RPT.L Regulatory News (RPT)

9 April 2020

REGAL PETROLEUM PLC

2019 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 2019.

Highlights

Ukraine Operations

Finance

Outlook

Sergii Glazunov, CEO, commented: "2019 was a strong operational year for Regal Petroleum. Record production from the MEX-GOL, SV and VAS fields helped offset the impact of lower gas prices experienced in the year, and the Board believes that the acquisition of LLC Arkona Gas-Energy in March of this year will bolster our production capacity following completion of initial drilling planned to commence in the next twelve months.

We are looking forward to further progressing our development programme in the new financial year and continuing to improve production rates and revenue streams in the future. We are watching closely the unprecedented developments of the current COVID-19 pandemic, and although we have seen no material impact so far, we have taken and will keep taking actions to ensure the safety of our employees and local communities."

The Annual Report and Financial Statements for 2019, together with the Notice of Annual General Meeting, will be posted to shareholders and published on the Company's website during May/June 2020.

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 preliminary results of the Group. This year has been a strong year for the Group, with good progress in the development of the MEX-GOL, SV and VAS gas and condensate fields in north-eastern Ukraine and a solid financial performance during the year. Drilling of the MEX-119 development well was successfully completed and brought on production in October 2019, with very strong flow rates.

At the MEX-GOL and SV fields, production was reasonably stable during 2019, with higher production volumes compared with the 2018 year, and at the VAS field production was also steady, and significantly higher than during 2018 following the hook-up of the VAS-10 well in November 2018.

Aggregate average daily production from the MEX-GOL, SV and VAS fields during 2019 was approximately 4,263 boepd, which compares with an aggregate daily production rate of approximately 3,391 boepd during 2018, an increase of nearly 26%.

The Group delivered a robust financial performance for the year ended 31 December 2019 on the back of record levels of production and despite a significant drop in the average gas price in the period, a function of weakened European gas prices. During 2019, the Group achieved a net profit of $12.2 million (2018: $54.3 million). Continued strong profitability, despite the weakened gas price, has enabled the Group to further enhance its balance sheet, with a 17% increase in closing cash resources, being a total of $62.5 million at 31 December 2019 (2018: $53.2 million).

The fiscal and economic situation in Ukraine was reasonably stable during 2019, with a better economic outlook, GDP growth, reduced inflation and stability in the Ukrainian Hryvnia exchange rates. Nevertheless, Ukraine retains residual risk of fiscal and economic stress, and we remain vigilant.

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 2019, gas prices trended lower, reflecting a similar trend in European gas prices, and were lower than in 2018. Similarly, condensate and LPG prices were also lower by comparison with last year.

New Acquisition

As announced on 24 March 2020, the Group has acquired the entire issued share capital of LLC Arkona Gas-Energy ("Arkona") for total consideration of up to $8.63 million, subject to satisfaction of certain conditions. Arkona holds a 100% interest in the Svystunivsko-Chervonolutskyi ("SC") exploration licence in north-eastern Ukraine, some 15 km east of the SV field. The SC licence was granted in May 2017, with a duration of 20 years, and is prospective for gas and condensate. As with the productive reservoirs in the SV field, the prospective reservoirs in this licence are Visean, at depths between 4,600 - 6,000 metres. We believe that our existing knowledge of the subsurface geology in the area will enable us to quickly progress our development planning for this licence, and we hope to be able to commence drilling operations on the licence within 12 months.

Board and Management Changes

In June 2019, Bruce Burrows was appointed as Finance Director of the Company, having previously been a non-executive Director, and Oleksiy Zayets was appointed as Chief Financial Officer of the Company's Ukrainian operations.

COVID-19 Virus

We are closely monitoring the current volatility in global financial markets, and the implications on the operational, economic and social environment within which we work caused by the COVID-19 pandemic, coupled with the recent sharp decline in oil prices. As of the date hereof, there has been no operational disruption linked to the COVID-19 pandemic, and no material impact is currently envisaged on the Group's prospects. However, the Board and management remain acutely aware of the risks, and are taking action to mitigate them where possible. This is a rapidly evolving situation and we are working to not only protect our staff and stakeholders but to minimise disruption to our business. Our supply chain is not materially exposed to countries currently most affected by the pandemic, and we hold good inventories of critical spares for our field operations. We have reassessed our medium-term forecasts based on current pricing and are highly confident we have the resources to continue to deliver on our plans. Of course, we cannot be certain of the duration of the pandemic's impact but will remain focussed on monitoring and protecting our business through the period of uncertainty. In protecting our stakeholders interests, we are conscious of our wider obligations to the communities, and country, in which we operate. Accordingly, we have acted, alongside other corporate entities in Ukraine, to directly acquire critical equipment and supplies from Chinese suppliers to donate to the Ukrainian State to assist its efforts to manage the pandemic in Ukraine. We have allocated $2 million to this initiative.

Outlook

Whilst there are still challenges in the business environment in Ukraine, the situation is improving gradually. After the steady operational performance during 2019, and the increased production output during the year, we are eagerly awaiting the results of the SV-54 development well, which are expected in the third quarter of 2020. We are also looking forward to achieving further successes in the development activities planned for 2020 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 and especially during the current COVID-19 pandemic.

Chris Hopkinson

Chairman

Chief Executive Officer's Statement

Introduction

The Group continued its good progress at its Ukrainian fields during 2019, with development activity at the MEX-GOL and SV fields including the successful drilling of the MEX-119 development well, which came on production in October 2019, the successful workover of the MEX-106 well to renew the production tubing, and hydraulic fracturing operations at the MEX-120 well. In addition, work continued to refine the geological model of the fields, upgrade the gas processing facilities and pipeline network, and undertake remedial work on existing wells.

At the VAS field, acquisition of the remaining coverage of 3D seismic over the field was completed in early 2019 and the data acquired was processed and interpreted. However, a decline in production rates from the VAS-10 well impacted overall production at the VAS field during the fourth quarter of 2019, and as a result, compression equipment was installed at the well.

Overall production was steady during 2019, and significantly higher than in 2018, with a substantial boost in the fourth quarter, once the MEX-119 well came on production.

Quality, Health, Safety and Environment ("QHSE")

The Group is committed to maintaining the highest QHSE standards and the effective management of these areas is an intrinsic element of the overall business ethos. Through strict enforcement of the Group's QHSE policies, 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 2019, a total of 413,419 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 2,954,500 man-hours without a Lost Time Incident. No environmental incidents were recorded during the year.

Production

The average daily production of gas, condensate and LPG from the MEX-GOL, SV and VAS fields for the year ended 31 December 2019 was as follows:-

Production rates were higher in 2019 when compared with 2018, predominantly due to the success of the MEX-119 well in the fourth quarter of 2019.

The Group's average daily production for the period from 1 January 2020 to 31 March 2020 from the MEX-GOL and SV field was 17.3 MMscf/d of gas, 659 bbl/d of condensate and 280 bbl/d m³/d of LPG (3,904 boepd in aggregate) and from the VAS field was 3.1 MMscf/d of gas and 34 bbl/d of condensate (604 boepd in aggregate).

Operations

The much improved fiscal and economic conditions in Ukraine, coupled with reasonable stability in the Ukrainian Hryvnia, 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 continue the Group's development programme at its Ukrainian fields during 2019. However, lower realised gas prices impacted revenues, following a general decline in gas prices in Europe.

The Group continued to refine its geological subsurface models of the MEX-GOL, SV and VAS fields, in order to enhance its strategies for the further development of the fields, including the timing and level of future capital investment required to exploit the hydrocarbon resources.

At the MEX-GOL and SV fields, the MEX-119 development well was spudded in February 2019 and drilled to a depth of 4,822 metres, which was slightly shallower than its planned depth, after the targeted horizons were encountered. The well targeted production from the B-20 reservoirs in the Visean formation. One interval, at a drilled depth of 4,804 - 4,816 metres, was perforated, and after successful testing, the well was hooked-up to the gas processing facilities. The well has demonstrated excellent production rates and is currently producing at approximately 4.8 MMscf/d of gas and 216 bbl/d of condensate (1,058 boepd in aggregate).

The Group continues to operate each of the SV-2 and SV-12 wells under joint venture agreements with NJSC Ukrnafta, the majority State-owned oil and gas producer. Under the agreements, the gas and condensate produced from the respective wells 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 wells as revenue, and the net profit share due to NJSC Ukrnafta being treated as a lease expense in cost of sales. Both of these wells have proven to be strong producers since being brought back on production.

At the MEX-106 well, a successful workover was undertaken to renew the production tubing, which boosted production from this well, and at the MEX-120 well, hydraulic fracturing operations were undertaken, following which the well was lifted using coiled tubing, but only modest flows of gas and condensate were recovered and the well is now under observation. In addition, the Group upgraded the gas processing facilities and pipeline network, and undertook remedial work on existing wells.

Drilling of the SV-54 well has been completed, with the well having reached a final depth of 5,322 metres. Completion operations have now commenced and these are scheduled to be concluded by the end of the second quarter of 2020, and, subject to successful testing, production hook-up is anticipated during the third quarter of 2020. The well is a development well, with its primary targets being the B-22 and B-23 horizons in the Visean formation.

At the VAS field, interpretation of the 3D seismic data acquired last year was completed and integrated into the geological model for the field. Planning is continuing for a new well to explore the VED prospect within the VAS licence area. However, a decline in production rates from the VAS-10 well impacted overall production at the VAS field during the fourth quarter, and as a result, compression equipment was installed to increase production from this well, with a longer term plan to undertake a workover of the well to access an alternative reservoir horizon.

In March 2019 (see announcement made on 12 March 2019), a regulatory issue arose 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 2019, the Group commissioned DeGolyer and MacNaughton ("D&M") to prepare an updated assessment of the remaining reserves and resources at the VAS field as at 31 December 2018 in order to provide an update since the previous reserves estimation undertaken by Senergy (GB) Limited ("Senergy") as at 1 January 2016.

The updated assessment of 1.895 MMboe of proved (1P) and 3.145 MMboe of proved + probable (2P) reserves resulted in a material increase in these categories of remaining reserves from the 2016 Senergy estimates, which were 0.66 MMboe and 1.80 MMboe respectively. These increases reflect a higher level of confidence in the understanding of the subsurface at the field as a result of the new data obtained since 2016. Further details of the D&M assessment are set out in the Company's announcement dated 21 August 2019. Over and above the increase in reserves themselves, the Group is tailoring its field development programme for the VAS fields, which is envisaged to include increased development activity, production and cash flow in future periods.

New Acquisitions

As announced on 24 March 2020, the Group has acquired the entire issued share capital of LLC Arkona Gas-Energy for total consideration of up to $8.63 million, with $4.3 million subject to the satisfaction of certain conditions as set out therein. Arkona holds a 100% interest in the Svystunivsko-Chervonolutskyi ("SC") exploration licence, which is located in the Poltava region in north-eastern Ukraine. The SC licence has an area of 97 km2, and is approximately 15 km east of the SV field. The licence was granted in May 2017 with a duration of 20 years. The licence is prospective for gas and condensate, and has been the subject of exploration since the 1980s, with 5 wells having been drilled on the licence since then, although none of these wells are currently on production. As with the productive reservoirs in the SV field, the prospective reservoirs in the licence are Visean, at depths between 4,600 - 6,000 metres.

According to the recorded information on the Ukrainian State Balance of Natural Resources as at 1 January 2020, the licence has hydrocarbon reserves, in the category of C1 and C2 under the Ukrainian classification, DKZ, of approximately 38.0 MMboe (4.9 Bm3 of gas and 0.86 Mtonnes of condensate). It should be noted, however, that whilst the Group's review of existing technical data for the licence is considered supportive of such assessment of hydrocarbon reserves, such hydrocarbon reserves have not been verified by an independent reserves assessor and do not correspond to the SPE/WPC/AAPG/SPEE Petroleum Resources Management System ("PRMS") standard for classification and reporting.

We believe that our existing knowledge of the subsurface geology in the area will enable us to quickly progress our development planning for this licence, and we envisage that this will include the commencement of a new well within the next 12 months, with drilling and completion operations expected to take up to a further 12 months.

As announced on 1 April 2020, the Memorandum of Understanding (the "Memorandum") for the potential acquisition of PJSC Science and Production Concern Ukrnaftinvest, announced on 26 November 2019, expired and was consequently terminated as a result of the parties to the Memorandum, being (1) the Company and (2) Ms Lidiia Chernysh and Bolaso Investments Limited, being unable to reach a final agreement for such potential acquisition. The provisions relating to such termination set out in the Memorandum are now applicable, and these include the refund of the deposit of $0.5 million previously paid under the Memorandum.

Outlook

During 2020, the Group will continue to develop the MEX-GOL, SV and VAS fields, as well as commence work of the development planning for the SC licence. At the MEX-GOL and SV fields, the development programme includes completing the drilling and production hook-up of the SV-54 development well (which is scheduled for Q4 2020), commencing a new well, SV-25, in the SV field, which is planned to be spudded later in the year, planning for a further well or sidetracking of an existing well in the SV field, investigating workover opportunities for other existing wells, installation of further 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, planning for the proposed new well to explore the VED prospect within the VAS licence area is continuing, and upgrades to the gas processing facilities, pipeline network and other infrastructure are planned.

There has also been encouraging recent 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 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 last 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 successful year for the Group, and to especially recognise their continuing efforts and professionalism during the current COVID-19 pandemic.

Sergii Glazunov

Chief Executive Officer

Overview of Assets

We operate three fields, and recently acquired a further field, in the Dnieper-Donets basin in north-eastern Ukraine.

Our fields have high potential for growth and longevity for future production - a strong foundation for success.

MEX-GOL and SV fields

The MEX-GOL and SV fields are held under two adjacent production licences, but are operated as one integrated asset, and have significant gas and condensate reserves and potential resources of unconventional gas.

Production Licences

We hold a 100% working interest in, and are the operator of, the MEX-GOL and SV fields. The production licences for the fields were granted to the Group in July 2004 with a duration of 20 years, and it is intended to apply to extend the licences under the applicable regulations in Ukraine in order to fully develop the remaining reserves. The economic life of these fields extend to 2038 and 2042 respectively pursuant to the most recent reserves and resources assessment by DeGolyer and MacNaughton ("D&M") as at 31 December 2017.

The two licences, located in Ukraine's Poltava region, are adjacent and extend over a combined area of 269 km², approximately 200 km east of Kyiv.

Geology

Geologically, the fields are located towards the middle of the Dnieper-Donets sedimentary basin which extends across the major part of north-eastern 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 inter-bedded with shales at around 4,700 metres below the surface, with a gross thickness between 800 and 1,000 metres.

Analysis suggests that the origin of these deposits ranges from fluvial to deltaic, and much of the trapping at these fields is stratigraphic. Below these reservoirs is a thick sequence of shale above deeper, similar, sandstones at a depth of around 5,800 metres. These sands are of Tournasian age and offer additional gas potential. Deeper sandstones of Devonian age have also been penetrated in the fields.

Reserves

The development of the fields began in 1995 by the Ukrainian State company Chernihivnaftogasgeologiya ("CNGG"), and shortly after this time, the Group entered a joint venture with CNGG in respect of the exploration and development of these fields.

The fields have been mapped with 3D seismic, and a geological subsurface model has been developed and refined using data derived from high-level reprocessing of such 3D seismic and new wells drilled on the fields.

The assessment undertaken by D&M as at 31 December 2017 estimated proved plus probable (2P) reserves attributable to the fields of 50.0 MMboe, with 3C contingent resources of 25.3 MMboe.

VAS field

The VAS field is a smaller field with interesting potential. The field has assessed proved plus probable reserves in excess of 3 MMboe and substantial contingent and prospective resources, as well as potential resources of unconventional gas.

Production Licence

We hold a 100% working interest in, and are the operator of, the VAS field. The production licence for the field was granted in August 2012 with a duration of 20 years. The economic life of the field extends to 2032 pursuant to the most recent reserves and resources assessment by D&M as at 31 December 2018.

The licence extends over an area of 33.2 km² and is located 17 km south-east of Kharkiv, in the Kharkiv region of Ukraine. The field was discovered in 1981, and the first well on the licence area was drilled in 2004.

The Group acquired this project in July 2016.

Geology

Geologically, the field is located towards the middle of the Dnieper-Donets sedimentary basin in north-east 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.

The productive reservoirs are at depths between 3,370 and 3,700 metres depth.

Reserves

The fields have been mapped with 3D seismic, and a geological subsurface model has been developed and refined using data derived from such 3D seismic and new wells drilled on the field.

The assessment undertaken by D&M as at 31 December 2018 estimated proved plus probable (2P) reserves of 3.1 MMboe, with contingent resources of 0.6 MMboe, and prospective resources of 7.7 MMboe in the VED area of the field. The next well planned on the field is designed to explore the VED area of the field.

Overview of Reserves

1. MEX-GOL and SV fields

The Group's estimates of the remaining Reserves and Resources at the MEX-GOL and SV fields are derived from an assessment undertaken by D&M, as at 31 December 2017 (the "MEX-GOL-SV Report"), which was announced on 31 July 2018. During the period from 1 January 2018 to 31 December 2019, the Group has produced 2.2 MMboe from these fields.

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

The MEX-GOL-SV 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 D&M as at 31 December 2018 (the "VAS Report"), which was announced on 21 August 2019. During the period from 1 January 2019 to 31 December 2019, 0.3 MMboe were produced from the field.

The VAS Report estimates the remaining Reserves as at 31 December 2018 in the VAS field as follows:-

The VAS Report estimates the Contingent Resources as at 31 December 2018 in the VAS field as follows:-

The VAS Report estimates the Prospective Resources as at 31 December 2018 in the VED prospect as follows:-

Finance Review

The Group delivered a very solid financial performance in 2019, enabled by a record level of gas production, and despite a significant drop in average gas realisations. Net profit for the year was $12.2 million (2018: $54.3 million including the $36.1 million benefit of a one-off reversal of impairment of oil and gas development and production assets).

Gross profit for the year ended 31 December 2019 was $23.5 million (2018: $34.2 million). The 31% drop in gross profit year-on-year is almost entirely a result of weakened gas prices in the year (average realisations of $219/Mm3 compared to $312/Mm3 in 2018), with condensate and LPG sales up 7.5% and 5.5% respectively, and cost of sales up a modest 1.7% year-on-year.

Revenue for the year, derived from the sale of the Group's Ukrainian gas, condensate and LPG production, was $55.9 million (2018: $66.1 million). The gas price-driven fall in revenue also impacted cash generated from operations during the year, which was 32% lower at $24.6 million (2018: $36.3 million) predominantly, as noted, as a result of lower gas prices and despite the higher production volumes achieved in the year.

The average realised gas, condensate and LPG prices during the 2019 year were $219/Mm3 (UAH5,729/Mm3), $58/bbl and $55/bbl respectively (2018: $312/Mm3 (UAH8,528/Mm3), $72/bbl and $64/bbl respectively).

During the period from 1 January 2020 to 7 April 2020, the average realised gas, condensate and LPG prices were $158/Mm3 (UAH3,961/Mm3), $47/bbl and $43/bbl respectively. The current realised gas price is $128/Mm3 (3,469/Mm3).

As noted above, 2019 saw a significant drop in averaged realised gas prices, having the singularly greatest impact on our 2019 performance. 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 2019 year, gas prices were depressed, as a combined result of lower international prices reducing the price of imported gas, and the unseasonally warm 2019/20 winter. Condensate and LPG prices were also lower than in 2018.

Cost of sales for the year ended 31 December 2019 was marginally higher at $32.4 million (2018: $31.9 million). Whilst broadly consistent with last year, there were some significant intra-total movements: production taxes declined by 22% as a result of reduced gas revenues, in turn a function of the reduced gas prices as noted above; a 19% increase in rent expense, a function of increased production; staff costs increased by 19% as a function of a maturing employment market in Ukraine and associated salary inflation; and a new transmission tariff for use of the Ukrainian gas system of UAH91.87/Mm3 of gas was introduced and applicable to oil and gas producers in Ukraine, including the Group, resulting in a $673,000 (2018: nil) charge in the period.

New legislation relating to the oil and gas sector in Ukraine has been introduced over the last year, and in this regard, with effect from 1 January 2019, the subsoil tax rates, as included in cost of sales, applicable to condensate production 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.

Administrative expenses for the year were higher at $7.4 million (2018: $5.7 million), primarily as a result of: an 18% increase in payroll and related taxes, consistent with the maturing employment market as noted above; a 150% increase in depreciation of fixed assets as a result of additions, and the implementation of IFRS 16 from 1 January 2019, whereby the Group now calculates the expense by depreciation of the right-to-use assets and interest expense on the liability over the lease term; and a 94% increase in other expenses primarily in relation to increased costs for managing gas transportation and storage, and marketing.

The tax charge for the year reduced by 23% to $9.6 million (2018: $12.5 million charge) and comprises a current tax charge of $4.8 million (2018: $6.5 million charge) and a deferred tax charge of $4.8 million (2018: $6.0 million charge). The material reduction in the deferred tax charge results from the $5.5 million 2018 deferred tax charge being incurred 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 derecognised a deferred tax asset of $2.1 million at 31 December 2019 (31 December 2018: $2.1 million). In the period the opening balance deferred tax asset of $2.1 million in relation to UK tax losses carried forward was charged to the Income Statement because the Group does not expect to be able to utilise unrecognised UK losses carried forward in the foreseeable future. In addition, a deferred tax liability relating to the development and production asset at the MEX-GOL and SV fields of $2.3 million (31 December 2018: deferred tax asset $0.8 million) is recognised on the tax effects of the temporary differences of the provision for decommissioning and the carrying value relating of these assets, and their tax bases.

A deferred tax liability relating to the development and production asset at the VAS field of $0.2 million (31 December 2018: $0.5 million) was recognised at 31 December 2019 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.

A significant increase in capital investment to $17.7 million reflects the expenditure on oil and gas development assets during the year (2018: $9.6m), following the field studies and revised development plans undertaken by the Group over recent periods. The carrying value of the Group's assets was reviewed at year end as a result of the significant drop in gas prices during the year, which did not result in any impairment of assets.

Cash and cash equivalents held at 31 December 2019 were up 17% at $62.5 million (31 December 2018: $53.2 million). The Group's cash and cash equivalents balance at 7 April 2020 was $55.2 million, held as to $18.5 million equivalent in Ukrainian Hryvnia and the balance of $36.7 million equivalent predominantly in US Dollars, Euros and Pounds Sterling.

Between early 2014 and 2018, the Ukrainian Hryvnia 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, during 2019, the Ukrainian Hryvnia strengthened materially against the US Dollar averaging UAH25.8/$1.00 during the period (average rate during 2018: UAH27.2/$1.00). The total foreign exchange gain in the period was $3.5 million (2018: $0.5 million). In the later part of Q1 2020 however, global financial markets have become extremely volatile as a combined function of a significant fall in oil prices and the effects of the COVID-19 pandemic, and the Ukrainian Hryvnia has weakened against the US Dollar with the exchange rate at 7 April 2020 being UAH27.2/$1.00. 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 2020 and beyond. This is coupled with the fact that the Group is currently debt-free, and therefore has no debt covenants that may otherwise impede the ability to implement contingency plans if domestic and/or global circumstances dictate. This flexibility and ability to monitor and manage development plans and liquidity is a cornerstone of our planning, and underpins our assessments of the future.

The Group manages its revenue, cash from operations and production volumes as key performance indicators. The achieved results for 2019 were as follows:

Principal Risks

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 on 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 2019 or 2018, 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 2019 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 2020.

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 above.

As of 31 December 2019 and 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 Vadym Novynskyi. Accordingly, the Company was ultimately controlled by Mr Vadym 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.

In 2019, the Ukrainian economy was showing signs of stabilisation after years of political and economic tensions. The year-on-year inflation rate in Ukraine decreased to 4.1% during 2019 (as compared to 9.8% in 2018 and 13.7% in 2017), while GDP continued to grow at an estimated 3.5% (after 3.3% growth in 2018).

After several years of devaluation, in 2019 the Ukrainian currency strengthened and during the year, appreciated by 14% (as at 31 December 2019, the official National Bank of Ukraine ("NBU") exchange rate of the Ukrainian Hryvnia against the US Dollar was UAH23.69/$1.00, compared to UAH27.69/$1.00 as at 31 December 2018). Among the key factors attributable to the strengthening of the Hryvnia were strong revenues of agricultural exporters, tight Hryvnia liquidity, growth in remittances from labour migrants and high demand for government debt instruments.

With effect from April 2019, the NBU launched a cycle of easing of monetary policy and a gradual decrease of its discount rate, for the first time in two years, from 18% in April 2019 to 11% in January 2020, which was justified by a sustained trend of inflation deceleration.

In December 2018, the International Monetary Fund ("IMF") approved a stand-by assistance ("SBA") 14-month programme for Ukraine, totalling $3.9 billion. In December 2018, Ukraine had already 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 increased Ukraine's chances of meeting its foreign currency obligations in 2019, and thus has supported the financial and macroeconomic stability of the country. Continued cooperation with the IMF is dependent on Ukraine's success in implementing policies and reforms that underpin a new IMF-supported programme.

In 2020, Ukraine faces major public debt repayments, which will require mobilisation of substantial domestic and external financing in an increasingly challenging financing environment for emerging markets.

The events which led to annexation of Crimea by the Russian Federation in February 2014 and the conflict in the east of Ukraine which started in spring 2014 have not been resolved to date. The relationships between Ukraine and the Russian Federation have remained strained.

Ukraine held presidential elections in March-April 2019, and parliamentary elections in July 2019. Amid these double elections, the degree of uncertainty including in respect of the future direction of structural reforms in 2020 remains very high. Despite certain improvements in 2019, the final resolution and the ongoing effects of the political and economic situation in Ukraine 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 section above.

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. These consolidated financial statements are prepared under the historical cost convention as modified by the certain financial instruments measured in accordance with the requirements of IFRS 9 Financial instruments. 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 16 effective from 1 January 2019, these policies have been consistently applied to all the periods presented, unless otherwise stated (refer to Note 4).

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 5.

Going Concern

Based on the positive operational and financial performance of the Group and for the reasons outlined in the Principal Risks section above, 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 2019. 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 section above. The Group does not foresee any positive or negative impact on its operations as a result of Brexit.  As a consequence of the COVID-19 pandemic the Group is re-visiting processes and controls intended to ensure protection of all its stakeholders and minimise any disruption to its business.

New and amended standards adopted by the Group

A number of new or amended standards became applicable for the current reporting period. The Group had to change its accounting policies as a result of the adoption of IFRS 16 Leases.

The impact of the adoption of the leasing standard and the new accounting policies are disclosed in Note 4 below.

The following amended standards became effective from 1 January 2019, but did not have any material impact on the Group:

Impact of standards issued but not yet applied by the Group

Certain new standards and interpretations have been issued that are mandatory for the annual periods beginning on or after 1 January 2020 or later, and which the Group has not early adopted.

These amendments address an inconsistency between the requirements in IFRS 10 and those in IAS 28 in dealing with the sale or contribution of assets between an investor and its associate or joint venture. The main consequence of the amendments is that a full gain or loss is recognised when a transaction involves a business. A partial gain or loss is recognised when a transaction involves assets that do not constitute a business, even if these assets are held by a subsidiary.

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) (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.

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.

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). The amendments are prospective and the Group will apply them and assess their impact from 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 amendments were triggered by replacement of benchmark interest rates such as LIBOR and other inter-bank offered rates ('IBORs'). The amendments provide temporary relief from applying specific hedge accounting requirements to hedging relationships directly affected by the IBOR reform. Cash flow hedge accounting under both IFRS 9 and IAS 39 requires the future hedged cash flows to be 'highly probable'. Where these cash flows depend on an IBOR, the relief provided by the amendments requires an entity to assume that the interest rate on which the hedged cash flows are based does not change as a result of the reform. Both IAS 39 and IFRS 9 require a forward-looking prospective assessment in order to apply hedge accounting. While cash flows under IBOR and IBOR replacement rates are currently expected to be broadly equivalent, which minimises any ineffectiveness, this might no longer be the case as the date of the reform gets closer. Under the amendments, an entity may assume that the interest rate benchmark on which the cash flows of the hedged item, hedging instrument or hedged risk are based, is not altered by IBOR reform. IBOR reform might also cause a hedge to fall outside the 80-125% range required by retrospective test under IAS 39. IAS 39 has therefore been amended to provide an exception to the retrospective effectiveness test such that a hedge is not discontinued during the period of IBOR-related uncertainty solely because the retrospective effectiveness falls outside this range. However, the other requirements for hedge accounting, including the prospective assessment, would still need to be met. In some hedges, the hedged item or hedged risk is a non-contractually specified IBOR risk component. In order for hedge accounting to be applied, both IFRS 9 and IAS 39 require the designated risk component to be separately identifiable and reliably measurable. Under the amendments, the risk component only needs to be separately identifiable at initial hedge designation and not on an ongoing basis. In the context of a macro hedge, where an entity frequently resets a hedging relationship, the relief applies from when a hedged item was initially designated within that hedging relationship. Any hedge ineffectiveness will continue to be recorded in profit or loss under both IAS 39 and IFRS 9. The amendments set out triggers for when the reliefs will end, which include the uncertainty arising from interest rate benchmark reform no longer being present. The amendments require entities to provide additional information to investors about their hedging relationships that are directly affected by these uncertainties, including the nominal amount of hedging instruments to which the reliefs are applied, any significant assumptions or judgements made in applying the reliefs, and qualitative disclosures about how the entity is impacted by IBOR reform and is managing the transition process.

Unless otherwise described above, the new standards and interpretations are not expected to affect significantly the Group's consolidated financial statements.

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.

Foreign exchange gains and losses not related to intra-group balances are recognised on a net basis as other gains or losses.

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:

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 18) 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 oil and gas development and production assets within property, plant and equipment.

Right-of-use assets

The Group leases various offices, equipment, wells, land. Contracts may contain both lease and non-lease components. The Group allocates the consideration in the contract to the lease and non-lease components based on their relative stand-alone prices.

Assets arising from a lease are initially measured on a present value basis.

Right-of-use assets are measured at cost comprising the following:

Right-of-use assets are generally depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis. If the Group is reasonably certain to exercise a purchase option, the right-of-use asset is depreciated over the underlying assets' useful lives. Depreciation on the items of the right-of-use assets is calculated using the straight-line method over their estimated useful lives as follows:

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:

The principal rates of exchange used for translating foreign currency balances at 31 December 2019 were $1:UAH23.7 (2018: $1:UAH27.7), $1:£0.8 (2018: $1:£0.8), $1:€0.9 (2018: $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.

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.

Value added tax

Output value added tax related to sales is payable to tax authorities on the earlier of (a) collection of receivables from customers or (b) delivery of goods or services to customers. Input VAT is generally recoverable against output VAT upon receipt of the VAT invoice. The tax authorities permit the settlement of VAT on a net basis. VAT related to sales and purchases is recognised in the consolidated statement of financial position on a gross basis and disclosed separately as an asset and a liability. Where provision has been made for expected credit losses ("ECL") of receivables, the impairment loss is recorded for the gross amount of the debtor, including VAT.

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 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.

Prepayments

Prepayments are carried at cost less provision for impairment. A prepayment is classified as non-current when the goods or services relating to the prepayment are expected to be obtained after one year, or when the prepayment relates to an asset which will itself be classified as non-current upon initial recognition. Prepayments to acquire assets are transferred to the carrying amount of the asset once the Group has obtained control of the asset and it is probable that future economic benefits associated with the asset will flow to the Group. Other prepayments are written off to profit or loss when the services relating to the prepayments are received. If there is an indication that the assets, goods or services relating to a prepayment will not be received, the carrying value of the prepayment is written down accordingly and a corresponding impairment loss is recognised in profit or loss for the year.

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.

Lease liabilities

Liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:

Extension and termination options are included in a number of property and equipment leases across the Group. These terms are used to maximise operational flexibility in terms of managing contracts. Extension options (or period after termination options) are only included in the lease term if the lease is reasonably certain to be extended (or not terminated). Lease payments to be made under reasonably certain extension options are also included in the measurement of the liability.

The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be readily determined, which is generally the case for leases of the Group, the Group's incremental borrowing rate is used, being the rate that the Group would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions.

To determine the incremental borrowing rate, the Group:

The Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in the lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability is reassessed and adjusted against the right-of-use asset.

Lease payments are allocated between principal and finance costs. The finance costs are charged to profit or loss over the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.

Payments associated with short-term leases and all leases of low-value assets are recognised on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less.

Operating lease

Where the Group is a lessor in a lease which does not transfer substantially all the risks and rewards incidental to ownership to the lessee (i.e. operating lease), lease payments from operating leases are recognised as other income on a straight-line basis.

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:

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. Changes in accounting policies

This note explains the impact of the adoption of IFRS 16 Leases on the Group's financial statements and also discloses the new accounting policies that have been applied from 1 January 2019.

The Group has adopted IFRS 16 retrospectively from 1 January 2019, but has not restated comparatives for the 2018 reporting period, as permitted under the specific transitional provisions in the standard. The reclassifications and the adjustments arising from the new leasing rules are therefore recognised in the opening balance sheet on 1 January 2019.

Adjustments recognised on adoption of IFRS 16

 On adoption of IFRS 16, the Group recognised lease liabilities in relation to leases which had previously been classified as 'operating leases' under the principles of IAS 17 Leases. These liabilities were measured at the present value of the remaining lease payments, discounted using the lessee's incremental borrowing rate as of 1 January 2019. The weighted average lessee's incremental borrowing rate applied to the lease liabilities on 1 January 2019 was 19.8% for contracts denominated in Ukrainian Hryvnia and 7.4% for contracts denominated in US Dollars.

Right-of-use assets were measured at the amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognised in the balance sheet as at 31 December 2018. There were no onerous lease contracts that would have required an adjustment to the right-of-use assets at the date of initial application.

The recognised right-of-use assets relate to the following types of assets:

The change in accounting policy affected the following items in the balance sheet on 1 January 2019:

Practical expedients applied

In applying IFRS 16 for the first time, the Group has used the following practical expedients permitted by the standard:

The Group has also elected not to reassess whether a contract is, or contains a lease at the date of initial application. Instead, for contracts entered into before the transition date, the Group relied on its assessment made applying IAS 17 and IFRIC 4 Determining whether an Arrangement contains a Lease.

The Group's leasing activities and how these are accounted for

The Group leases various wells, offices, equipment and land. Rental contracts are typically made for fixed periods of 1 to 25 years but may have extension options as described in (ii) below. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The lease agreements do not impose any covenants, but leased assets may not be used as security for borrowing purposes.

Until 1 January 2019, leases of property, plant and equipment were classified as either finance or operating leases. Payments made under operating leases (net of any incentives received from the lessor) were charged to profit or loss on a straight-line basis over the period of the lease.

From 1 January 2019, leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group. Each lease payment is allocated between the liability and finance cost. The finance cost is charged to profit or loss over the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis.

Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:

The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the lessee's incremental borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions.

Right-of-use assets are measured at cost comprising the following:

Payments associated with short-term leases and leases of low-value assets are recognised on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less.

(i) Variable lease payments

Estimation uncertainty arising from variable lease payments

Some property leases contain variable payment terms that are linked to the volume of production. For wells, up to 100 per cent of lease payments are on the basis of variable payment terms. Variable payment terms are used for a variety of reasons, including minimising the fixed costs base for wells under reconstruction. Variable lease payments that depend on the volume of production are recognised in profit or loss in the period in which the condition that triggers those payments occurs.

 (ii) Extension and termination options

Extension and termination options are included in a number of property and equipment leases across the Group. These terms are used to maximise operational flexibility in terms of managing contracts.

Critical judgements in determining the lease term

In determining the lease term, management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. Extension options (or periods after termination options) are only included in the lease term if the lease is reasonably certain to be extended (or not terminated).

The assessment is reviewed if a significant event or a significant change in circumstances occurs which affects this assessment and that is within the control of the lessee.

(iii) Residual value guarantees

The Group does not provide residual value guarantees in relation to equipment leases.

5. 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.

The valuation method used for determination of recoverable value in use is based on unobservable market data, which is within Level 3 of the fair value hierarchy.

MEX-GOL and SV gas and condensate fields

The impairment assessment carried out at 31 December 2019 has not resulted in an impairment loss. Further details of this assessment, including the sensitivity to the above assumptions, are set out in Note 18.

VAS gas and condensate field

Following the successful outcome of the VAS-10 well and the subsequent revision of the field development plan for the VAS field in 2019, the Group considered it appropriate to undertake a reassessment of the reserves and resources at the VAS field. 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 2018. The revised field development plan for this field prepared in 2019 assumes an increase in the number of new wells from one to three wells. The final report issued by D&M in August 2019 provided an estimate of the Group's proved plus probable ("2P") reserves of 3.1 MMboe. The report represents a significant increase in the remaining reserves and resources in this field since the previous estimation undertaken by Senergy (GB) Limited as at 1 January 2016 (1.8 MMboe). The increase in 2P reserves caused the revision of the expected economic life of the field from 2024 to 2028. Further details of this reserves update are set out in the Company's announcement made on 21 August 2019.

The impairment assessment carried out at 31 December 2019 has not resulted in an impairment loss. Further details of this assessment, including the sensitivity to the above assumptions, are set out in Note 18.

Depreciation of Oil and Gas Development and Production Assets

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

In light of the revision of the field development plan for the VAS field and the re-assessment of the 2P reserves at this field performed in 2019 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 and amortisation 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 $283,000 in the depletion charge of property, plant and equipment (the depletion charge decreased by $1,504,600 due to the increase in 2P reserves and increased by $1,787,000 due to the increase in future capital expenditure) and a decrease of $338,000 in amortisation of mineral reserves for the year 2019.

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 2019 was 3.68% (31 December 2018: 8.14%). 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 2019 resulted from the revision of the estimated costs of decommissioning (increase of $711,000 in provision), the decrease in the discount rate applied (increase of $2,430,000 in provision) and the extension of the economic life of the VAS field as a result of the revision of the field development plan in 2019 (decrease of $289,000 in provision). The decrease in discount rate at 31 December 2019 resulted from the decrease in Ukrainian Eurobonds yield and the respective decrease 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 2028 on the VAS field (31 December 2018: by 2038 on the MEX-GOL field, by 2042 on the SV field 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 2019 would be $11,564,000 (31 December 2018: $6,268,000).

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 2019, 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 are considered as a primary source of repayment on the loans. 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. As of 31 December 2019, the present value of future net cash flows to be generated by the subsidiaries operating in Ukraine during 2020 - 2024, adjusted for the subsidiaries' working capital as at 31 December 2019 and estimated amounts reserved by the Group for investment projects in the 5-year horizon was calculated. The decrease in the net present value of future net cash flows as at 31 December 2019 in comparison with 31 December 2018 was affected by the significant decrease in gas prices forecast and the revision of the field development plan for the VAS field in 2019 that included drilling of new wells in the 2021-2023 years. 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 2019. As such, the Company has recorded $15,450,000 of loss, 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 2019.

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 2018, a Group subsidiary, Regal Petroleum Corporation (Ukraine) Limited, planned to settle $9,000,000 of intra-group liability, however $20,616,000 was settled in the period. A further amount of $4,600,000 is planned to be settled by the end of 2020. As such, a foreign exchange difference of $3,487,000 accumulated on the intra-group balance of $170,223,000 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 2019 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 not settled as at 31 December 2019, other than the above-mentioned amount of $4,600,000, 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 2019.

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 27.

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 18)

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 2019, the Group was 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 Vadym Novynskyi, who through an indirect 82.65% 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, which is intended to result in higher sales prices due to the larger sales volumes. At the commencement of this sales arrangement, in order to cover Smart Energy's sales, administration and regulatory compliance costs, the Group sold its gas to Smart Energy at a discount of 0.5% to the gas sales prices achieved by Smart Energy, who sold the combined volumes in line with market prices. Due to changes in the regulatory regime in Ukraine, which has increased the burden of administration and regulatory compliance obligations involved in the sale of gas, and in order to ensure that the Group is compliant with current transfer pricing regulations in Ukraine, the Group and Smart Energy agreed in 2019 to increase the discount on the price at which the Group sells its gas to Smart Energy from 0.5% to 2%. The terms of sale 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 18)

7. Cost of Sales

New legislation relating to the oil and gas sector in Ukraine has been introduced over the last year, and in this regard, with effect from 1 January 2019, the subsoil tax rates applicable to condensate production 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.

From 1 January 2019, a transmission tariff for use of the Ukrainian gas system of UAH91.87 per 1000 m3 of gas was introduced.

Due to implementation of IFRS 16 from 1 January 2019 the Group has changed its policy for accounting for rent expenses. Instead of rent expenses the Group recognises depreciation of the right-of-use assets and interest expense on the liability over the lease term. However some property leases contain variable payment terms that are linked to the volume of production. Variable lease payments that depend on the volume of production are recognised in profit or loss in the period in which the condition that triggers those payments occurs. Also payments associated with short-term leases and leases of low-value assets are recognised on a straight-line basis as an expense in profit or loss.

8. Administrative Expenses

All amounts shown as Auditors' remuneration in 2019 and 2018 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:

Bruce Burrows was appointed as Finance Director in June 2019, and is paid £276,000 per annum. Prior to his appointment as Finance Director, Mr Burrows was Non-Executive Director and was paid £45,000 per annum for the period from January 2019 to May 2019.

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 2019, the Group recorded interest income of $nil (2018: $153,000) from placement of cash on long-term deposit accounts and recognised foreign exchange gains less losses of $3,487,000 (2018: $488,000).

13. Finance Costs

During 2019, the Group recorded an unwinding of discount on lease liabilities of $177,000 (2018: nil) and unwinding of a discount on provision for decommissioning of $273,000 (2018: $140,000) (Note 26).

14. Other losses, (net)

15. 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 and the difference in capital allowances allowed under Ukrainian and UK taxation.

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

16. 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 loss after tax of $17,507,000 for the year ended 31 December 2019 (2018: profit $12,057,000).

17. Earnings per Share

The calculation of basic profit per ordinary share has been based on the profit for the year and 320,637,836 (2018: 320,637,836) ordinary shares, being the weighted average number of shares in issue for the year. There are no dilutive instruments.

18. Property, Plant and Equipment