RPT.L Regulatory News (RPT)

30 April 2019

REGAL PETROLEUM PLC

2018 AUDITED RESULTS

Regal Petroleum plc (the "Company", and with its subsidiaries, the "Group"), the AIM-quoted (RPT) oil and gas exploration and production group, today announces its audited results for the year ended 31 December 2018.

Highlights

Ukraine Operations

Finance

Outlook

The Annual Report and Financial Statements for 2018, together with the Notice of Annual General Meeting, will be posted to shareholders and published on the Company's website during May/June 2019.

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

For further information, please contact:

Dmitry Sazonenko, MSc Geology, MSc Petroleum Engineering, Member of AAPG, SPE and EAGE, 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.

Chairman's Statement

I am delighted to introduce the 2018 Annual Report and Financial Statements. This year has been an exceptional year for the Group, with excellent progress in the development of the MEX-GOL, SV and VAS gas and condensate fields in north-eastern Ukraine and an extremely strong financial performance during the year. 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 operational successes have resulted in significantly higher production levels.

At the MEX-GOL and SV fields, production was stable during the first half of 2018, with much 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 824 boepd, providing a further significant boost to production from the field. During the year, the VAS field continued to produce consistently, and in November 2018, the VAS-10 well was brought into production, providing a significant production increase at the VAS field.

Aggregate average daily production from the MEX-GOL, SV and VAS fields during 2018 was approximately 3,391 boepd, which compares with an aggregate daily production rate of approximately 2,235 boepd during 2017, an increase of nearly 52%.

The Group's strong production performance is reflected in the Group's financial performance for the year ended 31 December 2018, which was also extremely strong and a significant improvement on the prior year. During 2018, the Group grew its net profit to $54.3 million (2017: $2.3 million), predominantly as a result of improved revenues of $66.1 million (2017: $35.1 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 arose as a result of the reassessment of the reserves and resources at the MEX-GOL and SV fields, and which was a one-off item. Gross profits were much higher at $34.2 million (2017: $10.8 million) and cash generated from operations during the year was also much higher at $36.8 million (2017: $18.0 million).

The fiscal and economic situation in Ukraine has improved during 2018, with a better economic outlook, GDP growth, reduced inflation and reasonable stability in the Ukrainian Hryvnia exchange rates. Nevertheless, there are still fiscal and economic stresses in Ukraine and a continued 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 2018, gas prices were reasonably stable, allowing for some seasonal variation, and were higher than in 2017. Furthermore, condensate and LPG prices were also higher by comparison with last year.

Board and Management Changes

At the end of September 2018, there were a number of changes to the management and Board of Directors of the Company. Yevhen (Gene) Palyenka left his position as Chief Financial Officer to pursue another opportunity, Phil Frank stepped down from the Board and Dmitry Sazonenko joined the Board as Non-Executive Director.

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 gradually. After the operational successes of 2018 and the increased production output during the year, we are looking forward to achieving further successes in the development activities planned for 2019 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

Chief Executive Officer's Statement

Introduction

The Group made excellent progress at its Ukrainian fields during 2018, with the increase in development activity at the MEX-GOL and SV fields resulting in the successful workover of the SV-12 well, which came on production in July 2018, and at the VAS field, resulting in the successful drilling of the VAS-10 well, which came on production in November 2018. These successes have provided a significant boost to overall production rates.

During the year, the Group continued its work on the subsurface analysis 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 the year 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, drilling of the VAS-10 well was completed in July 2018, and after testing of different zones, the well was hooked up to the gas processing facilities and put onto production in November 2018. Planning for the acquisition of the remaining coverage of 3D seismic over the field was undertaken after some local access issues had caused delays, and the acquisition work was completed in early 2019.

Health, Safety, Environment and Security ("HSES")

The Group is committed to maintaining the highest HSES standards and the effective management of these areas is an intrinsic element of the overall business ethos. Through strict enforcement of the Group's HSES Management System, together with regular management meetings, training and the appointment of dedicated safety professionals, the Group strives to ensure that the impact of its business activities on its staff, contractors and the environment is as low as is reasonably practicable. The Group reports safety and environmental performance in accordance with industry practice and guidelines.

I am pleased to report that during 2018, a total of 398,773 man-hours of staff and contractor time were recorded without a Lost Time Incident occurring. The total number of safe man-hours now stands at over 2,277,175 man-hours without a Lost Time Incident. No environmental incidents were recorded during the year.

Production

Average daily production from the MEX-GOL and SV fields over the year ended 31 December 2018 was 341,216 m³/d of gas, 70 m³/d of condensate and 36 m³/d of LPG (2,717 boepd in aggregate) (2017: 197,961 m3/d of gas, 47 m3/d of condensate and 24 m³/d of LPG (1,629 boepd in aggregate). Production rates 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 for the year ended 31 December 2018 was 94,752 m3/d of gas and 8.2 m3/d of condensate (674 boepd in aggregate) ( 2017: 86,010 m3/d of gas and 6.5 m3/d of condensate (606 boepd in aggregate)). Production rates were boosted significantly following commencement of production from the VAS-10 well in November 2018.

The Group's average production for the period from 1 January 2019 to 25 April 2019 from the MEX-GOL and SV field was 402,245 m³/d of gas, 87 m³/d of condensate and 45 m³/d of LPG (3,245 boepd in aggregate) and from the VAS field was 139,900 m³/d of gas and 15 m³/d of condensate (1,012 boepd in aggregate).

Operations

The much improved fiscal and economic conditions in Ukraine, coupled with reasonable stability in the Ukrainian Hryvnia, higher hydrocarbon prices, reductions in the subsoil tax rates and improvements in the regulatory procedures in the oil and gas sector in Ukraine over the last year, gave the Board the confidence to expand and 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 is a strong producer, with stable production rates of approximately 94,000 m3/d of gas, 27 m3/d of condensate and 9 m3/d of LPG, which has significantly increased production at the SV 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, planning took place for the acquisition of new 3D seismic data over the field, which was finally completed in January 2019, after the seismic contractor experienced some local access issues which delayed the acquisition field work. The data acquired is now being 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. As a result, the shallower B-16/17 reservoir was tested and flowed strongly. Accordingly, this interval was put on production during November 2018, and is producing steadily at rates of approximately 50,000 m3/d of gas and 8 m3/d of condensate.

However, as announced on 12 March 2019, a regulatory issue did arise when the State Service of Geology and Subsoil of Ukraine issued an order for suspension (the "Order") of the production licence for the VAS field. Under the applicable legislation, the Order would lead to a shut down of production operations at the VAS field, but the Group has issued legal proceedings to challenge the Order, and has obtained a ruling suspending operation of the Order pending a hearing of the substantive issues. The Group does not believe that there are any grounds for the Order, and intends to pursue its challenge to the Order through the Ukrainian Courts.

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.

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 2019, 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, completing the drilling of the new development well, MEX-119, which was spudded in February 2019 and is designed to accelerate production from the B-20 Visean reservoirs in the MEX-GOL field, commencement of a new well in the SV field, planning for a further well in the SV field, investigating workover opportunities for other existing wells, installation of compression equipment, 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 processing and interpreting of the new 3D seismic data will be completed, a new geological model will be developed, and planning for a new 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 install compression equipment, and upgrade the gas processing facilities, pipeline network and other infrastructure.

The Group has also commissioned an updated assessment of the remaining reserves and resources at the VAS field, which is being undertaken by D&M. It is anticipated that the updated reserves and resources assessment will be completed in mid-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 gas production from new wells drilled after 1 January 2018 and came 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 over what has been a very successful year for the Group.

Sergii Glazunov

Chief Executive Officer

Overview of Assets and Reserves

Assets

1. MEX-GOL and SV fields

Regal Petroleum Corporation Limited (a wholly owned subsidiary in the Group) holds a 100% working interest in and is the operator of the MEX-GOL and SV fields. The production licences extend over a combined area of 269 km², approximately 200 km east of Kiev. The two licences are adjacent and the interests are operated and managed as one field. The licences were granted in July 2004 and have a duration of 20 years.

The fields are located, geologically, towards the middle of the Dnieper-Donets sedimentary basin which extends across the majority of north-east Ukraine. The vast majority of Ukrainian gas and condensate production comes from this basin. The reservoirs comprise a series of gently dipping Carboniferous sandstones of Visean age ("B-Sands") inter-bedded with shales at approximately 4,700 metres below the surface, with a gross thickness between 800 metres and 1,000 metres. Analysis suggests that these deposits range from fluvial to deltaic in origin, and much of the trapping at these fields is stratigraphic in nature. Below these reservoirs is a thick sequence of shale above deeper, similar, sandstones which are encountered at a depth of around 5,800 metres. These sands are of Tournasian age ("T-Sands") and may offer additional gas potential. Deeper sandstones of Devonian age ("D-Sands") have also been penetrated in the fields.

2. VAS field

LLC Prom-Enerho Produkt (a wholly owned subsidiary in the Group) holds a 100% working interest in and is the operator of the VAS field. The production licence extends over an area of 33.2 km² and is located approximately 17 km south-east of Kharkiv. The licence was granted in August 2012 and has a duration of 20 years.

The field is also located, geologically, towards the middle of the Dnieper-Donets sedimentary basin in the north-east of Ukraine. The field is trapped in an anticlinal structure broken into several faulted blocks, which are gently dipping to the north, stretching from the north-east to south-west along a main bounding fault. The gas is located in Carboniferous sandstones of Bashkirian, Serpukhovian and Visean age at depths of 2,900 - 3,400 metres below the surface.

Reserves

1. MEX-GOL and SV fields

The Group's estimates of the remaining Reserves and Resources at the MEX-GOL and SV licence areas are derived from an assessment undertaken by independent petroleum consultants, DeGolyer and MacNaughton ("D&M"), as at 31 December 2017 (the "D&M Report"), which was announced on 31 July 2018. During the period from 1 January 2018 to 31 December 2018, the Group has produced 1.0 MMboe from these fields.

The D&M Report estimated the remaining Reserves as at 31 December 2017 in the MEX-GOL and SV fields as follows:-

The D&M Report estimated the Contingent Resources as at 31 December 2017 in the MEX-GOL and SV fields as follows:-

2. VAS field

The Group's estimates of the remaining Reserves and Resources at the VAS field and the Prospective Resources at the VED prospect are derived from an assessment undertaken by independent petroleum consultants, Senergy (GB) Limited, as at 1 January 2016 (the "Senergy Report"), which was announced on 5 July 2016. During the period from 1 January 2016 to 31 December 2018, 0.7 MMboe were produced from the field.

The Senergy Report estimates the remaining Reserves as at 1 January 2016 in the VAS field as follows:-

The Senergy Report estimates the Contingent Resources as at 1 January 2016 in the VAS field as follows:-

The Senergy Report estimates the Prospective Resources as at 1 January 2016 in the VED prospect as follows:-

Finance Review

The Group achieved a very strong financial performance during 2018, with a significantly improved net profit of $54.3 million (2017: $2.3 million) during the year ended 31 December 2018, mainly as a result of improved revenue from combined higher production volumes and hydrocarbon prices, and a significant reversal of an impairment of the Group's oil and gas development and production assets of $36.1 million as a result of the reassessment of the remaining reserves and resources at the MEX-GOL and SV fields as at 31 December 2017, which was a one-off item.

Gross profit for the year ended 31 December 2018 more than trebled to at $34.2 million (2017: $10.8 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 positive re-assessment of the Group's reserves at the MEX-GOL and SV fields as at 31 December 2017, which took place during the year.

During 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 4 to the financial statements, 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 year.

The reversal of impairment of the Group's oil and gas assets also led to a consequential reversal of impairment of intra-group loans of $10.9 million in the Company's financial statements as a result of an increase in the present value of estimated future cash flows following the reassessment of the carrying value of the Group's oil and gas assets.

Revenue for the year, derived from the sale of the Group's Ukrainian gas, condensate and LPG production, was also significantly higher at $66.1 million (2017: $35.1 million). Similarly, cash generated from operations during the year was much higher at $36.8 million (2017: $18.0 million) as a result of higher production volumes and hydrocarbon prices.

The average realised gas, condensate and LPG prices during the 2018 year were $312/Mm3 (UAH8,528/Mm3), $72/bbl and $64/bbl respectively (2017: $241/Mm3 (UAH6,412/Mm3), $67/bbl and $56/bbl respectively).

During the period from 1 January 2019 to 25 April 2019, the average realised gas, condensate and LPG prices were $279/Mm3 (UAH7,597/Mm3), $52/bbl and $47/bbl respectively. The current realised gas price is $287/Mm3 (UAH7,712/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 2018 year, gas prices were reasonably stable, allowing for some seasonal variation, and were higher than in 2017, as were condensate and LPG prices by comparison with 2017.

The subsoil tax rates applicable to gas and condensate production were stable during the year 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 were reduced from 45% to 31% for condensate produced from deposits above 5,000 metres and from 21% to 16% for condensate produced from deposits below 5,000 metres.

In addition, with effect from 1 January 2019, a transmission tariff of UAH91.87/Mm3 ($3.23/Mm3) for use of the Ukrainian national pipeline system became applicable to oil and gas producers in Ukraine, including the Group.

Cost of sales for the year ended 31 December 2018 was higher at $31.9 million (2017: $24.3 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 year.

Administrative expenses for the year were slightly higher at $5.7 million (2017: $5.3 million), primarily as a result of an increase in payroll and related taxes.

The tax charge for the year of $12.5 million (2017: $4.3 million charge) comprises a current tax charge of $6.5 million (2017: $3.0 million charge) and a deferred tax charge of $6.0 million (2017: $1.3 million charge). A significant deferred tax charge was incurred in the year 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 $3.3 million at 31 December 2018 (31 December 2017: $9.3 million). This comprises a deferred tax asset of $2.1 million (31 December 2017: $2.6 million) in relation to UK tax losses carried forward, and $1.2 million (31 December 2017: $0.1 million) which is recognised on the tax effects of the temporary differences of the provision for decommissioning and the carrying value of the Group's oil and gas development and production assets, and their tax bases.

A deferred tax liability relating to the development and production asset at the VAS field of $0.5 million (31 December 2017: $0.8 million) was recognised at 31 December 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.

Increased capital investment of $9.6 million reflects investment in the Group's oil and gas development and production assets during the year (2017: $4.0 million), primarily relating to the expenditure associated with the drilling of the VAS-10 well.

Cash and cash equivalents held at 31 December 2018 were $53.2 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 25 April 2019 was $54.2 million, held as to $24.2 million equivalent in Ukrainian Hryvnia and the balance of $30.0 million equivalent predominantly in US Dollars, Euros and Pounds Sterling.

Since early 2014, the Ukrainian Hryvnia has devalued significantly against the US Dollar, falling from UAH8.3/$1.00 on 1 January 2014 to UAH27.7/$1.00 on 31 December 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 2018, the exchange rate between the Ukrainian Hryvnia and the US Dollar has been reasonably stable averaging UAH27.2/$1.00 during the period (average rate during 2017: UAH26.6/$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 year, 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 2019.

The Group manages its revenue, cash from operations and production volumes as key performance indicators. The achieved results for 2018 were as follows:

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:-

Consolidated Income Statement

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

Consolidated Statement of Comprehensive Income

Company Statement of Comprehensive Income

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

Consolidated Balance Sheet

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

Consolidated Statement of Changes in Equity

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

Consolidated Cash Flow Statement

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

 Notes forming part of the financial statements

1. Statutory Accounts

The financial information set out above does not constitute the Company's statutory accounts for the year ended 31 December 2018 or 2017, but is derived from those accounts. The Auditor has reported on those accounts, and its reports were unqualified and did not contain statements under sections 498(2) or (3) of the Companies Act 2006.

The statutory accounts for 2018 will be delivered to the Registrar of Companies following the Company's Annual General Meeting.

While the financial information included in this preliminary announcement has been prepared in accordance with International Financial Reporting Standards as adopted by the European Union ("IFRS"), this announcement does not itself contain sufficient information to comply with IFRS. The Company expects to distribute the full financial statements that comply with IFRS in May/June 2019.

2. General Information and Operational Environment

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

The Company is a public limited 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. The principal activities of the Group and the nature of the Group's operations are set out in the Directors' Report.

As of 31 December 2017 the Company's immediate parent company was Energees Management Limited, which is 100% owned by Pelidona Services Limited. On 11 December 2018, Energees Management Limited transferred 100% of its shares in the Company to Pelidona Services Limited. As at 31 December 2018, the Company's immediate parent company was Pelidona Services Limited, which is 100% owned by Lovitia Investments Limited, which is 100% owned by Mr V Novynskyi. Accordingly, the Company was ultimately controlled by Mr V Novynskyi.

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 in late 2013, has led to a deterioration of Ukrainian State finances, volatility of financial markets, illiquidity on capital markets, higher inflation and a depreciation of the national currency against major foreign currencies, although there have been some gradual improvements recently.

The Ukrainian economy is showing signs of stabilisation after the previous years of political and economic tensions. The year-on-year inflation rate in Ukraine decreased to 9.8% during 2018 (as compared to 13.7% in 2017), while GDP grew at 3.3% (after 2% growth in 2017).

The National Bank of Ukraine ("NBU") continued its inflation targeting policy and periodically raised its key policy rate from 12.5% in May 2017 to 18% in September 2018. This has helped restrain inflation below 10%, although the cost of domestic funding has increased significantly. The NBU adhered to a floating Ukrainian Hryvnia exchange rate, which finished the 2018 year at UAH27.69/$1.00, compared to UAH28.07/$1.00 as at 31 December 2017. Among the key mitigating factors for the relative stability of the Ukrainian Hryvnia were the agreement on the International Monetary Fund ("IMF") programme, strong revenues of agricultural exporters, tight Ukrainian Hryvnia liquidity and a growth in remittances from labour migrants.

In December 2018, the IMF approved a 14-month Stand-By Arrangement ("SBA") programme for Ukraine, totalling $3.9 billion. In December 2018, Ukraine received $2 billion from the IMF and the European Union ("EU"), as well as $750 million credit guarantees from the World Bank. The approval of the IMF programme significantly increases the chance of Ukraine meeting its foreign currency obligations in 2019, and thus will support the financial and macroeconomic stability of the country. The IMF will decide on further tranches in May and November 2019, depending on Ukraine's success in fulfilling the terms of the Memorandum on Economic and Financial Policies, which Ukraine plans to follow during the SBA programme's implementation.

In 2019-2020, Ukraine faces major public debt repayments, which will require the arrangement of substantial domestic and external financing in an increasingly challenging financing environment for emerging markets. In addition, presidential elections held in March and April 2019 resulted in the election of a new President, and parliamentary elections are scheduled for October 2019. As a consequence of these elections, a degree of political uncertainty will remain for the foreseeable future. Despite certain improvements in 2018, the outcome of these matters and the ongoing effects of the political and economic situation are difficult to predict, but they may have further severe effects on the Ukrainian economy and the Group's business.

Further details of risks relating to Ukraine can be found within the Principal Risks and Uncertainties section of the Strategic Report.

3. Accounting Policies

The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.

Basis of Preparation

The Group has prepared its consolidated financial statements and the Company's financial statements under International Financial Reporting Standards ("IFRSs") and interpretations issued by the IFRS Interpretations Committee ("IFRS IC"), as adopted by the European Union. The financial statements have been prepared in accordance with the Companies Act 2006 as applicable to companies using IFRS. The principal accounting policies applied in the preparation of the consolidated financial statements are set out below. Apart from the accounting policy changes resulting from the adoption of IFRS 9 and IFRS 15 effective from 1 January 2018, these policies have been consistently applied to all the periods presented, unless otherwise stated (refer to Notes 5 and 34). The principal accounting policies in respect of financial instruments and revenue recognition applied until 31 December 2017 are presented in Note 34.

The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in Note 4.

Going Concern

Based on the positive operational and financial performance of the Group and for the reasons outlined in the Principal Risks and Uncertainties section of the Strategic Report, 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 after the date of signing of these financial statements. Accordingly, the going concern basis has been adopted in preparing its consolidated financial statements and the Company's financial statements for the year ended 31 December 2018. The use of this basis of accounting takes into consideration the Company's and the Group's current and forecast financing position, additional details of which are provided in the Principal Risks and Uncertainties section of the Strategic Report. The Group does not foresee any positive or negative impact on its operations as a result of the ongoing Brexit negotiations or any outcome from those negotiations.

New and amended standards adopted by the Group

The Group has applied the following new and revised standards and interpretations for the first time for its annual reporting period commencing 1 January 2018. The Group had to change its accounting policies as a result of adopting the following standards:

· IFRS 9 Financial Instruments;

· IFRS 15 Revenue from contracts with customers.

The impact of the adoption of these standards and the new accounting policies are disclosed in Note 5 below.

The following amended standards became effective for the Group from 1 January 2018, but did not have any material impact on the Group:

· Amendments to IFRS 2 Share-based Payment (issued on 20 June 2016 and effective for annual periods beginning on or after 1 January 2018).

· Amendments to IFRS 4 - Applying IFRS 9 Financial Instruments with IFRS 4 Insurance Contracts (issued on 12 September 2016 and effective, depending on the approach, for annual periods beginning on or after 1 January 2018 for entities that choose to apply temporary exemption option, or when the entity first applies IFRS 9 for entities that choose to apply the overlay approach).

· Annual Improvements to IFRSs 2014-2016 cycle ‒ Amendments to IFRS 1 an IAS 28 (issued on 8 December 2016 and effective for annual periods beginning on or after 1 January 2018).

· IFRIC 22 Foreign Currency Transactions and Advance Consideration (issued on 8 December 2016 and effective for annual periods beginning on or after 1 January 2018).

· Amendments to IAS 40 - Transfers of Investment Property (issued on 8 December 2016 and effective for annual periods beginning on or after 1 January 2018).

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 the annual periods beginning on or after 1 January 2019 or later, and which the Group has not early adopted. The Group's assessment of the impact of these new standards and interpretations is set out below.

I) IFRS 16 Leases (issued on 13 January 2016 and effective for annual periods beginning on or after 1 January 2019)

The new standard sets out the principles for the recognition, measurement, presentation and disclosure of leases. All leases result in the lessee obtaining the right to use an asset at the start of the lease and, if lease payments are made over time, also obtaining financing. Accordingly, IFRS 16 eliminates the classification of leases as either operating leases or finance leases as is required by IAS 17 and, instead, introduces a single lessee accounting model. Lessees will be required to recognise: (a) assets and liabilities for all leases with a term of more than 12 months, unless the underlying asset is of low value; and (b) depreciation of lease assets separately from interest on lease liabilities in the statement of profit or loss and other comprehensive income. IFRS 16 substantially carries forward the lessor accounting requirements in IAS 17. Accordingly, a lessor continues to classify its leases as operating leases or finance leases, and to account for those two types of leases differently.

The Group decided that it will apply the standard from its mandatory adoption date of 1 January 2019 using the modified retrospective method, without restatement of comparatives. Right-of-use assets for property leases are measured on transition as if the new rules had always applied. All other right-of-use assets are measured at the amount of the lease liability on adoption (adjusted for any prepaid or accrued expenses).

As at 31 December 2018, the Group has non-cancellable lease commitments of $1,884,000. Of these commitments, approximately $10,000 relate to low values leases and $85,000 to short-term leases which will both be recognised on a straight-line basis as expenses in profit or loss, leaving a balance of $1,789,000.

A reconciliation of the operating lease commitments disclosed in Note 28 to the recognised liability is as follows:

The Company has only short-term leases in the amount of $85,000 which will be recognised as expenses in profit or loss.

For the remaining lease commitments, the Group expects to recognise right-of-use assets of approximately $1,122,000 on 1 January 2019, and lease liabilities of $1,122,000 (after adjustments for prepayments and accrued lease payments recognised as at 31 December 2018). Overall net current assets will be approximately $371,000 lower due to the presentation of a portion of the liability as a current liability. The Group expects that net profit for the year ending 31 December 2019 will increase by approximately $64,000 as a result of adopting the new rules. Operating cash flows will increase and financing cash flows decrease by approximately $406,000 as repayment of the principal portion of the lease liabilities will be classified as cash flows from financing activities.

II) IFRS 17 Insurance Contracts (issued on 18 May 2017 and effective for annual periods beginning on or after 1 January 2021)

IFRS 17 replaces IFRS 4, which has given companies dispensation to carry on accounting for insurance contracts using existing practices. As a consequence, it was difficult for investors to compare and contrast the financial performance of otherwise similar insurance companies. IFRS 17 is a single principle-based standard to account for all types of insurance contracts, including reinsurance contracts that an insurer holds. The standard requires recognition and measurement of groups of insurance contracts at: (i) a risk-adjusted present value of the future cash flows (the fulfilment cash flows) that incorporates all of the available information about the fulfilment cash flows in a way that is consistent with observable market information; plus (if this value is a liability) or minus (if this value is an asset), and (ii) an amount representing the unearned profit in the group of contracts (the contractual service margin). Insurers will be recognising the profit from a group of insurance contracts over the period they provide insurance coverage, and as they are released from risk. If a group of contracts is or becomes loss-making, an entity will be recognising the loss immediately. 

III) IFRIC 23 "Uncertainty over Income Tax Treatments" (issued on 7 June 2017 and effective for annual periods beginning on or after 1 January 2019)

IAS 12 specifies how to account for current and deferred tax, but not how to reflect the effects of uncertainty. The interpretation clarifies how to apply the recognition and measurement requirements in IAS 12 when there is uncertainty over income tax treatments. An entity should determine whether to consider each uncertain tax treatment separately or together with one or more other uncertain tax treatments based on which approach better predicts the resolution of the uncertainty. An entity should assume that a taxation authority will examine amounts it has a right to examine and have full knowledge of all related information when making those examinations. If an entity concludes it is not probable that the taxation authority will accept an uncertain tax treatment, the effect of uncertainty will be reflected in determining the related taxable profit or loss, tax bases, unused tax losses, unused tax credits or tax rates by using either the most likely amount or the expected value, depending on which method the entity expects to better predict the resolution of the uncertainty. An entity will reflect the effect of a change in facts and circumstances or of new information that affects the judgments or estimates required by the interpretation as a change in accounting estimate. Examples of changes in facts and circumstances or new information that can result in the reassessment of a judgment or estimate include, but are not limited to, examinations or actions by a taxation authority, changes in rules established by a taxation authority or the expiry of a taxation authority's right to examine or re-examine a tax treatment. The absence of agreement or disagreement by a taxation authority with a tax treatment, in isolation, is unlikely to constitute a change in facts and circumstances or new information that affects the judgments and estimates required by the interpretation.

IV) Prepayment Features with Negative Compensation - Amendments to IFRS 9 (issued on 12 October 2017 and effective for annual periods beginning on or after 1 January 2019)

The amendments enable measurement at amortised cost of certain loans and debt securities that can be prepaid at an amount below amortised cost, for example at fair value or at an amount that includes a reasonable compensation payable to the borrower equal to present value of an effect of increase in market interest rate over the remaining life of the instrument. In addition, the text added to the standard's basis for conclusion reconfirms existing guidance in IFRS 9 that modifications or exchanges of certain financial liabilities measured at amortised cost that do not result in the derecognition will result in a gain or loss in profit or loss. Reporting entities will thus in most cases not be able to revise the effective interest rate for the remaining life of the loan in order to avoid an impact on profit or loss upon a loan modification.

V) Annual Improvements to IFRSs 2015-2017 cycle - amendments to IFRS 3, IFRS 11, IAS 12 and IAS 23 (issued on 12 December 2017 and effective for annual periods beginning on or after 1 January 2019) 

The narrow scope amendments impact four standards. IFRS 3 was clarified that an acquirer should re-measure its previously held interest in a joint operation when it obtains control of the business. Conversely, IFRS 11 now explicitly explains that the investor should not re-measure its previously held interest when it obtains joint control of a joint operation, similarly to the existing requirements when an associate becomes a joint venture and vice versa. The amended IAS 12 explains that an entity recognises all income tax consequences of dividends where it has recognised the transactions or events that generated the related distributable profits, e.g. in profit or loss or in other comprehensive income.

It is now clear that this requirement applies in all circumstances as long as payments on financial instruments classified as equity are distributions of profits, and not only in cases when the tax consequences are a result of different tax rates for distributed and undistributed profits. The revised IAS 23 now includes explicit guidance that the borrowings obtained specifically for funding a specified asset are excluded from the pool of general borrowings costs eligible for capitalisation only until the specific asset is substantially complete. 

VI) Amendments to IAS 19 "Plan Amendment, Curtailment or Settlement" (issued on 7 February 2018 and effective for annual periods beginning on or after 1 January 2019)

The amendments specify how to determine pension expenses when changes to a defined benefit pension plan occur. When a change to a plan - an amendment, curtailment or settlement - takes place, IAS 19 requires to remeasure net defined benefit liability or asset. The amendments require to use the updated assumptions from this remeasurement to determine current service cost and net interest for the remainder of the reporting period after the change to the plan. Before the amendments, IAS 19 did not specify how to determine these expenses for the period after the change to the plan. By requiring the use of updated assumptions, the amendments are expected to provide useful information to users of financial statements. The Group is currently assessing the impact of the amendments on its financial statements.

VII) Amendments to the Conceptual Framework for Financial Reporting (issued on 29 March 2018 and effective for annual periods beginning on or after 1 January 2020)

The revised Conceptual Framework includes: a new chapter on measurement; guidance on reporting financial performance; improved definitions and guidance - in particular the definition of a liability; and clarifications in important areas, such as the roles of stewardship, prudence and measurement uncertainty in financial reporting.

VIII) Definition of a business - Amendments to IFRS 3 (issued on 22 October 2018 and effective for acquisitions from the beginning of annual reporting period that starts on or after 1 January 2020).

The amendments revise definition of a business. A business must have inputs and a substantive process that together significantly contribute to the ability to create outputs. The new guidance provides a framework to evaluate when an input and a substantive process are present, including for early stage companies that have not generated outputs. An organised workforce should be present as a condition for classification as a business if are no outputs. The definition of the term "outputs" is narrowed to focus on goods and services provided to customers, generating investment income and other income, and it excludes returns in the form of lower costs and other economic benefits. It is also no longer necessary to assess whether market participants are capable of replacing missing elements or integrating the acquired activities and assets. An entity can apply a "concentration test". The assets acquired would not represent a business if substantially all of the fair value of gross assets acquired is concentrated in a single asset (or a group of similar assets). 

IX) Definition of materiality - Amendments to IAS 1 and IAS 8 (issued on 31 October 2018 and effective for annual periods beginning on or after 1 January 2020)

The amendments clarify the definition of material and how it should be applied by including in the definition guidance that until now has featured elsewhere in IFRS. In addition, the explanations accompanying the definition have been improved. Finally, the amendments ensure that the definition of material is consistent across all IFRS Standards. Information is material if omitting, misstating or obscuring it could reasonably be expected to influence the decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.

The Group is currently assessing the impact of the interpretation and amendments on its financial statements.

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.

Exchange differences on intra-group balances with foreign operation

The Group has certain inter-company monetary balances of which the Company is the beneficial owner. These monetary balances are payable by a subsidiary that is a foreign operation and are eliminated on consolidation.

In the consolidated financial statements, exchange differences arising on such payables because the transaction currency differs from the subsidiary's functional currency are recognised initially in other comprehensive income if the settlement of such payables is continuously deferred and is neither planned nor likely to occur in the foreseeable future.

In such cases, the respective receivables of the Company are regarded as an extension of the Company's net investment in that foreign operation, and the cumulative amount of the abovementioned exchange differences recognised in other comprehensive income is carried forward within the foreign exchange reserve in equity and is reclassified to profit or loss only upon disposal of the foreign operation.

When the subsidiary that is a foreign operation settles its quasi-equity liability due to the Company, but the Company continues to possess the same percentage of the subsidiary, i.e. there has been no change in its proportionate ownership interest, such settlement is not regarded as a disposal or a partial disposal, and therefore cumulative exchange differences are not reclassified.

The designation of inter-company monetary balances as part of the net investment in a foreign operation is re-assessed when management's expectations and intentions on settlement change due to a change in circumstances.

Where, because of a change in circumstances, a receivable balance, or part thereof, previously designated as a net investment into a foreign operation is intended to be settled, the receivable is de-designated and is no longer regarded as part of the net investment.

In such cases, the exchange differences arising on the subsidiary's payable following de-designation are recognised within finance costs / income in profit or loss, similar to foreign exchange differences arising from financing.

Basis of Consolidation

The consolidated financial statements incorporate the financial information of the Company and entities controlled by the Company (and its subsidiaries) made up to 31 December each year.

Subsidiaries

Subsidiaries are all entities (including structured entities) over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases.

The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The Group recognises any non-controlling interest in the acquiree on an acquisition-by-acquisition basis at the non-controlling interest's proportionate share of the recognised amounts of the acquiree's identifiable net assets.

Acquisition-related costs are expensed as incurred.

If the business combination is achieved in stages, the acquisition date carrying value of the acquirer's previously held equity interest in the acquiree is re-measured to fair value at the acquisition date; any gains or losses arising from such re-measurement are recognised in profit or loss.

Any contingent consideration to be transferred by the Group is recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability is recognised in accordance with IFRS 9 in profit or loss.

Inter-company transactions, balances and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are also eliminated. When necessary, amounts reported by subsidiaries have been adjusted to conform with the Group's accounting policies.

Segment reporting

The Group's only class of business activity is oil and gas exploration, development and production. The Group's primary operations are located in Ukraine, with its head office in the United Kingdom. The geographical segments are the basis on which the Group reports its segment information to management. Operating segments are reported in a manner consistent with the internal reporting provided to the Board of Directors.

Commercial Reserves

Proved and probable oil and gas reserves are estimated quantities of commercially producible hydrocarbons which the existing geological, geophysical and engineering data show to be recoverable in future years from known reservoirs. Proved reserves are those quantities of petroleum that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable from known reservoirs and under defined technical and commercial conditions. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. The proved and probable reserves conform to the definition approved by the Petroleum Resources Management System.

Oil and Gas Exploration/Evaluation and Development/Production Assets

The Group applies the successful efforts method of accounting for oil and gas assets, having regard to the requirements of IFRS 6 "Exploration for and Evaluation of Mineral Resources".

Exploration costs are incurred to discover hydrocarbon resources. Evaluation costs are incurred to assess the technical feasibility and commercial viability of the resources found. Exploration, as defined in IFRS 6 'Exploration and evaluation of mineral resources', starts when the legal rights to explore have been obtained. Expenditure incurred before obtaining the legal right to explore is generally expensed; an exception to this would be separately acquired intangible assets such as payment for an option to obtain legal rights.

Expenditures incurred in exploration activities should be expensed unless they meet the definition of an asset. An entity recognises an asset when it is probable that economic benefits will flow to the entity as a result of the expenditure. The economic benefits might be available through commercial exploitation of hydrocarbon reserves or sales of exploration findings or further development rights. Exploration and evaluation ("E&E") assets are recognised within property, plant and equipment in single field cost centres.

The capitalisation point is the earlier of:

(a) the point at which the fair value less costs to sell of the property can be reliably determined as higher than the total of the expenses incurred and costs already capitalised (such as licence acquisition costs); and

(b) an assessment of the property demonstrates that commercially viable reserves are present and hence there are probable future economic benefits from the continued development and production of the resource.

E&E assets are reclassified from Exploration and Evaluation when evaluation procedures have been completed. E&E assets that are not commercially viable are written down. E&E assets for which commercially viable reserves have been identified are reclassified to Development and Production assets. E&E assets are tested for impairment immediately prior to reclassification out of E&E.

Once an E&E asset has been reclassified from E&E, it is subject to the normal IFRS requirements. This includes impairment testing at the cash-generating unit ("CGU") level and depreciation.

Abandonment and Retirement of Individual Items of Property, Plant and Equipment

Normally, no gains or losses shall be recognised if only an individual item of equipment is abandoned or retired or if only a single lease or other part of a group of proved properties constituting the amortisation base is abandoned or retired as long as the remainder of the property or group of properties constituting the amortisation base continues to produce oil or gas. Instead, the asset being abandoned or retired shall be deemed to be fully amortised, and its costs shall be charged to accumulated depreciation, depletion or amortisation. When the last well on an individual property (if that is the amortisation base) or group of properties (if amortisation is determined on the basis of an aggregation of properties with a common geological structure) ceases to produce and the entire property or group of properties is abandoned, a gain or loss shall be recognised. Occasionally, the partial abandonment or retirement of a proved property or group of proved properties or the abandonment or retirement of wells or related equipment or facilities may result from a catastrophic event or other major abnormality. In those cases, a loss shall be recognised at the time of abandonment or retirement.

Intangible Assets other than Oil and Gas Assets

Intangible assets other than oil and gas assets are stated at cost less accumulated amortisation and any provision for impairment. These assets represent exploration licences. Amortisation is charged so as to write off the cost, less estimated residual value on a straight-line basis of 20-25% per annum.

Depreciation, Depletion and Amortisation

All expenditure carried within each field is amortised from the commencement of commercial production on a unit of production basis, which is the ratio of gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field by field basis. In certain circumstances, fields within a single development area may be combined for depletion purposes. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs necessary to bring the reserves into production.

Impairment

At each balance sheet date, the Group reviews the carrying amount of oil and gas development and production assets to determine whether there is any indication that those assets have suffered an impairment loss. This includes exploration and appraisal costs capitalised which are assessed for impairment in accordance with IFRS 6. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss.

For oil and gas development and production assets, the recoverable amount is the greater of fair value less costs to dispose and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using an expected weighted average cost of capital. 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. Impairment losses are recognised as an expense immediately.

Should an impairment loss subsequently reverse, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset in prior years. A reversal of an impairment loss is recognised as income immediately.

Decommissioning Provision

Where a material liability for the removal of existing production facilities and site restoration at the end of the productive life of a field exists, a provision for decommissioning is recognised. The amount recognised is the present value of estimated future expenditure determined in accordance with local conditions and requirements. The cost of the relevant property, plant and equipment is increased with an amount equivalent to the provision and depreciated on a unit of production basis. Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated fixed asset. The unwinding of the discount on the decommissioning provision is included within finance costs.

Property, Plant and Equipment other than Oil and Gas Assets

Property, plant and equipment other than oil and gas assets (included in Other fixed assets in Note 17) are stated at cost less accumulated depreciation and any provision for impairment. Depreciation is charged so as to write off the cost of assets on a straight-line basis over their useful lives as follows:

Useful lives in years

Spare parts and equipment purchased with the intention to be used in future capital investment projects are recognised as oil and gas development and production assets within property, plant and equipment.

Inventories

Inventories typically consist of materials, spare parts and hydrocarbons, and are stated at the lower of cost and net realisable value. Cost of finished goods is determined on the weighted average bases. Cost of other than finished goods inventory is determined on the first in first out basis. Net realisable value represents the estimated selling price less all estimated costs of completion and costs to be incurred in marketing, selling and distribution.

Revenue Recognition

Revenue is income arising in the course of the Group's ordinary activities. Revenue is recognised in the amount of transaction price. Transaction price is the amount of consideration to which the Group expects to be entitled in exchange for transferring control over promised goods or services to a customer, excluding the amounts collected on behalf of third parties.

Revenue is recognised net of indirect taxes and excise duties.

Sales of gas, condensate and LPG are recognised when control of the good has transferred, being when the goods are delivered to the customer, the customer has full discretion over the goods, and there is no unfulfilled obligation that could affect the customer's acceptance of the goods. Delivery occurs when the goods have been shipped to the specific location, the risks of obsolescence and loss have been transferred to the customer, and either the customer has accepted the goods in accordance with the contract, the acceptance provisions have lapsed, or the Group has objective evidence that all criteria for acceptance have been satisfied.

A receivable is recognised when the goods are delivered as this is the point in time that the consideration is unconditional because only the passage of time is required before the payment is due.

The Group normally uses standardised contracts for the sale of gas, condensate and LPG, which define the point of control transfer. The price and quantity of each sale transaction are indicated in the specifications to the sales contracts.

The control over gas is transferred to a customer when the respective act of acceptance is signed by the parties to a contract upon delivery of gas to the point of sale specified in the contract, normally being a certain point in the Ukrainian gas transportation system. Acts of acceptance of gas are signed and the respective revenues are recognised on a monthly basis.

The control over condensate and LPG is transferred to a customer when the respective waybill is signed by the parties to a contract upon shipment of goods at the point of sale specified in the contract, which is normally the Group's production site.

Foreign Currencies

The Group's consolidated financial statements and those of the Company are presented in US Dollars. The functional currency of the subsidiaries which operate in Ukraine is Ukrainian Hryvnia. The remaining entities have US Dollars as their functional currency.

The functional currency of individual companies is determined by the primary economic environment in which the entity operates, normally the one in which it primarily generates and expends cash. In preparing the financial statements of the individual companies, 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 assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing on the balance sheet date. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the Income Statement. Non-monetary assets and liabilities carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Non-monetary items which are measured in terms of historical cost in a foreign currency are not retranslated. Gains and losses arising on retranslation are included in net profit or loss for the period, except for exchange differences arising on balances which are considered long term investments where the changes in fair value are recognised directly in other comprehensive income.

On consolidation, the assets and liabilities of the Group's subsidiaries which do not use US Dollars as their functional currency are translated into US Dollars as follows:

(a) assets and liabilities for each Balance Sheet presented are translated at the closing rate at the date of that Balance Sheet;

(b) income and expenses for each Income Statement are translated at average monthly exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of the transactions); and

(c) all resulting exchange differences are recognised in other comprehensive income.

The principal rates of exchange used for translating foreign currency balances at 31 December 2018 were $1:UAH27.7 (2017: $1:UAH28.1), $1:£0.8 (2017: $1:£0.7), $1:€0.9 (2017: $1:€0.8).

None of the Group's operations are considered to use the currency of a hyperinflationary economy, however this is kept under review.

Pensions

The Group contributes to a local government pension scheme in Ukraine and defined benefit plans. The Group has no further payment obligations towards the local government pension scheme once the contributions have been paid.

Defined benefit plans define an amount of pension benefit that an employee will receive on retirement, usually dependent on one or more factors such as age, years of service and compensation.

The Group companies participate in a mandatory Ukrainian State-defined retirement benefit plan, which provides for early pension benefits for employees working in certain workplaces with hazardous and unhealthy working conditions. The Group also provides lump sum benefits upon retirement subject to certain conditions. The early pension benefit (in the form of a monthly annuity) is payable by employers only until the employee has reached the statutory retirement age. The pension scheme is based on a benefit formula which depends on each individual member's average salary, his/her total length of past service and total length of past service at specific types of workplaces ("list II" category).

The liability recognised in the Balance Sheet in respect of defined benefit pension plans is the present value of the defined benefit obligation at the end of the reporting period less the fair value of plan assets. The defined benefit obligation is calculated annually by independent actuaries using the projected unit credit method. The present value of the defined benefit obligation is determined by discounting the estimated future cash outflows using interest rates of high-quality corporate bonds that are denominated in the currency in which the benefits will be paid, and that have terms to maturity approximating to the terms of the related pension obligation. Since Ukraine has no deep market in such bonds, the market rates on government bonds are used.

The current service cost of the defined benefit plan, recognised in the Income Statement in employee benefit expense, except where included in the cost of an asset, reflects the increase in the defined benefit obligation resulting from employee service in the current year, benefit changes curtailments and settlements. Past-service costs are recognised immediately in the Income Statement.

The net interest cost is calculated by applying the discount rate to the net balance of the defined benefit obligation and the fair value of plan assets. This cost is included in employee benefit expense in the Income Statement.

Actuarial gains and losses arising from experience adjustments and changes in actuarial assumptions are charged or credited to equity in other comprehensive income in the period in which they arise.

Leases

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases.

Rentals payable / receivable under operating leases are charged / credited to the Income Statement on a straight-line basis over the term of the relevant lease. Benefits received or given as an incentive to enter into an operating lease are also spread on a straight-line basis over the lease term.

Taxation

The tax expense represents the sum of the current tax and deferred tax.

Current tax, including UK corporation and overseas tax, is provided at amounts expected to be paid (or recovered) using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date.

Deferred tax is the tax expected to be payable or recoverable 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 goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the tax 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.

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

Other taxes which include recoverable value added tax, excise tax and custom duties represent the amounts receivable or payable to local tax authorities in the countries where the Group operates.

Financial Instruments

Financial instruments - key measurement terms. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The best evidence of fair value is the price in an active market. An active market is one in which transactions for the asset or liability take place with sufficient frequency and volume to provide pricing information on an ongoing basis.

Fair value of financial instruments traded in an active market is measured as the product of the quoted price for the individual asset or liability and the number of instruments held by the entity. This is the case even if a market's normal daily trading volume is not sufficient to absorb the quantity held and placing orders to sell the position in a single transaction might affect the quoted price.

A portfolio of financial derivatives or other financial assets and liabilities that are not traded in an active market is measured at the fair value of a group of financial assets and financial liabilities on the basis of the price that would be received to sell a net long position (i.e. an asset) for a particular risk exposure or paid to transfer a net short position (i.e. a liability) for a particular risk exposure in an orderly transaction between market participants at the measurement date. This is applicable for assets carried at fair value on a recurring basis if the Group: (a) manages the group of financial assets and financial liabilities on the basis of the Group's net exposure to a particular market risk (or risks) or to the credit risk of a particular counterparty in accordance with the Group's documented risk management or investment strategy; (b) it provides information on that basis about the group of assets and liabilities to the Group's key management personnel; and (c) the market risks, including duration of the Group's exposure to a particular market risk (or risks) arising from the financial assets and financial liabilities are substantially the same.

Valuation techniques such as discounted cash flow models or models based on recent arm's length transactions or consideration of financial data of the investees are used to measure fair value of certain financial instruments for which external market pricing information is not available. Fair value measurements are analysed by level in the fair value hierarchy as follows: (i) level one are measurements at quoted prices (unadjusted) in active markets for identical assets or liabilities, (ii) level two measurements are valuations techniques with all material inputs observable for the asset or liability, either directly (that is, as prices) or indirectly (that is, derived from prices), and (iii) level three measurements are valuations not based on solely observable market data (that is, the measurement requires significant unobservable inputs). Transfers between levels of the fair value hierarchy are deemed to have occurred

Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. An incremental cost is one that would not have been incurred if the transaction had not taken place. Transaction costs include fees and commissions paid to agents (including employees acting as selling agents), advisors, brokers and dealers, levies by regulatory agencies and securities exchanges, and transfer taxes and duties. Transaction costs do not include debt premiums or discounts, financing costs or internal administrative or holding costs.

Amortised cost ("AC") is the amount at which the financial instrument was recognised at initial recognition less any principal repayments, plus accrued interest, and for financial assets less any allowance for expected credit losses ("ECL"). Accrued interest includes amortisation of transaction costs deferred at initial recognition and of any premium or discount to the maturity amount using the effective interest method. Accrued interest income and accrued interest expense, including both accrued coupon and amortised discount or premium (including fees deferred at origination, if any), are not presented separately and are included in the carrying values of the related items in the consolidated statement of financial position.

The effective interest method is a method of allocating interest income or interest expense over the relevant period, so as to achieve a constant periodic rate of interest (effective interest rate) on the carrying amount. The effective interest rate is the rate that exactly discounts estimated future cash payments or receipts (excluding future credit losses) through the expected life of the financial instrument or a shorter period, if appropriate, to the gross carrying amount of the financial instrument. The effective interest rate discounts cash flows of variable interest instruments to the next interest repricing date, except for the premium or discount which reflects the credit spread over the floating rate specified in the instrument, or other variables that are not reset to market rates. Such premiums or discounts are amortised over the whole expected life of the instrument. The present value calculation includes all fees paid or received between parties to the contract that are an integral part of the effective interest rate. For assets that are purchased or originated credit impaired ("POCI") at initial recognition, the effective interest rate is adjusted for credit risk, i.e. it is calculated based on the expected cash flows on initial recognition instead of contractual payments.

Financial instruments - initial recognition. Financial instruments at fair value through profit or loss ("FVTPL") are initially recorded at fair value. All other financial instruments are initially recorded at fair value adjusted for transaction costs. Fair value at initial recognition is best evidenced by the transaction price. A gain or loss on initial recognition is only recorded if there is a difference between fair value and transaction price which can be evidenced by other observable current market transactions in the same instrument or by a valuation technique whose inputs include only data from observable markets. After the initial recognition, an ECL allowance is recognised for financial assets measured at AC and investments in debt instruments measured at fair value through other comprehensive income ("FVOCI"), resulting in an immediate accounting loss.

All purchases and sales of financial assets that require delivery within the time frame established by regulation or market convention ("regular way" purchases and sales) are recorded at trade date, which is the date on which the Group commits to deliver a financial asset. All other purchases are recognised when the entity becomes a party to the contractual provisions of the instrument.

Financial assets - classification and subsequent measurement - measurement categories. The Group classifies financial assets in the following measurement categories: FVTPL, FVOCI and AC. The classification and subsequent measurement of debt financial assets depends on: (i) the Group's business model for managing the related assets portfolio and (ii) the cash flow characteristics of the asset. The Group's financial assets include cash and cash equivalents, trade and other receivables, loans to subsidiary undertakings, all of which are classified as AC in accordance with IFRS 9.

 Financial assets - classification and subsequent measurement - business model.The business model reflects how the Group manages the assets in order to generate cash flows - whether the Group's objective is: (i) solely to collect the contractual cash flows from the assets ("hold to collect contractual cash flows",) or (ii) to collect both the contractual cash flows and the cash flows arising from the sale of assets ("hold to collect contractual cash flows and sell") or, if neither of (i) and (ii) is applicable, the financial assets are classified as part of "other" business model and measured at FVTPL.

Business model is determined for a group of assets (on a portfolio level) based on all relevant evidence about the activities that the Group undertakes to achieve the objective set out for the portfolio available at the date of the assessment. Factors considered by the Group in determining the business model include past experience on how the cash flows for the respective assets were collected.

The Group's business model for financial assets is to collect the contractual cash flows from the assets ("hold to collect contractual cash flows").

Financial assets - classification and subsequent measurement - cash flow characteristics. Where the business model is to hold assets to collect contractual cash flows or to hold contractual cash flows and sell, the Group assesses whether the cash flows represent solely payments of principal and interest ("SPPI"). Financial assets with embedded derivatives are considered in their entirety when determining whether their cash flows are consistent with the SPPI feature. In making this assessment, the Group considers whether the contractual cash flows are consistent with a basic lending arrangement, i.e. interest includes only consideration for credit risk, time value of money, other basic lending risks and profit margin.

Where the contractual terms introduce exposure to risk or volatility that is inconsistent with a basic lending arrangement, the financial asset is classified and measured at FVTPL. The SPPI assessment is performed on initial recognition of an asset and it is not subsequently reassessed.

Financial assets - reclassification. Financial instruments are reclassified only when the business model for managing the portfolio as a whole changes. The reclassification has a prospective effect and takes place from the beginning of the first reporting period that follows after the change in the business model. The Group did not change its business model during the current and comparative period and did not make any reclassifications.

Financial assets impairment - credit loss allowance for ECL. The Group assesses, on a forward-looking basis, the ECL for debt instruments measured at AC and FVOCI and for the exposures arising for contract assets. The Group measures ECL and recognises Net impairment losses on financial and contract assets at each reporting date. The measurement of ECL reflects: (i) an unbiased and probability weighted amount that is determined by evaluating a range of possible outcomes, (ii) time value of money and (iii) all reasonable and supportable information that is available without undue cost and effort at the end of each reporting period about past events, current conditions and forecasts of future conditions.

Debt instruments measured at AC and contract assets are presented in the consolidated statement of financial position net of the allowance for ECL. For loan commitments and financial guarantees, a separate provision for ECL is recognised as a liability in the consolidated statement of financial position.

The Group applies a three stage model for impairment, based on changes in credit quality since initial recognition. A financial instrument that is not credit-impaired on initial recognition is classified in Stage 1. Financial assets in Stage 1 have their ECL measured at an amount equal to the portion of lifetime ECL that results from default events possible within the next 12 months or until contractual maturity, if shorter ("12 Months ECL"). If the Group identifies a significant increase in credit risk ("SICR") since initial recognition, the asset is transferred to Stage 2 and its ECL is measured based on ECL on a lifetime basis, that is, up until contractual maturity but considering expected prepayments, if any ("Lifetime ECL"). If the Group determines that a financial asset is credit-impaired, the asset is transferred to Stage 3 and its ECL is measured as a Lifetime ECL. For financial assets that are purchased or originated credit-impaired ("POCI Assets"), the ECL is always measured as a Lifetime ECL.

Financial assets - write-off. Financial assets are written-off, in whole or in part, when the Group exhausted all practical recovery efforts and has concluded that there is no reasonable expectation of recovery. The write-off represents a derecognition event. The Group may write-off financial assets that are still subject to enforcement activity when the Group seeks to recover amounts that are contractually due, however, there is no reasonable expectation of recovery.

Financial assets - derecognition. The Group derecognises financial assets when (a) the assets are redeemed or the rights to cash flows from the assets otherwise expire or (b) the Group has transferred the rights to the cash flows from the financial assets or entered into a qualifying pass-through arrangement whilst (i) also transferring substantially all the risks and rewards of ownership of the assets or (ii) neither transferring nor retaining substantially all the risks and rewards of ownership but not retaining control.

Financial assets - modification. If the modified terms are substantially different, the rights to cash flows from the original asset expire and the Company derecognises the original financial asset and recognises a new asset at its fair value. The date of renegotiation is considered to be the date of initial recognition for subsequent impairment calculation purposes, including determining whether a SICR has occurred. Any difference between the carrying amount of the original asset derecognised and fair value of the new substantially modified asset is recognised in profit or loss, unless the substance of the difference is attributed to a capital transaction with owners. If the modified asset is not substantially different from the original asset and the modification does not result in derecognition. The Group recalculates the gross carrying amount by discounting the modified contractual cash flows by the original effective interest rate (or credit-adjusted effective interest rate for POCI financial assets), and recognises a modification gain or loss in profit or loss. 

Financial liabilities - measurement categories. Financial liabilities are classified as subsequently measured at AC, except for (i) financial liabilities at FVTPL: this classification is applied to derivatives, financial liabilities held for trading (e.g. short positions in securities), contingent consideration recognised by an acquirer in a business combination and other financial liabilities designated as such at initial recognition and (ii) financial guarantee contracts and loan commitments. The Group's financial liabilities include trade and other payables, all of which are classified as AC in accordance with IFRS 9.

Financial liabilities - derecognition. Financial liabilities are derecognised when they are extinguished (i.e. when the obligation specified in the contract is discharged, cancelled or expires).

Trade Receivables

Trade receivables are amounts due from customers for goods sold in the ordinary course of business. If collection is expected in one year or less, they are classified as current assets. If not, they are presented as non-current assets.

Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.

Investments in subsidiaries

Investments made by the Company in its subsidiaries are stated at cost in the Company's financial statements and reviewed for impairment if there are indications that the carrying value may not be recoverable.

Loans issued to subsidiaries

Loans issued by the Company to its subsidiaries are initially recognised in the Company's financial statements at fair value and are subsequently carried at amortised cost using the effective interest method, less credit loss allowance. Net change in credit losses and foreign exchange differences on loans issued are recognised in the Company's statement of profit or loss in the period when incurred.

Trade Payables

Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less. If not, they are presented as non-current liabilities.

Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.

Equity Instruments

Ordinary shares are classified as equity. Equity instruments issued by the Company and the Group are recorded at the proceeds received, net of direct issue costs. Any excess of the fair value of consideration received over the par value of shares issued is recorded as share premium in equity.

Cash and Cash Equivalents

Cash and cash equivalents comprise cash on hand and deposits held at call with banks and other short-term highly liquid investments which are readily convertible to a known amount of cash with no significant loss of interest. Cash and cash equivalents are carried at amortised cost. Interest income that relates to cash and cash equivalents on current and deposit accounts is disclosed within operating cash flow.

Other short-term investments

Other short-term investments include current accounts and deposits held at banks, which do not meet cash and cash equivalents definition. Current accounts and deposits held at banks, which do not meet cash and cash equivalents definition are measured initially at fair value and subsequently carried at amortised cost using the effective interest method. Interest received on other short-term investments is disclosed within operating cash flow.

The Group classifies its financial assets as at amortised cost only if both of the following criteria are met:

- The asset is held within a business model whose objective is to collect the contractual cash flows, and

- The contractual terms give rise to cash flows that are solely payments of principal and interest.

Interest income

Interest income is recognised as it accrues, taking into account the effective yield on the asset. Interest income on current bank accounts and on demand deposits or term deposits with the maturity less than three months recognised as part of cash and cash equivalents is recognised as other operating income. Interest income on term deposits other than those classified as cash and cash equivalents is recognised as finance income.

4. Critical Accounting Estimates and Judgments

The Group makes estimates and judgments concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and judgments which have a risk of causing material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

Recoverability of Oil and Gas 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 the 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 oil and gas 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 oil and gas development and production assets related to these fields. As such, as at 30 June 2018, the Group 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 17.

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 year ended 31 December 2018 in these 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 completed abandonment of the 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 year ended 31 December 2018.

VAS gas and condensate field

At 31 December 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 31 December 2018, and accordingly no impairment testing was required as at that date.

Depreciation of Oil and Gas Development and Production Assets

Oil and gas 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 oil and gas development and production assets. 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 $11,290,000 in depletion charge for the year 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 31 December 2018 was 8.14% (31 December 2017: 4.70%). 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 31 December 2018 resulted from the revision of the estimated costs of decommissioning (increase of $1,133,000 in provision), the increase in the discount rate applied (decrease of $1,003,000 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 $180,000 in provision). The increase in discount rate at 31 December 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 31 December 2018 would be $6,268,000 (31 December 2017: $2,613,000).

Net Carrying Amount of Inter-Company Loans Receivable by the Company from a Subsidiary

The Company has certain inter-company loans receivable from a subsidiary, which are eliminated on consolidation. For the purpose of the Company's financial statements, these receivable balances are carried at amortised cost using the effective interest method, less credit loss allowance. Measurement of lifetime expected credit losses on inter-company loans is a significant judgment that involves models and data inputs including forward-looking information, current conditions and forecasts of future conditions impacting the estimated future cash flows that are expected to be recovered, time value of money, etc. In previous years, significant impairment charges were recorded against the carrying amount of the loans issued to subsidiaries as the present value of estimated future cash flows discounted at the original effective interest rate was less than carrying amount of the loans, and the resulting impairment losses were recognised in profit or loss in the Company's financial statements.

For the purpose of assessment of the credit loss allowance as at 31 December 2018, the Company considered all reasonable and supportable forward looking information available as of that date without undue cost and effort, which includes a range of factors, such as estimated future net cash flows to be generated by the subsidiaries operating in Ukraine, upcoming planned changes in the Group's structure, cash flow management and planned debt structuring between Group entities. All these factors have significant impact on the amounts subject to repayment on the loans. The estimated future discounted cash flows generated by the subsidiaries operating in Ukraine, which are considered as a primary source of repayment on the loans, have significantly increased following the revision of the field development plan and reassessment of mineral reserves at the MEX-GOL and SV fields in 2018 as described above in this Note. For the purpose of this assessment, these cash flows were taken for a period of five years, as management believes there is no reasonably available information to build reliable expectations and demonstrate the ability to settle the loans in a longer perspective, especially in light of the anticipated changes in the Group's legal structure and reassignment of the loans to another subsidiary. As of 31 December 2018, the present value of future net cash flows to be generated by the subsidiaries operating in Ukraine during 2019 - 2023, adjusted for the subsidiaries' working capital as at 31 December 2018 and estimated amounts reserved by the Group for investment projects in the 5-years horizon was calculated. The resulting amount, net of the carrying value of the Company's investments in subsidiaries, was compared to the carrying value of the loans issued to subsidiaries as at 31 December 2018. As such, the Company has recorded $10,923,000 of gain, being the net change in credit loss allowance for loans issued to subsidiaries in the Company's statement of profit or loss for the year ended 31 December 2018.

As with any economic forecast, the projections and likelihoods of occurrence are subject to a high degree of inherent uncertainty, and therefore the actual outcomes may be significantly different to those projected. The Company considers these forecasts to represent its best estimate of the possible outcomes.

Exchange Differences on Intra-group Balances with Foreign Operations

As at 31 December 2017, a Group subsidiary, Regal Petroleum Corporation (Ukraine) Limited, planned to settle $6,000,000 of intra-group liability, of which $4,200,000 was settled in the period. A further amount of $9,000,000 (including $1,800,000 not paid during 2018) is planned to be settled by the end of 2019. As such, a foreign exchange difference of $488,000 accumulated on the intra-group balance of $13,200,000 since the date of de-designation of this balance as part of the Company's net investment in the foreign operation up to 31 December 2018 was recognised in profit or loss in these consolidated financial statements. No reclassification of the foreign exchange difference accumulated in equity prior to de-designation was made as there has been no change in the Company's proportionate ownership interest in the foreign operation and therefore no disposal or partial disposal of the foreign operation. There were no changes in management's plans or intentions regarding the payment of intra-group balances unsettled as at 31 December 2018, other than the above-mentioned amount of $9,000,000, and as such, a foreign exchange difference related to the balance designated as net investment in a foreign operation was recognised in other comprehensive income in the Company Statement of Comprehensive Income for the year ended 31 December 2018.

Recognition of Deferred Tax Asset

The recognition of deferred tax assets is based upon whether it is more likely than not that sufficient and suitable taxable profits will be available in the future against which the reversal of temporary differences can be deducted. This requires judgement for forecasting future profits. Further details of the deferred tax assets recognised can be found in Note 25.

5. 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 Group adopted IFRS 9, Financial Instruments, from 1 January 2018. The Group elected not to restate comparative figures and recognised any adjustments to the carrying amounts of financial assets and liabilities in the opening retained earnings as of the date of initial application of the standards, 1 January 2018.

The following table reconciles the carrying amounts of each class of financial assets as previously measured in accordance with IAS 39 and the new amounts determined upon adoption of IFRS 9 on 1 January 2018.

*L&R - Loans and receivables

**AC - Amortised cost

***ECL - Expected credit losses

*L&R - Loans and receivables

**AC - Amortised cost

The Group has two types of financial assets that are subject to IFRS 9's new expected credit loss ("ECL") 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.

The lifetime expected credit loss for loans issued to subsidiaries is based on a forward-looking information, reflects the amount that is considered to be the most probable outcome to be recovered, takes into account current conditions, forecasts of future conditions and time value of money

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 decreased by a further $53,000 to $99,000 for trade and other receivables during 2018.

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 $5,000 in 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.

6. 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, budget 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.

*Comprises additions to property, plant and equipment (Note 17)

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. Revenue is recognised at a point in time.

During 2017-2018, the Group sold 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 V Novynskyi, 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 the last two 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 current 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, with the intention to achieve higher sales prices due to the larger sales volumes. In order to cover Smart Energy's sales, administration and regulatory compliance costs, the Group has agreed to sell 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.

*Comprises additions to property, plant and equipment (Note 17)

7. Cost of Sales

The increase in production taxes in 2018 is mainly represented by the increase in the volume of production on existing wells and the introduction of the new wells, MEX-109 and VAS-10, and the leased well, SV-12.

As described in Note 4, 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.

8. Administrative Expenses

All amounts shown as auditors' remuneration in 2018 and 2017 were payable to the Group auditors, PricewaterhouseCoopers LLP and other member firms of PricewaterhouseCoopers LLP.

9. Remuneration of Directors

The emoluments of the individual Directors were as follows:

Sergii Glazunov was appointed as Chief Executive Officer in August 2017, and is paid $252,000 per annum. During the 2018 year, he was also paid a bonus of $124,000.

Philip Frank stepped down as Non-Executive Director in September 2018. He was paid £45,000 per annum for the period from January 2018 to September 2018.

Dmitry Sazonenko was appointed as Non-Executive Director in September 2018, and is paid £45,000 per annum.

The emoluments include base salary, bonuses and fees. According to the Register of Directors' Interests, no rights to subscribe for shares in or debentures of the Group companies were granted to any of the Directors or their immediate families during the financial year, and there were no outstanding options to Directors.

10. Staff Numbers and Costs

The average monthly number of employees on a full time equivalent basis during the year (including Executive Directors) was as follows:

The aggregate staff costs of these employees were as follows:

11. Other operating gains, (net)

12. Finance Income

During 2018, the Group recorded interest income of $153,000 (2017: $32,000) from placement of cash on long-term deposit accounts and recognised foreign exchange gains less losses of $488,000 (2017: $351,000).

13. Finance Costs

During 2018, the Group recorded an unwinding of a discount on provision for decommissioning of $140,000 (2017: $112,000) (Note 23).

14. Income tax expense

a) Income tax expense and (benefit):

b) Factors affecting tax charge for the year:

The tax assessed for the year is different from the blended rate of corporation tax in the UK of 19.00%. The expense for the year can be reconciled to the profit as per the Income Statement as follows:

The tax effect of disallowed expenses and non-taxable income are mainly represented by foreign exchange differences of Regal Petroleum Corporation (Ukraine) Limited.

The tax effect losses not recognised as deferred tax assets are mainly represented by accumulated losses of Regal Petroleum Corporation (Ukraine) Limited.

15. Profit for the Year

The Company has taken advantage of the exemption allowed under section 408 of the Companies Act 2006 and has not presented its own Income Statement in these financial statements. The Group profit for the year includes Parent Company profit after tax of $12,057,000 for the year ended 31 December 2018 (2017: $12,239,000).

16. Earnings per Share

The calculation of basic profit per ordinary share has been based on the profit for the year and 320,637,836 (2017: 320,637,836) ordinary shares, being the weighted average number of shares in issue for the year. There are no dilutive instruments.

17. Property, Plant and Equipment

MEX-GOL and SV gas and condensate fields

As described in Note 4, as at 30 June 2018, the Group determined the recoverable amount of its oil and gas development and production 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 in 2018.

The key assumptions on which the Group has based its determination of FVLCD for its oil and gas development and production 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 was 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 report, 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 4, the Group has also recorded a $1,648,000 impairment loss on an individual basis in respect of the SV-69 well in 2018.

Notwithstanding the reversal of impairment recorded at 30 June 2018, at 31 December 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 31 December 2018, and accordingly no impairment testing was required as at that date.

During the 2018 year, the SV-69 well was abandoned, and was fully depreciated and its cost of $6,328,000 was charged to accumulated depreciation and impairment.

VAS gas and condensate fields

At 31 December 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 31 December 2018, and accordingly no impairment testing was required as at that date.

During the 2018 year, the Group commenced acquisition of new 3D seismic over the VAS field which will assist in the evaluation of the VAS licence, and particularly the VED area of the licence. Since no commercially viable reserves have been identified in the VED area as yet, the costs of the seismic over this area were capitalised within property, plant and equipment as exploration and evaluation assets.

18. Intangible Assets