RPT.L Regulatory News (RPT)

3 April 2018

REGAL PETROLEUM PLC

2017 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 2017.

Highlights

Ukraine Operations

Finance

Outlook

The Annual Report and Financial Statements for 2017, together with the Notice of Annual General Meeting, will be posted to shareholders and published on the Company's website during May 2018.

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

For further information, please contact:

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

Chairman's Statement

I am pleased to introduce the 2017 Audited Results. During 2017, the Group has made very promising progress in the development of its MEX-GOL, SV and VAS gas and condensate fields in north-eastern Ukraine, with significant improvements in production rates, leading to a much improved financial performance.

At the Group's MEX-GOL and SV fields, production was reasonably stable during the first half of 2017, but in June 2017, the new MEX-109 well, utilising improved drilling and completion techniques developed as a result of recent studies, was completed successfully and put on production, and in August 2017, following completion of its workover, the SV-2 well was also put on production. Together, these successes have nearly doubled output from the MEX-GOL-SV licence areas. In addition, the VAS field has continued to produce consistently during the year. With the improved contribution from the new wells on the MEX-GOL and SV fields, aggregate production at the end of 2017 from all fields was approximately 2,800 boepd. This compares with an aggregate production rate of approximately 1,700 boepd at the end of 2016, which represents an increase of nearly 65% over the year.

The fiscal and economic situation in Ukraine continues to improve, with a better economic outlook, GDP growth and improved stability in the Ukrainian Hryvnia exchange rates, although the inflation rate did increase moderately. Nevertheless, there continue to be stresses in the economy and weaknesses in the Ukrainian banking sector.

The Ukrainian Government has implemented a number of reforms in the oil and gas industry 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 proposed 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 2017, gas prices were reasonably stable, allowing for some seasonal variation, and were higher than in 2016. Furthermore, condensate and LPG prices were also higher by comparison with last year.

As regards the Group's financial performance in the year ended 31 December 2017, I am pleased to report that the Group made a profit of $2.3 million (2016: $1.3 million loss), mainly as a result of improved revenues from higher production volumes and hydrocarbon prices. Cash generated from operations during the year was higher at $18.0 million (2016: $10.0 million).

Board and Management Changes

During the year, there were significant changes to the management and Board of Directors of the Company. With effect from the start of August 2017, Sergii Glazunov became Chief Executive Officer, having previously been Finance Director, and Yevhen (Gene) Palyenka was appointed Chief Financial Officer. Later in August 2017, Bruce Burrows joined the Board as Non-Executive Director, and Adrian Coates stepped down from the Board at the same time.

I joined the Board as Non-Executive Director in September 2017, and was appointed Non-Executive Chairman in October 2017. At the same time, Phil Frank joined the Board as Non-Executive Director, and Keith Henry and Alastair Graham stepped down from the Board. On behalf of the Board, I would like to thank each of Keith, Alastair and Adrian for their valued contributions during their respective tenures with the Company.

Outlook

Whilst there are still challenges in the business environment in Ukraine, the situation is improving and the Group is continuing to progress the development of its Ukrainian fields. After the operational successes of 2017 and the increased production output during the year, we are looking forward to achieving further successes in the development activities planned for 2018 and delivering a steadily increasing production and revenue stream in the future.

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

Chris Hopkinson

Chairman

Chief Executive Officer's Statement

Introduction

The Group has made good progress at its Ukrainian fields during 2017, with the increase in development activity at the MEX-GOL and SV fields resulting in the successes of the MEX-109 well, which came on production in June 2017, and the SV-2 well, which came on production in August 2017, providing a significant boost to production rates.

During the year, the Group continued its work on the subsurface of the MEX-GOL and SV fields, utilising the results of P.D.F Limited's comprehensive re-evaluation study to plan additional development of these fields. This work included detailed reprocessing of the existing 3D seismic data, using the latest processing technology, with the reprocessed data now under interpretation. As well as the drilling of the MEX-109 well and the workover of the SV-2 well, the Group undertook workover operations on the GOL-2 and SV-6 wells during the year to eliminate water ingress into the wells, but these operations were not successful and the Group is currently considering further remedial work on these wells. In addition, the Group installed additional compression equipment, 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 over the field and the drilling of the VAS-10 well, both of which activities commenced in early 2018.

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 2017, a total of 448,618 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 1,444,850 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 2017 was 197,961 m³/d of gas, 47 m³/d of condensate and 24 m³/d of LPG (1,629 boepd in aggregate) (2016: 157,228 m3/d of gas, 41 m3/d of condensate and 19 m³/d of LPG (1,321 boepd in aggregate). Production rates improved significantly following the commencement of production from the MEX-109 well in June 2017 and the SV-2 well in August 2017.

Average daily production of gas and condensate from the VAS field for the year ended 31 December 2017 was 86,242 m3/d of gas and 6.5 m3/d of condensate (608 boepd in aggregate) (Period from 4 July 2016 to 31 December 2016: 82,624 m3/d of gas and 6.5 m3/d of condensate (556 boepd in aggregate)), contributing material volumes to the Group's production output.

The Group's average production for the period from 1 January 2018 to 28 March 2018 from the MEX-GOL and SV field was 272,656 m³/d of gas, 53 m³/d of condensate and 32 m³/d of LPG (2,169 boepd in aggregate) and from the VAS field was 86,214 m³/d of gas and 6.2 m³/d of condensate (606 boepd in aggregate).

Operations

The improving geopolitical situation in Ukraine, coupled with the stabilisation of the Ukrainian Hryvnia, the higher hydrocarbon prices and improvements in the fiscal and economic situation over the last year, meant that the Group was able to increase the development programme at its Ukrainian fields during 2017.

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 detailed reprocessing of existing 3D seismic data, using the latest processing technology, to try to improve the definition in such data. Interpretation of this new dataset is underway, with the intention of utilising it to refine the new geological subsurface model of the fields. This work, undertaken in conjunction with P.D.F. Limited, will enable 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.

The MEX-109 well, which was spudded in July 2016, targeted the Visean reservoirs ("B-Sands") in the MEX-GOL field. The well was drilled to a depth of 4,873 metres, and completed in the B-20 Visean reservoir. It was brought on production in June 2017. The initial production rates were very encouraging and the well has been producing consistently in excess of 90,000 m3/d since then.

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, if successful, would result in the well being brought back into production. Pursuant to the agreement, the gas and condensate produced from the well is to be sold under an equal net profit sharing arrangement between the Group and NJSC Ukrnafta. The workover operations were successful and production from the well recommenced in August 2017, providing a further significant boost to production volumes.

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 the new 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. Investigative work has been undertaken to ascertain the condition of the well and preparations for workover operations on the well are underway. It is anticipated that the workover operations will be concluded during the fourth quarter of 2018.

The Group also undertook workover operations on the GOL-2 and SV-6 wells during the year to eliminate water ingress into the wells. Although these operations were successful in preventing the water ingress, the wells did not return to production and are now under observation. The Group is currently considering further remedial work on these wells. In addition at the MEX-GOL and SV fields, the Group installed additional compression equipment, upgraded the gas processing facilities and pipeline network, and undertook remedial work on existing wells.

At the VAS field, during 2017, planning work took place for the acquisition of new 3D seismic data over the field and the drilling of the VAS-10 well. The acquisition of the 3D seismic will shortly be completed and thereafter the data will be processed and interpreted.

The VAS-10 well was spudded on 13 March 2018, with a planned depth of 3,450 metres. The well is designed to appraise horizons in the Visean formation, and to evaluate the western edge of field, at an offset of approximately 1 km from the nearest currently producing well. The drilling operations are scheduled to be completed in June 2018 and, subject to successful testing, production hook-up is anticipated during the third quarter of 2018.

Outlook

During 2018, the Group is continuing 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, concluding the workover of the SV-12 well, planning for a new development well, investigating workover opportunities for other existing wells, installation of additional compression equipment, further upgrading of the gas processing facilities and pipeline network, and remedial work on existing wells, pipelines and other infrastructure.

At the VAS field, the work on processing and interpreting the new 3D seismic data will continue, as will the drilling of the VAS-10 well. In addition, consideration and planning for a further appraisal/development well will be undertaken. It is also intended to undertake further evaluation of the VED area of the licence, which appears highly prospective on the current 2D seismic data and will benefit from the improved imaging of the new 3D seismic data. Work is also planned to upgrade the gas processing facilities, pipeline network and other infrastructure.

It is also intended to commission updated assessments of the remaining reserves and resources at each of the MEX-GOL and SV fields and the VAS field, which will be undertaken by an independent petroleum reserves consultant later in 2018. The extensive re-evaluation of the MEX-GOL and SV fields by P.D.F. Limited, the interpretation work being undertaken on the reprocessed 3D seismic dataset and the ongoing revision of the geological model, means that the Group considers that now is an appropriate time to undertake a reassessment of the remaining reserves and resources at the MEX-GOL and SV fields, and this reassessment is planned to be undertaken during the first half of 2018. Similarly, the interpretation of the newly acquired 3D seismic and associated subsurface studies, together with the data collected from the VAS-10 well at the VAS field, means that a reassessment of the remaining reserves and resources at the VAS field will also be appropriate by the end of 2018.

There has also been encouraging new legislation relating to the oil and gas sector in Ukraine, which demonstrates the Ukrainian Government's stated intention to promote and support the domestic oil and gas production industry. These new measures include reductions in the subsoil taxes applicable to the production of hydrocarbons, which became effective for new wells from 1 January 2018 and for condensate production from 1 January 2019. Furthermore, there is newly announced legislation to simplify a number of the regulatory procedures relating to oil and gas exploration and production activities in Ukraine, which, has passed through the Ukrainian Parliament and is now awaiting the signature of the President of Ukraine to bring it into law.

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

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

Sergii Glazunov

Chief Executive Officer

Overview of Assets and Reserves

Assets

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.

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

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, ERC Equipoise Limited ("ERCE"), as at 31 December 2013 (the "ERCE Report"), which was announced on 25 March 2014. During the period from 1 January 2014 to 31 December 2017, the Group has produced 2.04 MMboe from these fields.

The ERCE Report estimated the remaining Reserves as at 31 December 2013 in the Visean B-Sands reservoirs of the MEX-GOL and SV fields, based on the drilling of ten further wells, as follows:-

The ERCE Report estimated the Contingent Resources in the Visean B-Sands reservoirs of the MEX-GOL and SV fields as follows, based on the potential drilling of up to 113 future wells (not currently budgeted):-

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 in connection with the Group's acquisition of PEP. During the period from 1 January 2016 to 31 December 2017, 0.4 MMboe were produced from the field.

The Senergy Report estimates the remaining Reserves as at 1 January 2016 in the VAS field, based on the drilling of one further well, as follows:-

The Senergy Report estimates the Contingent Resources as at 1 January 2016 in the VAS field, based on the drilling of an additional further well, as follows:-

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

Finance Review

The Group made a profit of $2.3 million (2016: $1.3 million loss) during the year ended 31 December 2017, mainly as a result of improved revenue from higher production volumes and hydrocarbon prices. Revenue in the year, derived from the sale of the Group's Ukrainian gas, condensate and LPG production, was higher at $35.1 million (2016: $25.7 million).

Cash generated from operations during the year increased to $18.0 million (2016: $10.0 million), as a result of higher production volumes and hydrocarbon prices.

For the year ended 31 December 2017, the average realised gas, condensate and LPG prices were $241/Mm3 (UAH6,412/Mm3), $67/bbl and $56/bbl respectively (2016: $213/Mm3 (UAH5,441/Mm3) gas, $51/bbl condensate and $43/bbl LPG).

During the period from 1 January 2018 to 28 March 2018, the average realised gas, condensate and LPG prices were $277/Mm3 (UAH7,574/Mm3), $70/bbl and $55/bbl respectively. The current realised gas price is $265/Mm3 (UAH6,972/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 2017 year, gas prices were reasonably stable, allowing for some seasonal variation, and were higher than in 2016, as were condensate and LPG prices by comparison with 2016.

In the first half of 2017, the Group commenced selling all of its gas production to LLC Smart Energy ("Smart Energy"), which is part of the PJSC Smart-Holding Group, which is ultimately controlled by Mr Vadim Novinskiy, who, through an indirect 54% majority shareholding, ultimately controls the Group. This arrangement came about as a consequence of the introduction of a number of new taxation regulations in Ukraine, which significantly increased the regulatory burden on affected companies. 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. As a result, the new tax regulations impose additional regulatory obligations on the Group's potential customers, who may be less inclined to purchase the Group's gas and/or may seek discounts on sales prices. In light of this situation, the Group and Smart Energy reached an agreement under which Smart Energy will purchase all of the Group's gas production and assume responsibility for the regulatory obligations under the Ukrainian tax regulations, as well as combining the Group's gas production with Smart Energy's own gas production so as to sell such gas as combined volumes, which should result in higher sales prices due to the larger sales volumes. In order to cover Smart Energy's sales, administration and regulatory compliance costs, the Group sells its gas to Smart Energy at a small discount to the gas sales prices achieved by Smart Energy, who sell the combined volumes in line with market prices. The terms of sale, effective from June 2017, for the Group's gas to Smart Energy are (i) payment for one third of the estimated monthly volume of gas by the 20th of the month of delivery, and (ii) payment of the remaining balance by the 10th of the month following the month of delivery. As a consequence of their common ultimate control, the Company and Smart Energy are deemed to be related parties under the AIM Rules for Companies, and more details of this arrangement are set out in the announcement made on 30 June 2017, as well as in Note 5 and 32 below.

The subsoil taxes 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, in December 2017, the Ukrainian Government passed new legislation under which (i) for new wells drilled after 1 January 2018, the subsoil tax rates will be 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, and (ii) with effect from 1 January 2019 and applicable to all wells, the subsoil tax rates for condensate will be reduced from 45% to 29% for condensate produced from deposits above 5,000 metres and from 21% to 14% for condensate produced from deposits below 5,000 metres.

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

Cost of sales for the year ended 31 December 2017 was higher at $24.3 million (2016: $18.6 million), mainly due to the inclusion of a full year of the cost of sales of hydrocarbons from the VAS field of $5.7 million (Period from 4 July 2016 to 31 December 2016: $2.6 million).

Administrative expenses for the year were higher at $5.3 million (2016: $4.7 million), primarily as a result of the inclusion of administrative expenses relating to LLC Prom-Enerho Produkt ("PEP"), the owner of the VAS field, of $0.4 million (Period from 4 July 2016 to 31 December 2016: $0.1 million) and staff termination compensation of $0.2 million (2016:nil).

The tax charge for the year of $4.3 million (2016: $4.1 million charge) comprises a current tax charge of $3.0 million (2016: $1.9 million) and a deferred tax charge of $1.3 million (2016: $2.2 million charge).

The Group has recognised a deferred tax asset of $9.3 million at 31 December 2017 (31 December 2016: $11.1 million). This comprises a deferred tax asset of $2.6 million (31 December 2016: $3.7 million) in relation to UK tax losses carried forward, and $6.7 million (31 December 2016: $7.4 million) relating to the Group's MEX-GOL and SV asset and the provision for decommissioning in Ukraine, which is recognised on the tax effect of temporary timing differences between the carrying value of such asset and its tax base. The reduction in the deferred tax asset in 2017 is primarily due to a decrease of forecasted taxable income for the following five years caused by partial settlement of intra-group loans receivable by the Company. The Group has also recognised a deferred tax liability of $0.8 million at 31 December 2017 (31 December 2016: $1.2 million liability) relating to the Group's VAS asset in Ukraine, which is recognised on the tax effect of temporary timing differences between the carrying value of such asset and its tax base, mainly due to revaluation of the VAS asset at the date of acquisition by the Group.

Capital investment of $4.0 million reflects investment in the Group's oil and gas development and production assets during the period (2016: $13.9 million), primarily a continuation of the expenditure associated with the drilling of the MEX-109 well.

Under the agreement between the Group and NJSC Ukrnafta relating to the SV-2 well, which was a suspended well owned by NJSC Ukrnafta located within the Group's SV licence area, the Group agreed to carry out a workover of the well and, if successful, to operate, produce and sell the gas and condensate from the well under an equal net profit sharing arrangement with NJSC Ukrnafta. The workover was successful and production from this well commenced in August 2017.

Cash and cash equivalents held at 31 December 2017 were $14.2 million and short-term investments were $16.0 million (31 December 2016: $20.0 million and nil respectively). The Group's cash and cash equivalents balance at 28 March 2018 was $20.3 million, held as to $13.5 million equivalent in Ukrainian Hryvnia and the balance of $6.8 million equivalent predominantly in US Dollars and Pounds Sterling. The Group's other short-term investments at 28 March 2018 were $16.0 million.

Since early 2014, the Ukrainian Hryvnia has devalued significantly against the US Dollar, falling from UAH8.3/$1.00 on 1 January 2014 to UAH28.1/$1.00 on 31 December 2017, 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 2017, the exchange rate between the Ukrainian Hryvnia and the US Dollar has been reasonably stable averaging UAH26.6/$1.00 during the period (average rate during 2016: UAH 27.0/$1.00). Nevertheless, further devaluation of the Ukrainian Hryvnia against the US Dollar may affect the carrying value of the Group's assets in the future.

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

The Group manages its revenue, cash from operations and production volumes as key performance indicators. The achieved results for 2017 were as follows:

Yevhen Palyenka

Chief Financial Officer

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

for the year ended 31 December 2017

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

Company Statement of Comprehensive Income

for the year ended 31 December 2017

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

Consolidated Balance Sheet

at 31 December 2017

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

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

Consolidated Cash Flow Statement

for the year ended 31 December 2017

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

Notes forming part of the financial statements

The financial information set out above does not constitute the Company's statutory accounts for the year ended 31 December 2017 or 2016, 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 2017 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 2018.

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

The Company is a company quoted on the AIM Market of London Stock Exchange plc and incorporated in England and Wales under the Companies Act 2006. The Company's registered office is at 16 Old Queen Street, London SW1H 9HP, United Kingdom and its registered number is 4462555. The principal activities of the Group and the nature of the Group's operations are set out earlier in this announcement.

As of 31 December 2017 and 2016 the Company's immediate parent company was Energees Management Limited, which is 100% owned by Pelidona Services Limited, which is 100% owned by Lovitia Investments Ltd, which is 100% owned by Mr V Novinskiy. Accordingly, the Company was ultimately controlled by Mr V Novinskiy.

The Group's gas, condensate and LPG extraction and production facilities are located in Ukraine. The ongoing political and economic instability in Ukraine, which commenced 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 and has continued in 2017, though to a lesser extent as compared to 2014-2016.

The inflation rate in Ukraine during 2017 increased to 14% (as compared to 12% in 2016).

Devaluation of the Ukrainian Hryvnia during 2017 has been moderate. As at 29 March 2018, the official exchange rate of the Ukrainian Hryvnia against the US Dollar was UAH26.4/$1.00, compared to UAH28.1/$1.00 as at 31 December 2017 (31 December 2016: UAH27.2/$1.00).

In 2017, there was a further easing of the currency control restrictions that were introduced by the National Bank of Ukraine during 2014 - 2015. In particular, the required share of foreign currency for mandatory sale was decreased from 65% to 50% from 4 April 2017, and the settlement period for export-import transactions in foreign currency was increased from 120 to 180 days from 26 May 2017. In addition, from 13 June 2016, Ukrainian companies were permitted to pay dividends to non-residents with a limit of $5 million per month.

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

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 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 financial statements are prepared on the historical cost basis as modified by the initial recognition of subsidiary acquisition and financial instruments based on fair value.

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 this announcement, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future regarded as at least 12 months after the date of signing of these financial statements.Accordingly,the going concern basis has been adopted in preparing its consolidated financial statements for the year ended 31 December 2017. 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 this announcement.

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 2017. These improvements relate to the following areas:

The adoption of these amendments had no significant impact on these financial statements.

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 2017 reporting periods and have not been early adopted by the Group. The Group's assessment of the impact of these new standards and interpretations is set out below:

The Group has decided not to adopt IFRS 9 until it becomes mandatory on 1 January 2018. The Group does not expect the new guidance to have a significant impact on the classification and measurement of its financial assets and liabilities.

The following table reconciles the carrying amounts of financial assets, from their previous measurement categories in accordance with IAS 39 into their new measurement categories upon transition to IFRS 9 on 1 January 2018:

*L&R - Loans and receivables

**AC - Amortised cost

*L&R - Loans and receivables

**AC - Amortised cost

The new standard also introduces expanded disclosure requirements and changes in presentation. Management of the Group does not expect a significant impact on its consolidated financial statements effected by implementation of IFRS 9 on 1 January 2018.

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 IAS 39 either in profit or loss or as a change to other comprehensive income. Contingent consideration that is classified as equity is not re-measured, and its subsequent settlement is accounted for within equity.

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. The proved and probable reserves conform to the definition approved by the Petroleum Resources Management System.

Oil and Gas Development and Producing 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".

All licence acquisition, exploration and evaluation costs are initially capitalised as intangible assets in cost centres by field or by exploration area, as appropriate, pending determination of commerciality of the relevant property. Directly attributable administration costs are capitalised insofar as they relate to specific exploration activities, as are finance costs to the extent they are directly attributable to financing development projects. Pre-licence costs and general exploration costs not specific to any particular licence or prospect are expensed as incurred.

If prospects are deemed to be impaired ('unsuccessful') on completion of the evaluation, the associated costs are charged to the Income Statement. If the field is determined to be commercially viable, the attributable costs are transferred to development / producing assets within property, plant and equipment in single field cost centres.

Subsequent expenditure is capitalised only where it either enhances the economic benefits of the development / producing asset or replaces part of the existing development / producing asset.

Net proceeds from any disposal of an exploration asset are initially credited against the previously capitalised costs. Any surplus proceeds are credited to the Income Statement. Net proceeds from any disposal of development / producing assets are credited against the previously capitalised cost. Gains and losses on disposals of development / producing assets are determined by comparing proceeds from sale with the appropriate portion of the net capitalised costs of the asset and are recognised in the Income Statement for the year.

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 development and producing 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 development / producing 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 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:

Spare parts and equipment purchased with the intention to be used in future capital investment projects are recognised as 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 from sale of goods represents amounts invoiced in respect of sales of gas, condensate and LPG exclusive of indirect taxes and excise duties and is recognised at the point of transfer of risks and rewards of ownership of the goods, normally when the goods are shipped. To the extent that revenue arises from test production during an evaluation programme, an amount is charged from intangible exploration assets to cost of sales so as to reflect a zero net margin.

Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount.

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:

The principal rates of exchange used for translating foreign currency balances at 31 December 2017 were $1:UAH28.1 (2016: $1:UAH27.2), $1:£0.7 (2016: $1:£0.8), $1:€0.8 (2016: $1:€0.9).

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.

In October 2017 there were certain changes introduced to the Law of Ukraine on Mandatory State Pension Insurance:

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 substantially 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, sales tax and custom duties represent the amounts receivable or payable to local tax authorities in the countries where the Group operates.

Financial Instruments

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

The Group classifies its financial assets as loans and receivables. The classification depends on the purpose for which the financial assets were acquired. Management determines the classification of its financial assets at initial recognition.

The Group does not currently utilise derivative financial instruments.

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, less provision for impairment.

The Group assesses at the end of each reporting period whether there is objective evidence that a financial asset or group of financial assets is impaired. A financial asset or a group of financial assets is impaired and impairment losses are incurred only if there is objective evidence of impairment as a result of one or more events that occurred after the initial recognition of the asset (a 'loss event') and that loss event (or events) has an impact on the estimated future cash flows of the financial asset or group of financial assets that can be reliably estimated.

For the financial assets carried at amortised cost the evidence of impairment may include indications that the debtors or a group of debtors is experiencing significant financial difficulty, default or delinquency in interest or principal payments, the probability that they will enter bankruptcy or other financial reorganisation, and where observable data indicate that there is a measurable decrease in the estimated future cash flows, such as changes in arrears or economic conditions that correlate with defaults.

For loans and receivables category, the amount of the loss is measured as the difference between the asset's carrying amount and the present value of estimated future cash flows (excluding future credit losses that have not been incurred) discounted at the financial asset's original effective interest rate. The carrying amount of the asset is reduced and the amount of the loss is recognised in the consolidated Income Statement.

If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised (such as an improvement in the debtor's credit rating), the reversal of the previously recognised impairment loss is recognised in the consolidated Income Statement.

Investments and loans to subsidiaries

Investments in subsidiaries and loans issued to subsidiaries for subsequent finance of the business are stated at cost and reviewed for impairment if there are indications that the carrying value may not be recoverable.

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.

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

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 is compared to its recoverable amount. In previous years, management had assessed value in use, using a discounted cash flow model to measure its recoverable amount. The cash flows in the model were projected in real terms, i.e. they did not take into account the impact on cash flows of the estimated commodity price index during the period of projection. The discount rate was adjusted accordingly and represented a real terms discount rate. No impairment loss was recognised as a result of the assessment as at 31 December 2016. In the current year, no impairment indicators were identified, due to a favourable change in the Group's performance and the economic environment in Ukraine, and therefore, no impairment test was required. In addition, the Group considered if there were any triggers to reverse any previously recognised impairment and concluded that there was insufficient information to be able to do so. The Group is currently undertaking certain projects with the purpose of refining its field development strategy, including the required capital expenditure, and the re-assessment of its mineral reserves. The information that will be obtained from these projects is expected to enable the Group to determine the need for any re-assessment of the carrying value of its oil and gas assets.

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 impaired if the present value of estimated future cash flows (excluding future credit losses that have not been incurred) discounted at the original effective interest rate is less than the asset's carrying amount, and the resulting impairment loss is recognised in profit or loss in the Company's financial statements. In previous years, impairment charges were recognised against the cumulative balance of the loans issued to subsidiaries based on an analysis of their recoverability. During 2017, the Company received $12,450,000 in repayment of loans receivable from its subsidiaries, including $6,360,000 of interest accrued, which had been impaired in the prior year. In light of this repayment, the provision related to the interest was reversed in the amount repaid. In addition, the Company considered if there were any triggers to reverse any additional previously recognised impairment and concluded that there was insufficient information to be able to do so. The Group is currently undertaking certain projects with the purpose of refining its field development strategy, including the required capital expenditure, and the re-assessment of its mineral reserves. The information that will be obtained from these projects is expected to enable the Company to determine the need for any re-assessment of the carrying value of its inter-company loans.

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 2017 was 4.7% (31 December 2016: 6.11%). 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 during 2017 reflects a combination of a revision in the estimated costs (increase of $559,000) and the discount rate applied (increase of $421,000).

The decommissioning costs are estimated to be incurred by June 2036 on the MEX-GOL and SV gas and condensate fields, which is the current estimated end of the economic life of the fields, and by 2024 on the VAS gas and condensate field. Management believes that the current licences for the MEX-GOL and SV gas and condensate fields, which are due to expire in July 2024, will be extended until June 2036.

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 and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions about the number of wells required to produce those reserves, the cost of the wells, future production facilities and operating costs, together with assumptions on oil and gas realisations, and are revised annually. The reserves estimates used are determined using estimates of gas in place, recovery factors, future hydrocarbon prices and also take into consideration the Group's latest development plan for the associated development and production asset. Additionally, the latest development plan and therefore the inputs used to determine the depreciation charge, assume that the current licences for the MEX-GOL and SV gas and condensate fields which are due to expire in July 2024, can be extended until June 2036.

The Group is currently undertaking certain projects on the MEX-GOL and SV fields with the purpose of refining its field development strategy, including the required capital expenditure, and the re-assessment of its mineral reserves. These projects include the interpretation of a reprocessed 3D seismic dataset, further analysis of technical and economic data, and ongoing revision of the geological model. The information that will be obtained from these projects is to be used in a re-assessment of the remaining reserves and resources at these fields, which is planned to be completed in the middle of 2018.

The majority of the Group's materials and spare parts inventory balance comprises items to be used in the Ukraine drilling programme. Where there is uncertainty whether these items will be realised through the drilling programme, or through sale, the materials are recorded at scrap value. Where materials inventory is intended for sale, management uses current market rates to estimate the recoverable amount through sale.

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 judgment for forecasting future profits.

Further details of the deferred tax assets recognised can be found in Note 25.

During 2017, a Group subsidiary, Regal Petroleum Corporation (Ukraine) Limited, settled $12,480,000 of intra-group liability of which the Company is the beneficial owner. A further amount of $6,000,000 is expected to be settled by the end of 2018. As such, a foreign exchange difference of $351,000 accumulated on the intra-group balance of $14,560,000 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 2017 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 2017, other than the abovementioned amounts of $6,000,000, 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 2017.

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.

There are no inter-segment sales within the Group and all products are sold in the geographical region in which they are produced.

During 2017, the Group commenced selling all of its gas production to its related party, LLC Smart Energy ("Smart Energy"). Smart Energy has oil and gas operations in Ukraine and is part of the PJSC Smart-Holding Group, which is ultimately controlled by Mr Vadim Novinskiy, who through an indirect 54% majority shareholding, ultimately controls the Group. This arrangement came about 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 new tax regulations, this places additional regulatory obligations on each of the Group's potential customers who may be less inclined to purchase the Group's gas and/or may seek discounts on sales prices. As a result of discussions between the Company and Smart Energy, Smart Energy agreed to purchase all of the Group's gas production and to assume responsibility for the regulatory obligations under the Ukrainian tax regulations. Furthermore, Smart Energy has agreed to combine the Group's gas production with its own gas production, and to sell such gas as combined volumes, which should result in higher sales prices due to the larger sales volumes. In order to cover Smart Energy's sales, administration and regulatory compliance costs, the Group 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 16)

All amounts shown as auditor's remuneration in 2017 and 2016 were payable to the Group auditors, PricewaterhouseCoopers LLP and other member firms of PricewaterhouseCoopers LLP.

The emoluments of the individual Directors were as follows:

Sergii Glazunov was appointed as a Chief Executive Officer in August 2017, and is paid $252,000 per annum. Prior to his appointment as Chief Executive Officer, Mr Glazunov was Finance Director, and was paid $118,000 for the period from January 2017 to July 2017.

Chris Hopkinson was appointed as Non-Executive Director in September 2017, for which he was paid £45,000 per annum. In October 2017, he was appointed Non-Executive Chairman, for which he is now paid £100,000 per annum.

Bruce Burrows was appointed as Non-Executive Director in August 2017, and is paid £45,000 per annum.

Phil Frank was appointed as Non-Executive Director in October 2017, and is paid £45,000 per annum.

Keith Henry's role as Executive Chairman was made redundant in October 2017. He was paid £250,000 per annum for the period from January 2017 to October 2017, and thereafter was paid termination compensation of £123,886 and unused holiday pay of £12,500.

Adrian Coates stepped down as Non-Executive Director in August 2017. He was paid £45,000 per annum for the period from January 2017 to August 2017, and thereafter termination compensation of £22,500.

Alastair Graham stepped down as Non-Executive Director in October 2017. He was paid £45,000 per annum for the period from January 2017 to October 2017, and thereafter was paid termination compensation of £32,500.

The emoluments include base salary 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.

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

The increase in the average monthly number of employees is due to an increase in employees upon the acquisition of PEP in July 2016.

The aggregate staff costs of these employees were as follows:

During 2017, the Group recorded interest income of $956,000 (2016: $770,000) from placement of cash on current and deposit accounts and recognised foreign exchange gains less losses of $351,000 (2016: nil).

12. Other operating gains and (losses), (net) 

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 19.25%. The expense / (income) for the year can be reconciled to the profit / (loss) 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.

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 a Parent Company profit after tax of $12,239,000 for the year ended 31 December 2017. For the year ended 31 December 2016, the Group loss included a Parent Company loss after tax of $15,616,000.

The calculation of basic profit or loss per ordinary share has been based on the profit or loss for the year and 320,637,836 (2016: 320,637,836) ordinary shares, being the weighted average number of shares in issue for the year. There are no dilutive instruments.

According to the results of the annual count and revision carried out in 2017, individual obsolete and damaged non-current assets were impaired by the amount of $180,000 (Note 12).

In accordance with the Group's accounting policies, the oil and gas development and producing assets are tested for impairment at each balance sheet date if impairment indicators exists. As at 31 December 2017, no impairment indicators were identified.