation in Ukraine, coupled with reasonable stability in the Ukrainian Hryvnia, higher hydrocarbon prices and improvements in the fiscal and economic situation over the recent period, gave the Board the confidence to accelerate the Group's development programme at its Ukrainian fields during 2018.

At the MEX-GOL and SV fields, the Group continued to work with P.D.F. Limited to utilise their re-evaluation study of these fields, which involved analysis of all available geological, geophysical, petroleum engineering and well performance data. The continuing work included interpretation of newly reprocessed existing 3D seismic data, with the intention of utilising this data to update the new geological subsurface model of the fields. This work, undertaken in conjunction with P.D.F. Limited, is enabling the Group to refine its strategies for the further development of the fields, including the timing and level of future capital investment required to exploit the hydrocarbon resources.

In early 2017, the Group entered into an agreement with NJSC Ukrnafta, the majority State-owned oil and gas producer, relating to the SV-2 well, which is a suspended well owned by NJSC Ukrnafta located within the Group's SV licence area. Under the agreement, the Group agreed to undertake a workover of the well, which was successful, and resulted in the well being brought back into production in August 2017. Pursuant to the agreement, the gas and condensate produced from the well is sold under an equal net profit sharing arrangement between the Group and NJSC Ukrnafta, with the Group accounting for the hydrocarbons produced and sold from the well as revenue, and the net profit share due to NJSC Ukrnafta being treated as a lease expense in cost of sales.

Following on from the success of the SV-2 well operations, in November 2017, the Group entered into a similar agreement with NJSC Ukrnafta, in relation to the SV-12 well, which is also a suspended well owned by NJSC Ukrnafta located within the SV licence area. The terms of this agreement are fundamentally consistent with the agreement relating to the SV-2 well, including the equal net profit sharing arrangement between the Group and NJSC Ukrnafta. Workover operations were undertaken on this well during the first half of 2018, which were successfully concluded in July 2018 and the well was put on production from two intervals in the B-22 Visean formation. The well has undergone production testing and is now producing at approximately 120,000 m3/d of gas and 31 m3/d of condensate, which has significantly increased production at the MEX-GOL field.

In addition at the MEX-GOL and SV fields, the Group upgraded the gas processing facilities and pipeline network, and undertook remedial work on existing wells.

At the VAS field, during the first half of 2018, planning work took place for the acquisition of new 3D seismic data over the field, which is now underway, although the seismic contractor is experiencing local access issues, which is delaying the acquisition field work. Once the acquisition has been completed, the data will be processed and interpreted. The VAS-10 well was spudded in March 2018 and drilled to a depth of 3,380 metres. The well is located to the north-west of the VAS field, at an offset of approximately 1 km from the nearest producing well, and targeted two reservoir zones in the Visean formation: the B-16/17 and the deeper B-25/26. The B-16/17 reservoir is currently the main production horizon in the VAS field. In July 2018, one interval in the B-25/26 Visean formation was perforated and short-term initial flow testing was undertaken, and whilst there was gas flow, a stabilised flow rate was not established. Since then the well has been hooked up to the gas processing facility and currently production testing of this reservoir interval is underway. Depending on the outcome of such testing, either this interval will be put into production, or alternatively the shallower B-16/17 reservoir will be tested.

Reserves Update

In early 2018, the Group commissioned DeGolyer and MacNaughton ("D&M") to prepare an updated assessment of the remaining reserves and resources at the MEX-GOL and SV fields as at 31 December 2017, in order to update the Group's reserves and resources since the previous reserves estimation undertaken by ERC Equipoise Limited ("ERCE") as at 31 December 2013. The new assessment took into account data and information gathered since then, which included the results of the comprehensive re-evaluation study of the fields undertaken by P.D.F. Limited over the last two years and the data obtained from further seismic reprocessing and the drilling of additional wells in the fields.

D&M's report estimated the Proved (1P) reserves at 27.8 MMboe and the Proved + Probable (2P) reserves at 50.0 MMboe as at 31 December 2017, showing a material increase in these categories of remaining reserves from the ERCE 2013 estimates, which were 1.9 MMboe and 11.7 MMboe respectively. These increases reflect a higher level of confidence in the understanding of the subsurface at the fields as a result of the re-evaluation study and new data obtained since 2013, which has led to a revision of the development plan for the fields, including an increase in the number of new wells (from 10 to 24) and an acceleration of the phasing of these new wells.

Further details of the D&M assessment are set out in the Company's announcement dated 31 July 2018.

Outlook

During the remainder of 2018, the Group will continue to develop the MEX-GOL, SV and VAS fields. At the MEX-GOL and SV fields, the development programme includes revision of the geological model utilising the newly interpreted reprocessed seismic data, planning for a new development well, MEX-119, which is expected to be spudded around the end of the year and which is designed to accelerate production from the B-20 Visean reservoirs in the MEX-GOL field, investigating workover opportunities for other existing wells, further upgrading of the gas processing facilities and pipeline network, and remedial and upgrade work on existing wells, pipelines and other infrastructure.

At the VAS field, the work on acquisition, processing and interpreting the new 3D seismic data will continue, a new geological model will be developed, and consideration and planning for a further appraisal/development well will be undertaken. It is also intended to undertake further evaluation of the VED area of the licence, which appears highly prospective on the current 2D seismic data and will benefit from the improved imaging of the new 3D seismic data. Work is also planned to upgrade the gas processing facilities, pipeline network and other infrastructure.

It is also intended to commission an updated assessment of the remaining reserves and resources at the VAS field, which will be undertaken by an independent petroleum reserves consultant following interpretation of the newly acquired 3D seismic, completion of associated subsurface studies and the newly developed geological model, and assessment of the data collected from the VAS-10 well. In light of the delays in completing the acquisition of the new 3D seismic, it is now anticipated that the updated reserves and resources assessment will not be completed until the first half of 2019.

There has also been encouraging new legislation relating to the oil and gas sector in Ukraine, demonstrating the Ukrainian Government's stated intention to promote and support the domestic oil and gas production industry. These new measures include reductions in the subsoil taxes applicable to the production of hydrocarbons, which became effective for new wells drilled after 1 January 2018 and will come into effect for condensate production from all wells from 1 January 2019. Furthermore, new legislation was introduced earlier this year to simplify a number of the regulatory procedures relating to oil and gas exploration and production activities in Ukraine.

These measures, and the general improvement in the business climate in Ukraine, are encouraging and supportive of the independent oil and gas producers in Ukraine.

Finally, I would like to add my thanks to all of our staff for the continued hard work and dedication they have shown during this year.

Sergii Glazunov

Chief Executive Officer

Finance Review

The Group made a significantly improved net profit of $38.9 million (1H 2017: $0.3 million loss) during the period ended 30 June 2018, mainly as a result of improved revenue from higher production volumes and hydrocarbon prices, and a significant reversal of an impairment of the Group's oil and gas production assets of $36.1 million, which was a one-off item.

Gross profit for the period ended 30 June 2018 was higher at $11.9 million (1H 2017: $3.2 million), predominantly as a result of higher production volumes and hydrocarbons prices, and a decrease in the depreciation charge arising from the revision of the depletion calculation following the re-assessment of the Group's reserves at the MEX-GOL and SV fields as at 31 December 2017, which took place during the period.

In the first half of 2018, there was a significant reversal of an impairment of the Group's oil and gas assets of $36.1 million. The amount of the reversal was determined as $39.8 million, being the total amount of the previous impairment accumulated on the MEX-GOL and SV fields up to 30 June 2018, net of depreciation, that would have been incurred had the fields not been previously impaired, less $3.7 million of previous impairment allowance for the SV-69 well. The Group did not reverse the previous impairment allowance relating to the SV-69 well for the reasons explained in Note 2 below, and additionally the Group impaired the remaining carrying value of this well to nil on the individual basis and recorded the respective impairment loss of $1.6 million as an expense during the period.

Revenue for the first half of 2018, derived from the sale of the Group's Ukrainian gas, condensate and LPG production, was higher at $24.6 million (1H 2017: $12.4 million). Cash generated from operations during the year increased to $13.1 million (1H 2017: $5.5 million), as a result of higher production volumes and hydrocarbon prices.

For the six month period ended 30 June 2018, the average realised gas, condensate and LPG prices were $280/Mm3 (UAH7,491/Mm3), $69/bbl and $73/bbl respectively (1H 2017: $226/Mm3 (UAH6,060/Mm3), $59/bbl and $49/bbl respectively).

During the period from 1 July 2018 to 20 September 2018, the average realised gas, condensate and LPG prices were $310/Mm3 (UAH8,496/Mm3), $75/bbl and $84/bbl respectively. The current realised gas price is $316/Mm3 (UAH8,812/Mm3).

Since the deregulation of the gas supply market in Ukraine in October 2015, the market price for gas has broadly correlated to the price of imported gas, which generally reflects trends in European gas prices. Gas prices are also subject to seasonal variation. During the first half of 2018, gas prices were reasonably stable, allowing for some seasonal variation, and were higher than in the first half of 2017, as were condensate and LPG prices by comparison with the same period in 2017.

The subsoil tax rates applicable to gas and condensate production were stable during the first half of 2018 at 29% for gas produced from deposits at depths above 5,000 metres and 14% for gas produced from deposits below 5,000 metres, and 45% for condensate produced from deposits above 5,000 metres and 21% for condensate produced from deposits below 5,000 metres.

However, new subsoil rates have been implemented, under which (i) for new wells drilled after 1 January 2018, the subsoil tax rates were reduced from 29% to 12% for gas produced from deposits at depths above 5,000 metres and from 14% to 6% for gas produced from deposits below 5,000 metres for the period between 2018 and 2022, and (ii) with effect from 1 January 2019 and applicable to all wells, the subsoil tax rates for condensate will be reduced from 45% to 29% for condensate produced from deposits above 5,000 metres and from 21% to 14% for condensate produced from deposits below 5,000 metres.

In addition, with effect from 1 April 2017, a transmission tariff of UAH296.80/Mm3 ($11.00/Mm3) for use of the Ukrainian national pipeline system became applicable to oil and gas producers in Ukraine, including the Group. However, shortly after its imposition, the tariff was suspended following a legal challenge to the legality of the tariff, and it is currently uncertain if, and/or when the tariff will be reinstated, and what the amount of the tariff may be.

Cost of sales for the six month period ended 30 June 2018 was higher at $12.8 million (1H 2017: $9.2 million), mainly due to higher production of hydrocarbons resulting in higher production taxes and lease expenses relating to the profit share in respect of the SV-2 and SV-12 wells, offset by a decrease in the depreciation charge arising from the revision of the depletion calculation following the re-assessment of the Group's reserves at the MEX-GOL and SV fields as at 31 December 2017, which took place during the period.

Administrative expenses for the first half of 2018 were higher at $2.9 million (1H 2017: $2.2 million), primarily as a result of an increase in payroll and related taxes.

The tax charge for the six month period ended 30 June 2018 of $6.1 million (1H 2017: $2.0 million charge) comprises a current tax charge of $2.1 million (1H 2017: $0.9 million) and a deferred tax charge of $4.0 million (1H 2017: $1.1 million charge). A significant deferred tax charge was incurred in the period as a result of the reversal of the impairment of the carrying value of the Group's MEX-GOL and SV development and production asset, and the reversal of the impairment of intra-group loans receivable by the Company.

The Group has recognised a deferred tax asset of $7.7 million at 30 June 2018 (31 December 2017: $2.7 million). This comprises a deferred tax asset of $7.2 million (31 December 2017: $2.6 million) in relation to UK tax losses carried forward and $0.5 million (31 December 2017: $0.1 million) relating to the provisions for decommissioning at the MEX-GOL, SV and VAS fields, which are recognised on the tax effects of the temporary differences of the decommissioning provisions, and their tax bases.

A deferred tax liability relating to the development and production asset at the MEX-GOL and SV fields of $1.8 million (31 December 2017 deferred tax asset: $6.6 million) was recognised at 30 June 2018 on the tax effect of the temporary differences between the carrying value of the Group's development and production asset at the MEX-GOL and SV fields, and its tax base.

A deferred tax liability relating to the development and production asset at the VAS field of $1.0 million (31 December 2017: $1.1 million) was recognised at 30 June 2018 on the tax effect of the temporary differences between the carrying value of the development and production asset at the VAS field, and its tax base.

Capital investment of $5.0 million reflects investment in the Group's oil and gas development and production assets during the period (1H 2017: $2.1 million), primarily as a result of the expenditure associated with the drilling of the VAS-10 well.

Cash and cash equivalents held at 30 June 2018 were $40.0 million (31 December 2017: $14.2 million cash and cash equivalents and $16.0 million other short-term investments). The Group's cash and cash equivalents balance at 19 September 2018 was $46.8 million, held as to $22.5 million equivalent in Ukrainian Hryvnia and the balance of $24.3 million equivalent predominantly in US Dollars and Pounds Sterling.

Since early 2014, the Ukrainian Hryvnia has devalued significantly against the US Dollar, falling from UAH8.0/$1.00 on 1 January 2014 to UAH26.2/$1.00 on 30 June 2018, which resulted in substantial foreign exchange translation losses for the Group over that period, and in turn adversely impacted the carrying value of the MEX-GOL and SV asset due to the translation of two of the Group's subsidiaries from their functional currency of Ukrainian Hryvnia to the Group's presentation currency of US Dollars. However in the first half of 2018, the exchange rate between the Ukrainian Hryvnia and the US Dollar has been reasonably stable averaging UAH26.8/$1.00 during the period (average rate during 1H 2017: UAH26.8/$1.00). Nevertheless, further devaluation of the Ukrainian Hryvnia against the US Dollar may affect the carrying value of the Group's assets in the future.

Cash from operations has funded the capital investment during the period, and the Group's current cash position and positive operating cash flow are the sources from which the Group plans to fund the development programmes for its assets in the remainder of 2018.

Yevhen Palyenka

Chief Financial Offic

Principal Risks and Uncertainties

The Group has a risk evaluation methodology in place to assist in the review of the risks across all material aspects of its business. This methodology highlights external, operational and technical, financial and corporate risks and assesses the level of risk and potential consequences. It is periodically presented to the Audit Committee and the Board for review, to bring to their attention potential risks and, where possible, propose mitigating actions. Key risks recognised and mitigation factors are detailed below:-

Directors Responsibility Statement

The Directors confirm that, to the best of their knowledge:-

a) the unaudited condensed interim consolidated financial statements have been prepared in accordance with IAS 34 as adopted by the European Union; and

b) these unaudited interim results include:

(i) a fair review of the information required (i.e. an indication of important events and their impact and a description of the principal risks and uncertainties for the remaining six months of the financial year); and

(ii) a fair review of the information required on related party transactions.

Condensed Interim Consolidated Income Statement

The Notes set out below are an integral part of these unaudited condensed interim consolidated financial statements.

Condensed Interim Consolidated Statement of Comprehensive Income

The Notes set out below are an integral part of these unaudited condensed interim consolidated financial statements.

Condensed Interim Consolidated Balance Sheet

The Notes set out below are an integral part of these unaudited condensed interim consolidated financial statements.

Condensed Interim Consolidated Statement of Changes in Equity

* Predominantly as result of exchange differences on retranslation, where the subsidiaries functional currency is not US Dollar

The Notes set out below are an integral part of these unaudited condensed interim consolidated financial statements.

Condensed Interim Consolidated Statement of Cash Flows

The Notes set out below are an integral part of these unaudited condensed interim consolidated financial statements.

Notes to the Unaudited Condensed Interim Consolidated Financial Statements

1.General Information and Operational Environment

Regal Petroleum plc (the "Company") and its subsidiaries (together the "Group") is a gas, condensate and LPG production group.

Regal Petroleum plc is a company quoted on the AIM Market of London Stock Exchange plc and incorporated in England and Wales under the Companies Act 2006. The Company's registered office is at 16 Old Queen Street, London SW1H 9HP, United Kingdom and its registered number is 4462555.

As of 30 June 2018 and 2017, the Company's immediate parent company was Energees Management Limited, which is 100% owned by Pelidona Services Limited, which is 100% owned by Lovitia Investments Ltd, which is 100% owned by Mr V Novinskiy. Accordingly, the Company was ultimately controlled by Mr V Novinskiy.

The Group's gas, condensate and LPG extraction and production facilities are located in Ukraine. The ongoing political and economic instability in Ukraine, which commenced at the end of 2013 and led to a deterioration of Ukrainian State finances, volatility of financial markets, illiquidity on capital markets, higher inflation and depreciation of the national currency against major foreign currencies, has continued in 2018, though to a lesser extent as compared to 2014-2017.

The Ukrainian economy suffered a deep slump in 2014-2016 due to the political instability and unfavourable global markets for key export-oriented sectors. Since 2017, the Ukrainian economy has demonstrated slight recovery amid overall macroeconomic stabilisation supported by a rise in domestic investment, revival in household consumption, increase in agricultural and industrial production, construction activity and an improved environment on external markets.

The inflation rate in Ukraine has decreased to 4% during the first half of 2018 (as compared to 14% during the 2017 year).

Devaluation of the Ukrainian Hryvnia during 2018 has been moderate. As at 20 September 2018, the official exchange rate of the Ukrainian Hryvnia against the US Dollar was UAH28.1/$1.00, compared to UAH26.2/$1.00 as at 30 June 2018 (31 December 2017: UAH28.1/$1.00).

In 2016 and 2017, the National Bank of Ukraine ("NBU") took certain steps to ease the currency control restrictions introduced in 2014 - 2015. In particular, the required share of foreign currency proceeds subject to mandatory sale on the interbank market was decreased from 75% to 65% starting from 9 June 2016 and further to 50% starting from 5 April 2017. The current restriction is effective until 13 December 2018. Additionally, the settlement period for export-import transactions in foreign currency was increased from 90 to 120 days starting from 28 July 2016 and further to 180 days starting from 26 May 2017. Also, starting from March 2018, the National Bank of Ukraine allowed Ukrainian companies to pay dividends to non-residents with a limit of $7,000,000 per month regardless of the period.

On 21 June 2018, the Ukrainian Parliament adopted new legislation designed to ease the existing currency control regulations in Ukraine. Among the most significant changes introduced by this legislation are the abolishment of the requirement to obtain a licence for investing abroad for individuals and legal entities, the removal of the requirement to register loans provided by non-residents with the National Bank of Ukraine, and the removal of a maximum term for settlement of liabilities under foreign trade operations. The legislation will take effect seven months after being signed by the President of Ukraine and its official publication, which is expected to be in February 2019.

The International Monetary Fund continues to support the Ukrainian Government under the four-year Extended Fund Facility ("EFF") Programme, though further disbursements of EFF tranches depend on the continued implementation of Ukrainian Government reforms, and other economic, legal and political factors.

Further details of risks relating to Ukraine can be found within the Principal Risks and Uncertainties section earlier in this announcement.

For the reasons outlined in the Principal Risks and Uncertainties section of this announcement, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future regarded as at least 12 months from the date of this announcement. Accordingly, the going concern basis has been adopted in preparing these unaudited condensed interim consolidated financial statements for the period ended 30 June 2018. The use of this basis of accounting takes into consideration the Company's and the Group's current and forecast financing position.

The unaudited condensed interim consolidated financial statements for the six month period ended 30 June 2018 have been prepared in accordance with International Accounting Standard 34 'Interim Financial Reporting' as adopted by the European Union. The unaudited condensed interim consolidated financial statements do not include all the notes of the type normally included in annual financial statements. Accordingly, this report should be read in conjunction with the annual consolidated financial statements for the year ended 31 December 2017, which have been prepared in accordance with International Financial Reporting Standards (hereinafter "IFRSs") as adopted by the European Union.

These unaudited condensed interim consolidated financial statements do not comprise statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2017 were approved by the Board of Directors on 29 March 2018 and subsequently filed with the Registrar of Companies. The Auditor's Report on those accounts was not qualified and did not contain any statement under section 498 of the Companies Act 2006.

The Auditor has carried out a review of the unaudited condensed interim consolidated financial statements for the six month period ended 30 June 2018 and its report is shown at the end of this announcement.

2.Accounting Judgements and Estimates

The accounting policies and methods of computation and presentation used are consistent with those used in the Group's Annual Report and Financial Statements for the year ended 31 December 2017, with the exception of the following new or revised standards and interpretations:

New and amended standards adopted by the Group

A number of new or amended standards became applicable for the current reporting period. The Group had to change its accounting policies as a result of adopting the following standards.

The impact of the adoption of these standards and the new accounting policies are disclosed in Note 3 below.

Impact of standards issued but not yet applied by the Group

Certain new accounting standards and interpretations have been published that are not mandatory for 2018 reporting periods and have not been early adopted by the Group. The Group's assessment of the impact of these new standards and interpretations is set out below:

· IFRS 16 'Leases' was issued in January 2016. It will result in almost all leases being recognised on the balance sheet, as the distinction between operating and finance leases is removed. Under the new standard, an asset (the right to use the leased item) and a financial liability to pay rentals are recognised. The only exceptions are short-term and low-value leases. The accounting for lessors will not significantly change. The standard will affect primarily the accounting for the Group's operating leases. The standard is mandatory for first interim periods within annual reporting periods beginning on or after 1 January 2019. At this stage, the Group does not intend to adopt the standard before its effective date. The Group is currently assessing the full impact of the new standard on its consolidated financial statements. The Group has not yet determined to what extent its existing operating lease commitments will result in the recognition of an asset and a liability for future payments and how it will affect the Group's profit and classification of cash flows. Some of the commitments may be covered by the exception for short-term and low-value leases and some commitments may relate to arrangements that will not quality as leases or will be excluded from the measurement of lease liabilities under IFRS 16.

There are no other IFRSs or IFRIC interpretations that are not yet effective that would be expected to have a material impact on the Group in the current or future reporting periods and on foreseeable future transactions. 

Estimates

The preparation of the unaudited condensed interim consolidated financial statements requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expenses. Actual results may differ from these estimates.

In preparing these unaudited condensed interim consolidated financial statements, the significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were consistent with those that applied to the consolidated financial statements for the year ended 31 December 2017 with certain updates described below.

Recoverability of Development and Production Assets in Ukraine

According to the Group's accounting policies, costs capitalised as assets are assessed for impairment at each balance sheet date if impairment indicators exist. In assessing whether an impairment loss has occurred, the carrying value of the asset or cash-generating unit ("CGU") is compared to its recoverable amount. The recoverable amount is the greater of fair value less costs to dispose and value in use and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount and the respective impairment loss is recognised as an expense immediately. A previously recognised impairment loss is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such reversals are recognised as income immediately.

MEX-GOL and SV gas and condensate fields

As at 31 December 2017, no impairment indicators were identified by the Group, and therefore no impairment test was performed for the MEX-GOL and SV fields. In addition, at that date the Group considered whether there were any triggers to reverse any impairment loss recognised in prior years and concluded that there was insufficient information to be able to do so.

Over the last two years, the Group has been undertaking certain projects on the MEX-GOL and SV fields with the purpose of refining its field development strategy, including the interpretation of a reprocessed 3D seismic dataset, analysis of technical and economic data and ongoing revision of the geological model. The new information and understanding obtained as a result of the comprehensive re-evaluation study of the geology, geophysics, petroleum engineering and well performance of the fields, together with the recent successful drilling and workover projects implemented with enhanced drilling technologies, resulted in a boost to production in the second half of 2017, and led to a revision of the field development plan. The revised field development plan for these fields prepared in 2018 assumes an increase in the number of new wells from 10 to 24 and an acceleration of the phasing of these new wells.

Following the successful outcomes of the recent drilling and workover projects and subsequent revision of the field development plan in 2018, the Group considered it appropriate to undertake a reassessment of the reserves and resources at the MEX-GOL and SV fields. Accordingly, the Group engaged independent petroleum consultants DeGolyer and MacNaughton ("D&M") to prepare an updated estimate of remaining reserves and resources as of 31 December 2017. The final report issued by D&M in July 2018 provided an estimate of the Group's proved plus probable ("2P") reserves of 50.0 MMboe based on the Group's revised field development plan and other relevant information available at the date of the assessment. The report represents an update on the Group's reserves and resources since the previous estimation undertaken by ERC Equipoise Limited ("ERCE") as at 31 December 2013. Further details of the updated reserves report are set out in Chief Executive Officer's Statement above and in the Company's announcement made on 31 July 2018.

In accordance with its accounting policy, at the end of each reporting period, the Group assesses whether there is any indication that an impairment loss recognised in prior periods for its development and production assets may no longer exist or may have decreased. Given that the 2P reserves remaining as at 31 December 2017, as estimated in the 2018 D&M report, significantly exceeded the previous 2P reserves estimated by ERCE (11.7 MMboe remaining as at 31 December 2013), the Group considered that such a change in reserves estimate reflected a substantial increase in the potential of the MEX-GOL and SV fields and therefore triggered the re-assessment of the recoverable amount of development and production assets related to these fields. As such, as at 30 June 2018, the Group has determined the recoverable amount based on the Fair Value Less Costs of Disposal ("FVLCD") approach using a discounted cash flow methodology. The discounted after tax cash flows for the CGU were derived based on estimates that a typical market participant would use in valuing such assets. The Group has determined that the MEX-GOL and SV fields are a single CGU, being the smallest group of assets that generate independent cash inflows, as the investment decisions are not based on a single well, but on the expected production of the fields, and these fields are dependent on common infrastructure. The estimate of FVLCD meets the definition of Level 3 fair value measurements as it is determined mostly from unobservable inputs. For the discounted cash flows to be calculated, the Group has used a production profile based on the best estimate of 2P reserves and a range of assumptions, including gas price, economic life of the fields, future capital expenditures and a discount rate which, taking into account other assumptions used in the calculation, are considered to be reflective of the risks. These assumptions are further described in Note 9.

The FVLCD determined by the Group as at 30 June 2018 amounted to $311,100,000, mostly as a result of a substantial increase in the forecasted volume of 2P reserves, accelerated production schedule, growth in gas price and decrease in production tax rates for the wells drilled after 1 January 2018. This resulted in the reversal of the impairment loss of $36,117,000 being recorded as income for the six months ended 30 June 2018 in these unaudited condensed interim consolidated financial statements. The amount of the reversal was determined as $39,773,000, being the total amount of the previous impairment accumulated on the MEX-GOL and SV fields up to 30 June 2018, net of depreciation, that would have been incurred had the fields not been previously impaired, less $3,656,000 of previous impairment attributed to the SV-69,well, net of depreciation, which was assessed for impairment purposes separately as at 30 June 2018. This development-type well has not resulted in any production for the Group due to mechanical issues which occurred during its drilling and the well was plugged back with initial plans for a side track at a later stage. Since then, no side-tracking of this well or drilling of an alternative well targeting the same location has been performed and no information was obtained from this well that could be applied to the development of the targeted area of the field, which could lead to future production. No commercial reserves were assigned to the respective field area in the reserves and resources estimation by D&M in 2018 and the Group plans to abandon this well by the end of 2018. As such, as at 30 June 2018, the Group did not reverse the previous impairment allowance related to this well and additionally the Group impaired the remaining carrying value of the well to nil on the individual basis and recorded the respective impairment loss of $1,648,000 as an expense for the six months ended 30 June 2018.

VAS gas and condensate field

At 30 June 2018, the Group performed an assessment of external and internal indicators to ascertain whether there was any indication of potential impairment. Based on the analysis performed, the Group concluded that no external or internal impairment indicators existed as at 30 June 2018, and accordingly no impairment testing was required as at that date.

Depreciation of Development and Production Assets

Development and production assets held in property, plant and equipment are depreciated on a unit of production basis at a rate calculated by reference to proven and probable reserves at the end of the period plus the production in the period, and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions about the number of wells required to produce those reserves, the cost of the wells, future production facilities and operating costs, together with assumptions on oil and gas realisations, and are revised annually. The reserves estimates used are determined using estimates of gas in place, recovery factors, future hydrocarbon prices and also take into consideration the Group's latest development plan for the associated development and production asset. Additionally, the latest development plan and therefore the inputs used to determine the depreciation charge, assume that the current licences for the MEX-GOL and SV fields, which are due to expire in July 2024, can be extended until the end of the economic life of the fields.

In light of the revision of the field development plan for the MEX-GOL and SV fields and the re-assessment of the 2P reserves at these fields performed in 2018 by D&M as described above, the Group has revised the estimate of 2P reserves and future cost of developing and extracting those reserves used for the depletion calculation. The effect of the change in estimates made in the current reporting period was appropriately recognised in profit or loss in the period of the change and amounted to a decrease of $3,980,000 in depletion charge for the first half of 2018.

Provision for Decommissioning

The Group has decommissioning obligations in respect of its Ukrainian assets. The full extent to which the provision is required depends on the legal requirements at the time of decommissioning, the costs and timing of any decommissioning works and the discount rate applied to such costs.

A detailed assessment of gross decommissioning cost was undertaken on a well-by-well basis using local data on day rates and equipment costs. The discount rate applied on the decommissioning cost provision at 30 June 2018 was 6.62% (31 December 2017: 4.7%). The discount rate is calculated in real terms based on the yield to maturity of Ukrainian Government bonds denominated in the currency in which the liability is expected to be settled and with the settlement date that approximates the timing of settlement of decommissioning obligations.

The change in estimate applied to calculate the provision as at 30 June 2018 resulted from the revision of the estimated costs of decommissioning (increase of $346,000 in provision), the increase in the discount rate applied (decrease of $640,000 in provision) and the extension of the economic life of the MEX-GOL and SV fields as a result of the revision of the field development plan in 2018 (decrease of $190,000 in provision). The increase in discount rate at 30 June 2018 resulted from the increase in Ukrainian Eurobonds yield and the respective increase of country risk premium. The costs are expected to be incurred by 2038 on the MEX-GOL field, by 2042 on the SV field, and by 2024 on the VAS field (31 December 2017: by 2036 on the MEX-GOL and SV fields and 2024 on the VAS field respectively), which is the end of the estimated economic life of the respective fields. If the costs on the MEX-GOL and SV fields were to be incurred at the current expiry of the production licences in 2024, the provision for decommissioning at 30 June 2018 would be $4,990,000 (31 December 2017: $2,613,000). 

3.Changes in accounting policies

This note explains the impact of the adoption of IFRS 9 'Financial Instruments' and IFRS 15 'Revenue from contracts with customers' on the Group's financial statements and also discloses the new accounting policies that have been applied from 1 January 2018, where they are different to those applied in prior periods.

Impact on the financial statements

The reclassifications and the adjustments arising from the new impairment rules are not reflected in the restated balance sheet as at 31 December 2017, but are recognised in the opening balance sheet on 1 January 2018.

The following table shows the adjustments recognised for each individual line item. Line items that were not affected by the changes have not been included. The adjustments are explained in more details below.

IFRS 9 'Financial Instruments' - Impact of adoption

IFRS 9 replaces the provisions of IAS 39 'Financial instruments: recognition and measurement' that relate to the recognition, classification and measurement of financial assets and financial liabilities, derecognition of financial instruments, impairment of financial assets and hedge accounting.

The adoption of IFRS 9 'Financial Instruments' from 1 January 2018 resulted in changes in accounting policies and adjustments to the amounts recognised in the financial statements. The new accounting policies are set out below. In accordance with the transitional provisions in IFRS 9, comparative figures have not been restated.

The Group has two types of financial assets that are subject to IFRS 9's new expected credit loss model:

·trade and other receivables,

·other financial assets carried at amortised cost.

The Group was required to revise its impairment methodology under IFRS 9 for each of these classes of financial assets. The impact of the change in impairment methodology on the Group's accumulated losses and equity is disclosed in the table above.

Under IFRS 9, loss allowances are measured on either of the following bases:

·12-month ECLs: these are ECLs that result from possible default events within the 12 months after the reporting date; and

·lifetime ECLs: these are ECLs that result from all possible default events over the expected life of a financial instrument.

The Group applies the IFRS 9 simplified approach to measuring expected credit losses which uses a lifetime expected loss allowance for all trade receivables. To measure the expected credit losses, trade and other receivables have been grouped based on shared credit risk characteristics and ageing.

When determining whether the credit risk of a financial asset has increased significantly since initial recognition and when estimating expected credit losses, the Group considers reasonable and supportable information that is relevant and available without undue cost or effort. The calculation of expected credit losses is carried out on an individual basis taking into account agreement terms, expected repayment period and debtors` credit rating. This includes both quantitative and qualitative information and analysis based on the publicly available observable information, including the information published by the credit ratings agencies and the National Bank of Ukraine, used as benchmarks for expected credit losses and taking into account forward-looking information. For individually insignificant debtors, the Group calculates the expected credit losses based on the Group's historical default rates over the expected life of the financial assets and adjusted for forward-looking estimates. 

Impairment losses related to financial assets are presented as part of other operating expenses in the statement of profit or loss.

The total impact on the Group's accumulated losses as at 1 January 2018 is represented by the increase in impairment provision on respective line items as presented in the above table, and is based on estimated rates of expected loss amounts for receivables from related parties and third parties.

Trade and other receivables

To measure the expected credit losses, trade and other receivables have been grouped based on shared credit risk characteristics. The loss allowances for trade and other receivables as at 31 December 2017 reconcile to the opening loss allowances on 1 January 2018 as follows:

The loss allowance increased by a further $11,000 to $163,000 for trade and other receivables during the six months to 30 June 2018. The increase would have been $4,000 lower under the incurred loss model of IAS 39.

Other financial assets at amortised cost

Other financial assets at amortised cost include cash and cash equivalents and other short-term investments. Applying the expected credit risk model resulted in the recognition of a loss allowance of $44,000 on 1 January 2018 (previous loss allowance was nil) and a further decrease in the allowance by $38,000 in the six months ending 30 June 2018 due to the decrease in other short-term investments.

IFRS 15 'Revenue from contracts with customers' - Impact of adoption

Starting from 1 January 2018, the Group is obliged to apply IFRS 15 Revenue from Contracts with Customers. The new standard recognition requirements provide more advanced guidance on complex transactions, such as accounting for multiple-element arrangements. The new standard introduces the core principle that revenue must be recognised when the goods or services are transferred to the customer, at the transaction price. Any bundled goods or services that are distinct must be separately recognised, and any discounts or rebates on the contract price must generally be allocated to the separate elements. When the consideration varies for any reason, minimum amounts must be recognised if they are not at significant risk of reversal. Costs incurred to secure contracts with customers have to be capitalised and amortised over the period when the benefits of the contract are consumed.

IFRS 15 also includes a cohesive set of disclosure requirements that would result in an entity providing users of financial statements with comprehensive information about the nature, amount, timing, and uncertainty of revenue and cash flows arising from the entity's contracts with customers.

Based on management's assessment, the adoption of this standard had no significant impact on these financial statements.

4.Segmental Information

In line with the Group's internal reporting framework and management structure, the key strategic and operating decisions are made by the Board of Directors, who review internal monthly management reports, budgets and forecast information as part of this process. Accordingly, the Board of Directors is deemed to be the Chief Operating Decision Maker within the Group.

The Group's only class of business activity is oil and gas exploration, development and production. The Group's operations are located in Ukraine, with its head office in the United Kingdom. These geographical regions are the basis on which the Group reports its segment information. The segment results as presented represent operating profit before depreciation, amortisation and impairment of non-current assets.

6 months ended 30 June 2018 (unaudited)

6 months ended 30 June 2017 (unaudited)

12 months ended 31 December 2017 (audited)

*Comprises additions to property, plant and equipment and intangible assets (Notes 9 and 10).

There are no inter-segment sales within the Group and all products are sold in the geographical region in which they are produced. The Group is not significantly impacted by seasonality.

During the first half of 2018, the Group continued selling all of its gas production to its related party, LLC Smart Energy ("Smart Energy"). Smart Energy has oil and gas operations in Ukraine and is part of the PJSC Smart-Holding Group, which is ultimately controlled by Mr Vadim Novinskiy, who, through an indirect 54% majority shareholding, ultimately controls the Group. This arrangement came about in 2017 as a consequence of the Ukrainian Government introducing a number of new provisions into the Ukrainian Tax Code over recent years, including transfer pricing regulations for companies operating in Ukraine. The introduction of the new regulations has meant that there is an increased regulatory burden on affected companies in Ukraine who must prepare and submit reporting information to the Ukrainian Tax Authorities. Due to the corporate structure of the Group, a substantial proportion of its gas production is produced by a non-Ukrainian subsidiary of the Group, which operates in Ukraine as a branch, or representative office as it is classified in Ukraine. Under the new tax regulations, this places additional regulatory obligations on each of the Group's potential customers who may be less inclined to purchase the Group's gas and/or may seek discounts on sales prices. As a result of discussions between the Company and Smart Energy, Smart Energy agreed to purchase all of the Group's gas production and to assume responsibility for the regulatory obligations under the Ukrainian tax regulations. Furthermore, Smart Energy has agreed to combine the Group's gas production with its own gas production, and to sell such gas as combined volumes, which should result in higher sales prices due to the larger sales volumes. In order to cover Smart Energy's sales, administration and regulatory compliance costs, the Group sells its gas to Smart Energy at a small discount to the gas sales prices achieved by Smart Energy, who sell the combined volumes in line with market prices. The terms of sale, effective from June 2017, for the Group's gas to Smart Energy are (i) payment for one third of the estimated monthly volume of gas by the 20th of the month of delivery, and (ii) payment of the remaining balance by the 10th of the month following the month of delivery.

5.Cost of Sales

As described in Note 2, as a result of the revision of the field development plan and re-assessment of the Group's 2P reserves at the MEX-GOL and SV fields in 2018, the Group has revised the estimate of 2P reserves and future capital expenditure associated with developing and extracting those reserves used for the depletion calculation, which resulted in a significant decrease in depreciation expenses.

6.Finance income

Finance income recognised during the six month period ended 30 June 2018 is comprised of interest income of $1,060,000 (six month period ended 30 June 2017: $408,000) from placement of cash on current and deposit accounts and foreign exchange gains of $388,000 (six month period ended 30 June 2017: $334,000).

7.Taxation

The income tax charge of $6,119,000 for the six month period ended 30 June 2018 relates to a сurrent tax charge of $2,102,000 and a deferred tax charge of $4,017,000 (six month period ended 30 June 2017: current tax charge of $906,000 and deferred tax charge of $1,086,000).

The movement in the period was as follows:

Taxes on income in the interim periods are accrued using the tax rate that would be applicable to the expected total annual profit or loss.

At 30 June 2018, the Group recognised a deferred tax asset of $7,236,000 in relation to UK tax losses carried forward (31 December 2017: $2,567,000). The increase in the deferred tax charge is related to the reversal of previously accumulated impairment losses on intra-group loans owing to the Company as a result of the increase in the present value of estimated future cash flows as at 30 June 2018 following the revision of the field development plan and reassessment of mineral reserves at the MEX-GOL and SV fields as described in Note 2. There was a further $55 million (31 December 2017: $83 million) of unrecognised UK tax losses carried forward for which no deferred tax asset has been recognised. These losses can be carried forward indefinitely, subject to certain rules regarding capital transactions and changes in the trade of the Company. The Group considers it appropriate to recognise deferred tax assets resulting from accumulated tax losses at 30 June 2018 to the extent that it is probable that there will be sufficient future taxable profits.

The deferred tax asset relating to the Group's provision for decommissioning at 30 June 2018 of $166,000 (31 December 2017: $127,000) was recognised on the tax effect of the temporary differences of the Group's provision for decommissioning at the MEX-GOL and SV fields, and its tax base. The deferred tax liability relating to the Group's development and production assets at the MEX-GOL and SV fields at 30 June 2018 of $1,785,000 (31 December 2017 deferred tax asset: $6,567,000) was recognised on the tax effect of the temporary differences between the carrying value of the Group's development and production asset at the MEX-GOL and SV fields, and its tax base. A significant deferred tax charge relating to development and production assets at the MEX-GOL and SV fields for the six month period ended 30 June 2018 arose as a result of the impairment reversal described in Note 2.

The deferred tax asset relating to the Group's provision for decommissioning at 30 June 2018 of $277,000 (31 December 2017: $277,000) was recognised on the tax effect of the temporary differences on the Group's provision on decommissioning at the VAS field, and its tax base. The deferred tax liability relating to the Group's development and production assets at the VAS field at 30 June 2018 of $1,038,000 (31 December 2017: $1,097,000) was recognised on the tax effect of the temporary differences between the carrying value of the Group's development and production asset at the VAS field, and its tax base.

UK Corporation tax change

A change to the UK corporation tax rate was announced in the Chancellor's Budget on 16 March 2016. The change announced is to reduce the corporation tax rate to 17% from 1 April 2020. Changes to reduce the UK corporation tax rate to 19% from 1 April 2017 and to 18% from 1 April 2020 were substantively enacted on 26 October 2015. The changes to reduce the UK corporation tax rate to 17% from 1 April 2020 were substantively enacted on 6 September 2016 and the effect of these changes are included in these unaudited condensed interim consolidated financial statements.

6.Profit/(Loss) per Share

The calculation of basic and diluted earnings per ordinary share has been based on the profit for the six month period ended 30 June 2018 and 320,637,836 ordinary shares (loss for the six month period ended 30 June 2017 and 320,637,836 ordinary shares), being the average number of shares in issue for the period. There are no dilutive instruments.

7.Property, Plant and Equipment

MEX-GOL and SV gas and condensate fields

As described in Note 2, as at 30 June 2018, the Group determined the recoverable amount of its production and development assets at the MEX-GOL and SV fields based on a FVLCD approach using a discounted cash flow methodology, where the cash flows were derived based on estimates that a typical market participant would use in valuing such assets. This resulted in the reversal of the previously accumulated impairment loss of $36,117,000 recorded as income for the six months ended 30 June 2018 in these unaudited condensed interim consolidated financial statements.

The key assumptions on which the Group has based its determination of FVLCD for its production and development assets at the MEX-GOL and SV fields and to which this CGU's recoverable amount is most sensitive are described below:

(i) Commodity prices - the model assumes a gas price of $278/Mm3 (UAH7,290/Mm3) during 2018 - 2042 for the MEX-GOL and SV fields. The prices were estimated based on the price of recent Group transactions and the forecast of natural gas price dynamics for Europe published by the World Bank.

(ii)Discount rate - reflects the current market assessment of the time value of money and risks specific to the assets. The discount rate has been determined as the post-tax weighted average cost of capital based on observable inputs and inputs from third party financial analysts. For 2018 and onwards the discount rate applied was 15.1% (13.8% during previous measurement of the recoverable amount as at 31 December 2016). The discount rate and future cash flows are determined in real terms, i.e. they do not take into account the impact of the estimated commodity price index during the period of projection.

(iii)Production levels and Reserves - production levels at the MEX-GOL and SV fields are derived from the estimate of remaining proven plus probable reserves of 50.0 MMboe assessed in the report prepared by D&M as at 31 December 2017. This report includes estimated production volumes, including from new wells, over the remaining economic life of the MEX-GOL and SV fields. The estimated production is based on the Group's revised field development plan, which includes the drilling of 24 new wells. Estimating oil and gas reserves is a complex process requiring the knowledge and experience of a reservoir engineer. The quality of the estimate of proved plus probable reserves depends on the availability, completeness, and accuracy of data needed to develop the estimate, including production history available, and on the experience and judgement of the reservoir engineer. Estimates of proved plus probable reserves inevitably change over time as additional data become available and are taken into account. The magnitude of changes in these estimates is often substantial.

(iv)Production taxes - for existing wells, the Group assumed production tax rates of 29% for gas and 45% for condensate extracted from deposits up to depths of 5,000 metres and 14% for gas and 21% for condensate extracted from deposits deeper than 5,000 metres. From 1 January 2019, production tax rates for condensate produced from all wells will be reduced from 45% to 29% for condensate produced from deposits above 5,000 metres and from 21% to 14% for condensate produced from deposits below 5,000 metres. For new wells drilled after 1 January 2018, production tax rates were reduced to 12% for gas produced from deposits at depths above 5,000 metres and to 6% for gas produced from deposits below 5,000 metres, effective for the period 2018 - 2022.

(v)Capital expenditure - the Group assumed that capital expenditure of $229,774,000 will be incurred during the period from the second half of 2018 - 2042 under the revised field development plan for the MEX-GOL and SV fields.

(vi)Life of field - the current licences for the MEX-GOL and SV fields, which are due to expire in July 2024, can be extended under applicable legislation in Ukraine until the end of the economic life of the fields, which is assessed to be 2038 for the MEX-GOL field and 2042 for the SV field, based on the assessment contained in the D&M report. No application for such extensions have been made at the date of this announcement, but the Group considers the assumptions to be reasonable based on its intention to seek such extensions in due course and that the Group is legally entitled to request such extensions. However, if the extensions were not to be granted, it would result in a further reduction of $128,953,000 in the recoverable amount for these fields.

There are no reasonably possible changes in key assumptions on which the Group has based its determination of the MEX-GOL and SV CGU's recoverable amount, which could cause a change in the amount of the reversal of previously accumulated impairment recorded in the first half of 2018.

As described in Note 2, the Group has also recorded a $1,648,000 impairment loss in the first half of 2018 on an individual basis.

VAS gas and condensate fields

At 30 June 2018, the Group performed an assessment of external and internal indicators to ascertain whether there was any indication of potential impairment. Based on the analysis performed, the Group concluded that no external or internal impairment indicators existed as at 30 June 2018, and accordingly no impairment testing was required as at that date.

8.Intangible assets

Intangible assets consist mainly of the hydrocarbon production licence relating to the VAS gas and condensate field which is held by LLC Prom-Enerho Produkt. The Group amortises this intangible asset using the straight-line method over the term of the economic life of the VAS field until 2024.

At 30 June 2018, the Group performed an assessment of external and internal indicators to ascertain whether there was any indication of potential impairment of intangible assets. Based on the analysis performed, the Group concluded that no external or internal impairment indicators existed as at 30 June 2018, and accordingly no impairment testing was required as at that date.

9.Inventories

Inventories consist of materials, spare parts and finished goods. Materials and spare parts are represented by spare parts that were not assigned to any new wells as at 30 June 2018, production raw materials and fuel at the storage facility. Finished goods consist mostly of condensate and LPG held at the processing facility prior to sale.

All inventories are measured at the lower of cost or net realisable value. There was no write down of inventory as at 30 June 2018.

10.Trade and Other Receivables

Due to the short-term nature of the current trade and other financial receivables, their carrying amount is assumed to be the same as their fair value. All trade and other financial receivables, except those provided for, are considered to be of high credit quality.

All of the trade receivables are from a related party company, Smart Energy, that purchases all of the Group's gas production (see Note 4). The applicable payment terms are payment for one third of the estimated monthly volume of gas by the 20th of the month of delivery, and payment of the remaining balance by the 10th of the month following the month of delivery. The trade receivables were paid in full after the end of the period.

Prepayments and accrued income mainly consist of prepayment of $966,000 relating to the 3D seismic over the VAS field (31 December 2017: $3,130,000 relating to the development of the VAS field).

11.Trade and Other Payables

Accruals and other payables are mostly represented by employee related payables and fees payable on well lease agreements entered into in 2017.

The increase in trade payables is mostly related to workover operations on the SV-12 well (Note 19).

The carrying amounts of trade and other payables are assumed to be the same as their fair values, due to their short-term nature.

12.Provision for Decommissioning

The provision for decommissioning is based on the net present value of the Group's estimated liability for the removal of the Ukraine production facilities and well site restoration at the end of production life.

The non-current provision of $2,916,000 (31 December 2017: $3,027,000) represents a provision for the decommissioning of the Group's MEX-GOL, SV and VAS production facilities, including site restoration. None of the provision was utilised during the reporting period (2017: none).

As described in Note 2, the change in estimates applied to calculate the provision as at 30 June 2018 resulted from the revision of the estimated costs of decommissioning (increase of $346,000 in provision), the increase in the discount rate applied (decrease of $640,000 in provision) and the extension of the economic life of the MEX-GOL and SV fields as a result of the revision of the field development plan in 2018 (decrease of $190,000 in provision).

13.Financial Instruments

The Group's financial instruments comprise cash and cash equivalents and various items such as debtors and creditors that arise directly from its operations. The Group has bank accounts denominated in British Pounds, US Dollars, Euros, Canadian Dollars and Ukrainian Hryvnia. The Group does not have any borrowings. The main future risks arising from the Group's financial instruments are currently currency risk, interest rate risk, liquidity risk and credit risk.

The Group's financial assets and financial liabilities, measured at amortised cost, which approximates their fair value, comprise the following:

All assets and liabilities of the Group where fair value is disclosed are of level 2 value hierarchy and valued using current cost accounting techniques.

At 30 June 2018, the Group held cash and cash equivalents and other short-term investments in the following currencies:

All of the cash and cash equivalents held in Ukrainian Hryvnia are held in banks within Ukraine, and all other cash and cash equivalents and other short-term investments are held in banks within the United Kingdom.

14.Reconciliation of Operating Profit to Operating Cash Flow

15.Contingencies and Commitments

Amounts related to works contracted but not yet undertaken in relation to the Group's 2018 investment programme at the MEX-GOL, SV and VAS gas and condensate fields in Ukraine, but not recorded in the unaudited condensed interim consolidated financial statements at 30 June 2018, were $2,418,000 (31 December 2017: $3,151,000).

Lease payments under operating leases recognised as an expense for the six month period ended 30 June 2018 amounted to $1,468,000 (year ended 31 December 2017: $973,000, six month period ended 30 June 2017: $301,000) and were mainly represented by the leases of land and wells in Ukraine of $1,317,000 (year ended 31 December 2017: $707,000, six month period ended 30 June 2017: $174,000) and rentals of office properties in Ukraine and the UK of $128,000 (year ended 31 December 2017: $266,000, six month ended 30 June 2017: $107,000). The increase in lease expenses in the six month period ended 30 June 2018 is mainly attributable to the profit share of NJSC Ukrnafta relating to the SV-2 and SV-12 wells of $1,171,000 and $113,000 respectively. The agreements for the lease of these wells are concluded for the entire SV licence term, which expires in 2024. However, it is impracticable to estimate the outstanding off-balance sheet commitments related to the lease of wells as at 30 June 2018 as lease payments under these agreements are determined monthly and are linked to the changes in benchmark prices and future production from the leased wells. At the balance sheet date, the Group had outstanding off-balance sheet commitments for future minimum lease payments under non-cancellable operating leases for office properties, which fall due within one year, of $26,000 (31 December 2017: $103,000).

During 2010 - 2018, the Group has been in dispute with the Ukrainian tax authorities in respect of VAT receivables on imported leased equipment, with a disputed liability of up to UAH8,487,000 ($324,000) inclusive of penalties and other associated costs. There is a level of ambiguity in the interpretation of the relevant tax legislation, and the position adopted by the Group has been challenged by the Ukrainian tax authorities, which has led to legal proceedings to resolve the issue. The Group had been successful in three court cases in respect of this dispute in сourts of different levels. On 20 September 2016, a hearing was held in the Supreme Court of Ukraine of an appeal of the Ukrainian tax authorities against the decision of the Higher Administrative Court of Ukraine, in which the appeal of the Ukrainian tax authorities was upheld. As a result of this appeal decision, all decisions of the lower courts were cancelled, and the case was remitted to the first instance court for a new trial. On 1 December 2016 and 7 March 2017, the Group received positive decisions in the first and second instance courts, but further legal proceedings may arise. Since the Group had been successful in previous court cases in respect of this dispute in сourts of different levels, the date of the next legal proceedings has not been set and as the Group believes that adequate defences exist to the claim, no liability has been recognised in these unaudited condensed interim consolidated financial statements for the six months ended 30 June 2018 (31 December 2017: nil).

16.Related Party Disclosures

Key management personnel of the Group are considered to comprise only the Directors. Remuneration of the Directors for the six month period ended 30 June 2018 was $468,000 (six month period ended 30 June 2017: $327,000, and year ended 31 December 2017: $940,000).

During the period, Group companies entered into the following transactions with related parties which are not members of the Group:

All related party transactions were with subsidiaries of the ultimate parent company, and primarily relate to the sale of gas to Smart Energy (Note 4), the rental of office facilities and vehicles and the sale of equipment. The amounts outstanding were unsecured and have been or will be settled in cash.

As of 30 June 2018 and 2017, the Company's immediate parent company was Energees Management Limited, which is 100% owned by Pelidona Services Limited, which is 100% owned by Lovitia Investments Ltd, which is 100% owned by Mr V Novinskiy. Accordingly, the Company's ultimate parent company was Lovitia Investments Ltd and the Company was ultimately controlled by Mr V Novinskiy.

The Group operates bank accounts in Ukraine with a related party bank, Unex Bank, which is ultimately controlled by Mr V Novinskiy. There were the following transactions and balances with Unex Bank during the period:

At the date of this announcement, none of the Company's controlling parties prepares consolidated financial statements available for public use.

17.Post Balance Sheet Events

As announced on 9 August 2018, CTF Holdings SA notified the Company on 7 August 2018 that it no longer had an interest in any shares in the issued share capital of the Company.

As announced on 14 August 2018, Kelda Limited notified the Company on 14 August 2018 that, through its 100% owned subsidiary Kylestone Limited, it has an interest in 24.43% of the issued share capital of the Company.

On 13 July 2018, the Group announced the successful completion of workover operations on the SV-12 well and that flow testing had established good gas and condensate flow. The SV-12 well is a suspended well owned by NJSC Ukrnafta, the partially State-owned oil and gas producer, and is located within the Group's SV licence area. In late 2017, the Group entered into a leasing agreement with NJSC Ukrnafta relating to the workover and production from the well (Note 17). The well is now hooked up to the Group's gas processing facilities and is in production.

In July 2018, the VAS-10 well was completed. One interval in the B-25/26 Visean formation was perforated and short-term initial flow testing was undertaken, and whilst there was gas flow, a stabilised flow rate was not established. Since then the well has been hooked up to the gas processing facility and currently production testing of this reservoir interval is underway. Depending on the outcome of such testing, either this interval will be put into production, or alternatively the shallower B-16/17 reservoir will be tested.

Independent review report to Regal Petroleum plc

Report on the condensed interim consolidated financial statements

Our conclusion

We have reviewed Regal Petroleum plc's condensed interim consolidated financial statements (the "interim financial statements") in the interim results of Regal Petroleum plc for the 6 month period ended 30 June 2018. Based on our review, nothing has come to our attention that causes us to believe that the interim financial statements are not prepared, in all material respects, in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and the AIM Rules for Companies.

What we have reviewed

The interim financial statements comprise: