2020 Audited Results

RNS Number : 0378U

Enwell Energy PLC

31 March 2021

ENWELL ENERGY PLC

2020 AUDITED RESULTS

Enwell Energy plc (the "Company", and with its subsidiaries, the "Group"), the AIM-quoted (ENW) oil and gas exploration and production group, today announces its audited results for the year ended 31 December 2020.

2020 Highlights

Ukraine Operations

•	Aggregate average daily production of 4,541 boepd (2019: 4,263 boepd), an increase of approximately 6.5%
•	SV-54 development well successfully completed and brought on production in May 2020
•	Drilling of SV-25 appraisal well successfully completed and hooked-up for production in Q1 2021
•	MEX-GOL and SV production licences each extended to 2040 enabling full economic development of remaining reserves
•	No operational disruption to the Group's operations linked to the COVID-19 pandemic

Financials

•	Revenue of $47.3 million (2019: $55.9 million), down 15% as a function of weakened gas prices in the year
•	Gross profit of $15.7 million (2019: $23.5 million), down 33%
•	Cash generated from operations of $23.8 million (2019: $24.7 million), remained steady, predominantly due to record production increasing non-cash DD&A
•	Net profit of $3.2 million (2019: $12.2 million)
•	Cash and cash equivalents were steady at $61.0 million at 31 December 2020 (2019: $62.5 million)
•	Average realised gas, condensate and LPG prices in Ukraine were lower, particularly gas prices, at $136/Mm3 (UAH3,618/Mm3), $46/bbl and $46/bbl respectively (2019: $219/Mm3 (UAH5,729/Mm3) gas, $58/bbl condensate and $55/bbl LPG)

Outlook

•	Development work planned for 2021 at the MEX-GOL and SV fields includes: completing drilling operations of the SV-29 well; planning for a further new well or sidetracking of an existing well in the SV field; and upgrading of the gas processing facilities
•	Development work planned for 2021 at the VAS field includes: planning for a new well to explore the VED prospect within the VAS licence area; and upgrading of the gas processing facilities
•	Development work planned for 2021 at the SC field includes: planning for the drilling of the SVIST-4 well; and acquisition of 150 km2 of 3D seismic
•	2021 development programme expected to be funded from existing cash resources and operational cash flow

Sergii Glazunov, CEO, commented: "2020 was another strong operational year for Enwell Energy. Two further successful wells in the SV field led to record production levels from our fields, which helped offset the impact of lower gas prices experienced in the year. The recent resolution of the legal issues relating to LLC Arkona Gas-Energy has enabled us to commence development planning for the SC licence, with our first well planned within the next twelve months.

We are looking forward to the results of the SV-29 development well and to further progressing our development programme in the new financial year, whilst continuing to improve production rates and revenue streams in the future. Although we have not suffered any material impact from the COVID-19 pandemic, we have taken, and will continue to take, all possible actions to ensure the safety of our employees and local communities."

The Annual Report and Financial Statements for 2020, together with the Notice of Annual General Meeting, will be posted to shareholders and published on the Company's website during May/June 2021.

This announcement contains inside information for the purposes of Article 7 of EU Regulation 596/2014, which forms part of United Kingdom domestic law by virtue of the European (Withdrawal) Act 2018.

For further information, please contact:

Regal Petroleum plc	Tel: 020 3427 3550
Chris Hopkinson, Chairman
Sergii Glazunov, Chief Executive Officer
Bruce Burrows, Finance Director

Strand Hanson Limited	Tel: 020 7409 3494
Rory Murphy / Matthew Chandler

Arden Partners plc	Tel: 020 7614 5900
Ruari McGirr / Dan Gee-Summons (Corporate Finance)
Simon Johnson (Corporate Broking)

Citigate Dewe Rogerson	Tel: 020 7638 9571
Elizabeth Kittle

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.

Glossary

AAPG	American Association of Petroleum Geologists
Arkona	LLC Arkona Gas-Energy
bbl	barrel
bbl/d	barrels per day
Bm³	thousands of millions of cubic metres
boe	barrels of oil equivalent
boepd	barrels of oil equivalent per day
Bscf	thousands of millions of scf
C₁	reserves in deposits that were not put into commercial development and that may be the subject matter of production testing or individual well production testing
C₂	reserves in deposits that were not put into commercial development and that are developed based on a production testing plan or individual well production testing plan, matured with seismic exploration or other methods, and the availability of which is supported by geological and geophysical study data as well as testing data obtained from individual wells whilst drilling
Company	Enwell Energy plc
D&M	DeGolyer and MacNaughton
€	Euro
Group	Enwell Energy plc and its subsidiaries
km	kilometre
km²	square kilometre
LPG	liquefied petroleum gas
MEX-GOL	Mekhediviska-Golotvshinska
m³	cubic metres
m³/d	cubic metres per day
Mboe	thousand barrels of oil equivalent
Mm³	thousand cubic metres
MMbbl	million barrels
MMboe	million barrels of oil equivalent
MMm³	million cubic metres
MMscf	million scf
MMscf/d	million scf per day
Mtonnes	thousand tonnes
%	per cent
QCA Code	Quoted Companies Alliance Corporate Governance Code 2018
QHSE	quality, health, safety and environment
SC	Svystunivsko-Chervonolutskyi
scf	standard cubic feet measured at 20 degrees Celsius and one atmosphere
SPE	Society of Petroleum Engineers
SPEE	Society of Petroleum Evaluation Engineers
SV	Svyrydivske
$	United States Dollar
UAH	Ukrainian Hryvnia
VAS	Vasyschevskoye
VED	Vvdenska
WPC	World Petroleum Council

Chairman's Statement

I am delighted to present the 2020 Annual Report and Financial Statements. Whilst 2020 was an unprecedented year globally as a result of the COVID-19 pandemic, I am pleased to report that the Group has not been significantly affected on an operational level, and has achieved a robust performance despite the backdrop. The Group has continued to make good progress in the development of the MEX-GOL, SV and VAS gas and condensate fields in north-eastern Ukraine, and has delivered a solid financial performance during the year. Drilling of the SV-54 development well was successfully completed and brought on production in May 2020, whilst the SV-25 appraisal well was spudded in July 2020 and completed and brought on production in Q1 2021.

At the MEX-GOL and SV fields, production was stable during 2020, with higher production volumes compared with 2019. At the VAS field production was also steady, but lower than during 2019 after a decline in production from the VAS-10 well in late 2019.

Aggregate average daily production from the MEX-GOL, SV and VAS fields during 2020 was 4,541 boepd, which compares favourably with an aggregate daily production rate of 4,263 boepd during 2019, an increase of approximately 6.5%.

The Group delivered a solid financial performance for the year, despite the higher production levels being offset by a lower average gas price during the year, as a result of weakened European gas prices. During 2020, the Group achieved a net profit of $3.2 million (2019: $12.2 million) despite the weak gas prices, while cash generated from operations during the year was steady at $23.8 million (2019: $24.7 million), predominantly due to the higher production rates increasing non-cash depreciation, depletion and amortisation (DD&A).

The fiscal and economic environment in Ukraine remains stable, despite the effects of the COVID-19 pandemic resulting in a contraction in GDP and an increase in the rate of inflation, and recently Ukrainian Hryvnia exchange rates have been steady. Nevertheless, future fiscal and economic uncertainties remain in the Ukrainian market and we continue to be 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 2020, gas prices trended lower, reflecting a similar trend in European gas prices, and were lower than in 2019. Similarly, condensate and LPG prices were also lower by comparison with last year. However, prices have improved in 2021 to date.

Arkona Acquisition

As announced on 24 March 2020, the Group acquired the entire issued share capital of LLC Arkona Gas-Energy ("Arkona") for a 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.

However, NJSC Ukrnafta, the majority State-owned oil and gas producer, issued legal proceedings against Arkona, in which NJSC Ukrnafta made claims of irregularities in the procedures involved in the grant of the SC licence to Arkona in May 2017. In early July 2020, the First Instance Court in Ukraine made a ruling in favour of NJSC Ukrnafta, which found that the grant of the SC licence was irregular, but this ruling was overturned by the Appellate Administrative Court in September 2020, and a final appeal to the Supreme Court of Ukraine was determined in favour of Arkona in February 2021. Further information can be found in the Company's announcements dated 3 July 2020, 31 July 2020, 30 September 2020, 23 November 2020 and 11 February 2021.

With these legal issues now resolved, the Group has re-commenced planning for the development of this licence, and a new well is planned for later this year.

COVID-19 Pandemic

We continue to closely monitor the volatility in global financial markets, and the implications on the operational, economic and social environment caused by the COVID-19 pandemic, coupled with the weakened hydrocarbon 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, not only to protect our staff and other stakeholders, but also to minimise any potential disruption to our business. We have taken steps to continually monitor the health of our operational staff, including temperature checks for such staff at the commencement of each shift, as well as investing in technology to enable many staff to work from remote locations. We continue to reassess our medium-term forecasts based on current pricing and are highly confident we have the resources 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, as previously announced, in 2020 we 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. Our monetary contribution of $2 million to this initiative is reflected in the results for the year.

Outlook

Whilst there are still challenges in the business environment in Ukraine, the situation is relatively stable despite the COVID-19 outbreak. Following the steady operational performance during 2020, and the increased production output during the year, we are looking forward to the results of the SV-29 development well, which are expected in the fourth quarter of 2021. We are also looking forward to achieving further successes in the development activities planned for 2021 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 in the midst of the COVID-19 pandemic.

Chris Hopkinson

Chairman

Chief Executive's Statement

Introduction

The Group continued to make good progress at its Ukrainian fields during 2020, with development activity at the MEX-GOL and SV fields including successes with the drilling of the SV-54 development well, which came on production in May 2020 and the SV-25 appraisal well, which came on production in February 2021. In addition, work continued on the planning of an upgrade to the gas processing facilities, as well as work on upgrades to the flow-line network and remedial activity on existing wells.

At the VAS field, planning for a proposed new well to explore the VED prospect within the VAS licence area has continued, and upgrades to the gas processing facilities, flow-line network and other infrastructure are underway.

Overall production continued its upward trend during the year, achieving record levels for the Group and being approximately 6.5% higher than in 2019, with a substantial boost in May 2020, once the SV-54 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. The Group's QHSE policies and performance are overseen by the Health, Safety and Environment Committee. 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 2020, a total of 461,321 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 3,451,816 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 2020 was as follows:-

Field	Gas (MMscf/d)		Condensate (bbl/d)		LPG (bbl/d)		Aggregate boepd
	2020	2019	2020	2019	2020	2019	2020	2019
MEX-GOL & SV	17.6	14.8	640.6	577.8	295.3	274.4	3,960	3,391
VAS	2.9	4.4	32.2	61.9	-	-	581	872
Total	20.5	19.2	672.8	639.7	295.3	274.4	4,541	4,263

Production rates were higher in 2020 when compared with 2019, predominantly due to the contributions of the MEX-119 well, which commenced production in October 2019, and the SV-54 well, which commenced production in May 2020.

The Group's average daily production for the period from 1 January 2021 to 26 March 2021 from the MEX-GOL and SV field was 18.1 MMscf/d of gas, 634 bbl/d of condensate and 239 bbl/d of LPG (4,072 boepd in aggregate) and from the VAS field was 2.5 MMscf/d of gas and 28 bbls/d of condensate (499 boepd in aggregate).

Operations

Notwithstanding the impact of the COVID-19 pandemic during 2020, over recent periods, there have been relatively stable fiscal and economic conditions in Ukraine, as well as reductions in the subsoil tax rates and improvements in the regulatory procedures in the oil and gas sector in Ukraine , and this has given the Board confidence to continue the Group's development programme at its Ukrainian fields during 2020. 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 strategy 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 drilling of the SV-54 development well was completed to a final depth of 5,322 metres. One interval, at a drilled depth of 5,303 - 5,308 metres in the B-23 Visean formation, was perforated, and after successful testing, the well was hooked-up to the gas processing facilities in May 2020. In January 2021, additional intervals, at drilled depths of 5,143 - 5,146, 5,125 - 5,155 and 5,180 - 5,186 within the B-22 Visean formation were perforated. The well is currently producing at approximately 1.1 MMscf/d of gas and 25 bbl/d of condensate (212 boepd in aggregate).

In February 2021, the SV-25 appraisal well was completed, having been drilled to a final depth of 5,320 metres. One interval, at a drilled depth of 5,184 - 5,190 metres, within the B-22 Visean formation was perforated, and after successful testing, the well was hooked-up to the gas processing facilities. The well is currently producing at approximately 1.9 MMscf/d of gas and 80 bbl/d of condensate (423 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 VAS field, planning has continued 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 of 2019, 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 (as set out in the 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.

Arkona Acquisition

As announced on 24 March 2020, the Group acquired the entire issued share capital of LLC Arkona Gas-Energy ("Arkona") for a total consideration of up to $8.63 million, of which $4.32 million was subject to the satisfaction of certain conditions. Following satisfaction of the initial conditions, a second payment of $2.1 million (net of an indemnity liability) has been paid, and the balance of the consideration is subject to the remaining conditions. 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 covers 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 resources, such hydrocarbon resources 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.

However, NJSC Ukrnafta, as claimant, issued legal proceedings against Arkona, as defendant, in which NJSC Ukrnafta claimed that irregular procedures were adopted in the grant of the SC licence to Arkona in May 2017. NJSC Ukrnafta was the holder of a previous licence over this area which expired prior to the grant of the SC licence. In early July 2020, the First Instance Court in Ukraine announced a ruling in favour of NJSC Ukrnafta, which found that the grant of the SC licence was irregular, which would mean the licence is invalid. Arkona filed an appeal in the Appellate Administrative Court in Kyiv, which was determined in favour of Arkona in September 2020, as was a final appeal to the Supreme Court of Ukraine issued in February 2021. Further information can be found in the announcements dated 3 July 2020, 31 July 2020, 30 September 2020, 23 November 2020 and 11 February 2021.

With the resolution of these legal issues, the Group has re-commenced planning for the development of this licence, which includes the acquisition of 150 km² of 3D seismic and drilling of a new well, SVYST-4, both of which are planned to start later this year.

Outlook

During 2021, the Group will continue to develop the MEX-GOL, SV and VAS fields, as well as progressing the development planning for the SC licence . At the MEX-GOL and SV fields, the development programme includes continuing the drilling operations on the SV-29 development well, 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 flow-line network, and remedial and upgrade work on existing wells, pipelines and other infrastructure.

At the VAS field, a workover of the VAS-10 well has recently been completed to access an alternative production horizon, 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.

Ongoing legislative reforms and the general stability 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 the course of the year, and to especially recognise their continuing efforts and professionalism during the COVID-19 pandemic.

Sergii Glazunov

Chief Executive Officer

Overview of Assets

We operate four fields 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 an initial duration of 20 years, and the duration of these licences have recently been extended to 2040 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 253 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.

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.

SC field

The SC field is located near to and has similar characteristics to the SV field, and is prospective for gas and condensate.

Production Licence

We hold a 100% working interest in, and are the operator of, the SC field. The production licence for the field was granted in May 2017 with a duration of 20 years.

The licence extends over an area of 97 km² , and is located in the Poltava region in north-eastern Ukraine, approximately 15 km east of the SV field.

Geology

Geologically, the field is 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 depth between 4,600 and 6,000 metres.

Resources

The licence is prospective for gas and condensate, and has been the subject of exploration since the 1980s, with five wells having been drilled on the licence since then, although none of these wells are currently on production.

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 2020, the Group has produced 3.7 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:-

	Proved (1P)	Proved + Probable (2P)	Proved + Probable + Possible (3P)
Gas	121.9 Bscf / 3.5 Bm³	218.3 Bscf / 6.2 Bm³	256.5 Bscf / 7.3 Bm³
Condensate	4.3 MMbbl / 514 Mtonne	7.9 MMbbl / 943 Mtonne	9.2 MMbbl / 1,098 Mtonne
LPG	2.8 MMbbl / 233 Mtonne	5.0 MMbbl / 418 Mtonne	5.8 MMbbl / 491 Mtonne
Total	27.8 MMboe	50.0 MMboe	58.6 MMboe

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

	Contingent Resources (1C)	Contingent Resources (2C)	Contingent Resources (3C)
Gas	14.7 Bscf / 0.42 Bm³	38.3 Bscf / 1.08 Bm³	105.9 Bscf / 3.00 Bm³
Condensate	1.17 MMbbl / 144 Mtonne	2.8 MMbbl / 343 Mtonne	6.6 MMbbl / 812 Mtonne
Total	3.8 MMboe	9.6 MMboe	25.3 MMboe

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 2020, 0.5 MMboe were produced from the field.

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

	Proved (1P)	Proved + Probable (2P)	Proved + Probable + Possible (3P)
Gas	9,114 MMscf / 258 MMm³	15,098 MMscf / 427 MMm³	18,816 MMscf / 533 MMm³
Condensate	205 Mbbl / 25 Mtonne	346 Mbbl / 42 Mtonne	401 Mbbl / 48 Mtonne
Total	1.895 MMboe	3.145 MMboe	3.890 MMboe

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

Contingent Resources (1C)

Contingent Resources (2C)

Contingent Resources (3C)

Gas

2,912 MMscf / 83 MMm³

Condensate

74 Mbbl / 9 Mtonne

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

Low (1U)

Best (2U)

High (3U)

Mean

Gas

23,721 MMscf / 672 MMm³

38,079 MMscf / 1,078 MMm³

62,293 MMscf / 1,764 MMm³

41,291 MMscf / 1,169 MMm³

Finance Review

The Group's financial performance in 2020 was shaped largely by two factors, the significant drop in average gas realisations (which had started in 2019) materially affecting revenue but partly mitigated by the record level of gas production, and sale of gas from storage. Despite the challenges during the year, the Group made a net profit of $3.2 million (2019: $12.2 million).

Gross profit for the year was $15.7 million (2019: $23.5 million). The 33% decrease in gross profit year-on-year is almost entirely a result of significantly weakened gas prices in the year. Average gas realisations in the period were down 38% at $136/Mm³ (UAH3,618/Mm³), with condensate and LPG sales also down by 21% and 16% at $46/bbl and $46/bbl respectively (2019: $219/Mm³ (UAH5,729/Mm³), $58/bbl and $55/bbl respectively).

Revenue for the year, derived from the sale of the Group's Ukrainian gas, condensate and LPG production, was $47.3 million (2019: $55.9 million). Despite the gas price-driven fall in revenue, the cash generated from operations was only down 3.8% at $23.8 million (2019: $24.7 million) predominantly as a result of higher non-cash DD&A of $12.7 million compared to $10.2 million in 2019, less interest income recorded in the operating profit ($1.5 million compared to $4.8 million in 2019), and a $2.6 million draw of 24 MMm³ of gas from inventory in the period compared to a $3.2 million build to inventory in 2019.

During the period from 1 January 2021 to 26 March 2021, the average realised gas, condensate and LPG prices were $232/Mm³ (UAH6,489/Mm³), $66/bbl and $64/bbl respectively.

The significantly lower average realised gas price had the greatest impact on the Group's 2020 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 2020 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 2020. During 2021 to date however, there has been a sustained recovery in prices (a function of a more general recovery in European commodity prices, as well as Ukraine experiencing one of the coldest winters in a decade).

Cost of sales for the 2020 year was marginally lower at $31.5 million (2019: $32.4 million). Whilst broadly consistent with last year, there were some significant movements within this total: depreciation of property plant and equipment was 26% higher at $11.5 million (2019: $9.1 million) as a result of higher levels of production; production taxes declined by 19% as a result of reduced gas revenues, in turn a function of the reduced gas prices as noted above; a 42% decrease in rent expense, a function of lower well profitability in the period despite increased production; and staff costs increased by 31% as a function of a 2% increase in the number of staff, in combination with salary inflation,

The subsoil tax rates applicable to gas production were stable during the period at 29% for gas produced from deposits at depths shallower than 5,000 metres and 14% for gas produced from deposits deeper than 5,000 metres, but reductions in the subsoil rates applicable to new wells and to condensate production were applicable, under which (i) for new wells drilled after 1 January 2018, the subsoil tax rates were reduced from 29% to 12% for gas produced from deposits at depths shallower than 5,000 metres and from 14% to 6% for gas produced from deposits deeper than 5,000 metres for the period between 2018 and 2022, and (ii) with effect from 1 January 2019 and applicable to all wells, the subsoil tax rates for condensate were reduced from 45% to 31% for condensate produced from deposits shallower than 5,000 metres and from 21% to 16% for condensate produced from deposits deeper than 5,000 metres.

Administrative expenses for the year were marginally higher at $7.8 million (2019: $7.4 million), primarily as a result of: a 46% increase in consultancy fees mainly due to legal and advisory costs associated with the acquisition activity in the year; a 6% increase in payroll and related taxes, consistent with the increased staff level and salary inflation noted above; all partially mitigated by a 30% decrease in other expenses primarily in relation to decreased costs for managing gas transportation and storage, and marketing.

Other losses in the year reduced by 22% in the period, a net effect of: a foreign exchange gain in the period of $0.3 million compared to a loss of $1.5 million in 2019; no VAT credit in the period compared to the $0.5 million charge in 2019; and the charitable donations of $2.1 million (2019: nil) for the supply of COVID-19-related medical equipment for Ukrainian authorities and charitable foundations .

The tax charge for the year reduced by 65% to $3.3 million (2019: $9.6 million charge) mainly due to the decrease in profit before tax, and comprises a current tax charge of $3.0 million (2019: $4.8 million charge) and a deferred tax charge of $0.3 million (2019: $4.8 million charge).

A deferred tax asset relating to the Group's provision for decommissioning at 31 December 2020 of $0.2 million (2019: $0.3 million) was recognised on the tax effect of the temporary differences of the Group's provision for decommissioning at the MEX-GOL and SV fields, and its tax base. A deferred tax liability relating to the Group's development and production assets at the MEX-GOL and SV fields at 31 December 2020 of $2.9 million (2019: $2.5 million) was recognised on the tax effect of the temporary differences between the carrying value of the Group's development and production asset at the MEX-GOL and SV fields, and its tax base.

A deferred tax asset relating to the Group's provision for decommissioning at 31 December 2020 of $0.3 million (2019: $0.3 million) was recognised on the tax effect of the temporary differences on the Group's provision on decommissioning at the VAS field, and its tax base. A deferred tax liability relating to the Group's development and production assets at the VAS field at 31 December 2020 of $0.2 million (2019: $0.5 million) was recognised on the tax effect of the temporary differences between the carrying value of the Group's development and production asset at the VAS field, and its tax base.

Capital investment of $18.2 million reflects the investment in the Group's oil and gas development and production assets during the year (2019: $17.7 million), primarily relating to the drilling of the SV-54 and SV-25 wells. The carrying value of the Group's assets was reviewed at the 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 2020 were $61.0 million (2019: $62.5 million). The Group's cash and cash equivalents balance at 29 March 2021 was $60.9 million, held as to $22.8 million equivalent in Ukrainian Hryvnia and the balance of $38.1 million equivalent predominantly in US Dollars, Euros and Pounds Sterling.

Between early 2014 and 2019, the Ukrainian Hryvnia devalued significantly against the US Dollar, falling from UAH8.3/$1.00 on 1 January 2014 to UAH23.7/$1.00 on 31 December 2019, 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. During 2020, global financial markets became extremely volatile due to a combination of a significant fall, and then gradual recovery, in oil prices and the effects of the COVID-19 pandemic, and the Ukrainian Hryvnia weakened against the US Dollar with the exchange rate at 31 December 2020 being UAH28.3/$1.00. The impact of this devaluation was $15 million of foreign exchange losses (2019: $12 million of foreign exchange gain). 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 2021 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. With cash resources at the end of the period of $61 million, and annual running costs of less than $8 million, the Group remains in a very strong position should any local or global shocks occur to the industry and/or the Group. In making this assessment, the Group has forecast future cash flows under severe but reasonably plausible downside scenarios.

The Parent Company has recorded credit of $87.3 million, being the net change in credit loss allowance for loans issued to subsidiaries in its statement of profit or loss for the year ended 31 December 2020 (see Note 3). This credit was calculated following a review of the underlying cash flow forecasts of the subsidiaries and is due to an increase in gas prices forecast and the termination of the proposed acquisition of PJSC Science and Production Concern Ukrnaftinvest. The Parent Company has also recorded a loss of $30.1 million, being the net change in credit loss allowance for shares in subsidiary undertakings.

In 2020, after a Group restructuring, the Parent Company transferred $40 million from loans to subsidiaries to investments in subsidiaries as a result of the offsetting of payables for corporate rights, which did not impact the consolidated financial statements. Further details can be found in Note 19 below.

On 25 February 2021, the Company completed a reduction of its share capital through the cancellation of its entire share premium account. This reduction of capital creates distributable reserves of the Company, which enable the Company to make distributions to its shareholders in the future, subject to the Company's financial performance. However, the Company is not indicating any commitment, and does not have any current intention, to make any distributions to shareholders.

Bruce Burrows

Finance Director

Principal Risks and How We Manage Them

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:-

Risk	Mitigation
External risks
Risk relating to Ukraine
Ukraine is an emerging market and as such the Group is exposed to greater regulatory, economic and political risks than it would be in other jurisdictions. Emerging economies are generally subject to a volatile political and economic environment, which makes them vulnerable to market downturns elsewhere in the world and could adversely impact the Group's ability to operate in the market.	The Group minimises this risk by continuously monitoring the market in Ukraine and by maintaining a strong working relationship with the Ukrainian regulatory authorities. The Group also maintains a significant proportion of its cash holdings in international banks outside Ukraine.
Regional conflict
Ukraine continues to have a strained relationship with Russia, following Ukraine's agreement to join a free trade area with the European Union, which resulted in the implementation of mutual trade restrictions between Russia and Ukraine on many key products. Further, the conflict in parts of eastern Ukraine has not been resolved to date, and Russia continues to occupy Crimea. This conflict has put further pressure on relations between Ukraine and Russia, and the political tensions have had an adverse effect on the Ukrainian financial markets, hampering the ability of Ukrainian companies and banks to obtain funding from the international capital and debt markets. This strained relationship between Russia and Ukraine has also resulted in disputes and interruptions in the supply of gas from Russia.	As the Group has no assets in Crimea or the areas of conflict in the east of Ukraine, nor do its operations rely on sales or costs incurred there, the Group has not been directly affected by the conflict. However, the Group continues to monitor the situation and endeavours to procure its equipment from sources in other markets. The disputes and interruption to the supply of gas from Russia has indirectly encouraged Ukrainian Government support for the development of the domestic production of hydrocarbons since Ukraine imports a significant proportion of its gas, which has resulted in legislative measures to improve the regulatory requirements for hydrocarbon extraction in Ukraine.
Banking system in Ukraine
The banking system in Ukraine has been under great strain in recent years due to the weak level of capital, low asset quality caused by the economic situation, currency depreciation, changing regulations and other economic pressures generally, and so the risks associated with the banks in Ukraine have been significant, including in relation to the banks with which the Group has operated bank accounts. However, following remedial action imposed by the National Bank of Ukraine, Ukraine's banking system has improved moderately. Nevertheless, Ukraine continues to be supported by funding from the International Monetary Fund.	The creditworthiness and potential risks relating to the banks in Ukraine are regularly reviewed by the Group, but the geopolitical and economic events since 2013 in Ukraine have significantly weakened the Ukrainian banking sector. In light of this, the Group has taken and continues to take steps to diversify its banking arrangements between a number of banks in Ukraine. These measures are designed to spread the risks associated with each bank's creditworthiness, and the Group endeavours to use banks that have the best available creditworthiness. Nevertheless, and despite the recent improvements, the Ukrainian banking sector remains weakly capitalised and so the risks associated with the banks in Ukraine remain significant, including in relation to the banks with which the Group operates bank accounts. As a consequence, the Group also maintains a significant proportion of its cash holdings in international banks outside Ukraine.
Geopolitical environment in Ukraine
Although there have been some improvements in recent years, there has not been a final resolution of the political, fiscal and economic situation in Ukraine and its ongoing effects are difficult to predict and likely to continue to affect the Ukrainian economy and potentially the Group's business. Whilst not materially affecting the Group's production operations, the instability has disrupted the Group's development and operational planning for its assets.	The Group continually monitors the market and business environment in Ukraine and endeavours to recognise approaching risks and factors that may affect its business. In addition, the involvement of Smart Holding (Cyprus) Limited, as an indirect major shareholder with extensive experience in Ukraine, is considered helpful to mitigate such risks.
Climate change
Any near and medium-term continued warming of the Planet can have potentially increasing negative social, economic and environmental consequences, generally globally and regionally, and specifically in relation to the Group. The potential impacts include: loss of market; and increased costs of operation through increasing regulatory oversight and controls, including potential effective or actual loss of licence to operate. As a diligent operator aware and responsive to its good stewardship responsibilities, the Group not only needs to monitor and modify its business plans and operations to react to changes, but also to ensure its environmental footprint is as minimal as it can practicably be in managing the hydrocarbon resources the Group produces.	The Group's plans include: assessing, reducing and/or mitigating its emissions in its operations ; and identifying climate change-related risks and assessing the degree to which they can affect its business, including financial implications. The HSE Committee, which was established in 2020, is specifically tasked with overseeing measuring, benchmarking and mitigating the Group's environmental and climate impact, which will be reported on in future periods. At this stage, the Group does not consider climate change to have any material implications on the Group's financial statements, including the accounting estimates.
Operational and technical risks
Quality, Health, Safety and Environment ("QHSE")
The oil and gas industry, by its nature, conducts activities which can cause health, safety, environmental and security incidents. Serious incidents can not only have a financial impact but can also damage the Group's reputation and the opportunity to undertake further projects. As evidenced by events in 2020, pandemics also pose a risk to operations, by potential illness and threat to life of employees and contractors, and the associated disruptions in staffing levels, operations and supply chain.	The Group maintains QHSE policies and requires that management, staff and contractors adhere to these policies. The policies ensure that the Group meets Ukrainian legislative standards in full and achieves international standards to the maximum extent possible. As a consequence of the COVID-19 pandemic the Group is re-visiting processes and controls intended to ensure protection of all our stakeholders and minimise any disruption to our business. Whilst possible to only a limited extent in field operations, we have invested in technology that will allow many staff to work just as effectively from remote locations.
Industry risks
The Group is exposed to risks which are generally associated with the oil and gas industry. For example, the Group's ability to pursue and develop its projects and development programmes depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, gas, oil, condensate and LPG prices, development costs and drilling success. As a result of these uncertainties, it is unknown whether potential drilling locations identified on proposed projects will ever be drilled or whether these or any other potential drilling locations will be able to produce gas, oil or condensate. In addition, drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Drilling for hydrocarbons can be unprofitable, not only due to dry holes, but also as a result of productive wells that do not produce sufficiently to be economic. In addition, drilling and production operations are highly technical and complex activities and may be curtailed, delayed or cancelled as a result of a variety of factors.	The Group has well qualified and experienced technical management staff to plan and supervise operational activities. In addition, the Group engages with suitably qualified local and international geological, geophysical and engineering experts and contractors to supplement and broaden the pool of expertise available to the Group. Detailed planning of development activities is undertaken with the aim of managing the inherent risks associated with oil and gas exploration and production, as well as ensuring that appropriate equipment and personnel are available for the operations, and that local contractors are appropriately supervised.
Production of hydrocarbons
Producing gas and condensate reservoirs are generally characterised by declining production rates which vary depending upon reservoir characteristics and other factors. Future production of the Group's gas and condensate reserves, and therefore the Group's cash flow and income, are highly dependent on the Group's success in operating existing producing wells, drilling new production wells and efficiently developing and exploiting any reserves, and finding or acquiring additional reserves. The Group may not be able to develop, find or acquire reserves at acceptable costs. The experience gained from drilling undertaken to date highlights such risks as the Group targets the appraisal and production of these hydrocarbons.	In 2016, the Group engaged external technical consultants to undertake a comprehensive review and re-evaluation study of the MEX-GOL and SV fields in order to gain an improved understanding of the geological aspects of the fields and reservoir engineering, drilling and completion techniques, and the results of this study and further planned technical work is being used by the Group in the future development of these fields. The Group has established an ongoing relationship with such external technical consultants to ensure that technical management and planning is of a high quality in respect of all development activities on the Group's fields.
Risks relating to further development and operation of the Group's gas and condensate fields in Ukraine
The planned development and operation of the Group's gas and condensate fields in Ukraine is susceptible to appraisal, development and operational risk. This could include, but is not restricted to, delays in delivery of equipment in Ukraine, failure of key equipment, lower than expected production from wells that are currently producing, or new wells that are brought on-stream, problematic wells and complex geology which is difficult to drill or interpret. The generation of significant operational cash is dependent on the successful delivery and completion of the development and operation of the fields.	The Group's technical management staff, in consultation with its external technical consultants, carefully plan and supervise development and operational activities with the aim of managing the risks associated with the further development of the Group's fields in Ukraine. This includes detailed review and consideration of available subsurface data, utilisation of modern geological software, and utilisation of engineering and completion techniques developed for the fields. With operational activities, the Group ensures that appropriate equipment and personnel is available for the operations, and that operational contractors are appropriately supervised. In addition, the Group performs a review of its oil and gas assets for impairment on an annual basis, and considers whether an assessment of its oil and gas assets by a suitably qualified independent assessor is appropriate or required.
Drilling and workover operations
Due to the depth and nature of the reservoirs in the Group's fields, the technical difficulty of drilling or re-entering wells in the Group's fields is high, and this and the equipment limitations within Ukraine, can result in unsuccessful or lower than expected outcomes for wells.	The utilisation of detailed sub-surface analysis, careful well planning and engineering design in designing work programmes, along with appropriate procurement procedures and competent on-site management, aims to minimise these risks.
Maintenance of facilities
There is a risk that production or transportation facilities can fail due to non-adequate maintenance, control or poor performance of the Group's suppliers.	The Group's facilities are operated and maintained at standards above the Ukrainian minimum legal requirements. Operations staff are experienced and receive supplemental training to ensure that facilities are properly operated and maintained. Service providers are rigorously reviewed at the tender stage and are monitored during the contract period.
Financial risks
Exposure to cash flow and liquidity risk
There is a risk that insufficient funds are available to meet the Group's development obligations to commercialise the Group's oil and gas assets. Since a significant proportion of the future capital requirements of the Group is expected to be derived from operational cash generated from production, including from wells yet to be drilled, there is a risk that in the longer term insufficient operational cash is generated, or that additional funding, should the need arise, cannot be secured.	The Group maintains adequate cash reserves and closely monitors forecasted and actual cash flow, as well as short and longer-term funding requirements. The Group does not currently have any loans outstanding, internal financial projections are regularly made based on the latest estimates available, and various scenarios are run to assess the robustness of the liquidity of the Group. However, as the risk to future capital funding is inherent in the oil and gas exploration and development industry and reliant in part on future development success, it is difficult for the Group to take any other measures to further mitigate this risk, other than tailoring its development activities to its available capital funding from time to time.
Ensuring appropriate business practices
The Group operates in Ukraine, an emerging market, where certain inappropriate business practices may, from time to time occur, such as corrupt business practices, bribery, appropriation of property and fraud, all of which can lead to financial loss.	The Group maintains anti-bribery and corruption policies in relation to all aspects of its business, and ensures that clear authority levels and robust approval processes are in place, with stringent controls over cash management and the tendering and procurement processes. In addition, office and site protection is maintained to protect the Group's assets.
Hydrocarbon price risk
The Group derives its revenue principally from the sale of its Ukrainian gas, condensate and LPG production. These revenues are subject to commodity price volatility and political influence. A prolonged period of low gas, condensate and LPG prices may impact the Group's ability to maintain its long-term investment programme with a consequent effect on its growth rate, which in turn may impact the share price or any shareholder returns. Lower gas, condensate and LPG prices may not only decrease the Group's revenues per unit, but may also reduce the amount of gas, condensate and LPG which the Group can produce economically, as would increases in costs associated with hydrocarbon production, such as subsoil taxes and royalties. The overall economics of the Group's key assets (being the net present value of the future cash flows from its Ukrainian projects) are far more sensitive to long term gas, condensate and LPG prices than short-term price volatility. However, short-term volatility does affect liquidity risk, as, in the early stage of the projects, income from production revenues is offset by capital investment.	The Group sells a proportion of its hydrocarbon production through long-term offtake arrangements, which include pricing formulae so as to ensure that it achieves market prices for its products, as well utilising the electronic market platforms in Ukraine to achieve market prices for its remaining products. However, hydrocarbon prices in Ukraine are implicitly linked to world hydrocarbon prices and so the Group is subject to external price trends.
Currency risk
Since the beginning of 2014 , the Ukrainian Hryvnia significantly devalued against major world currencies, including the US Dollar, where it has fallen from UAH8.3/$1.00 on 1 January 2014 to UAH28.3/$1.00 on 31 December 2020. This devaluation through to 2020 was a significant contributor to the imposition of the banking restrictions by the National Bank of Ukraine over recent years. In addition, the geopolitical events in Ukraine over recent years, are likely to continue to impact the valuation of the Ukrainian Hryvnia against major world currencies. Further devaluation of the Ukrainian Hryvnia against the US Dollar will affect the carrying value of the Group's assets.	The Group's sales proceeds are received in Ukrainian Hryvnia, and the majority of the capital expenditure costs for the current investment programme will be incurred in Ukrainian Hryvnia, thus the currency of revenue and costs are largely matched. In light of the previous devaluation and volatility of the Ukrainian Hryvnia against major world currencies, and since the Ukrainian Hryvnia does not benefit from the range of currency hedging instruments which are available in more developed economies, the Group has adopted a policy that, where possible, funds not required for use in Ukraine be retained on deposit in the United Kingdom and Europe, principally in US Dollars.
Counterparty and credit risk
The challenging political and economic environment in Ukraine means that businesses can be subject to significant financial strain, which can mean that the Group is exposed to increased counterparty risk if counterparties fail or default in their contractual obligations to the Group, including in relation to the sale of its hydrocarbon production, resulting in financial loss to the Group.	The Group monitors the financial position and credit quality of its contractual counterparties and seeks to manage the risk associated with counterparties by contracting with creditworthy contractors and customers. Hydrocarbon production is sold on terms that limit supply credit and/or title transfer until payment is received .
Financial markets and economic outlook
The performance of the Group is influenced by global economic conditions and, in particular, the conditions prevailing in the United Kingdom and Ukraine. The economies in these regions have been subject to volatile pressures in recent periods, with the global economy having experienced a long period of difficulties, and more particularly the events that have occurred in Ukraine over recent years. This has led to extreme foreign exchange movements in the Ukrainian Hryvnia , high inflation and interest rates, and increased credit risk relating to the Group's key counterparties.	The Group's sales proceeds are received in Ukrainian Hryvnia and a significant proportion of investment expenditure is made in Ukrainian Hryvnia , which minimises risks related to foreign exchange volatility. However, hydrocarbon prices in Ukraine are implicitly linked to world hydrocarbon prices and so the Group is subject to external price movements. The Group holds a significant proportion of its cash reserves in the United Kingdom and Europe, mostly in US Dollars, with reputable financial institutions. The financial status of counterparties is carefully monitored to manage counterparty risks. Nevertheless, the risks that the Group faces as a result of these risks cannot be predicted and many of these are outside of the Group's control.
Corporate risks
Ukraine production licences
The Group operates in a region where the right to production can be challenged by State and non-State parties. During 2010, this manifested itself in the form of a Ministry Order instructing the Group to suspend all operations and production from its MEX-GOL and SV production licences, which was not resolved until mid-2011. In 2013, new rules relating to the updating of production licences led to further challenges being raised by the Ukrainian authorities to the production licences held by independent oil and gas producers in Ukraine, including the Group. In March 2019, a Ministry Order was issued instructing the Group to suspend all operations and production from its VAS production licence. The Group is challenging this Order through legal proceedings, during which production from the licence is continuing, but this matter remains unresolved. In 2020, LLC Arkona Gas-Energy ("Arkona") faced a challenge from NJSC Ukrnafta concerning the validity of its SC production licence , which was ultimately resolved in Arkona's favour by a decision of the Supreme Court of Ukraine in February 2021. All such challenges affecting the Group have thus far been successfully defended through the Ukrainian legal system. However, the business environment is such that these types of challenges may arise at any time in relation to the Group's operations, licence history, compliance with licence commitments and/or local regulations. In addition, production licences in Ukraine are issued with and/or carry ongoing compliance obligations, which if not met, may lead to the loss of a licence.	The Group ensures compliance with commitments and regulations relating to its production licences through Group procedures and controls or, where this is not immediately feasible for practical or logistical considerations, seeks to enter into dialogue with the relevant Government bodies with a view to agreeing a reasonable time frame for achieving compliance or an alternative, mutually agreeable course of action. Work programmes are designed to ensure that all licence obligations are met and continual interaction with Government bodies is maintained in relation to licence obligations and commitments.
Risks relating to key personnel
The Group's success depends upon skilled management as well as technical expertise and administrative staff. The loss of service of critical members from the Group's team could have an adverse effect on the business.	The Group periodically reviews the compensation and contractual terms of its staff. In addition, the Group has developed relationships with a number of technical and other professional experts and advisers, who are used to provided specialist services as required.

Consolidated Income Statement

for the year ended 31 December 2020


		2020	2019
	Note	$000	$000

Revenue	5	47,251	55,931
Cost of sales	6	(31, 511 )	(32,415)
Gross profit		15, 740	23,516
Administrative expenses	7	(7,791)	(7,396)
Other operating gains, (net)	10	1, 821	4,973
Operating profit		9, 770	21,093
Finance income	11	-	3,487
Finance costs	12	(1,418)	(450)
Net impairment gains on financial assets		24	32
Other losses (net)	13	(1,856)	(2,394)
Profit before taxation		6, 520	21,768
Income tax expense	14	(3,332)	(9,569)
Profit for the year		3, 188	12,199
Earnings per share (cents)
Basic and diluted	16	1.0c	3.8c

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

Consolidated Statement of Comprehensive Income

for the year ended 31 December 2020

	2020	2019
	$000	$000

Profit for the year	3, 188	12,199

Other comprehensive (expense)/income :
Items that may be subsequently reclassified to profit or loss: Equity - foreign currency translation	(15,050)	12,089
Items that will not be subsequently reclassified to profit or loss:
Re-measurements of post-employment benefit obligations	(73)	165


Total other comprehensive (expense)/income	(15,123)	12,254


Total comprehensive (expense)/income for the year	(1 1 , 935 )	24,453

Company Statement of Comprehensive Income

for the year ended 31 December 2020

	Note	2020	2019
		$000	$000

Profit / (loss) for the year	15	59,454	(17,507)


Total comprehensive income / (expense) for the year		59,454	(17,507)

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

Consolidated Balance Sheet

as at 31 December 2020


		2020	2019
	Note	$000	$000
Assets
Non-current assets
Property, plant and equipment	17	65, 662	70,052
Intangible assets	18	12,232	5,197
Right-of-use assets	19	512	940
Prepayment for shares		-	500
Corporation tax receivable		9	10
Deferred tax asset	26	167	-
		78, 582	76,699

Current assets
Inventories	21	1,541	4,813
Trade and other receivables	22	4,847	10,937
Cash and cash equivalents	23	60,993	62,474
		67,381	78,224

Total assets		145, 963	154,923

Liabilities
Current liabilities
Trade and other payables	24	(6,641)	(3,968)
Lease liabilities	19	(245)	(454)
Corporation tax payable		(1,062)	(2,221)
		(7,948)	(6,643)

Net current assets		59,433	71,581

Non-current liabilities
Provision for decommissioning	25	(6,819)	(7,447)
Lease liabilities	19	(371)	(515)
Defined benefit liability		(530)	(480)
Deferred tax liability	26	(2,705)	(2,288)
Other non-current liabilities	4	(1,975)	-
		(12,400)	(10,730)

Total liabilities		(20,348)	(17,373)

Net assets		125, 615	137,550

Equity
Called up share capital	27	28,115	28,115
Share premium account		555,090	555,090
Foreign exchange reserve	28	(105,222)	(90,172)
Other reserves	28	4,273	4,273
Accumulated losses		(356, 641 )	(359,756)
Total equity		125, 615	137,550

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

Consolidated Statement of Changes in Equity

as at 31 December 2020


	Called up share capital	Share premium account	Merger Reserve	Capital contributions reserve	Foreign exchange reserve*	Accumulated losses	Total equity
	$000	$000	$000	$000	$000	$000	$000

As at 1 January 2019	28,115	555,090	(3,204)	7,477	(102,261)	(372,120)	113,097
Profit for the year	-	-	-	-	-	12,199	12,199
Other comprehensive income - exchange differences	-	-	-	-	12,089	-	12,089
- re-measurements of post-employment benefit obligations	-	-	-	-	-	165	165
Total comprehensive income	-	-	-	-	12,089	12,364	24,453
As at 31 December 2019	28,115	555,090	(3,204)	7,477	(90,172)	(359,756)	137,550

	Called up share capital	Share premium account	Merger Reserve	Capital contributions reserve	Foreign exchange reserve*	Accumulated losses	Total equity
	$000	$000	$000	$000	$000	$000	$000

As at 1 January 2020	28,115	555,090	(3,204)	7,477	(90,172)	(359,756)	137,550
Profit for the year	-	-	-	-	-	3, 188	3, 188
Other comprehensive expense - exchange differences	-	-	-	-	(15,050)	-	(15,050)
- re-measurements of post-employment benefit obligations	-	-	-	-	-	(73)	(73)
Total comprehensive expense	-	-	-	-	(15,050)	3, 115	(1 1 , 935 )
As at 31 December 2020	28,115	555,090	(3,204)	7,477	(105,222)	(356, 641 )	125, 615
* Predominantly as a result of exchange differences on non-monetary assets and liabilities where the subsidiaries' functional currency is not the US Dollar.

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

Consolidated Cash Flow Statement

for the year ended 31 December 2020

		2020	2019
	Note	$000	$000

Operating activities
Cash generated from operations	29	2 3 ,7 64	24,708
Charitable donations	13	(2,077)	( 107 )
Income tax paid		(3,850)	(3,963)
Interest received		1,487	4,809
Net cash inflow from operating activities		19,324	25,447

Investing activities
Disposal of subsidiary		-	(7)
Purchase of property, plant and equipment		(12,749)	(19,050)
Purchase of intangible assets		(4,348)	(124)
Proceeds from return of prepayments for shares		250	-
Prepayment for shares		-	(500)
Proceeds from sale of property, plant and equipment		4	16
Net cash (outflow)/inflow from investing activities		(16,843)	(19,665)

Financing activities
Payment of principal portion of lease liabilities		(543)	(488)
Net cash outflow from financing activities		(543)	(488)

Net increase in cash and cash equivalents		1,938	5,294
Cash and cash equivalents at beginning of year		62,474	53,222
ECL of cash and cash equivalents		(6)	(7)
Effect of foreign exchange rate changes		(3,413)	3,965
Cash and cash equivalents at end of year	23	60,993	62,474

ECL - Expected credit losses

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 2020 or 2019, 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 2020 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 accounting standards in conformity with the requirements of the Companies Act 2006 ("framework"), this announcement does not itself contain sufficient information to comply with the framework. The Company expects to distribute the full financial statements that comply with IFRS in May/June 2021.

2. General Information and Operational Environment

Enwell Energy plc (formerly named 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 operated by 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 2020 and 2019, the Company's immediate parent company was Smart Energy (CY) Ltd (formerly named Pelidona Services Ltd) , which is 100% owned by Smart Holding (Cyprus) Ltd (formerly named Lovitia Investments Ltd) 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.

The macroeconomic situation in Ukraine during the first months of 2020 was reasonably stable, and this facilitated stability of the financial system. During 2020, consumer inflation in Ukraine was 5% (compared to 4.1% in 2019). However, internal and external factors that began to impact the Ukrainian economy in the second half of 2019, and which significantly strengthened in 2020, resulted in devaluation of the Ukrainian Hryvnia. As at 31 December 2020, the official National Bank of Ukraine ("NBU") exchange rate of the Ukrainian Hryvnia against the US Dollar was UAH28.27/$1.00, compared with UAH23.69/$1.00 as at 31 December 2019.

The repayment period of the sovereign debt owed by Ukraine to maintain the liquidity position during the crisis periods is being continually extended. The foreign currency sovereign debt repayments remain concentrated. In 2020-2022, the foreign currency repayments of the Ukrainian Government and the NBU including interest payments will cumulatively exceed $24 billion. The major portion of this amount is expected to be refinanced in external markets.

In the subsequent periods, the key macroeconomic risk is represented by significant sovereign debt repayments. Accordingly, implementation of the new International Monetary Fund programme and terms of cooperation with other international financial organisations remain critically important.

As of the end of 2019, the NBU set its discount rate at 13.5%. During 2020, the monetary policy was further eased and the NBU's discount rate was decreased to 6% as at the end of the year. On 4 March 2021, the NBU increased the discount rate to 6.5%. Rapid developments driven by the coronavirus spread resulted in liquidity gaps of certain banks and a growth in demand for interbank credit facilities. To support financial stability, the NBU changed the operational design of its monetary policy, implemented long-term refinancing of banks, supported banks with foreign currency, postponed formation of the capital buffer by banks, and proposed that banks implement a special grace period of loan servicing over the coronavirus quarantine period for both consumers and businesses.

A significant number of companies in Ukraine had to terminate or limit their operations for the coronavirus quarantine restriction period. Measures taken to constrain the spread of the coronavirus, including quarantine, social distancing and suspension of social infrastructure activities, have impacted economic activities of companies in Ukraine, including the Group.

The Ukrainian Government formed after parliamentary elections in July 2019 was dissolved on 4 March 2020 and a new Government was appointed. Amid political changes, the degree of uncertainty including in respect of the future direction of the reforms in Ukraine remains very high. In addition, negative trends in global markets due to the coronavirus pandemic may further affect the Ukrainian economy. The final resolution and the ongoing effects of the political and economic situation are difficult to predict but they may have further severe effects on the Ukrainian economy and the Group's business .

As at 30 March 2021, the official NBU exchange rate of the Ukrainian Hryvnia against the US Dollar was UAH27.97/$1.00, compared with UAH28.27/$1.00 as at 31 December 2020.

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 in accordance with international accounting standards in conformity with the requirements of the Companies Act 2006 (the "framework") and the applicable legal requirements of the Companies Act 2006. These consolidated financial statements are prepared under the historical cost convention as modified by 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.

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

Going Concern

The Group's business activities, together with the factors likely to affect its future operations, performance and position are set out in the Chairman's Statement, Chief Executive's Statement and Finance Review. The financial position of the Group, its cash flows and liquidity position are set out in these consolidated financial statements.

The Directors are carefully monitoring the evolving situation with respect to the coronavirus pandemic and maintain a significant level of financial flexibility to modify the Group's development plans as may be required in order to preserve cash resources, using base, low and high cases for liquidity management.

As part of their Going Concern review conducted in mid-March 2021, the Directors have analysed the Group's cash flow forecasts and considered a severe but possible downside case scenario, being: a low case production profile; forward curve commodity prices being reduced by 20%; and all non-production costs being maintained at current levels with no reduction as would otherwise be possible.

In the Directors' view, while this scenario constitutes a remote possibility, it demonstrates that the Group would be able to operate well within its current financing arrangements.

New and amended standards adopted by the Group

A number of new or amended standards became applicable for the current reporting period. The following amendments to standards, which are relevant to the Group's consolidated financial statements, have been issued:

Definition of a business - Amendments to IFRS 3 (issued on 22 October 2018 and effective for acquisitions from the beginning of annual reporting period that starts on or after 1 January 2020). The amendments revise the 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 there 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 the gross assets acquired is concentrated in a single asset (or a group of similar assets).

COVID-19-Related Rent Concessions Amendment to IFRS 16 issued on 28 May 2020 and effective for annual periods beginning on or after 1 June 2020. The amendment provides lessees with relief in the form of an optional exemption from assessing whether a rent concession related to COVID-19 is a lease modification. Lessees can elect to account for rent concessions in the same way as if they were not lease modifications. The practical expedient only applies to rent concessions occurring as a direct consequence of the COVID-19 pandemic and only if all of the following conditions are met: the change in lease payments results in revised consideration for the lease that is substantially the same as, or less than, the consideration for the lease immediately preceding the change; any reduction in lease payments affects only payments due on or before 30 June 2021; and there is no substantive change to the other terms and conditions of the lease.

The Group had to change its accounting policies as a result of the adoption of amendments to IFRS 3, however this change had no impact on the reporting period.

The following amended standards became effective from 1 January 2020, but did not have a material impact on the Group c onsolidated or Company's financial statements :

•	Amendments to the Conceptual Framework for Financial Reporting (issued on 29 March 2018 and effective for annual periods beginning on or after 1 January 2020).
•	Definition of materiality - Amendments to IAS 1 and IAS 8 (issued on 31 October 2018 and effective for annual periods beginning on or after 1 January 2020).
•	Interest rate benchmark reform - Amendments to IFRS 9, IAS 39 and IFRS 7 (issued on 26 September 2019 and effective for annual periods beginning on or after 1 January 2020).

Impact of standards issued but not yet applied by the Group

Certain new standards and interpretations have been issued that are mandatory for annual periods beginning on or after 1 January 2021 or later, and which the Group has not early adopted.

I)	Sale or Contribution of Assets between an Investor and its Associate or Joint Venture - Amendments to IFRS 10 and IAS 28 (issued on 11 September 2014 and effective for annual periods beginning on or after a date to be determined by the IASB)

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.

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

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

III)	Amendments to IFRS 17 and an amendment to IFRS 4 (issued on 25 June 2020 and effective for annual periods beginning on or after 1 January 2023)

The amendments include a number of clarifications intended to ease implementation of IFRS 17, simplify some requirements of the standard and transition. The amendments relate to eight areas of IFRS 17, and they are not intended to change the fundamental principles of the standard. The following amendments to IFRS 17 were made:

•	Effective date: The effective date of IFRS 17 (incorporating the amendments) has been deferred by two years to annual reporting periods beginning on or after 1 January 2023; and the fixed expiry date of the temporary exemption from applying IFRS 9 in IFRS 4 has also been deferred to annual reporting periods beginning on or after 1 January 2023.
•	Expected recovery of insurance acquisition cash flows: An entity is required to allocate part of the acquisition costs to related expected contract renewals, and to recognise those costs as an asset until the entity recognises the contract renewals. Entities are required to assess the recoverability of the asset at each reporting date, and to provide specific information about the asset in the notes to the financial statements.
•	Contractual service margin attributable to investment services : Coverage units should be identified, considering the quantity of benefits and expected period of both insurance coverage and investment services, for contracts under the variable fee approach and for other contracts with an 'investment-return service' under the general model. Costs related to investment activities should be included as cash flows within the boundary of an insurance contract, to the extent that the entity performs such activities to enhance benefits from insurance coverage for the policyholder.

Reinsurance contracts held - recovery of losses: When an entity recognises a loss on initial recognition of an onerous group of underlying insurance contracts, or on addition of onerous underlying contracts to a group, an entity should adjust the contractual service margin of a related group of reinsurance contracts held and recognise a gain on the reinsurance contracts held. The amount of the loss recovered from a reinsurance contract held is determined by multiplying the loss recognised on underlying insurance contracts and the percentage of claims on underlying insurance contracts that the entity expects to recover from the reinsurance contract held. This requirement would apply only when the reinsurance contract held is recognised before or at the same time as the loss is recognised on the underlying insurance contracts.

Other amendments : Other amendments include scope exclusions for some credit card (or similar) contracts, and some loan contracts; presentation of insurance contract assets and liabilities in the statement of financial position in portfolios instead of groups; applicability of the risk mitigation option when mitigating financial risks using reinsurance contracts held and non-derivative financial instruments at fair value through profit or loss; an accounting policy choice to change the estimates made in previous interim financial statements when applying IFRS 17; inclusion of income tax payments and receipts that are specifically chargeable to the policyholder under the terms of an insurance contract in the fulfilment cash flows; and selected transition reliefs and other minor amendments.

IV)	Classification of liabilities as current or non-current - Amendments to IAS 1 (issued on 23 January 2020 and effective for annual periods beginning on or after 1 January 2022)

These narrow scope amendments clarify that liabilities are classified as either current or non-current, depending on the rights that exist at the end of the reporting period. Liabilities are non-current if the entity has a substantive right, at the end of the reporting period, to defer settlement for at least twelve months. The guidance no longer requires such a right to be unconditional. Management's expectations whether they will subsequently exercise the right to defer settlement do not affect classification of liabilities. The right to defer only exists if the entity complies with any relevant conditions as of the end of the reporting period. A liability is classified as current if a condition is breached at or before the reporting date even if a waiver of that condition is obtained from the lender after the end of the reporting period. Conversely, a loan is classified as non-current if a loan covenant is breached only after the reporting date. In addition, the amendments include clarifying the classification requirements for debt a company might settle by converting it into equity. 'Settlement' is defined as the extinguishment of a liability with cash, other resources embodying economic benefits or an entity's own equity instruments. There is an exception for convertible instruments that might be converted into equity, but only for those instruments where the conversion option is classified as an equity instrument as a separate component of a compound financial instrument.

V)	Classification of liabilities as current or non-current, deferral of effective date - Amendments to IAS 1 (issued on 15 July 2020 and effective for annual periods beginning on or after 1 January 2023)

The amendment to IAS 1 on classification of liabilities as current or non-current was issued in January 2020 with an original effective date of 1 January 2022. However, in response to the Covid-19 pandemic, the effective date was deferred by one year to provide companies with more time to implement classification changes resulting from the amended guidance.

VI)

Proceeds before intended use, Onerous contracts - cost of fulfilling a contract, Reference to the Conceptual Framework - narrow scope amendments to IAS 16, IAS 37 and IFRS 3, and Annual Improvements to IFRSs 2018-2020 - amendments to IFRS 1, IFRS 9, IFRS 16 and IAS 41 (issued on 14 May 2020 and effective for annual periods beginning on or after 1 January 2022)

The amendment to IAS 16 prohibits an entity from deducting from the cost of an item of PPE any proceeds received from selling items produced while the entity is preparing the asset for its intended use. The proceeds from selling such items, together with the costs of producing them, are now recognised in profit or loss. An entity will use IAS 2 to measure the cost of those items. Cost will not include depreciation of the asset being tested because it is not ready for its intended use. The amendment to IAS 16 also clarifies that an entity is 'testing whether the asset is functioning properly' when it assesses the technical and physical performance of the asset.

The financial performance of the asset is not relevant to this assessment. An asset might therefore be capable of operating as intended by management and subject to depreciation before it has achieved the level of operating performance expected by management.

The amendment to IAS 37 clarifies the meaning of 'costs to fulfil a contract'. The amendment explains that the direct cost of fulfilling a contract comprises the incremental costs of fulfilling that contract; and an allocation of other costs that relate directly to fulfilling. The amendment also clarifies that, before a separate provision for an onerous contract is established, an entity recognises any impairment loss that has occurred on assets used in fulfilling the contract, rather than on assets dedicated to that contract. IFRS 3 was amended to refer to the 2018 Conceptual Framework for Financial Reporting, in order to determine what constitutes an asset or a liability in a business combination. Prior to the amendment, IFRS 3 referred to the 2001 Conceptual Framework for Financial Reporting. In addition, a new exception in IFRS 3 was added for liabilities and contingent liabilities. The exception specifies that, for some types of liabilities and contingent liabilities, an entity applying IFRS 3 should instead refer to IAS 37 or IFRIC 21, rather than the 2018 Conceptual Framework. Without this new exception, an entity would have recognised some liabilities in a business combination that it would not recognise under IAS 37. Therefore, immediately after the acquisition, the entity would have had to derecognise such liabilities and recognise a gain that did not depict an economic gain. It was also clarified that the acquirer should not recognise contingent assets, as defined in IAS 37, at the acquisition date. The amendment to IFRS 9 addresses which fees should be included in the 10% test for derecognition of financial liabilities. Costs or fees could be paid to either third parties or the lender. Under the amendment, costs or fees paid to third parties will not be included in the 10% test. Illustrative Example 13 that accompanies IFRS 16 was amended to remove the illustration of payments from the lessor relating to leasehold improvements. The reason for the amendment is to remove any potential confusion about the treatment of lease incentives. IFRS 1 allows an exemption if a subsidiary adopts IFRS at a later date than its parent. The subsidiary can measure its assets and liabilities at the carrying amounts that would be included in its parent's consolidated financial statements, based on the parent's date of transition to IFRS, if no adjustments were made for consolidation procedures and for the effects of the business combination in which the parent acquired the subsidiary. IFRS 1 was amended to allow entities that have taken this IFRS 1 exemption to also measure cumulative translation differences using the amounts reported by the parent, based on the parent's date of transition to IFRS. The amendment to IFRS 1 extends the above exemption to cumulative translation differences, in order to reduce costs for first-time adopters. This amendment will also apply to associates and joint ventures that have taken the same IFRS 1 exemption. The requirement for entities to exclude cash flows for taxation when measuring fair value under IAS 41 was removed. This amendment is intended to align with the requirement in the standard to discount cash flows on a post-tax basis

VII)	Interest rate benchmark (IBOR) reform - phase 2 amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16 (issued on 27 August 2020 and effective for annual periods beginning on or after 1 January 2021)

The Phase 2 amendments address issues that arise from the implementation of the reforms, including the replacement of one benchmark with an alternative one. The amendments cover the following areas:

•	Accounting for changes in the basis for determining contractual cash flows as a result of IBOR reform: For instruments to which the amortised cost measurement applies, the amendments require entities, as a practical expedient, to account for a change in the basis for determining the contractual cash flows as a result of IBOR reform by updating the effective interest rate using the guidance in paragraph B5.4.5 of IFRS 9. As a result, no immediate gain or loss is recognised. This practical expedient applies only to such a change and only to the extent it is necessary as a direct consequence of IBOR reform, and the new basis is economically equivalent to the previous basis. Insurers applying the temporary exemption from IFRS 9 are also required to apply the same practical expedient. IFRS 16 was also amended to require lessees to use a similar practical expedient when accounting for lease modifications that change the basis for determining future lease payments as a result of IBOR reform.
•	End date for Phase 1 relief for non contractually specified risk components in hedging relationships: The Phase 2 amendments require an entity to prospectively cease to apply the Phase 1 reliefs to a non-contractually specified risk component at the earlier of when changes are made to the non-contractually specified risk component, or when the hedging relationship is discontinued. No end date was provided in the Phase 1 amendments for risk components.
•	Additional temporary exceptions from applying specific hedge accounting requirements: The Phase 2 amendments provide some additional temporary reliefs from applying specific IAS 39 and IFRS 9 hedge accounting requirements to hedging relationships directly affected by IBOR reform.

Additional IFRS 7 disclosures related to IBOR reform: The amendments require disclosure of: (i) how the entity is managing the transition to alternative benchmark rates, its progress and the risks arising from the transition; (ii) quantitative information about derivatives and non-derivatives that have yet to transition, disaggregated by significant interest rate benchmark; and (iii) a description of any changes to the risk management strategy as a result of IBOR reform. #

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:

(a)	the point at which the fair value less costs to sell of the property can be reliably determined as higher than the total of the expenses incurred and costs already capitalised (such as licence acquisition costs); and
(b)	an assessment of the property demonstrates that commercially viable reserves are present and hence there are probable future economic benefits from the continued development and production of the resource.

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

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

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

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

Intangible Assets other than Oil and Gas Assets

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

Depreciation, Depletion and Amortisation

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

Impairment

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

For oil and gas development and production assets, the recoverable amount is the greater of fair value less costs to dispose and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using an expected weighted average cost of capital. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. Impairment losses are recognised as an expense immediately. The valuation method used for determination of fair value less cost of disposal is based on unobservable market data, which is within Level 3 of the fair value hierarchy.

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

Decommissioning Provision

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

Property, Plant and Equipment other than Oil and Gas Assets

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

	Useful lives in years
Buildings and constructions	10 to 20 years
Machinery and equipment	2 to 5 years
Vehicles	5 years
Office and other equipment	4 to 12 years

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

Right-of-use assets

The Group leases various offices, equipment, wells and 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:

•	the amount of the initial measurement of lease liability,
•	any lease payments made at or before the commencement date less any lease incentives received,
•	any initial direct costs, and
•	costs to restore the asset to the conditions required by lease agreements.

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:

	Useful lives in years
Land	40 to 50 years
Wells	10 to 20 years
Properties:
Buildings and constructions	10 to 20 years
Machinery and equipment	2 to 5 years
Vehicles	5 years
Office and other equipment	4 to 12 years

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 by the amount of the transaction price. Transaction price is the amount of consideration to which the Group expects to be entitled in exchange for transferring control over promised goods or services to a customer, excluding the amounts collected on behalf of third parties.

Revenue is recognised net of indirect taxes and excise duties.

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

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

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

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

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

Foreign Currencies

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

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

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

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

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

The principal rates of exchange used for translating foreign currency balances at 31 December 2020 were $1:UAH28.3 (2019: $1:UAH23.7), $1:£0.8 (2019: $1:£0.8), $1:€0.81 (2019: $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), advisers, 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 has 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:

•	fixed payments (including in-substance fixed payments), less any lease incentives receivable,
•	variable lease payment that are based on an index or a rate, initially measured using the index or rate as at the commencement date,
•	the exercise price of a purchase option if the Group is reasonably certain to exercise that option, and
•	payments of penalties for terminating the lease, if the lease term reflects the Group exercising that option.

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:

•	where possible, uses recent third-party financing received by the individual lessee as a starting point, adjusted to reflect changes in financing conditions since third party financing was received,
•	uses a build-up approach that starts with a risk-free interest rate adjusted for credit risk, and
•	makes adjustments specific to the lease, e.g. term, country, currency and collateral.

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

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

•	the asset is held within a business model whose objective is to collect the contractual cash flows, and
•	the contractual terms give rise to cash flows that are solely payments of principal and interest.

Interest income

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

4. Significant Accounting Judgements and Estimates

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.

Significant judgement

Acquisition of LLC Arkona Gas-Energy

The Group acquired control of LLC Arkona Gas-Energy ("Arkona") on 24 March 2020. This acquisition required a determination to be made as to whether the acquisition should be treated as a business or asset acquisition. Following such determination, the transaction has been treated as an asset acquisition as there were no employees or production operations acquired. In applying the concentration test under amended IFRS 3 Business Combinations, the fair value of the acquired Svystunivsko-Chervonolutske licence ("SC Licence") comprises the majority amount (more than 90%) of the consideration. The SC Licence is classified as an exploration and evaluation intangible asset at the acquisition date. The Group believes no impairment indicators exist at the reporting date, and note the following:

•	the SC Licence is valid until 18 May 2037; and
•	further exploration and evaluation plans are included in the Group's Budgets.

The following table provides the allocation of the fair value of the consideration to Arkona's assets and liabilities at their relative fair values at the date of acquisition:

	$000

Property, plant and equipment	88
Trade and other receivables	35
Trade and other payables	(291)
Net liabilities - at the acquisition date, excluding licence	(168)
Gross value of consideration (1st, 2nd and 3rd tranches)	8,469
Discounting effect	(306)
Fair value of consideration (1st, 2nd and 3rd tranches)	8,163
Fair value of licence at the acquisition date	8,331

Under the terms of the sale and purchase agreement for Arkona, the total consideration payable is $8,630,000, with payment divided into three tranches. The first tranche of $4,315,000 was paid on 24 March 2020 upon completion of the acquisition of 100% of the issued share capital of Arkona.

The second and third tranches of $2,157,500 respectively were contingent on satisfaction of certain conditions, including the favourable resolution of the legal proceedings brought by NJSC Ukrnafta against Arkona relating to the SC Licence (the "Licence Case"), the absence of any contractual, warranty or indemnity claims, and the delivery of certain documentation by the sellers of Arkona, with provision that if such conditions are not satisfied, then neither the second tranche nor the third tranche would become payable.

The second tranche is stated at its fair value at the date of acquisition and the estimated date of the relevant Court`s decision in the Licence Case was assumed to be before 31 December 2020. The Group assumes that the financing effect between the estimated date and the actual adjudication described in Note 31 is immaterial.

The third tranche is payable in twelve months from the date of payment of the second tranche. At the date of acquisition, the fair value of the third tranche amounts to the discounted value at the effective interest rate, being the Company's effective borrowing rate of 9%. The Group recognised $306,000 of discounting effect calculated against the value of the acquired assets.

The total consideration comprising the three tranches estimated at the date of acquisition amounts to $8,163,000. Other non-current liabilities as at 31 December 2020 of $1,975,000 comprise the non-current portion of the Arkona consideration, being $1,852,000, and $12 3 ,000 of other liabilities of Arkona for infrastructure development. The current portion of the Arkona consideration of $2,157,500 is reflected in trade and other payables giving the total outstanding balance related to the acquisition of $4,009,500.

Estimates

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 (assessed using estimates for oil and gas prices, production and reserves), 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.

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 proved 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 estimates 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. The latest development plan and therefore the inputs used to determine the depreciation charge for the MEX-GOL and SV fields continue until the end of the economic life of the fields, which is assessed to be 2038 and 2042 respectively, based on the assessment contained in the DeGolyer & MacNaughton reserves report for these fields. The licences for each of these fields have recently been extended until 2040, and therefore the inputs used to determine the depreciation charge for the SV field assume that the SV licence can be further extended until the end of its economic life in 2042.

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 2020 was 3.70% (31 December 2019: 3.68%). 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 2020 resulted from the revision of the estimated costs of decommissioning (increase of $248,000 in provision) and an increase in the discount rate applied (decrease of $22,000 in provision). 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 2019: by 2038 on the MEX-GOL field, by 2042 on the SV field and 2028 on the VAS field respectively), which is the end of the estimated economic life of the respective fields.

Net Carrying Amount of Inter-Company Loans Receivable and Investments by the Company into 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 2020, 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 subsidiary operating in Ukraine and cash flow management. All these factors have a significant impact on the amounts subject to repayment on the loans and investments. The estimated future discounted cash flows generated by the subsidiaries operating in Ukraine are considered as a primary source of repayment on the loans and investments. For the purpose of the assessment of loans, 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. As of 31 December 2020, the present value of future net cash flows to be generated by the subsidiary operating in Ukraine during 2021 - 2025, adjusted for the subsidiaries' working capital as at 31 December 2020 and estimated amounts reserved by the Group for investment projects in the time horizon was calculated. The increase in the net present value of future net cash flows as at 31 December 2020 in comparison with 31 December 2019 was affected by the increase in gas prices forecast and termination of the proposed acquisition of PJSC Science and Production Concern Ukrnaftinvest. For the purpose of the assessment of investments, these cash flows were taken for a period of the full economic life of the respective CGUs. The resulting amount, net of the carrying value of the Company's investments in subsidiaries, was compared to the discounted cash flows and net financial assets of the subsidiaries as at 31 December 2020. As such, the Company has recorded $57,122,000 of income, being the net change in credit loss allowance for loans issued to and investments in subsidiaries in the Company's statement of profit or loss for the year ended 31 December 2020.

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 2019, a Group subsidiary, Regal Petroleum Corporation (Ukraine) Limited, planned to settle $4,500,000 of intra-group liability by the end of 2020 and $4,317,000 was settled in the period. A further amount of $3,102,000 is planned to be settled by the end of 2021. As such, a foreign exchange difference of $1,031,000 accumulated on the intra-group balance of $165,906,000 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 2020 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 2020, other than the abovementioned amount of $4,500,000, 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 2020.

5. 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.

	Ukraine	United Kingdom	Total
	2020	2020	2020
	$000	$000	$000

Revenue
Gas sales	32,309	-	32,309
Condensate sales	11,418	-	11,418
Liquefied Petroleum Gas sales	3,524	-	3,524
Total revenue	47,251	-	47,251

Segment result	25,473	(3,053)	22,420
Depreciation and amortisation of non-current assets	(12,650)	-	(12,650)
Operating profit			9,770

Segment assets	106,587	39,376	145, 963

Capital additions*	18,167	-	18,167

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

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

During 2020, 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 20^th of the month of delivery, and (ii) payment of the remaining balance by the 10th of the month following the month of delivery.

	Ukraine	United Kingdom	Total
	2019	2019	2019
	$000	$000	$000

Revenue
Gas sales	38,345	-	38,345
Condensate sales	13,724	-	13,724
Liquefied Petroleum Gas sales	3,862	-	3,862
Total revenue	55,931	-	55,931

Segment result	33,218	(1,935)	31,283
Depreciation and amortisation of non-current assets	(10,190)	-	(10,190)
Operating profit			21,093

Segment assets	114,722	42,408	157,130

Capital additions*	17,672	-	17,672

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

6. Cost of Sales

	2020	2019
	$000	$000

Depreciation of property, plant and equipment	11,546	9,102
Production taxes	9,361	11,636
Staff costs (Note 9)	3,202	2,450
Rent expenses	3,15	5,317
Cost of inventories recognised as an expense	1,22	1,158
Transmission tariff for Ukrainian gas system	824	673
Amortisation of mineral reserves	48	510
Other expenses	1,712	1,569
	31, 511	32,415

The main reason for the increase in depreciation in 2020 was the growth of production in the period. A transmission tariff for use of the Ukrainian gas transit system of UAH101.93/Mm3 of gas was applicable to the Group (2019: UAH91.87/Mm3). The reduction in production taxes and rent expenses is a function of those charges being price-linked, with hydrocarbon prices having fallen significantly in the period.

7. Administrative Expenses

	2020	2019
	$000	$000

Staff costs (Note 9)	4,521	4,282
Consultancy fees	1,271	869
Depreciation of other fixed assets	456	449
Auditors' remuneration	394	327
Rent expenses	154	138
Amortisation of other intangible assets	160	129
Other expenses	835	1,202
	7,791	7,396



	2020	2019
	$000	$000


Audit of the Company and subsidiaries	176	119
Audit of subsidiaries in Ukraine	123	108
Audit related assurances services - interim review	47	28
Total assurance services	346	255

Tax compliance services	3	24
Legal services	-	12
Tax advisory services	45	36
Total non-audit services	48	72

Total audit and other services	394	327

All amounts shown as Auditors' remuneration in 2020 and 2019 were payable to the Group Auditors, PricewaterhouseCoopers LLP and other member firms of PricewaterhouseCoopers LLP.

8. Remuneration of Directors

	2020	2019
	$000	$000

Directors' emoluments	1,026	977

The emoluments of the individual Directors were as follows:

	Total Emoluments	Total emoluments
	2020	2019
	$000	$000
Executive Directors:
Sergii Glazunov	370	448
Bruce Burrows	354	206

Non-executive Directors:
Chris Hopkinson	128	128
Alexey Pertin	58	57
Yuliia Kirianova	58	57
Dmitry Sazonenko	58	57
Bruce Burrows	-	24
	1,026	977

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 any 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.

9. Staff Numbers and Costs

The average monthly number of employees on a full-time equivalent basis during the year (including Executive Directors) and the aggregate staff costs of such employees were as follows:

	Number of employees

	2020		2019
Group
Management / operational	147		144
Administrative support	78		69
	225		213

		2020		2019
		$000		$000

Wages and salaries		6,664		5,874
Pension costs		953		772
Social security costs		106		86
		7,723		6,732

10. Other Operating Gains, (net)

	2020	2019
	$000	$000

Interest income on cash and cash equivalents	1,421	4,751
Contractor penalties applied	-	15
Reversal of impairment of property, plant and equipment	81	-
Gain on sales of current assets	26	-
Other operating income, net	2 93	207
	1, 821	4,973

11. Finance Income

During 2020, the Group recognised foreign exchange gains less losses of $nil (2019: $3,487,000).

12. Finance Costs

	2020	2019
	$000	$000

Foreign exchange losses less gains	1,058	-
Unwinding of a discount on provision for decommissioning (Note 25)	234	273
Unwinding of discount on lease liabilities	126	177
	1,418	450

13. Other Losses, (net)

	2020	2019
	$000	$000

Charitable donations	2,077	107
Foreign exchange (gains)/losses	(340)	1,508
Unconfirmed tax credit on VAT	-	473
Other losses, net	1 19	306
	1,85 6	2,394

Charitable donations for the year ended 31 December 2020 comprise the supply of medical equipment and COVID-19 testing equipment to Ukrainian authorities and charitable foundations.

14. Income Tax Expense

a) Income tax expense and (benefit):



	2020	2019
	$000	$000
Current tax
UK - prior year	555	-
Overseas - current year	2,770	4,768
Overseas - prior year	(329)	-

Deferred tax (Note 26)
UK - current year	640	3,211
UK - prior year	-	1,996
Overseas - current year	(304)	(406)
Income tax expense	3,332	9,569

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:


	2020	2019
	$000	$000


Profit before taxation	6,520	21,768
Tax charge at UK tax rate of 19.00% (2019: 19.00%)	1,239	4,136

Tax effects of:
Lower foreign corporate tax rates in Ukraine (18.00%) (2019: 18.00%)	(95)	(242)
Disallowed expenses and non-taxable income	22,648	3,598
Changes in tax losses previously not recognised as deferred tax asset	(21,015)	81
Adjustments in respect of prior periods	555	1,996
Total tax expense for the year	3,332	9,569

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 net change in credit loss allowance for loans issued to subsidiaries and shares in subsidiary undertakings.

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

15. Profit for the Year

The Company has taken advantage of the exemption allowed under section 408 of the Companies Act 2006 and has not presented its own Income Statement in these financial statements. The Parent Company profit after tax was $59,454,000 for the year ended 31 December 2020 (2019: loss $17,507,000).

16. Earnings per Share

The calculation of basic earnings per ordinary share has been based on the profit for the year and 320,637,836 (2019: 320,637,836) ordinary shares, being the weighted average number of shares in issue for the year. There are no dilutive instruments.

17. Property, Plant and Equipment

	2020					2019
	Oil and Gas Development and Production assets Ukraine	Oil and Gas Exploration and Evaluation Assets	Other fixed assets	Total	Oil and Gas Development and Production assets Ukraine	Oil and Gas Exploration and Evaluation Assets	Other fixed assets	Total
Group	$000	$000	$000	$000		$000	$000	$000

Cost
At beginning of year	143,127	2,571	2,103	147,801	104,809	1,259	1,293	107,361
Additions	17,241	213	713	18,167	16,132	962	578	17,672
Change in decommissioning provision	372	-	-	372	3,207	-	-	3,207
Disposals	(443)	-	(73)	(516)	(130)	-	(17)	(147)
Exchange differences	(24,331)	(422)	(52 6 )	(25,2 79 )	19,109	350	249	19,708
At end of year	135,966	2,362	2,21 7	140,54 5	143,127	2,571	2,103	147,801

Accumulated depreciation and impairment
At beginning of year	76,802	-	947	77,749	56,567	-	602	57,169
Charge for year	10, 450	-	319	10, 769	9,983	-	237	10,220
Disposals	(327)	-	(30)	(357)	(85)	-	(15)	(100)
Exchange differences	(13,10 9 )	-	(169)	(13,278)	10,337	-	123	10,460
At end of year	73,816	-	1,06 7	74,88 3	76,802	-	947	77,749
Net book value at beginning of year	66,325	2,571	1,156	70,052	48,242	1,259	691	50,192
Net book value at end of year	62, 150	2,362	1,150	65, 662	66,325	2,571	1,156	70,052

In accordance with the Group's accounting policies, the oil and gas development and producing assets are tested for impairment at each balance sheet date if impairment indicators exist. As at 31 December 2020, no impairment indicators were identified.

18. Intangible Assets

		2020				2019
	Mineral reserve rights		Exploration and evaluation intangible assets	Other intangible assets	Total	Mineral reserve rights	Other intangible assets	Total
Group	$000		$000	$000	$000	$000	$000	$000

Cost
At beginning of year	7,843		-	572	8,415	6,709	330	7,039
Additions	-		8,331	224	8,555	-	137	137
Disposals	-		-	(85)	(85)	-	-	-
Exchange differences	(1,273)		(45)	(95)	(1,413)	1,134	105	1,239
At end of year	6,570		8,286	616	15,472	7,843	572	8,415

Accumulated amortisation and impairment
At beginning of year	2,851		-	367	3,218	1,965	194	2,159
Charge for year	488		-	166	654	509	130	639
Disposals	-		-	(85)	(85)	-	-	-
Exchange differences	(484)		-	(63)	(547)	377	43	420
At end of year	2,855		-	385	3,240	2,851	367	3,218
Net book value at beginning of year	4,992		-	205	5,197	4,744	136	4,880
Net book value at end of year	3,715		8,286	231	12,232	4,992	205	5,197

Intangible assets consist mainly of the hydrocarbon production licence relating to the VAS field which is held by one of the Group's subsidiaries LLC Prom-Enerho Produkt and a new hydrocarbon production licence relating to the Svystunivsko-Chervonolutske ("SC") field which is held by LLC Arkona Gas-Energy. The Group amortises the hydrocarbon production licence relating to the VAS field using the straight-line method over the term of the economic life of the VAS field until 2028. The hydrocarbon production licence relating to the SC field is not amortised due to it being in an exploration and evaluation stage.

In accordance with the Group's accounting policies, intangible assets are tested for impairment at each balance sheet date as part of the impairment testing of the Group's oil and gas development and production assets to determine if impairment indicators exist. As at 31 December 2020, no impairment indicators were identified.

19. Leases

This note provides information for leases where the Group is a lessee.

Amount recognised in the balance sheet:


	2020	2019
	$000	$000
Right-of-use assets
Properties	108	423
Land	236	299
Wells	16 8	218
	512	940


	2020	2019
	$000	$000
Lease liabilities
Current	245	454
Non-current	371	515
	616	969

Additions to the right-of-use assets during the 2020 financial year were $56,000 (2019: $170,000).

Amounts recognised in the statement of profit or loss:


	2020	2019
	$000	$000
Depreciation charge
Properties	(308)	(297)
Land	(15)	(16)
Wells	(35)	(39)
	(35 8 )	(352)

Interest expense (included in finance cost)	(126)	(177)
Expense relating to short-term leases (included in cost of sales and administrative expenses)	(139)	(123)
Expense relating to variable lease payments not included in lease liabilities (included in cost of sales and administrative expenses)	(3,101)	(5,283)
Expense relating to lease payments for land under wells not included in lease liabilities (included in cost of sales)	(65)	(49)

The total cash outflow for leases in 2020 was $3,456,000 (2019: $7,934,000).

20. Investments and Loans to Subsidiary Undertakings

	Shares in subsidiary undertakings	Loans to subsidiary undertakings	Total
	$000	$000	$000
Company
At 1 January 2019	17,279	47,552	64,831
Additions including accrued interest	-	3,162	3,162
Repayment of interests and loans	-	(20,616)	(20,616)
Impairment of loans to subsidiary	-	(15,450)	(15,450)
Exchange differences	-	(467)	(467)
At 31 December 2019	17,279	14,181	31,460

At 1 January 2020	17,279	14,181	31,460
Additions including accrued interest	8,163	4,336	12,499
Transfers	39,987	(39,987)	-
Repayment of interests and loans	-	(4,318)	(4,318)
(Impairment)/reversal of impairment	(30,142)	87,264	57,122
Exchange differences	-	1,352	1,352
At 31 December 2020	35,287	62,828	98,115

The Company has recorded a credit of $87,264,000, 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 2020 (Note 4). This credit was calculated following a review of the underlying cash flow forecasts of the subsidiaries and is due to an increase in gas prices forecast and the termination of the proposed acquisition of PJSC Science and Production Concern Ukrnaftinvest. The Company also recorded a loss of $30,142,000, being the net change in credit loss allowance for shares in subsidiary undertakings.

The Company's discounted cash flow model used for the assessment of the investments recoverability, flexed for sensitivities, produced the following results:

	Recoverable amount	Gross balance of investment	Impairment
	$000	$000	$000
31 December 2020	35,287	65,429	(30,142)

Sensitivities:
1. 10% reduction in gas price	32,407	65, 429	( 33 , 022 )
2. 10% increase in gas price	38,166	65, 429	(27,263)
3. 1% reduction in discount rate	36,154	65, 429	(29,275)
4. 1% increase in discount rate	34,477	65, 429	(30,952)

In 2020, after a Group restructuring, the Company transferred $39,987,000 from loans to subsidiary undertakings to shares in subsidiary undertakings as a result of the offsetting of payables for corporate rights.

The table presented below discloses the changes in the gross carrying amount and credit loss allowance between the beginning and the end of the reporting period for loans to subsidiary undertakings carried at amortised cost and classified within a three stage model for impairment assessment as at 31 December 2020:

	Credit loss allowance				Gross carrying amount
	Stage 1	Stage 2	Stage 3	Total	Stage 1	Stage 2	Stage 3	Total
	(12-months ECL)	(lifetime ECL for SICR)	(lifetime ECL for credit impaired)	Total	(12-months ECL)	(lifetime ECL for SICR)	(lifetime ECL for credit impaired)	Total

	$000	$000	$000	$000	$000	$000	$000	$000

At 1 January 2020	-	-	(167,072)	(167,072)	-	--	181,253	181,253

Movements with impact on credit loss allowance charge for the period:

Modification of loans	-	-	72,412	72,412	-	-	(72,412)	(72,412)
Additions including accrued interest	-	-	-	-	-	-	4,336	4,336
Transfers	-	-	-	-	-	-	(39,987)	(39,987)
Payment of interest	-	-	-	-	-	-	(4,318)	(4,318)
Repayment of loans	-	-	-	-	-	-	-	-
Exchange difference	-	-	(12,979)	(12,979)	-	-	14,331	14,331
Changes to ECL measurement model assumptions	-	-	87,264	87,264	-	-	-	-

Total movements with impact on credit loss allowance charge for the period	-	-	146,697	146,697	-	-	(98,050)	(98,050)

At 31 December 2020	-	-	(20,375)	(20,375)	-	-	83,203	83,203

ECL - Expected credit losses

SICR - Significant increase in credit risk

	Credit loss allowance				Gross carrying amount
	Stage 1	Stage 2	Stage 3	Total	Stage 1	Stage 2	Stage 3	Total
	(12-months ECL)	(lifetime ECL for SICR)	(lifetime ECL for credit impaired)	Total	(12-months ECL)	(lifetime ECL for SICR)	(lifetime ECL for credit impaired)	Total

	$000	$000	$000	$000	$000	$000	$000	$000

At 1 January 2019	-	-	(193,386)	(193,386)	-	-	240,938	240,938

Movements with impact on credit loss allowance charge for the period:

Modification of loans	-	-	42,733	42,733	-	-	(42,733)	(42,733)
Additions including accrued interest	-	-	(3,572)	(3,572)	-	-	6,734	6,734
Payment of interest	-	-	-	-	-	-	(7,221)	(7,221)
Repayment of loans	-	-	-		-	-	(13,395)	(13,395)
Exchange difference	-	-	2,603	2,603	-	-	(3,070)	(3,070)
Changes to ECL measurement model assumptions	-	-	(15,450)	(15,450)	-	-	-	-

Total movements with impact on credit loss allowance charge for the period	-	-	26,314	26,314	-	-	(59,685)	(59,685)

At 31 December 2019	-	-	(167,072)	(167,072)	-	-	181,253	181,253

ECL - Expected credit losses

SICR - Significant increase in credit risk*

Subsidiary undertakings

At 31 December 2020, the Company's subsidiary undertakings, all of which are included in the consolidated financial statements, were:

	Registered address	Country of incorporation	Country of operation	Principal activity	% of shares held

Regal Petroleum Corporation Limited	3^rd Floor, Charter Place, 23-27 Seaton Place, St Helier, Jersey, JE4 0WH	Jersey	Ukraine	Oil & Natural Gas Extraction	100%

Regal Group Services Limited	16 Old Queen Street, London, SW1H 9HP	United Kingdom	United Kingdom	Service Company	100%

Regal Petroleum (Jersey) Limited	3^rd Floor, Charter Place, 23-27 Seaton Place, St Helier, Jersey, JE4 0WH	Jersey	United Kingdom	Holding Company	100%

Regal Petroleum Corporation (Ukraine) Limited	162 Shevchenko Str., Yakhnyky Village, Lokhvytsya District, Poltava Region, 37212	Ukraine	Ukraine	Service Company	100%

LLC Prom-Enerho Produkt	3 Klemanska Str., Kiev, 02081	Ukraine	Ukraine	Oil & Natural Gas Extraction	100%
LLC Arkona Gas-Energy	162 Shevchenko Str., Yakhnyky Village, Lokhvytsya District, Poltava Region, 37212	Ukraine	Ukraine	Exploration and Evaluation for Oil and Natural Gas	100%

The Parent Company, Enwell Energy plc, holds direct interests in 100% of the share capital of Regal Petroleum Corporation Limited, Regal Group Services Limited, Regal Petroleum (Jersey) Limited, Regal Petroleum Corporation (Ukraine) Limited and LLC Arkona Gas-Energy, and a 100% indirect interest in LLC Prom-Enerho Produkt through its 100% shareholding in Regal Petroleum Corporation (Ukraine) Limited, which owns all of the share capital of LLC Prom-Enerho Produkt.

The Group acquired 100% of the share capital of LLC Arkona Gas-Energy on 24 March 2020 (Note 4).

Regal Group Services Limited, company number 5252958, has taken advantage of the subsidiary audit exemption allowed under section 479A of the Companies Act 2006 for the year ended 31 December 2020.

21. Inventories

	Group
	2020	2019
	$000	$000
Current
Materials and spare parts	1,445	1,791
Finished goods	96	3,022
	1,541	4,813

Inventories consist of materials, spare parts and finished goods. Materials and spare parts are represented by spare parts that were not assigned to any new wells as at 31 December 2020, production raw materials and fuel at the storage facility. Finished goods as at 31 December 2020 consist of produced gas held in underground gas storage facilities and condensate and LPG held at the processing facility prior to sale.

All inventories are measured at the lower of cost or net realisable value. There was no write down of inventory as at 31 December 2020 or 2019.

22. Trade and Other Receivables

	Group		Company
	2020	2019	2020	2019
	$000	$000	$000	$000

Trade receivables	1,936	2,881	-	-
Other financial receivables	1,053	1,718	304	-
Less credit loss allowance	(133)	(155)	-	-
Total financial receivables	2,856	4,444	304	-

Prepayments and accrued income	1,387	5,959	55	8
Other receivables	604	534	76	93
Total trade and other receivables	4,847	10,937	435	101

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

At 31 December 2020, the Group's total trade receivables amounted to $1,806,000 and 100% were denominated in Ukrainian Hryvnia (31 December 2019: $2,726,000 and 100% were denominated in Ukrainian Hryvnia). Further description of financial receivables is disclosed in Note 30.

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

Prepayments and accrued income mainly consist of prepayments of $926,000 relating to the development of the SV field (31 December 2019: of $3,987,000 relating to the development of the SV field and $1,094,000 relating to the development of the VAS field).

Analysis by credit quality of financial trade and other receivables and expected credit loss allowance as at 31 December 2020 is as follows:

	Loss rate	Gross carrying amount	Life-time ECL	Carrying amount	Basis
		$000	$000	$000

Trade receivables from related parties	5%	1,804	(3)	1,801	financial position of related party

Trade receivables - credit impaired	100%	127	(127)	-	number of days the asset past due

Trade receivables - other	0.21%	5	-	5	historical credit losses experienced

Other financial receivables	0.42%	1,053	(3)	1,050	individual default rates

Total trade and other receivables for which individual approach for ECL is used		2,989	(133)	2,856

Analysis by credit quality of financial trade and other receivables and expected credit loss allowance as at 31 December 2019 is as follows:

	Loss rate	Gross carrying amount	Life-time ECL	Carrying amount	Basis
		$000	$000	$000

Trade receivables from related parties	5%	2,644	(3)	2,641	financial position of related party

Trade receivables - credit impaired	100%	152	(152)	-	number of days the asset past due

Trade receivables - other	0.36%	85	(0)	85	historical credit losses experienced

Other financial receivables	0.92%-2.05%	1,718	(0)	1,718	individual default rates

Total trade and other receivables for which individual approach for ECL is used		4,599	(155)	4,444

ECL - Expected credit losses

The following table explains the changes in the credit loss allowance for trade and other receivables under the simplified ECL model between the beginning and the end of the annual period:

	2020	2019
	$000	$000
Trade receivables
Balance at 1 January	155	99
New originated or purchased	-	3
Financial assets derecognised during the period	-	-
Changes in estimates and assumptions	3	30
Foreign exchange movements	(25)	23
Balance at 31 December	13 3	155

23. Cash and Cash Equivalents

	Group		Company
	2020	2019	2020	2019
	$000	$000	$000	$000

Cash and Cash Equivalents
Cash at bank	53,710	28,089	38,619	23,656
Demand deposits and term deposits with maturity less than 3 months	7,283	34,385	-	18,015
	60,993	62,474	38,619	41,671

Cash at bank earns interest at fluctuating rates based on daily bank deposit rates. Demand deposits are made for varying periods depending on the immediate cash requirements of the Group and earn interest at the respective short-term deposit rates. The terms and conditions upon which the Group's demand deposits are made allow immediate access to all cash deposits, with no significant loss of interest.

The credit quality of cash and cash equivalents balances and other short-term investments may be summarised based on Moody's ratings as follows at 31 December:

	Cash at bank and on hand	Demand deposits and term deposits with maturity less than 3 months	Total cash and cash equivalents
	2020	2020	2020
	$000	$000	$000

A- to A+ rated	38,615	-	38,615
B- to B+ rated	1	5,477	5,478
Unrated	15,094	1,806	16,900
	53,710	7,283	60,993

	Cash at bank and on hand	Demand deposits and term deposits with maturity less than 3 months	Total cash and cash equivalents
	2019	2019	2019
	$000	$000	$000

A- to A+ rated	23,655	18,015	41,670
B- to B+ rated	2	8,048	8,050
Unrated	4,432	8,322	12,754
	28,089	34,385	62,474

For cash and cash equivalents, the Group assessed ECL based on the Moody's rating for rated banks and based on the sovereign rating of Ukraine defined by Fitch as "B" as of 31 December 2020 for non-rated banks. Based on this assessment, the Group concluded that the identified impairment loss was immaterial.

24. Trade and Other Payables

	2020		2019
	$000		$000

Accruals and other payables	4,037		2,418
Taxation and social security	1,3 96		1,092
Trade payables	843		277
Advances received	365		181
		6, 6 41	3,968

The carrying amounts of trade and other payables are assumed to be the same as their fair values, due to their short-term nature. Financial payables are disclosed in Note 30.

25. Provision for Decommissioning

	2020	2019
	$000	$000
Group
At beginning of the year	7,447	3,137
Amounts provided	146	355
Unwinding of discount	234	273
Change in estimate	226	2,852
Effect of exchange difference	(1,234)	830
At end of the year	6,819	7,447

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

The non-current provision of $6,819,000 (31 December 2019: $7,447,000) represents a provision for the decommissioning of the Group's MEX-GOL, SV and VAS production facilities, including site restoration.

The change in estimates applied to calculate the provision as at 31 December 2020 is explained in Note 4.

The principal assumptions used are as follows:

	31 December 2020	31 December 2019

Discount rate (%)	3.70%	3.68%
Average cost of restoration per well ($000)	342	406

The sensitivity of the restoration provision to changes in the principal assumptions to the provision balance and related asset is presented below:

	31 December 2020	31 December 2019
	$000	$000

Discount rate (increase)/decrease by 1%	(948)/1,143	(1,086)/1,319
Change in average cost of restoration increase/ (decrease) by 10%	469/(469)	523/(523)

26. Deferred Tax



		2020	2019
		$000	$000
Deferred tax asset recognised on tax losses
At beginning of year		-	2,134
Charged to Income Statement - current year		-	(2,134)
At end of year		-	-

	2020		2019
	$000		$000
Deferred tax (liability)/asset recognised relating to oil and gas development and production assets at MEX-GOL-SV fields and provision for decommissioning
At beginning of year	(2,141)		1,149
Charged to Income Statement - current year	(640)		(1,077)
Charged to Income Statement - prior year	-		(1,996)
Effect of exchange difference	76		(217)
At end of year	(2,705)		(2,141)

	2020		2019
	$000		$000
Deferred tax asset/(liability) recognised relating to development and production assets at VAS field and provision for decommissioning
At beginning of year	(147)		(504)
Credited to Income Statement - current year	304		406
Effect of exchange difference	10		(49)
At end of year	167		(147)

There was a further $73,661,000 (31 December 2019: $85,000,000) of unrecognised UK tax losses carried forward for which no deferred tax asset has been recognised. These losses can be carried forward indefinitely, subject to certain rules regarding capital transactions and changes in the trade of the Company.

The deferred tax asset relating to the Group's provision for decommissioning at 31 December 2020 of $170,000 (31 December 2019: $326,000) was recognised on the tax effect of the temporary differences of the Group's provision for decommissioning at the MEX-GOL and SV fields, and its tax base. The deferred tax liability relating to the Group's development and production assets at the MEX-GOL and SV fields at 31 December 2020 of $2,875,000 (31 December 2019: $2,467,000) was recognised on the tax effect of the temporary differences between the carrying value of the Group's development and production asset at the MEX-GOL and SV fields, and its tax base.

The deferred tax asset relating to the Group's provision for decommissioning at 31 December 2020 of $323,000 (31 December 2019: $329,000) was recognised on the tax effect of the temporary differences on the Group's provision on decommissioning at the VAS field, and its tax base. The deferred tax liability relating to the Group's development and production assets at the VAS field at 31 December 2020 of $156,000 (31 December 2019: $476,000) was recognised on the tax effect of the temporary differences between the carrying value of the Group's development and production asset at the VAS field, and its tax base. The deferred tax assets are expected to be recovered more than twelve months after the reporting period.

Losses accumulated in a Ukrainian subsidiary service company of UAH1,763,494,270 ($116,622,885) at 31 December 2020 and UAH2,762,352,984 ($62,370,264) at 31 December 2019 mainly originated as foreign exchange differences on inter-company loans and for which no deferred tax asset was recognised as this subsidiary is not expected to have taxable profits to utilise these losses in the future.

As at 31 December 2020 and 2019, the Group has not recorded a deferred tax liability in respect of taxable temporary differences associated with investments in subsidiaries as the Group is able to control the timing of the reversal of those temporary differences and does not intend to reverse them in the foreseeable future.

UK Corporation tax change

In the Spring Budget 2020, the UK Government announced that from 1 April 2020 the corporation tax rate would remain at 19% (rather than reducing to 17% as previously enacted) and the effect of this change is included in these consolidated financial statements.

Double tax treaty

On 30 October 2019, the Parliament of Ukraine voted for ratification of a Protocol changing the Double Tax Treaties between Ukraine and the United Kingdom. The Protocol and the new Treaty will enter into force upon completion of ratification formalities, and for the purposes of withholding tax, commence applying from 1 January 2020. The Group accrues and pays withholding tax on current amounts of interest at the moment when such interest accrues and is paid.

27. Called Up Share Capital

	2020		2019
	Number	$000	Number	$000
Allotted, called up and fully paid
Opening balance at 1 January	320,637,836	28,115	320,637,836	28,115
Issued during the year	-	-	-	-
Closing balance at 31 December	320,637,836	28,115	320,637,836	28,115

There are no restrictions over ordinary shares issued. The Company is a public company limited by shares.

28. Other Reserves

The holders of ordinary shares are entitled to receive dividends as declared and are entitled to one vote per share at any general meeting of shareholders. The share premium reserves are not available for distribution by way of dividends.

Other reserves, the movements in which are shown in the statements of changes in equity, comprise the following:

Capital contributions reserve

The capital contributions reserve is non-distributable and represents the value of equity invested in subsidiary entities prior to the Company listing.

Merger reserve

The merger reserve represents the difference between the nominal value of shares acquired by the Company and those issued to acquire subsidiary undertakings. This balance relates wholly to the acquisition of Regal Petroleum (Jersey) Limited and that company's acquisition of Regal Petroleum Corporation Limited during 2002.

Foreign exchange reserve

Exchange reserve movement for the year attributable to currency fluctuations. This balance predominantly represents the result of exchange differences on non-monetary assets and liabilities where the subsidiaries' functional currency is not the US Dollar.

29. Reconciliation of Operating Profit to Operating Cash Flow


	2020	2019
	$000	$000
Group
Operating profit	9, 770	21,093
Depreciation and amortisation	12, 679	10,190
Less interest income recorded within operating profit	(1,421)	(4,751)
Fines and penalties received	(18)	(236)
Gain on sales of current assets, net	(31)	(27)
Reversal of loss allowance on other financial assets	-	(46)
Loss from write off of non-current assets	159	47
Change in working capital:
Increase in provisions	(55)	67
Decrease/(increase) in inventory	2,499	(3,208)
Decrease in receivables	359	2,447
Decrease in payables	(177)	(868)
Cash generated from operations	23,764	24,708

	2020	2019
	$000	$000
Company
Operating profit/(loss)	58,034	(15,016)
Interest received	(4,336)	(3,162)
Change in working capital:
Movement in provisions (including impairment of subsidiary loans)	(57,122)	15,450
Increase in receivables	(101)	(453)
Increase in payables	13	159
Cash used in operations	(3,512)	(3,022)

30. Financial Instruments

Capital Risk Management

The Group defines its capital as equity. The primary source of the Group's liquidity has been cash generated from operations. As at 31 December 2020, primary capital was $60,993,000 (31 December 2019: $62,474,000).The Group's objectives when managing capital are to safeguard the Group's and the Company's ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital.

In order to maintain or adjust the capital structure, the Group may adjust the amount of dividends paid to shareholders, return capital to shareholders, issue new shares or sell assets.

The capital structure of the Group consists of equity attributable to the equity holders of the parent, comprising issued share capital, share premium, reserves and retained deficit.

There are no capital requirements imposed on the Group.

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

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

Financial Assets
	2020	2019
	$000	$000
Group
Cash and cash equivalents	60,993	62,474
Trade and other receivables	2,856	4,444
Prepayment for shares	-	500
	63,849	67,418

	2020	2019
	$000	$000
Company
Cash and cash equivalents	38,619	41,671
Loans to subsidiary undertakings	62,828	14,181
Prepayment for shares	-	500
	101,447	56,352

Financial Liabilities
	2020	2019
	$000	$000
Group
Lease liabilities	616	969
Trade payables	843	277
Other financial liabilities	4,336	1,018
	5,795	2,264

	2020	2019
	$000	$000
Company
Other financial liabilities	4,247	256
	4,247	256

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

Financial instruments that potentially subject the Group to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable, and financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of cash and cash equivalents and loans to subsidiary undertakings.

Currency Risk

The functional currencies of the Group's entities are US Dollars and Ukrainian Hryvnia. The following analysis of net monetary assets and liabilities shows the Group's currency exposures. Exposures comprise the monetary assets and liabilities of the Group that are not denominated in the functional currency of the relevant entity.

	2020	2019
Currency	$000	$000

British Pounds	232	301
Euros	5	33
Net monetary assets less liabilities	237	334

The Group's exposure to currency risk at the end of the reporting period is not significant due to immaterial balances of monetary assets and liabilities denominated in foreign currencies.

Interest Rate Risk Management

The Group is not exposed to interest rate risk on financial liabilities as none of the entities in the Group have any external borrowings. The Group does not use interest rate forward contracts and interest rate swap contracts as part of its strategy.

The Group is exposed to interest rate risk on financial assets as entities in the Group hold money market deposits at floating interest rates. The risk is managed by fixing interest rates for a period of time when indications exist that interest rates may move adversely.

The Group's exposure to interest rates on financial assets and financial liabilities are detailed in the liquidity risk section below.

Interest Rate Sensitivity Analysis

The sensitivity analysis below has been determined based on exposure to interest rates for non-derivative instruments at the balance sheet date. A 0.5% increase or decrease is used when reporting interest rate risk internally to key management personnel and represents management's assessment of a reasonably possible change in interest rates.

If interest rates earned on money market deposits had been 0.5% higher / lower and all other variables were held constant, the Group's:

•

profit for the year ended 31 December 2020 would increase by $97,000 in the event of 0.5% higher interest rates and decrease by $97,000 in the event of 0.5% lower interest rates (profit for the year ended 31 December 2019 would increase by $159,000 in the event of 0.5% higher interest rates and decrease by $159,000 in the event of 0.5% lower interest rates). This is mainly attributable to the Group's exposure to interest rates on its money market deposits; and

•

other equity reserves would not be affected (2019: not affected).

Interest payable on the Group's liabilities would have an immaterial effect on the profit or loss for the year.

Liquidity Risk

The Group's objective throughout the year has been to ensure continuity of funding. Operations have primarily been financed through revenue from Ukrainian operations.

The table below shows liabilities by their remaining contractual maturity. The amounts disclosed in the maturity table are the contractual undiscounted cash flows including future interest. Such undiscounted cash flows differ from the amount included in the statement of financial position because the statement of financial position amount is based on discounted cash flows and does not include the interest that will be accrued in future periods.

When the amount payable is not fixed, the amount disclosed is determined by reference to the conditions existing at the reporting date. Foreign currency payments are translated using the spot exchange rate at the end of the reporting period. The maturity analysis of financial liabilities at 31 December 2020 is as follows:

As at 31 December 2020	On demand and less than 1 month	From 1 to 3 months	From 3 to 12 months	From 12 months to 5 years	More than 5 years	Total
Liabilities
Trade and other payables	1 , 137	2,158	33	-	-	3 , 32 8
Lease liabilities	40	80	101	291	539	1,051
Other non-current liabilities	-	27	-	2,569		2 , 59 6
Total future payments, including future principal and interest payments	1 , 1 7 7	2 ,26 5	1 3 4	2 ,860	539	6,975

The maturity analysis of financial liabilities at 31 December 2019 is as follows:

As at 31 December 2019	On demand and less than 1 month	From 1 to 3 months	From 3 to 12 months	From 12 months to 5 years	More than 5 years	Total
Liabilities
Trade and other payables	1 , 295	-	-	-	-	1 , 295
Lease liabilities	42	83	375	511	563	1,574
Total future payments, including future principal and interest payments	1 ,337	83	375	511	563	2,869

Details of the Group's cash management policy are explained in Note 23.

Liquidity risk for the Group is further detailed under the Principal Risks section above.

Credit Risk

Credit risk principally arises in respect of the Group's cash balance. For balances held outside Ukraine, where $38.6 million of the overall cash and cash equivalents is held (31 December 2019: $41.7 million), the Group only deposits cash surpluses with major banks of high quality credit standing (Note 23). As at 31 December 2020, the remaining balance of $22.4 million of cash and cash equivalents was held in Ukraine (31 December 2019: $20.8 million). In September 2020, Standard & Poor's affirmed Ukraine's sovereign credit rating of 'B', Outlook Stable. There is no international credit rating information available for the specific banks in Ukraine where the Group currently holds its cash and cash equivalents.

The Group has taken steps to diversify its banking arrangements between a number of banks in Ukraine, and increased the quality of cash placed with UK and European banking institutions. These measures are designed to spread the risks associated with each bank's creditworthiness.

Interest Rate Risk Profile of Financial Assets

The Group had the following cash and cash equivalent and other short-term investments balances which are included in financial assets as at 31 December with an exposure to interest rate risk:

Currency	Total	Floating rate financial assets	Fixed rate financial assets	Total	Floating rate financial assets	Fixed rate financial assets
	2020	2020	2020	2019	2019	2019
	$000	$000	$000	$000	$000	$000

Euros	5	5	-	30	30	-
British Pounds	232	232	-	257	257	-
Ukrainian Hryvnia	20,569	-	20,569	17,881	-	17,881
US Dollars	40,187	40,187	-	44,306	44,306	-
	60,993	40,424	20,569	62,474	44,593	17,881

Cash deposits included in the above balances comprise short-term deposits.

As at 31 December 2020, cash and cash equivalents of the Company of $39 million were held in US Dollars at a floating rate (2019: $42 million).

Interest Rate Risk Profile of Financial Liabilities

As at 31 December 2020 and 2019, the Group had no interest bearing financial liabilities at the year end.

Maturity of Financial Liabilities

The maturity profile of financial liabilities, on an undiscounted basis, is as follows:

	2020	2019
	$000	$000
Group
In one year or less	3,576	1,795
	3,457	1,795

	2020	2019
	$000	$000
Company
In one year or less	2,395	256
	2,395	256

Borrowing Facilities

As at 31 December 2020 and 2019, the Group did not have any borrowing facilities available to it.

Fair Value of Financial Assets and Liabilities

The fair value of all financial instruments is not materially different from the book value.

31. Contingencies and Commitments

Amounts contracted in relation to the Group's 2020 investment programme in the MEX-GOL, SV and VAS fields in Ukraine, but not provided for in the financial statements at 31 December 2020, were $9,052,165 (2019: $2,306,000).

Since 2010, the Group has been in dispute with the Ukrainian tax authorities in respect of VAT receivables on imported leased equipment, with a disputed liability of up to UAH8,487,000 ($302,000) inclusive of penalties and other associated costs. There is a level of ambiguity in the interpretation of the relevant tax legislation, and the position adopted by the Group has been challenged by the Ukrainian tax authorities, which has led to legal proceedings to resolve the issue. The Group had been successful in three court cases in respect of this dispute in courts of different levels. On 20 September 2016, a hearing was held in the Supreme Court of Ukraine of an appeal of the Ukrainian tax authorities against the decision of the Higher Administrative Court of Ukraine, in which the appeal of the Ukrainian tax authorities was upheld. As a result of this appeal decision, all decisions of the lower courts were cancelled, and the case was remitted to the first instance court for a new trial. On 1 December 2016 and 7 March 2017 respectively, the Group received positive decisions in the first and second instance courts, but further legal proceedings may arise. Since, at the end of the year, the Group had been successful in previous court cases in respect of this dispute in courts of different levels, the date of the next legal proceedings has not been set and as management believes that adequate defences exist to the claim, no liability has been recognised in these consolidated financial statements for the year ended 31 December 2020 (31 December 2019: nil).

On 12 March 2019 the Group announced the publication of an Order for suspension (the "Order") by the State Service of Geology and Subsoil of Ukraine affecting the production licence for its VAS gas and condensate field. The Group is confident there are no violations of the terms of the licence or in relation to the operational activities of the Group that would justify the Order or the suspension of the licence. The Group has issued legal proceedings in the Ukrainian Courts to challenge the validity of the Order, and in these proceedings, on 18 March 2019, the Court made a ruling on interim measures to suspend the Order pending hearings of the substantive issues of the case to be held subsequently. The effect of this ruling is that the suspension of operational activities at the VAS licence is deferred until the result of the legal proceedings is determined. These legal proceedings are continuing through the Ukrainian Court system and the ultimate outcome is not yet known. However, the Group considers that the Order is groundless and that the outcome of the legal proceedings challenging the Order will ultimately be in favour of the Group, and consequently, the Group does not expect any negative effect on its operations in respect of this matter.

On 24 March 2020, the Company completed the acquisition of the entire share capital of LLC Arkona Gas-Energy. In July 2020, legal proceedings issued by NJSC Ukrnafta ("Ukrnafta"), as claimant, against Arkona, as defendant, relating to a claim by Ukrnafta that irregular procedures were followed in the grant of the Svystunivsko-Chervonolutskyi exploration licence (the "Licence") to Arkona in May 2017, were considered by the First Instance Court in Ukraine. Ukrnafta also brought these proceedings against the State Service of Geology and Subsoil of Ukraine ("SGS"). Ukrnafta was the holder of a previous licence over a part of this area which expired prior to the grant of the Licence. Both Arkona and SGS disputed these claims. In the legal proceedings, the First Instance Court made a ruling in favour of Ukrnafta which determined that the grant of the Licence was irregular, and accordingly, the Licence would be invalid. In August 2020, Arkona filed an appeal of this decision in the Appellate Administrative Court in Kyiv, and on 29 September 2020, the Appellate Administrative Court ruled in favour of Arkona, overturning the earlier decision of the First Instance Court. In November 2020, Ukrnafta filed a further appeal in the Supreme Court in Kyiv, appealing the ruling made by the Appellate Administrative Court on 29 September 2020. In February 2021, the Supreme Court delivered its decision and written judgement on this appeal, in which the Supreme Court ruled that the arguments raised by Ukrnafta in the appeal were not substantiated, and that the proceedings against Arkona should be dismissed. The decision of the Supreme Court represents the final appeal procedure in the Ukrainian Courts, and accordingly, these legal proceedings against Arkona have now been exhausted. As a consequence, the Licence remains valid.

32. Related Party Disclosures

Key management personnel of the Group are considered to comprise only the Directors. Details of Directors' remuneration are disclosed in Note 8.

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

	2020	2019
	$000	$000

Sale of goods / services	32,074	38,417
Purchase of goods / services	890	963
Amounts owed by related parties	1,805	2,649
Amounts owed to related parties	202	137

All related party transactions were with subsidiaries of the ultimate Parent Company, and primarily relate to the sale of gas (see Note 4 for more details), the rental of office facilities and a vehicle and the sale of equipment. The amounts outstanding were unsecured and will be settled in cash.

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

	2020	2019
	$000	$000

Bank charges	3	1
Closing cash balance (as at 31 December)	1	1

The bank charges represent cash transit fees.

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

33. Post Balance Sheet Events

With effect from 25 February 2021, the Company completed a reduction of capital through the cancellation of its entire share premium account, thereby creating distributable reserves, which enable the Company to make distributions to its shareholders in the future, subject to the Company's financial performance. However, the Company is not indicating any commitment, and does not have any current intention, to make any distributions to shareholders.

From 1 January 2021, after changes to Ukrainian tax legislation, the Company's subsidiary, Regal Petroleum Corporation Limited, is obliged to register as an income tax payer in Ukraine and to pay income tax instead of its branch (Representative Office) in Ukraine.

In March 2021, following the satisfaction of conditions relating to the payment of the second tranche of the consideration for the acquisition of LLC Arkona Gas-Energy, this tranche has been paid (net of an indemnity liability).

No subsequent events have arisen as a result of the COVID-19 pandemic that have had a material impact on the consolidated and the Company's financial statements for the period ended 31 December 2020.

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