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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Regal Petroleum Plc | LSE:RPT | London | Ordinary Share | GB0031775819 | ORD 5P |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 15.325 | 14.75 | 15.90 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From Apr 2019 to Apr 2024
TIDMRPT
RNS Number : 2902J
Regal Petroleum PLC
09 April 2020
9 April 2020
REGAL PETROLEUM PLC
2019 AUDITED RESULTS
Regal Petroleum plc (the "Company", and with its subsidiaries, the "Group"), the AIM-quoted (RPT) oil and gas exploration and production group, today announces its audited results for the year ended 31 December 2019.
Highlights
Ukraine Operations
Hot Features
Premium
-- Aggregate average daily production from the MEX-GOL, SV and
VAS fields over the year to 31 December 2019 of 4,263 boepd
(2018: 3,391 boepd), an increase of nearly 26%
-- Aggregate average daily production from the MEX-GOL, SV and
VAS fields for Q4 2019 of 4,776 boepd (Q4 2018: 4,139 boepd),
representing an increase of over 15%, largely as a result
of the significant contribution from the MEX-119 well in Q4
2019
-- Reserves upgrade at VAS field announced in August 2019, nearly
doubling proved plus probable (2P) reserves to 3.145 MMboe
(from 1.80 MMboe)
-- MEX-119 well successfully completed and brought on production
in October 2019
Finance
-- Revenue for the year ended 31 December 2019 of $55.9 million
(2018: $66.1 million), down 15% as a function of weakened
gas prices in the year
-- Gross profit for the year of $23.5 million (2018: $34.2 million),
down 31%
-- Operating profit for the year of $21.1 million (2018: $66.4
million, including a one-off reversal of impairment item of
$36.1 million relating to impairment reversal of oil and gas
development and production assets)
-- Cash generated from operations during the year of $24.6 million
(2018: $36.3 million), down 32%
-- Net profit for the year of $12.2 million (2018: $54.3 million,
included a one-off reversal of impairment item of $36.1 million
relating to impairment reversal of oil and gas development
and production assets)
-- Average realised gas, condensate and LPG prices in Ukraine
were all lower, particularly gas prices, for the year to 31
December 2019 at $219/Mm(3) (UAH5,729/Mm(3) ), $58/bbl and
$55/bbl respectively (2018: $312/Mm(3) (UAH8,528/Mm(3) ) gas,
$72/bbl condensate and $64/bbl LPG)
-- Cash and cash equivalents up 17% at $62.5 million at 31 December
2019 (31 December 2018: cash and cash equivalents of $53.2
million), with cash and cash equivalents at 7 April 2020 of
$55.2 million, held as $18.5 million equivalent in Ukrainian
Hryvnia and $36.7[ ] million equivalent predominantly in US
Dollars, Euros and Pounds Sterling
Outlook
-- Development work planned for 2020 at MEX-GOL and SV fields
includes: completion of the SV-54 well; commencement of a
new well, SV-25; planning for a further new well or sidetracking
of an existing well in the SV field; investigating workover
opportunities for existing wells; installation of further
compression equipment; and continued investment in gas processing
facilities, pipeline network and other infrastructure
-- Development work planned for 2020 at the VAS field includes:
planning for a new well to explore the VED prospect within
the VAS licence area; installation of compression equipment;
and continued investment in gas processing facilities, pipeline
network and other infrastructure
-- Commencement of planning for development of the SC field operated
by Arkona
-- 2020 development programme expected to be funded from existing
cash resources and operational cash flow
-- As of the date of this announcement, the global economy, and
global social dynamics, are in a state of disruption and uncertainty
as result of the COVID-19 pandemic. The Board and management
continue to monitor the evolving situation and take any steps
necessary to protect our staff, stakeholders and business
alike. 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, with
the safety of individuals and communities being paramount.
To this end, we have joined with other Ukrainian businesses
to acquire medical equipment and supplies for donation to
the Ukrainian State, with our share of the pre-emptive initiative
being $2 million.
Sergii Glazunov, CEO, commented: "2019 was a strong operational year for Regal Petroleum. Record production from the MEX-GOL, SV and VAS fields helped offset the impact of lower gas prices experienced in the year, and the Board believes that the acquisition of LLC Arkona Gas-Energy in March of this year will bolster our production capacity following completion of initial drilling planned to commence in the next twelve months.
We are looking forward to further progressing our development programme in the new financial year and continuing to improve production rates and revenue streams in the future. We are watching closely the unprecedented developments of the current COVID-19 pandemic, and although we have seen no material impact so far, we have taken and will keep taking actions to ensure the safety of our employees and local communities."
The Annual Report and Financial Statements for 2019, together with the Notice of Annual General Meeting, will be posted to shareholders and published on the Company's website during May/June 2020.
This announcement contains inside information for the purposes of Article 7 of EU Regulation 596/2014.
For further information, please contact:
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 / Richard Tulloch 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 Louise Mason-Rutherford / 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.
Definitions
Arkona LLC Arkona Gas-Energy
bbl barrel
bbl/d barrels per day
Bm(3) thousands of millions cubic metres
boe barrels of oil equivalent
boepd barrels of oil equivalent per day
Bscf thousands of millions scf
Company Regal Petroleum plc
D&M DeGolyer and MacNaughton
Group Regal Petroleum plc and its subsidiaries
km kilometre
km(2) square kilometre
LPG liquefied petroleum gas
MEX-GOL Mekhediviska-Golotvshinska
m(3) cubic metres
m(3)/d cubic metres per day
Mboe thousand barrels of oil equivalent
Mm(3) thousand cubic metres
MMbbl million barrels
MMboe million barrels of oil equivalent
MMm(3) 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
SV Svyrydivske
Tscf trillion scf
$ United States Dollar
UAH Ukrainian Hryvnia
VAS Vasyschevskoye
VED Vvdenska
Chairman's Statement
I am delighted to introduce the preliminary results of the Group. This year has been a strong year for the Group, with good progress in the development of the MEX-GOL, SV and VAS gas and condensate fields in north-eastern Ukraine and a solid financial performance during the year. Drilling of the MEX-119 development well was successfully completed and brought on production in October 2019, with very strong flow rates.
At the MEX-GOL and SV fields, production was reasonably stable during 2019, with higher production volumes compared with the 2018 year, and at the VAS field production was also steady, and significantly higher than during 2018 following the hook-up of the VAS-10 well in November 2018.
Aggregate average daily production from the MEX-GOL, SV and VAS fields during 2019 was approximately 4,263 boepd, which compares with an aggregate daily production rate of approximately 3,391 boepd during 2018, an increase of nearly 26%.
The Group delivered a robust financial performance for the year ended 31 December 2019 on the back of record levels of production and despite a significant drop in the average gas price in the period, a function of weakened European gas prices. During 2019, the Group achieved a net profit of $12.2 million (2018: $54.3 million). Continued strong profitability, despite the weakened gas price, has enabled the Group to further enhance its balance sheet, with a 17% increase in closing cash resources, being a total of $62.5 million at 31 December 2019 (2018: $53.2 million).
The fiscal and economic situation in Ukraine was reasonably stable during 2019, with a better economic outlook, GDP growth, reduced inflation and stability in the Ukrainian Hryvnia exchange rates. Nevertheless, Ukraine retains residual risk of fiscal and economic stress, and we remain vigilant.
The Ukrainian Government has implemented a number of reforms in the oil and gas sector in recent years, which include the deregulation of the gas supply market in late 2015, and more recently, reductions in the subsoil tax rates relating to oil and gas production and a simplification of the regulatory procedures applicable to oil and gas exploration and production activities in Ukraine.
The deregulation of the gas supply market, supported by electronic gas trading platforms and improved pricing transparency, has meant that the market gas prices in Ukraine now broadly correlate with the imported gas prices. During 2019, gas prices trended lower, reflecting a similar trend in European gas prices, and were lower than in 2018. Similarly, condensate and LPG prices were also lower by comparison with last year.
New Acquisition
As announced on 24 March 2020, the Group has acquired the entire issued share capital of LLC Arkona Gas-Energy ("Arkona") for total consideration of up to $8.63 million, subject to satisfaction of certain conditions. Arkona holds a 100% interest in the Svystunivsko-Chervonolutskyi ("SC") exploration licence in north-eastern Ukraine, some 15 km east of the SV field. The SC licence was granted in May 2017, with a duration of 20 years, and is prospective for gas and condensate. As with the productive reservoirs in the SV field, the prospective reservoirs in this licence are Visean, at depths between 4,600 - 6,000 metres. We believe that our existing knowledge of the subsurface geology in the area will enable us to quickly progress our development planning for this licence, and we hope to be able to commence drilling operations on the licence within 12 months.
Board and Management Changes
In June 2019, Bruce Burrows was appointed as Finance Director of the Company, having previously been a non-executive Director, and Oleksiy Zayets was appointed as Chief Financial Officer of the Company's Ukrainian operations.
COVID-19 Virus
We are closely monitoring the current volatility in global financial markets, and the implications on the operational, economic and social environment within which we work caused by the COVID-19 pandemic, coupled with the recent sharp decline in oil prices. As of the date hereof, there has been no operational disruption linked to the COVID-19 pandemic, and no material impact is currently envisaged on the Group's prospects. However, the Board and management remain acutely aware of the risks, and are taking action to mitigate them where possible. This is a rapidly evolving situation and we are working to not only protect our staff and stakeholders but to minimise disruption to our business. Our supply chain is not materially exposed to countries currently most affected by the pandemic, and we hold good inventories of critical spares for our field operations. We have reassessed our medium-term forecasts based on current pricing and are highly confident we have the resources to continue to deliver on our plans. Of course, we cannot be certain of the duration of the pandemic's impact but will remain focussed on monitoring and protecting our business through the period of uncertainty. In protecting our stakeholders interests, we are conscious of our wider obligations to the communities, and country, in which we operate. Accordingly, we have acted, alongside other corporate entities in Ukraine, to directly acquire critical equipment and supplies from Chinese suppliers to donate to the Ukrainian State to assist its efforts to manage the pandemic in Ukraine. We have allocated $2 million to this initiative.
Outlook
Whilst there are still challenges in the business environment in Ukraine, the situation is improving gradually. After the steady operational performance during 2019, and the increased production output during the year, we are eagerly awaiting the results of the SV-54 development well, which are expected in the third quarter of 2020. We are also looking forward to achieving further successes in the development activities planned for 2020 and delivering a steadily increasing production and revenue stream in the future.
In conclusion, on behalf of the Board, I would like to thank all of our staff for the continued dedication and support they have shown during the year and especially during the current COVID-19 pandemic.
Chris Hopkinson
Chairman
Chief Executive Officer's Statement
Introduction
The Group continued its good progress at its Ukrainian fields during 2019, with development activity at the MEX-GOL and SV fields including the successful drilling of the MEX-119 development well, which came on production in October 2019, the successful workover of the MEX-106 well to renew the production tubing, and hydraulic fracturing operations at the MEX-120 well. In addition, work continued to refine the geological model of the fields, upgrade the gas processing facilities and pipeline network, and undertake remedial work on existing wells.
At the VAS field, acquisition of the remaining coverage of 3D seismic over the field was completed in early 2019 and the data acquired was processed and interpreted. However, a decline in production rates from the VAS-10 well impacted overall production at the VAS field during the fourth quarter of 2019, and as a result, compression equipment was installed at the well.
Overall production was steady during 2019, and significantly higher than in 2018, with a substantial boost in the fourth quarter, once the MEX-119 well came on production.
Quality, Health, Safety and Environment ("QHSE")
The Group is committed to maintaining the highest QHSE standards and the effective management of these areas is an intrinsic element of the overall business ethos. Through strict enforcement of the Group's QHSE policies, together with regular management meetings, training and the appointment of dedicated safety professionals, the Group strives to ensure that the impact of its business activities on its staff, contractors and the environment is as low as is reasonably practicable. The Group reports safety and environmental performance in accordance with industry practice and guidelines.
I am pleased to report that during 2019, a total of 413,419 man-hours of staff and contractor time were recorded without a Lost Time Incident occurring. The total number of safe man-hours now stands at over 2,954,500 man-hours without a Lost Time Incident. No environmental incidents were recorded during the year.
Production
The average daily production of gas, condensate and LPG from the MEX-GOL, SV and VAS fields for the year ended 31 December 2019 was as follows:-
Field Gas Condensate LPG Aggregate
(MMscf/d) (bbl/d) (bbl/d) boepd
2019 2018 2019 2018 2019 2018 2019 2018
------ ----- ------ ------ ------ ------ ------ ------
MEX-GOL
& SV 14.8 12.0 577.8 436.2 274.4 225.0 3,391 2,717
------ ----- ------ ------ ------ ------ ------ ------
VAS 4.4 3.3 61.9 49.9 - - 872 674
------ ----- ------ ------ ------ ------ ------ ------
Total 19.2 15.3 639.7 486.1 274.4 225.0 4,263 3,391
------ ----- ------ ------ ------ ------ ------ ------
Production rates were higher in 2019 when compared with 2018, predominantly due to the success of the MEX-119 well in the fourth quarter of 2019.
The Group's average daily production for the period from 1 January 2020 to 31 March 2020 from the MEX-GOL and SV field was 17.3 MMscf/d of gas, 659 bbl/d of condensate and 280 bbl/d m(3)/d of LPG (3,904 boepd in aggregate) and from the VAS field was 3.1 MMscf/d of gas and 34 bbl/d of condensate (604 boepd in aggregate).
Operations
The much improved fiscal and economic conditions in Ukraine, coupled with reasonable stability in the Ukrainian Hryvnia, reductions in the subsoil tax rates and improvements in the regulatory procedures in the oil and gas sector in Ukraine over the last year, gave the Board the confidence to continue the Group's development programme at its Ukrainian fields during 2019. However, lower realised gas prices impacted revenues, following a general decline in gas prices in Europe.
The Group continued to refine its geological subsurface models of the MEX-GOL, SV and VAS fields, in order to enhance its strategies for the further development of the fields, including the timing and level of future capital investment required to exploit the hydrocarbon resources.
At the MEX-GOL and SV fields, the MEX-119 development well was spudded in February 2019 and drilled to a depth of 4,822 metres, which was slightly shallower than its planned depth, after the targeted horizons were encountered. The well targeted production from the B-20 reservoirs in the Visean formation. One interval, at a drilled depth of 4,804 - 4,816 metres, was perforated, and after successful testing, the well was hooked-up to the gas processing facilities. The well has demonstrated excellent production rates and is currently producing at approximately 4.8 MMscf/d of gas and 216 bbl/d of condensate (1,058 boepd in aggregate).
The Group continues to operate each of the SV-2 and SV-12 wells under joint venture agreements with NJSC Ukrnafta, the majority State-owned oil and gas producer. Under the agreements, the gas and condensate produced from the respective wells is sold under an equal net profit sharing arrangement between the Group and NJSC Ukrnafta, with the Group accounting for the hydrocarbons produced and sold from the wells as revenue, and the net profit share due to NJSC Ukrnafta being treated as a lease expense in cost of sales. Both of these wells have proven to be strong producers since being brought back on production.
At the MEX-106 well, a successful workover was undertaken to renew the production tubing, which boosted production from this well, and at the MEX-120 well, hydraulic fracturing operations were undertaken, following which the well was lifted using coiled tubing, but only modest flows of gas and condensate were recovered and the well is now under observation. In addition, the Group upgraded the gas processing facilities and pipeline network, and undertook remedial work on existing wells.
Drilling of the SV-54 well has been completed, with the well having reached a final depth of 5,322 metres. Completion operations have now commenced and these are scheduled to be concluded by the end of the second quarter of 2020, and, subject to successful testing, production hook-up is anticipated during the third quarter of 2020. The well is a development well, with its primary targets being the B-22 and B-23 horizons in the Visean formation.
At the VAS field, interpretation of the 3D seismic data acquired last year was completed and integrated into the geological model for the field. Planning is continuing for a new well to explore the VED prospect within the VAS licence area. However, a decline in production rates from the VAS-10 well impacted overall production at the VAS field during the fourth quarter, and as a result, compression equipment was installed to increase production from this well, with a longer term plan to undertake a workover of the well to access an alternative reservoir horizon.
In March 2019 (see announcement made on 12 March 2019), a regulatory issue arose when the State Service of Geology and Subsoil of Ukraine issued an order for suspension (the "Order") of the production licence for the VAS field. Under the applicable legislation, the Order would lead to a shut-down of production operations at the VAS field, but the Group has issued legal proceedings to challenge the Order, and has obtained a ruling suspending operation of the Order pending a hearing of the substantive issues. The Group does not believe that there are any grounds for the Order, and intends to pursue its challenge to the Order through the Ukrainian Courts.
Reserves Update
In early 2019, the Group commissioned DeGolyer and MacNaughton ("D&M") to prepare an updated assessment of the remaining reserves and resources at the VAS field as at 31 December 2018 in order to provide an update since the previous reserves estimation undertaken by Senergy (GB) Limited ("Senergy") as at 1 January 2016.
The updated assessment of 1.895 MMboe of proved (1P) and 3.145 MMboe of proved + probable (2P) reserves resulted in a material increase in these categories of remaining reserves from the 2016 Senergy estimates, which were 0.66 MMboe and 1.80 MMboe respectively. These increases reflect a higher level of confidence in the understanding of the subsurface at the field as a result of the new data obtained since 2016. Further details of the D&M assessment are set out in the Company's announcement dated 21 August 2019. Over and above the increase in reserves themselves, the Group is tailoring its field development programme for the VAS fields, which is envisaged to include increased development activity, production and cash flow in future periods.
New Acquisitions
As announced on 24 March 2020, the Group has acquired the entire issued share capital of LLC Arkona Gas-Energy for total consideration of up to $8.63 million, with $4.3 million subject to the satisfaction of certain conditions as set out therein. Arkona holds a 100% interest in the Svystunivsko-Chervonolutskyi ("SC") exploration licence, which is located in the Poltava region in north-eastern Ukraine. The SC licence has an area of 97 km(2) , 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 C(1) and C(2) under the Ukrainian classification, DKZ, of approximately 38.0 MMboe (4.9 Bm(3) of gas and 0.86 Mtonnes of condensate). It should be noted, however, that whilst the Group's review of existing technical data for the licence is considered supportive of such assessment of hydrocarbon reserves, such hydrocarbon reserves have not been verified by an independent reserves assessor and do not correspond to the SPE/WPC/AAPG/SPEE Petroleum Resources Management System ("PRMS") standard for classification and reporting.
We believe that our existing knowledge of the subsurface geology in the area will enable us to quickly progress our development planning for this licence, and we envisage that this will include the commencement of a new well within the next 12 months, with drilling and completion operations expected to take up to a further 12 months.
As announced on 1 April 2020, the Memorandum of Understanding (the "Memorandum") for the potential acquisition of PJSC Science and Production Concern Ukrnaftinvest , announced on 26 November 2019, expired and was consequently terminated as a result of the parties to the Memorandum, being (1) the Company and (2) Ms Lidiia Chernysh and Bolaso Investments Limited, being unable to reach a final agreement for such potential acquisition. The provisions relating to such termination set out in the Memorandum are now applicable, and these include the refund of the deposit of $0.5 million previously paid under the Memorandum.
Outlook
During 2020, the Group will continue to develop the MEX-GOL, SV and VAS fields, as well as commence work of the development planning for the SC licence . At the MEX-GOL and SV fields, the development programme includes completing the drilling and production hook-up of the SV-54 development well (which is scheduled for Q4 2020), commencing a new well, SV-25, in the SV field, which is planned to be spudded later in the year, planning for a further well or sidetracking of an existing well in the SV field, investigating workover opportunities for other existing wells, installation of further compression equipment, further upgrading of the gas processing facilities and pipeline network, and remedial and upgrade work on existing wells, pipelines and other infrastructure.
At the VAS field, planning for the proposed new well to explore the VED prospect within the VAS licence area is continuing, and upgrades to the gas processing facilities, pipeline network and other infrastructure are planned.
There has also been encouraging recent legislation relating to the oil and gas sector in Ukraine, demonstrating the Ukrainian Government's stated intention to promote and support the domestic oil and gas production industry. These measures include reductions in the subsoil taxes applicable to the production of hydrocarbons, which became effective for gas production from new wells drilled after 1 January 2018 and came into effect for condensate production from all wells from 1 January 2019. Furthermore, new legislation was introduced last year to simplify a number of the regulatory procedures relating to oil and gas exploration and production activities in Ukraine.
These measures, and the general improvement in the business climate in Ukraine, are encouraging and supportive of the independent oil and gas producers in Ukraine.
Finally, I would like to add my thanks to all of our staff for the continued hard work and dedication they have shown over what has been a successful year for the Group, and to especially recognise their continuing efforts and professionalism during the current COVID-19 pandemic.
Sergii Glazunov
Chief Executive Officer
Overview of Assets
We operate three fields, and recently acquired a further field, in the Dnieper-Donets basin in north-eastern Ukraine.
Our fields have high potential for growth and longevity for future production - a strong foundation for success.
MEX-GOL and SV fields
The MEX-GOL and SV fields are held under two adjacent production licences, but are operated as one integrated asset, and have significant gas and condensate reserves and potential resources of unconventional gas.
Production Licences
We hold a 100% working interest in, and are the operator of, the MEX-GOL and SV fields. The production licences for the fields were granted to the Group in July 2004 with a duration of 20 years, and it is intended to apply to extend the licences under the applicable regulations in Ukraine in order to fully develop the remaining reserves. The economic life of these fields extend to 2038 and 2042 respectively pursuant to the most recent reserves and resources assessment by DeGolyer and MacNaughton ("D&M") as at 31 December 2017.
The two licences, located in Ukraine's Poltava region, are adjacent and extend over a combined area of 269 km(2), 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 km(2) and is located 17 km south-east of Kharkiv, in the Kharkiv region of Ukraine. The field was discovered in 1981, and the first well on the licence area was drilled in 2004.
The Group acquired this project in July 2016.
Geology
Geologically, the field is located towards the middle of the Dnieper-Donets sedimentary basin in north-east Ukraine. The field is trapped in an anticlinal structure broken into several faulted blocks, which are gently dipping to the north, stretching from the north-east to south-west along a main bounding fault. The gas is located in Carboniferous sandstones of Bashkirian, Serpukhovian and Visean age.
The productive reservoirs are at depths between 3,370 and 3,700 metres depth.
Reserves
The fields have been mapped with 3D seismic, and a geological subsurface model has been developed and refined using data derived from such 3D seismic and new wells drilled on the field.
The assessment undertaken by D&M as at 31 December 2018 estimated proved plus probable (2P) reserves of 3.1 MMboe, with contingent resources of 0.6 MMboe, and prospective resources of 7.7 MMboe in the VED area of the field. The next well planned on the field is designed to explore the VED area of the field.
Overview of Reserves
1. MEX-GOL and SV fields
The Group's estimates of the remaining Reserves and Resources at the MEX-GOL and SV fields are derived from an assessment undertaken by D&M, as at 31 December 2017 (the "MEX-GOL-SV Report"), which was announced on 31 July 2018. During the period from 1 January 2018 to 31 December 2019, the Group has produced 2.2 MMboe from these fields.
The MEX-GOL-SV Report estimated the remaining Reserves as at 31 December 2017 in the MEX-GOL and SV fields as follows:-
Proved Proved + Probable Proved + Probable
(1P) (2P) + Possible (3P)
121.9 Bscf / 3.5 218.3 Bscf / 6.2 256.5 Bscf / 7.3
Gas Bm(3) Bm(3) Bm(3)
----------------- ------------------ ------------------
4.3 MMbbl / 514 7.9 MMbbl / 943 9.2 MMbbl / 110
Condensate Mtonne Mtonne Mtonne
----------------- ------------------ ------------------
2.8 MMbbl / 233 5.0 MMbbl / 418 5.8 MMbbl / 491
LPG Mtonne Mtonne Mtonne
----------------- ------------------ ------------------
27.8 MMboe 50.0 MMboe 58.6 MMboe
Total
----------------- ------------------ ------------------
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 Contingent Resources Contingent Resources
(1C) (2C) (3C)
14.7 Bscf / 0.42 38.3 Bscf / 1.08 105.9 Bscf / 3.00
Gas Bm(3) Bm(3) Bm(3)
--------------------- --------------------- ---------------------
1.17 MMbbl / 144 2.8 MMbbl / 343 6.6 MMbbl / 812
Condensate Mtonne Mtonne Mtonne
--------------------- --------------------- ---------------------
3.8 MMboe 9.6 MMboe 25.3 MMboe
Total
--------------------- --------------------- ---------------------
2. VAS field
The Group's estimates of the remaining Reserves and Resources at the VAS field and the Prospective Resources at the VED prospect are derived from an assessment undertaken by D&M as at 31 December 2018 (the "VAS Report"), which was announced on 21 August 2019. During the period from 1 January 2019 to 31 December 2019, 0.3 MMboe were produced from the field.
The VAS Report estimates the remaining Reserves as at 31 December 2018 in the VAS field as follows:-
Proved Proved + Probable Proved + Probable
(1P) (2P) + Possible (3P)
9,114 MMscf / 258 15,098 MMscf / 18,816 MMscf /
Gas MMm(3) 427 MMm(3) 533 MMm(3)
--------------------- --------------------- ------------------
205 Mbbl / 25 Mtonne 346 Mbbl / 42 Mtonne 401 Mbbl / 48
Condensate Mtonne
--------------------- --------------------- ------------------
1.895 MMboe 3.145 MMboe 3.890 MMboe
Total
--------------------- --------------------- ------------------
The VAS Report estimates the Contingent Resources as at 31 December 2018 in the VAS field as follows:-
Contingent Resources Contingent Resources Contingent Resources
(1C) (2C) (3C)
2,912 MMscf /
Gas 0 0 83 MMm(3)
--------------------- --------------------- ---------------------
Condensate 0 0 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
23,721 MMscf 38,079 MMscf 62,293 MMscf 41,291 MMscf
Gas / 672 MMm(3) / 1,078 MMm(3) / 1,764 MMm(3) / 1,169 MMm(3)
-------------- ---------------- ---------------- ----------------
Finance Review
The Group delivered a very solid financial performance in 2019, enabled by a record level of gas production, and despite a significant drop in average gas realisations. Net profit for the year was $12.2 million (2018: $54.3 million including the $36.1 million benefit of a one-off reversal of impairment of oil and gas development and production assets).
Gross profit for the year ended 31 December 2019 was $23.5 million (2018: $34.2 million). The 31% drop in gross profit year-on-year is almost entirely a result of weakened gas prices in the year (average realisations of $219/Mm(3) compared to $312/Mm(3) in 2018), with condensate and LPG sales up 7.5% and 5.5% respectively, and cost of sales up a modest 1.7% year-on-year.
Revenue for the year, derived from the sale of the Group's Ukrainian gas, condensate and LPG production, was $55.9 million (2018: $66.1 million). The gas price-driven fall in revenue also impacted cash generated from operations during the year, which was 32% lower at $24.6 million (2018: $36.3 million) predominantly, as noted, as a result of lower gas prices and despite the higher production volumes achieved in the year.
The average realised gas, condensate and LPG prices during the 2019 year were $219/Mm(3) (UAH5,729/Mm(3) ), $58/bbl and $55/bbl respectively (2018: $312/Mm(3) (UAH8,528/Mm(3) ), $72/bbl and $64/bbl respectively).
During the period from 1 January 2020 to 7 April 2020, the average realised gas, condensate and LPG prices were $158/Mm(3) (UAH3,961/Mm(3) ), $47/bbl and $43/bbl respectively. The current realised gas price is $128/Mm(3) (3,469/Mm(3) ).
As noted above, 2019 saw a significant drop in averaged realised gas prices, having the singularly greatest impact on our 2019 performance. Since the deregulation of the gas supply market in Ukraine in October 2015, the market price for gas has broadly correlated to the price of imported gas, which generally reflects trends in European gas prices. Gas prices are also subject to seasonal variation. During the 2019 year, gas prices were depressed, as a combined result of lower international prices reducing the price of imported gas, and the unseasonally warm 2019/20 winter. Condensate and LPG prices were also lower than in 2018.
Cost of sales for the year ended 31 December 2019 was marginally higher at $32.4 million (2018: $31.9 million). Whilst broadly consistent with last year, there were some significant intra-total movements: production taxes declined by 22% as a result of reduced gas revenues, in turn a function of the reduced gas prices as noted above; a 19% increase in rent expense, a function of increased production; staff costs increased by 19% as a function of a maturing employment market in Ukraine and associated salary inflation; and a new transmission tariff for use of the Ukrainian gas system of UAH91.87/Mm(3) of gas was introduced and applicable to oil and gas producers in Ukraine, including the Group, resulting in a $673,000 (2018: nil) charge in the period.
New legislation relating to the oil and gas sector in Ukraine has been introduced over the last year, and in this regard, with effect from 1 January 2019, the subsoil tax rates, as included in cost of sales, applicable to condensate production were reduced from 45% to 31% for condensate produced from deposits above 5,000 metres and from 21% to 16% for condensate produced from deposits below 5,000 metres.
Administrative expenses for the year were higher at $7.4 million (2018: $5.7 million), primarily as a result of: an 18% increase in payroll and related taxes, consistent with the maturing employment market as noted above; a 150% increase in depreciation of fixed assets as a result of additions, and the implementation of IFRS 16 from 1 January 2019, whereby the Group now calculates the expense by depreciation of the right-to-use assets and interest expense on the liability over the lease term; and a 94% increase in other expenses primarily in relation to increased costs for managing gas transportation and storage, and marketing.
The tax charge for the year reduced by 23% to $9.6 million (2018: $12.5 million charge) and comprises a current tax charge of $4.8 million (2018: $6.5 million charge) and a deferred tax charge of $4.8 million (2018: $6.0 million charge). The material reduction in the deferred tax charge results from the $5.5 million 2018 deferred tax charge being incurred as a result of the reversal of the impairment of the carrying value of the Group's MEX-GOL and SV development and production asset, and the reversal of the impairment of intra-group loans receivable by the Company.
The Group derecognised a deferred tax asset of $ 2 . 1 million at 31 December 2019 (31 December 2018: $2.1 million ). In the period the opening balance deferred tax asset of $2.1 million in relation to UK tax losses carried forward was charged to the Income Statement because the Group does not expect to be able to utilise unrecognised UK losses carried forward in the foreseeable future. In addition, a deferred tax liability relating to the development and production asset at the MEX-GOL and SV fields of $2.3 million (31 December 2018: deferred tax asset $0.8 million) is recognised on the tax effects of the temporary differences of the provision for decommissioning and the carrying value relating of these assets, and their tax bases.
A deferred tax liability relating to the development and production asset at the VAS field of $0.2 million (31 December 2018: $0.5 million) was recognised at 31 December 2019 on the tax effect of the temporary differences between the carrying value of the development and production asset at the VAS field, and its tax base.
A significant increase in capital investment to $17.7 million reflects the expenditure on oil and gas development assets during the year (2018: $9.6m), following the field studies and revised development plans undertaken by the Group over recent periods. The carrying value of the Group's assets was reviewed at year end as a result of the significant drop in gas prices during the year, which did not result in any impairment of assets.
Cash and cash equivalents held at 31 December 2019 were up 17% at $62.5 million (31 December 2018: $53.2 million). The Group's cash and cash equivalents balance at 7 April 2020 was $55.2 million, held as to $18.5 million equivalent in Ukrainian Hryvnia and the balance of $36.7 million equivalent predominantly in US Dollars, Euros and Pounds Sterling.
Between early 2014 and 2018, the Ukrainian Hryvnia devalued significantly against the US Dollar, falling from UAH8.3/$1.00 on 1 January 2014 to UAH27.7/$1.00 on 31 December 2018, which resulted in substantial foreign exchange translation losses for the Group over that period, and in turn adversely impacted the carrying value of the MEX-GOL and SV asset due to the translation of two of the Group's subsidiaries from their functional currency of Ukrainian Hryvnia to the Group's presentation currency of US Dollars. However, during 2019, the Ukrainian Hryvnia strengthened materially against the US Dollar averaging UAH25.8/$1.00 during the period (average rate during 2018: UAH27.2/$1.00). The total foreign exchange gain in the period was $3.5 million (2018: $0.5 million). In the later part of Q1 2020 however, global financial markets have become extremely volatile as a combined function of a significant fall in oil prices and the effects of the COVID-19 pandemic, and the Ukrainian Hryvnia has weakened against the US Dollar with the exchange rate at 7 April 2020 being UAH27.2/$1.00. Further devaluation of the Ukrainian Hryvnia against the US Dollar may affect the carrying value of the Group's assets in the future.
Cash from operations has funded the capital investment during the year, and the Group's current cash position and positive operating cash flow are the sources from which the Group plans to fund the development programmes for its assets in 2020 and beyond. This is coupled with the fact that the Group is currently debt-free, and therefore has no debt covenants that may otherwise impede the ability to implement contingency plans if domestic and/or global circumstances dictate. This flexibility and ability to monitor and manage development plans and liquidity is a cornerstone of our planning, and underpins our assessments of the future.
The Group manages its revenue, cash from operations and production volumes as key performance indicators. The achieved results for 2019 were as follows:
-- revenue of $55.9 million (2018: $66.1 million)
-- cash from operations of $24.6 million (2018: $36.8 million)
-- daily production volumes from the MEX-GOL and SV fields for
the year of 14.8 MMscf/d of gas, 577.8 bbl/d of condensate
and 274.4 bbl/d of LPG (3,391 boepd in aggregate) (2018: 12.0
MMscf/d of gas, 436.2 bbl/d of condensate and 225.0 bbl/d
of LPG (2,717 boepd in aggregate))
-- daily production volumes from the VAS field for the year of
4.4 MMscf/d of gas and 61.9 bbl/d of condensate (872 boepd
in aggregate) (2018: 3.3 MMscf/d of gas and 49.9 bbl/d of
condensate (674 boepd in aggregate))
-- aggregate production volumes from the MEX-GOL and SV fields
for the year of 5,417 MMscf/d of gas, 210,894 bbl/d of condensate
and 100,168 bbl/d of LPG, equating to a combined total oil
equivalent of 1,237,695 boe (2018: 4,394 MMscf/d of gas, 159,203
bbl/d of condensate and 82,127 bbl/d of LPG (992,880 boe in
aggregate))
-- aggregate production volumes from the VAS field for the year
of 1,589 MMscf/d of gas and 22,603 bbl/d of condensate, equating
to a combined total oil equivalent of 318,254 boe (2018: 1,221
MMscf/d of gas and 18,206 bbl/d of condensate (245,392 boe
in aggregate))
-- Lost Time Incidents of zero (2018: zero).
Principal Risks
The Group has a risk evaluation methodology in place to assist in the review of the risks across all material aspects of its business. This methodology highlights external, operational and technical, financial and corporate risks and assesses the level of risk and potential consequences. It is periodically presented to the Audit Committee and the Board for review, to bring to their attention potential risks and, where possible, propose mitigating actions. Key risks recognised and mitigation factors are detailed below:-
Risk Mitigation
External risks
-----------------------------------------------
Risk relating to Ukraine
-----------------------------------------------
Ukraine is an emerging market and The Group minimises this risk by
as such the Group is exposed to continuously monitoring the market
greater regulatory, economic and in Ukraine and by maintaining a
political risks than it would be strong working relationship with
in other jurisdictions. Emerging the Ukrainian regulatory authorities.
economies are generally subject The Group also maintains a significant
to a volatile political and economic proportion of it cash holdings in
environment, which makes them vulnerable international banks outside Ukraine.
to market downturns elsewhere in
the world and could adversely impact
the Group's ability to operate
in the market.
-----------------------------------------------
Regional conflict
-----------------------------------------------
Ukraine continues to have a strained As the Group has no assets in Crimea
relationship with Russia, following or the areas of conflict in the
Ukraine's agreement to join a free east of Ukraine, nor do its operations
trade area with the European Union, rely on sales or costs incurred
which resulted in the implementation there, the Group has not been directly
of mutual trade restrictions between affected by the conflict. However,
Russia and Ukraine on many key the Group continues to monitor the
products. Further, the conflict situation and endeavours to procure
in parts of eastern Ukraine has its equipment from sources in other
not been resolved to date, and markets. The disputes and interruption
Russia continues to occupy Crimea. to the supply of gas from Russia
This conflict has put further pressure has indirectly encouraged Ukrainian
on relations between Ukraine and Government support for the development
Russia, and the political tensions of the domestic production of hydrocarbons
have had an adverse effect on the since Ukraine imports a significant
Ukrainian financial markets, hampering proportion of its gas, which has
the ability of Ukrainian companies resulted in legislative measures
and banks to obtain funding from to improve the regulatory requirements
the international capital and debt for hydrocarbon extraction in Ukraine.
markets. This strained relationship
between Russia and Ukraine has
also resulted in disputes and interruptions
in the supply of gas from Russia.
-----------------------------------------------
Banking system in Ukraine
-----------------------------------------------
The banking system in Ukraine has The creditworthiness and potential
been under great strain in recent risks relating to the banks in Ukraine
years due to the weak level of are regularly reviewed by the Group,
capital, low asset quality caused but the geopolitical and economic
by the economic situation, currency events since 2013 in Ukraine have
depreciation, changing regulations significantly weakened the Ukrainian
and other economic pressures generally, banking sector. In light of this,
and so the risks associated with the Group has taken and continues
the banks in Ukraine have been to take steps to diversify its banking
significant, including in relation arrangements between a number of
to the banks with which the Group banks in Ukraine. These measures
has operated bank accounts. However, are designed to spread the risks
following remedial action imposed associated with each bank's creditworthiness,
by the National Bank of Ukraine, and the Group endeavours to use
Ukraine's banking system has improved banks that have the best available
moderately. Nevertheless, Ukraine creditworthiness. Nevertheless,
continues to be supported by funding and despite the recent improvements,
from the International Monetary the Ukrainian banking sector remains
Fund. 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 The Group continually monitors the
in recent years, there has not market and business environment
been a final resolution of the in Ukraine and endeavours to recognise
political, fiscal and economic approaching risks and factors that
situation in Ukraine and its ongoing may affect its business. In addition,
effects are difficult to predict the involvement of Lovitia Investments
and likely to continue to affect Limited, as an indirect major shareholder
the Ukrainian economy and potentially with extensive experience in Ukraine,
the Group's business. Whilst not is considered helpful to mitigate
materially affecting the Group's such risks.
production operations, the instability
has disrupted the Group's development
and operational planning for its
assets.
-----------------------------------------------
Climate change
-----------------------------------------------
Any near and medium-term continued The Group's plans include: assessing,
warming of the Planet can have reducing and/or mitigating its emissions
potentially increasing negative in its operations ; and identifying
social, economic and environmental climate change-related risks and
consequences, generally globally assessing the degree to which they
and regionally, and specifically can affect its business, including
in relation to the Group. The potential financial implication.
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.
-----------------------------------------------
Operational and technical risks
-----------------------------------------------
Quality, Health, Safety and Environment
("QHSE")
-----------------------------------------------
The oil and gas industry, by its The Group maintains QHSE policies
nature, conducts activities which and requires that management, staff
can cause health, safety, environmental and contractors adhere to these
and security incidents. Serious policies. The policies ensure that
incidents can not only have a financial the Group meets Ukraine legislative
impact but can also damage the standards in full and achieves international
Group's reputation and the opportunity standards to the maximum extent
to undertake further projects. possible. As a consequence of the
As evidenced by events in Q1 2020, COVID-19 pandemic the Group is re-visiting
pandemics also pose a risk to operations, processes and controls intended
by potential illness and threat to ensure protection of all our
to life of employees and contractors, stakeholders and minimise any disruption
and the associated disruptions to our business. Whilst possible
in staffing levels, operations to only a limited extent in field
and supply chain. 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 The Group has well qualified and
are generally associated with the experienced technical management
oil and gas industry. For example, staff to plan and supervise operational
the Group's ability to pursue and activities. In addition, the Group
develop its projects and development engages with suitably qualified
programmes depends on a number local and international geological,
of uncertainties, including the geophysical and engineering experts
availability of capital, seasonal and contractors to supplement and
conditions, regulatory approvals, broaden the pool of expertise available
gas, oil, condensate and LPG prices, to the Group. Detailed planning
development costs and drilling of development activities is undertaken
success. As a result of these uncertainties, with the aim of managing the inherent
it is unknown whether potential risks associated with oil and gas
drilling locations identified on exploration and production, as well
proposed projects will ever be as ensuring that appropriate equipment
drilled or whether these or any and personnel are available for
other potential drilling locations the operations, and that local contractors
will be able to produce gas, oil are appropriately supervised.
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.
-----------------------------------------------
Production of hydrocarbons
-----------------------------------------------
Producing gas and condensate reservoirs In 2016, the Group engaged external
are generally characterised by technical consultants to undertake
declining production rates which a comprehensive review and re-evaluation
vary depending upon reservoir characteristics study of the MEX-GOL and SV fields
and other factors. Future production in order to gain an improved understanding
of the Group's gas and condensate of the geological aspects of the
reserves, and therefore the Group's fields and reservoir engineering,
cash flow and income, are highly drilling and completion techniques,
dependent on the Group's success and the results of this study and
in operating existing producing further planned technical work is
wells, drilling new production being used by the Group in the future
wells and efficiently developing development of these fields. The
and exploiting any reserves, and Group has established an ongoing
finding or acquiring additional relationship with such external
reserves. The Group may not be technical consultants to ensure
able to develop, find or acquire that technical management and planning
reserves at acceptable costs. The is of a high quality in respect
experience gained from drilling of all development activities on
undertaken to date highlights such the Group's fields.
risks as the Group targets the
appraisal and production of these
hydrocarbons.
-----------------------------------------------
Risks relating to further development
and operation of the Group's gas
and condensate fields in Ukraine
-----------------------------------------------
The planned development and operation The Group's technical management
of the Group's gas and condensate staff, in consultation with its
fields in Ukraine is susceptible external technical consultants,
to appraisal, development and operational carefully plan and supervise development
risk. This could include, but is and operational activities with
not restricted to, delays in delivery the aim of managing the risks associated
of equipment in Ukraine, failure with the further development of
of key equipment, lower than expected the Group's fields in Ukraine. This
production from wells that are includes detailed review and consideration
currently producing, or new wells of available subsurface data, utilisation
that are brought on-stream, problematic of modern geological software, and
wells and complex geology which utilisation of engineering and completion
is difficult to drill or interpret. techniques developed for the fields.
The generation of significant operational With operational activities, the
cash is dependent on the successful Group ensures that appropriate equipment
delivery and completion of the and personnel is available for the
development and operation of the operations, and that operational
fields. 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 utilisation of detailed sub-surface
the reservoirs in the Group's fields, analysis, careful well planning
the technical difficulty of drilling and engineering design in designing
or re-entering wells in the Group's work programmes, along with appropriate
fields is high, and this and the procurement procedures and competent
equipment limitations within Ukraine, on-site management, aims to minimise
can result in unsuccessful or lower these risks.
than expected outcomes for wells.
-----------------------------------------------
Maintenance of facilities
-----------------------------------------------
There is a risk that production The Group's facilities are operated
or transportation facilities can and maintained at standards above
fail due to non-adequate maintenance, the Ukraine minimum legal requirements.
control or poor performance of Operations staff are experienced
the Group's suppliers. 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 The Group maintains adequate cash
funds are available to meet the reserves and closely monitors forecasted
Group's development obligations and actual cash flow, as well as
to commercialise the Group's oil short and longer-term funding requirements.
and gas assets. Since a significant The Group does not currently have
proportion of the future capital any loans outstanding, internal
requirements of the Group is expected financial projections are regularly
to be derived from operational made based on the latest estimates
cash generated from production, available, and various scenarios
including from wells yet to be are run to assess the robustness
drilled, there is a risk that in of the liquidity of the Group. However,
the longer term insufficient operational as the risk to future capital funding
cash is generated, or that additional is inherent in the oil and gas exploration
funding, should the need arise, and development industry and reliant
cannot be secured. 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, The Group maintains anti-bribery
an emerging market, where certain and corruption policies in relation
inappropriate business practices to all aspects of its business,
may, from time to time occur, such and ensures that clear authority
as corrupt business practices, levels and robust approval processes
bribery, appropriation of property are in place, with stringent controls
and fraud, all of which can lead over cash management and the tendering
to financial loss. 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 The Group sells a proportion of
from the sale of its Ukrainian its hydrocarbon production through
gas, condensate and LPG production. long-term offtake arrangements,
These revenues are subject to commodity which include pricing formulae so
price volatility and political as to ensure that it achieves market
influence. A prolonged period of prices for its products, as well
low gas, condensate and LPG prices utilising the electronic market
may impact the Group's ability platforms in Ukraine to achieve
to maintain its long-term investment market prices for its remaining
programme with a consequent effect products. However, hydrocarbon prices
on growth rate, which in turn may in Ukraine are implicitly linked
impact the share price or any shareholder to world hydrocarbon prices and
returns. Lower gas, condensate so the Group is subject to external
and LPG prices may not only decrease price trends.
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.
-----------------------------------------------
Currency risk
-----------------------------------------------
Since the beginning of 2014 , the The Group's sales proceeds are received
Ukrainian Hryvnia significantly in Ukrainian Hryvnia, and the majority
devalued against major world currencies, of the capital expenditure costs
including the US Dollar, where for the current investment programme
it has fallen from UAH8.3/$1.00 will be incurred in Ukrainian Hryvnia,
on 1 January 2014 to UAH27.7/$1.00 thus the currency of revenue and
on 31 December 2018. It did, though, costs are largely matched. In light
strengthen significantly in 2019 of the previous devaluation and
to UAH23.7/$1.00 on 31 December volatility of the Ukrainian Hryvnia
2019. This devaluation through against major world currencies,
to 2018 was a significant contributor and since the Ukrainian Hryvnia
to the imposition of the banking does not benefit from the range
restrictions by the National Bank of currency hedging instruments
of Ukraine over recent years. In which are available in more developed
addition, the geopolitical events economies, the Group has adopted
in Ukraine over recent years, are a policy that, where possible, funds
likely to continue to impact the not required for use in Ukraine
valuation of the Ukrainian Hryvnia be retained on deposit in the United
against major world currencies. Kingdom and Europe, principally
Further devaluation of the Ukrainian in US Dollars.
Hryvnia against the US Dollar will
affect the carrying value of the
Group's assets.
-----------------------------------------------
Counterparty and credit risk
-----------------------------------------------
The challenging political and economic The Group monitors the financial
environment in Ukraine means that position and credit quality of its
businesses can be subject to significant contractual counterparties and seeks
financial strain, which can mean to manage the risk associated with
that the Group is exposed to increased counterparties by contracting with
counterparty risk if counterparties creditworthy contractors and customers.
fail or default in their contractual Hydrocarbon production is sold on
obligations to the Group, including terms that limit supply credit and/or
in relation to the sale of its title transfer until payment is
hydrocarbon production, resulting received .
in financial loss to the Group.
-----------------------------------------------
Financial markets and economic
outlook
-----------------------------------------------
The performance of the Group is The Group's sales proceeds are received
influenced by global economic conditions in Ukrainian Hryvnia and a significant
and, in particular, the conditions proportion of investment expenditure
prevailing in the United Kingdom is made in Ukrainian Hryvnia , which
and Ukraine. The economies in these minimises risks related to foreign
regions have been subject to volatile exchange volatility. However, hydrocarbon
pressures in recent periods, with prices in Ukraine are implicitly
the global economy having experienced linked to world hydrocarbon prices
a long period of difficulties, and so the Group is subject to external
and more particularly the events price movements. The Group holds
that have occurred in Ukraine over a significant proportion of its
recent years. This has led to extreme cash reserves in the United Kingdom
foreign exchange movements in the and Europe, mostly in US Dollars,
Ukrainian Hryvnia , high inflation with reputable financial institutions.
and interest rates, and increased The financial status of counterparties
credit risk relating to the Group's is carefully monitored to manage
key counterparties. 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 The Group ensures compliance with
where the right to production can commitments and regulations relating
be challenged by State and non-State to its production licences through
parties. During 2010, this manifested Group procedures and controls or,
itself in the form of a Ministry where this is not immediately feasible
Order instructing the Group to for practical or logistical considerations,
suspend all operations and production seeks to enter into dialogue with
from its MEX-GOL and SV production the relevant Government bodies with
licences, which was not resolved a view to agreeing a reasonable
until mid-2011. In 2013, new rules time frame for achieving compliance
relating to the updating of production or an alternative, mutually agreeable
licences led to further challenges course of action. Work programmes
being raised by the Ukrainian authorities are designed to ensure that all
to the production licences held licence obligations are met and
by independent oil and gas producers continual interaction with Government
in Ukraine, including the Group, bodies is maintained in relation
which may result in requirements to licence obligations and commitments.
for remediation work, financial
penalties and/or the suspension
of such licences, which, in turn,
may adversely affect the Group's
operations and financial position.
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. 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
challenge and/or loss of a licence.
-----------------------------------------------
Extension of MEX-GOL and SV licences
-----------------------------------------------
The Group's production licences The Group monitors legislation in
for the MEX-GOL and SV fields currently Ukraine which is likely to affect
expire in 2024. However, in the its licences and the obligations
estimation of its reserves, it associated therewith, and ensures
is assumed that licence extensions that its licence compliance obligations
will be granted in accordance with are monitored and maintained as
current Ukrainian legislation and such compliance is a likely to be
that consequently the fields' development a factor in the extension of the
will continue until the end of licences in 2024.
the fields' economic life in 2038
for the MEX-GOL field and 2042
for the SV field. Despite such
legislation, it is possible that
licence extensions will not be
granted, which would affect the
achievement of full economic field
development and consequently the
carrying value of the Group's MEX-GOL
and SV asset in the future .
-----------------------------------------------
Risks relating to key personnel
-----------------------------------------------
The Group's success depends upon The Group periodically reviews the
skilled management as well as technical compensation and contractual terms
expertise and administrative staff. of its staff. In addition, the Group
The loss of service of critical has developed relationships with
members from the Group's team could a number of technical and other
have an adverse effect on the business. professional experts and advisers,
who are used to provided specialist
services as required.
-----------------------------------------------
Consolidated Income Statement
2019 2018
Note $000 $000
Revenue 6 5 5 , 931 66,098
(3 2 , (31, 8 75
Cost of sales 7 415 ) )
------------------------------------------ ---- --------- ---------
Gross profit 2 3 , 516 34, 2 23
(5,7 09
Administrative expenses 8 (7,396) )
Reversal of impairment of property, plant
and equipment 18 - 34,469
Other operating gains , (net) 11 4, 973 3,387
------------------------------------------ ---- --------- ---------
Operating profit 21, 093 66 , 370
Finance income 12 3,487 641
Finance costs 13 (450) (140)
Net impairment gains on financial assets 32 60
Other losses (net) 14 (2,394) (140)
------------------------------------------ ---- --------- ---------
Profit before taxation 21 , 768 66, 7 91
(9, 569 ( 12,485
Income tax expense 15 ) )
------------------------------------------ ---- --------- ---------
Profit for the year 12,199 54,306
------------------------------------------ ---- --------- ---------
Earnings per share (cents)
Basic and diluted 17 3.8c 16.9c
------------------------------------------ ---- --------- ---------
The Notes set out on below are an integral part of these consolidated financial statements.
Consolidated Statement of Comprehensive Income
2019 201 8
$000 $000
Profit for the year 12,199 54,306
Other comprehensive income/(expense):
Items that may be subsequently reclassified
to profit or loss:
Equity - foreign currency translation 12 ,089 (1,329)
Items that will not be subsequently reclassified
to profit or loss:
Re-measurements of post-employment benefit
obligations 165 (142)
Total other comprehensive income/( expense) 1 2 ,254 (1,471)
Total comprehensive income for the year 24,453 52,835
-------------------------------------------------- -------- -------
Company Statement of Comprehensive Income
Note 2019 2018
$000 $000
( 17 , 507
(Loss)/Profit for the year 1 6 ) 12,057
------------------------------------- ---- ---------- ------
Total comprehensive (expense)/income ( 17 , 507
for the year ) 12,057
------------------------------------- ---- ---------- ------
The Notes set out below are an integral part of these consolidated financial statements.
Consolidated Balance Sheet
201 9 201 8
Note $000 $000
Assets
Non-current assets
Property, plant and equipment 18 70,052 50,1 92
Intangible assets 1 9 5,197 4,880
Right-of-use assets 20 940 -
Prepayment for shares 500 -
Corporation tax receivable 10 27
Deferred tax asset 27 - 3,283
------------------------------ ---- ------------- -----------
76,699 58,382
Current assets
Inventories 2 2 4,813 1,605
Trade and other receivables 23 10,937 10 , 130
Cash and cash equivalents 24 62,474 53,222
------------------------------ ---- ------------- -----------
78,224 64,9 57
Total assets 154,923 12 3 , 339
------------------------------ ---- ------------- -----------
Liabilities
Current liabilities
Trade and other payables 2 5 (3,968) (4,836)
Lease liabilities 20 (454) -
Corporation tax payable (2,221) (1,297)
(6,643) (6,133)
Net current assets 71,581 58, 8 24
------------------------------ ---- ------------- -----------
Non-current liabilities
Provision for decommissioning 2 6 (7,447) (3,137)
Lease liabilities 20 (515) -
Defined benefit liability (480) (468)
Deferred tax liability 2 7 (2,288) ( 504 )
(10,730) (4, 10 9 )
Total liabilities (17,373) (10,242)
------------------------------ ---- ------------- -----------
Net assets 137,550 113,097
------------------------------ ---- ------------- -----------
Equity
Called up share capital 2 8 28,115 28,115
Share premium account 555,090 555,090
Foreign exchange reserve 2 9 ( 90 , 1 72 ) (102, 261 )
Other reserves 29 4,273 4,273
Accumulated losses (359,756) (372, 120 )
Total equity 137,550 113,097
------------------------------ ---- ------------- -----------
The Notes set out below are an integral part of these consolidated financial statements.
Consolidated Statement of Changes in Equity
Called Share Merger Capital Foreign Accumulated Total equity
up share premium reserve contributions exchange losses
capital account reserve reserve*
$000 $000 $000 $000 $000 $000 $000
As at 1 January
201 8 28,115 555,090 (3,204) 7,477 (100,932) (426,178) 60,368
Change in
accounting policy - - - - - (106) (106)
------------------ -------------- -------- -------- ------------- ------------- -------------- ------------
Retained total
equity at the
beginning of the
financial year 28,115 555,090 (3,204) 7,477 (100,932) (426,284) 60,262
Profit for the
year - - - - - 54,306 54,306
Other
comprehensive
expense
- exchange
differences - - - - ( 1,329 ) - ( 1,329)
- re -
measurements of
post-employment
benefit
obligations - - - - - (142) (142)
------------------ -------------- -------- -------- ------------- ------------- -------------- ------------
Total
comprehensive
income/(expense) - - - - ( 1,329 ) 54,164 52,835
------------------ -------------- -------- -------- ------------- ------------- -------------- ------------
As at 31 December
201 8 28,115 555,090 (3,204) 7,477 (102, 261 ) (372,120) 113,097
------------------ -------------- -------- -------- ------------- ------------- -------------- ------------
Called Share Merger Capital Foreign Accumulated Total equity
up share premium reserve contributions exchange losses
capital account reserve reserve*
$000 $000 $000 $000 $000 $000 $000
As at 1 January
201 9 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
201 9 28,115 555,090 (3,204) 7,477 (90,172) (359,756) 137,550
------------------ -------------- -------- -------- ------------- ------------- -------------- ------------
* 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
2019 2018
Note $000 $000
Operating activities
2 4 ,
Cash generated from operations 3 1 6 01 36,342
Equipment rental income 26 8
Income tax paid (3,963) (6,316)
Interest received 4,783 3,038
------------------------------------------------------- ---- ------- --------
2 5 , 33, 07
Net cash inflow from operating activities 4 47 2
------------------------------------------------------- ---- ------- --------
Investing activities
Disposal of subsidiary (7) -
(1 9
, 050
Purchase of property, plant and equipment ) (10,001)
Prepayment for shares (500) -
Purchase of intangible assets (124) (95)
Proceeds from sale of property, plant and equipment 16 74
Proceeds from disposal of other short-term investments - 16,000
------------------------------------------------------- ---- ------- --------
(1 9
, 6 65
Net cash (outflow)/inflow from investing activities ) 5,97 8
------------------------------------------------------- ---- ------- --------
Financing activities
Payment of principal portion of lease liabilities (488) -
------------------------------------------------------- ---- ------- --------
Net cash outflow from financing activities (488) -
------------------------------------------------------- ---- ------- --------
Net increase in cash and cash equivalents 5 , 294 39,050
Cash and cash equivalents at beginning of year 53,222 14,249
Change in accounting policies 4 - (9)
ECL of cash and cash equivalents (7) (13)
Effect of foreign exchange rate changes 3,965 (55)
Cash and cash equivalents at end of year 24 62,474 53,222
------------------------------------------------------- ---- ------- --------
The Notes set out below are an integral part of these consolidated financial statements.
Notes forming part of the financial statements
1. Statutory Accounts
The financial information set out above does not constitute the Company's statutory accounts for the year ended 31 December 2019 or 2018, but is derived from those accounts. The Auditor has reported on those accounts, and its reports were unqualified and did not contain statements under sections 498(2) or (3) of the Companies Act 2006.
The statutory accounts for 2019 will be delivered to the Registrar of Companies following the Company's Annual General Meeting.
While the financial information included in this preliminary announcement has been prepared in accordance with International Financial Reporting Standards as adopted by the European Union ("IFRS"), this announcement does not itself contain sufficient information to comply with IFRS. The Company expects to distribute the full financial statements that comply with IFRS in May/June 2020.
2. General Information and Operational Environment
Regal Petroleum plc (the "Company") and its subsidiaries (the "Group") is a gas, condensate and LPG production group.
The Company is a public limited company quoted on the AIM Market of London Stock Exchange plc and incorporated in England and Wales under the Companies Act 2006. The Company's registered office is at 16 Old Queen Street, London, SW1H 9HP , United Kingdom and its registered number is 4462555. The principal activities of the Group and the nature of the Group's operations are set out above.
As of 3 1 December 2019 and 2018, the Company's immediate parent company was Pelidona Services Limited, which is 100% owned by Lovitia Investments Limited, which is 100% owned by Mr Vadym Novynskyi. Accordingly, the Company was ultimately controlled by Mr Vadym Novynskyi.
The Group's gas, condensate and LPG extraction and production facilities are located in Ukraine. The ongoing political and economic instability in Ukraine, which commenced in late 2013, has led to a deterioration of Ukrainian State finances, volatility of financial markets, illiquidity on capital markets, higher inflation and a depreciation of the national currency against major foreign currencies, although there have been some gradual improvements recently.
In 2019, the Ukrainian economy was showing signs of stabilisation after years of political and economic tensions. The year-on-year inflation rate in Ukraine decreased to 4.1% during 2019 (as compared to 9.8% in 2018 and 13.7% in 2017), while GDP continued to grow at an estimated 3.5% (after 3.3% growth in 2018).
After several years of devaluation, in 2019 the Ukrainian currency strengthened and during the year, appreciated by 14% (as at 31 December 2019, the official National Bank of Ukraine ("NBU") exchange rate of the Ukrainian Hryvnia against the US Dollar was UAH23.69/$1.00, compared to UAH27.69/$1.00 as at 31 December 2018). Among the key factors attributable to the strengthening of the Hryvnia were strong revenues of agricultural exporters, tight Hryvnia liquidity, growth in remittances from labour migrants and high demand for government debt instruments.
With effect from April 2019, the NBU launched a cycle of easing of monetary policy and a gradual decrease of its discount rate, for the first time in two years, from 18% in April 2019 to 11% in January 2020, which was justified by a sustained trend of inflation deceleration.
In December 2018, the International Monetary Fund ("IMF") approved a stand-by assistance ("SBA") 14-month programme for Ukraine, totalling $3.9 billion. In December 2018, Ukraine had already received $2 billion from the IMF and the European Union ("EU"), as well as $750 million credit guarantees from the World Bank. The approval of the IMF programme significantly increased Ukraine's chances of meeting its foreign currency obligations in 2019, and thus has supported the financial and macroeconomic stability of the country. Continued cooperation with the IMF is dependent on Ukraine's success in implementing policies and reforms that underpin a new IMF-supported programme.
In 2020, Ukraine faces major public debt repayments, which will require mobilisation of substantial domestic and external financing in an increasingly challenging financing environment for emerging markets.
The events which led to annexation of Crimea by the Russian Federation in February 2014 and the conflict in the east of Ukraine which started in spring 2014 have not been resolved to date. The relationships between Ukraine and the Russian Federation have remained strained.
Ukraine held presidential elections in March-April 2019, and parliamentary elections in July 2019. Amid these double elections, the degree of uncertainty including in respect of the future direction of structural reforms in 2020 remains very high. Despite certain improvements in 2019, the final resolution and the ongoing effects of the political and economic situation in Ukraine are difficult to predict but they may have further severe effects on the Ukrainian economy and the Group's business.
Further details of risks relating to Ukraine can be found within the Principal Risks section above.
3. Accounting Policies
The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.
Basis of Preparation
The Group has prepared its consolidated financial statements and the Company's financial statements under International Financial Reporting Standards ("IFRSs") and interpretations issued by the IFRS Interpretations Committee ("IFRS IC") , as adopted by the European Union. The financial statements have been prepared in accordance with the Companies Act 2006 as applicable to companies using IFRS. These consolidated financial statements are prepared under the historical cost convention as modified by the certain financial instruments measured in accordance with the requirements of IFRS 9 Financial instruments. The principal accounting policies applied in the preparation of the consolidated financial statements are set out below. Apart from the accounting policy changes resulting from the adoption of IFRS 16 effective from 1 January 2019, these policies have been consistently applied to all the periods presented, unless otherwise stated (refer to Note 4).
The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in Note 5.
Going Concern
Based on the positive operational and financial performance of the Group and for the reasons outlined in the Principal Risks section above, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future regarded as at least 12 months after the date of signing of these financial statements. Accordingly, the going concern basis has been adopted in preparing its consolidated financial statements and the Company's financial statements for the year ended 31 December 2019. T he use of this basis of accounting takes into consideration the Company's and the Group's current and forecast financing position, additional details of which are provided in the Principal Risks section above. The Group does not foresee any positive or negative impact on its operations as a result of Brexit. As a consequence of the COVID-19 pandemic the Group is re-visiting processes and controls intended to ensure protection of all its stakeholders and minimise any disruption to its business.
New and amended standards adopted by the Group
A number of new or amended standards became applicable for the current reporting period. The Group had to change its accounting policies as a result of the adoption of IFRS 16 Leases.
The impact of the adoption of the leasing standard and the new accounting policies are disclosed in Note 4 below.
The following amended standards became effective from 1 January 2019, but did not have any material impact on the Group:
-- IFRIC 23 "Uncertainty over Income Tax Treatments" (issued
on 7 June 2017 and effective for annual periods beginning
on or after 1 January 2019).
-- Prepayment Features with Negative Compensation - Amendments
to IFRS 9 (issued on 12 October 2017 and effective for annual
periods beginning on or after 1 January 2019).
-- Amendments to IAS 28 "Long-term Interests in Associates and
Joint Ventures" (issued on 12 October 2017 and effective for
annual periods beginning on or after 1 January 2019).
-- Annual Improvements to IFRSs 2015-2017 cycle -- amendments
to IFRS 3, IFRS 11, IAS 12 and IAS 23 (issued on 12 December
2017 and effective for annual periods beginning on or after
1 January 2019).
-- Amendments to IAS 19 "Plan Amendment, Curtailment or Settlement"
(issued on 7 February 2018 and effective for annual periods
beginning on or after 1 January 2019).
Impact of standards issued but not yet applied by the Group
Certain new standards and interpretations have been issued that are mandatory for the annual periods beginning on or after 1 January 2020 or later, and which the Group has not early adopted.
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) (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 the Conceptual Framework for Financial Reporting
(issued on 29 March 2018 and effective for annual periods
beginning on or after 1 January 2020)
The revised Conceptual Framework includes a new chapter on measurement; guidance on reporting financial performance; improved definitions and guidance -- in particular the definition of a liability; and clarifications in important areas, such as the roles of stewardship, prudence and measurement uncertainty in financial reporting.
IV) Definition of a business - Amendments to IFRS 3 (issued on
22 October 2018 and effective for acquisitions from the beginning
of annual reporting period that starts on or after 1 January
2020)
The amendments revise definition of a business. A business must have inputs and a substantive process that together significantly contribute to the ability to create outputs. The new guidance provides a framework to evaluate when an input and a substantive process are present, including for early stage companies that have not generated outputs. An organised workforce should be present as a condition for classification as a business if are no outputs. The definition of the term 'outputs' is narrowed to focus on goods and services provided to customers, generating investment income and other income, and it excludes returns in the form of lower costs and other economic benefits. It is also no longer necessary to assess whether market participants are capable of replacing missing elements or integrating the acquired activities and assets. An entity can apply a 'concentration test'. The assets acquired would not represent a business if substantially all of the fair value of gross assets acquired is concentrated in a single asset (or a group of similar assets). The amendments are prospective and the Group will apply them and assess their impact from 1 January 2020.
V) Definition of materiality - Amendments to IAS 1 and IAS 8
(issued on 31 October 2018 and effective for annual periods
beginning on or after 1 January 2020)
The amendments clarify the definition of material and how it should be applied by including in the definition guidance that until now has featured elsewhere in IFRS. In addition, the explanations accompanying the definition have been improved. Finally, the amendments ensure that the definition of material is consistent across all IFRS Standards. Information is material if omitting, misstating or obscuring it could reasonably be expected to influence the decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.
VI) 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)
The amendments were triggered by replacement of benchmark interest rates such as LIBOR and other inter-bank offered rates ('IBORs'). The amendments provide temporary relief from applying specific hedge accounting requirements to hedging relationships directly affected by the IBOR reform. Cash flow hedge accounting under both IFRS 9 and IAS 39 requires the future hedged cash flows to be 'highly probable'. Where these cash flows depend on an IBOR, the relief provided by the amendments requires an entity to assume that the interest rate on which the hedged cash flows are based does not change as a result of the reform. Both IAS 39 and IFRS 9 require a forward-looking prospective assessment in order to apply hedge accounting. While cash flows under IBOR and IBOR replacement rates are currently expected to be broadly equivalent, which minimises any ineffectiveness, this might no longer be the case as the date of the reform gets closer. Under the amendments, an entity may assume that the interest rate benchmark on which the cash flows of the hedged item, hedging instrument or hedged risk are based, is not altered by IBOR reform. IBOR reform might also cause a hedge to fall outside the 80-125% range required by retrospective test under IAS 39. IAS 39 has therefore been amended to provide an exception to the retrospective effectiveness test such that a hedge is not discontinued during the period of IBOR-related uncertainty solely because the retrospective effectiveness falls outside this range. However, the other requirements for hedge accounting, including the prospective assessment, would still need to be met. In some hedges, the hedged item or hedged risk is a non-contractually specified IBOR risk component. In order for hedge accounting to be applied, both IFRS 9 and IAS 39 require the designated risk component to be separately identifiable and reliably measurable. Under the amendments, the risk component only needs to be separately identifiable at initial hedge designation and not on an ongoing basis. In the context of a macro hedge, where an entity frequently resets a hedging relationship, the relief applies from when a hedged item was initially designated within that hedging relationship. Any hedge ineffectiveness will continue to be recorded in profit or loss under both IAS 39 and IFRS 9. The amendments set out triggers for when the reliefs will end, which include the uncertainty arising from interest rate benchmark reform no longer being present. The amendments require entities to provide additional information to investors about their hedging relationships that are directly affected by these uncertainties, including the nominal amount of hedging instruments to which the reliefs are applied, any significant assumptions or judgements made in applying the reliefs, and qualitative disclosures about how the entity is impacted by IBOR reform and is managing the transition process.
Unless otherwise described above, the new standards and interpretations are not expected to affect significantly the Group's consolidated financial statements.
Exchange differences on intra-group balances with foreign operation
The Group has certain inter-company monetary balances of which the Company is the beneficial owner. These monetary balances are payable by a subsidiary that is a foreign operation and are eliminated on consolidation.
In the consolidated financial statements, exchange differences arising on such payables because the transaction currency differs from the subsidiary's functional currency are recognised initially in other comprehensive income if the settlement of such payables is continuously deferred and is neither planned nor likely to occur in the foreseeable future.
In such cases, the respective receivables of the Company are regarded as an extension of the Company's net investment in that foreign operation, and the cumulative amount of the abovementioned exchange differences recognised in other comprehensive income is carried forward within the foreign exchange reserve in equity and is reclassified to profit or loss only upon disposal of the foreign operation.
When the subsidiary that is a foreign operation settles its quasi-equity liability due to the Company, but the Company continues to possess the same percentage of the subsidiary, i.e. there has been no change in its proportionate ownership interest, such settlement is not regarded as a disposal or a partial disposal, and therefore cumulative exchange differences are not reclassified.
The designation of inter-company monetary balances as part of the net investment in a foreign operation is re-assessed when management's expectations and intentions on settlement change due to a change in circumstances.
Where, because of a change in circumstances, a receivable balance, or part thereof, previously designated as a net investment into a foreign operation is intended to be settled, the receivable is de-designated and is no longer regarded as part of the net investment.
In such cases, the exchange differences arising on the subsidiary's payable following de-designation are recognised within finance costs / income in profit or loss, similar to foreign exchange differences arising from financing.
Foreign exchange gains and losses not related to intra-group balances are recognised on a net basis as other gains or losses.
Basis of Consolidation
The consolidated financial statements incorporate the financial information of the Company and entities controlled by the Company (and its subsidiaries) made up to 31 December each year.
Subsidiaries
Subsidiaries are all entities (including structured entities) over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases.
The Group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair value of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the Group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The Group recognises any non-controlling interest in the acquiree on an acquisition-by-acquisition basis at the non-controlling interest's proportionate share of the recognised amounts of the acquiree's identifiable net assets.
Acquisition-related costs are expensed as incurred.
If the business combination is achieved in stages, the acquisition date carrying value of the acquirer's previously held equity interest in the acquiree is re-measured to fair value at the acquisition date; any gains or losses arising from such re-measurement are recognised in profit or loss.
Any contingent consideration to be transferred by the Group is recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability is recognised in accordance with IFRS 9 in profit or loss .
Inter-company transactions, balances and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are also eliminated. When necessary, amounts reported by subsidiaries have been adjusted to conform with the Group's accounting policies.
Segment reporting
The Group's only class of business activity is oil and gas exploration, development and production. The Group's primary operations are located in Ukraine, with its head office in the United Kingdom. The geographical segments are the basis on which the Group reports its segment information to management. Operating segments are reported
in a manner consistent with the internal reporting provided to the Board of Directors.
Commercial Reserves
Proved and probable oil and gas reserves are estimated quantities of commercially producible hydrocarbons which the existing geological, geophysical and engineering data show to be recoverable in future years from known reservoirs. Proved reserves are those quantities of petroleum that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable from known reservoirs and under defined technical and commercial conditions. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. The proved and probable reserves conform to the definition approved by the Petroleum Resources Management System.
Oil and Gas Exploration/Evaluation and Development/Produc tion 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.
I ntangible Assets other than Oil and Gas Assets
Intangible assets other than oil and gas assets are stated at cost less accumulated amortisation and any provision for impairment. These assets represent exploration licences. Amortisation is charged so as to write off the cost, less estimated residual value on a straight-line basis of 20-25% per annum.
Depreciation, Depletion and Amortisation
All expenditure carried within each field is amortised from the commencement of commercial production on a unit of production basis, which is the ratio of gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field by field basis. In certain circumstances, fields within a single development area may be combined for depletion purposes. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs necessary to bring the reserves into production.
Impairment
At each balance sheet date, the Group reviews the carrying amount of oil and gas development and production assets to determine whether there is any indication that those assets have suffered an impairment loss. This includes exploration and appraisal costs capitalised which are assessed for impairment in accordance with IFRS 6. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss.
For oil and gas development and production assets, the recoverable amount is the greater of fair value less costs to dispose and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using an expected weighted average cost of capital. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. Impairment losses are recognised as an expense immediately.
Should an impairment loss subsequently reverse, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset in prior years. A reversal of an impairment loss is recognised as income immediately.
Decommissioning Provision
Where a material liability for the removal of existing production facilities and site restoration at the end of the productive life of a field exists, a provision for decommissioning is recognised. The amount recognised is the present value of estimated future expenditure determined in accordance with local conditions and requirements. The cost of the relevant property, plant and equipment is increased with an amount equivalent to the provision and depreciated on a unit of production basis. Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated fixed asset. The unwinding of the discount on the decommissioning provision is included within finance costs.
Property, Plant and Equipment other than Oil and Gas Assets
Property, plant and equipment other than oil and gas assets (included in Other fixed assets in Note 18) are stated at cost less accumulated depreciation and any provision for impairment. Depreciation is charged so as to write off the cost of assets on a straight-line basis over their useful lives as follows:
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, 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 in the amount of transaction price. Transaction price is the amount of consideration to which the Group expects to be entitled in exchange for transferring control over promised goods or services to a customer, excluding the amounts collected on behalf of third parties.
Revenue is recognised net of indirect taxes and excise duties.
Sales of gas, condensate and LPG are recognised when control of the good has transferred, being when the goods are delivered to the customer, the customer has full discretion over the goods, and there is no unfulfilled obligation that could affect the customer's acceptance of the goods. Delivery occurs when the goods have been shipped to the specific location, the risks of obsolescence and loss have been transferred to the customer, and either the customer has accepted the goods in accordance with the contract, the acceptance provisions have lapsed, or the Group has objective evidence that all criteria for acceptance have been satisfied.
A receivable is recognised when the goods are delivered as this is the point in time that the consideration is unconditional because only the passage of time is required before the payment is due.
The Group normally uses standardised contracts for the sale of gas, condensate and LPG, which define the point of control transfer. The price and quantity of each sale transaction are indicated in the specifications to the sales contracts.
The control over gas is transferred to a customer when the respective act of acceptance is signed by the parties to a contract upon delivery of gas to the point of sale specified in the contract, normally being a certain point in the Ukrainian gas transportation system. Acts of acceptance of gas are signed and the respective revenues are recognised on a monthly basis.
The control over condensate and LPG is transferred to a customer when the respective waybill is signed by the parties to a contract upon shipment of goods at the point of sale specified in the contract, which is normally the Group's production site.
Foreign Currencies
The Group's consolidated financial statements and those of the Company are presented in US Dollars. The functional currency of the subsidiaries which operate in Ukraine is Ukrainian Hryvnia. The remaining entities have US Dollars as their functional currency.
The functional currency of individual companies is determined by the primary economic environment in which the entity operates, normally the one in which it primarily generates and expends cash. In preparing the financial statements of the individual companies, transactions in currencies other than the entity's functional currency ("foreign currencies") are recorded at the rates of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing on the balance sheet date. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the Income Statement. Non-monetary assets and liabilities carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Non-monetary items which are measured in terms of historical cost in a foreign currency are not retranslated. Gains and losses arising on retranslation are included in net profit or loss for the period, except for exchange differences arising on balances which are considered long term investments where the changes in fair value are recognised directly in other comprehensive income .
On consolidation, the assets and liabilities of the Group's subsidiaries which do not use US Dollars as their functional currency are translated into US Dollars as follows:
(a) assets and liabilities for each Balance Sheet presented are
translated at the closing rate at the date of that Balance
Sheet;
(b) income and expenses for each Income Statement are translated
at average monthly exchange rates (unless this average is
not a reasonable approximation of the cumulative effect of
the rates prevailing on the transaction dates, in which case
income and expenses are translated at the rate on the dates
of the transactions); and
(c) all resulting exchange differences are recognised in other
comprehensive income.
The principal rates of exchange used for translating foreign currency balances at 31 December 2019 were $1:UAH 23 . 7 (201 8 : $1:UAH 27 . 7 ), $1:GBP0. 8 (201 8 : $1:GBP0. 8 ), $1:EUR0. 9 (201 8 : $1:EUR0. 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 I ncome Statement.
The net interest cost is calculated by applying the discount rate to the net balance of the defined benefit obligation and the fair value of plan assets. This cost is included in employee benefit expense in the Income Statement.
Actuarial gains and losses arising from experience adjustments and changes in actuarial assumptions are charged or credited to equity in other comprehensive income in the period in which they arise.
Taxation
The tax expense represents the sum of the current tax and deferred tax.
Current tax, including UK corporation and overseas tax, is provided at amounts expected to be paid (or recovered) using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the tax profit nor the accounting profit.
Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.
Deferred tax is calculated at the tax rates which are expected to apply in the period when the liability is settled or the asset is realised. Deferred tax is charged or credited in the Income Statement, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity.
Other taxes which include recoverable value added tax, excise tax and custom duties represent the amounts receivable or payable to local tax authorities in the countries where the Group operates.
Value added tax
Output value added tax related to sales is payable to tax authorities on the earlier of (a) collection of receivables from customers or (b) delivery of goods or services to customers. Input VAT is generally recoverable against output VAT upon receipt of the VAT invoice. The tax authorities permit the settlement of VAT on a net basis. VAT related to sales and purchases is recognised in the consolidated statement of financial position on a gross basis and disclosed separately as an asset and a liability. Where provision has been made for expected credit losses ("ECL") of receivables, the impairment loss is recorded for the gross amount of the debtor, including VAT.
Financial Instruments
Financial instruments - key measurement terms . Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The best evidence of fair value is the price in an active market. An active market is one in which transactions for the asset or liability take place with sufficient frequency and volume to provide pricing information on an ongoing basis.
Fair value of financial instruments traded in an active market is measured as the product of the quoted price for the individual asset or liability and the number of instruments held by the entity. This is the case even if a market's normal daily trading volume is not sufficient to absorb the quantity held and placing orders to sell the position in a single transaction might affect the quoted price.
A portfolio of financial derivatives or other financial assets and liabilities that are not traded in an active market is measured at the fair value of a group of financial assets and financial liabilities on the basis of the price that would be received to sell a net long position (i.e. an asset) for a particular risk exposure or paid to transfer a net short position (i.e. a liability) for a particular risk exposure in an orderly transaction between market participants at the measurement date. This is applicable for assets carried at fair value on a recurring basis if the Group: (a) manages the group of financial assets and financial liabilities on the basis of the Group's net exposure to a particular market risk (or risks) or to the credit risk of a particular counterparty in accordance with the Group's documented risk management or investment strategy; (b) it provides information on that basis about the group of assets and liabilities to the Group's key management personnel; and (c) the market risks, including duration of the Group's exposure to a particular market risk (or risks) arising from the financial assets and financial liabilities are substantially the same.
Valuation techniques such as discounted cash flow models or models based on recent arm's length transactions or consideration of financial data of the investees are used to measure fair value of certain financial instruments for which external market pricing information is not available. Fair value measurements are analysed by level in the fair value hierarchy as follows: (i) level one are measurements at quoted prices (unadjusted) in active markets for identical assets or liabilities, (ii) level two measurements are valuations techniques with all material inputs observable for the asset or liability, either directly (that is, as prices) or indirectly (that is, derived from prices), and (iii) level three measurements are valuations not based on solely observable market data (that is, the measurement requires significant unobservable inputs). Transfers between levels of the fair value hierarchy are deemed to have occurred
Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. An incremental cost is one that would not have been incurred if the transaction had not taken place. Transaction costs include fees and commissions paid to agents (including employees acting as selling agents), advisors, brokers and dealers, levies by regulatory agencies and securities exchanges, and transfer taxes and duties. Transaction costs do not include debt premiums or discounts, financing costs or internal administrative or holding costs.
Amortised cost ("AC") is the amount at which the financial instrument was recognised at initial recognition less any principal repayments, plus accrued interest, and for financial assets less any allowance for ECL. Accrued interest includes amortisation of transaction costs deferred at initial recognition and of any premium or discount to the maturity amount using the effective interest method. Accrued interest income and accrued interest expense, including both accrued coupon and amortised discount or premium (including fees deferred at origination, if any), are not presented separately and are included in the carrying values of the related items in the consolidated statement of financial position.
The effective interest method is a method of allocating interest income or interest expense over the relevant period, so as to achieve a constant periodic rate of interest (effective interest rate) on the carrying amount. The effective interest rate is the rate that exactly discounts estimated future cash payments or receipts (excluding future credit losses) through the expected life of the financial instrument or a shorter period, if appropriate, to the gross carrying amount of the financial instrument. The effective interest rate discounts cash flows of variable interest instruments to the next interest repricing date, except for the premium or discount which reflects the credit spread over the floating rate specified in the instrument, or other variables that are not reset to market rates. Such premiums or discounts are amortised over the whole expected life of the instrument. The present value calculation includes all fees paid or received between parties to the contract that are an integral part of the effective interest rate. For assets that are purchased or originated credit impaired ("POCI") at initial recognition, the effective interest rate is adjusted for credit risk, i.e. it is calculated based on the expected cash flows on initial recognition instead of contractual payments.
Financial instruments - initial recognition . F inancial instruments at fair value through profit or loss ("FVTPL") are initially recorded at fair value. All other financial instruments are initially recorded at fair value adjusted for transaction costs. Fair value at initial recognition is best evidenced by the transaction price. A gain or loss on initial recognition is only recorded if there is a difference between fair value and transaction price which can be evidenced by other observable current market transactions in the same instrument or by a valuation technique whose inputs include only data from observable markets. After the initial recognition, an ECL allowance is recognised for financial assets measured at AC and investments in debt instruments measured at fair value through other comprehensive income ("FVOCI"), resulting in an immediate accounting loss.
All purchases and sales of financial assets that require delivery within the time frame established by regulation or market convention ("regular way" purchases and sales) are recorded at trade date, which is the date on which the Group commits to deliver a financial asset. All other purchases are recognised when the entity becomes a party to the contractual provisions of the instrument.
Financial assets - classification and subsequent measurement - measurement categories. The Group classifies financial assets in the following measurement categories: FVTPL, FVOCI and AC. The classification and subsequent measurement of debt financial assets depends on: (i) the Group's business model for managing the related assets portfolio and (ii) the cash flow characteristics of the asset. The Group's financial assets include cash and cash equivalents, trade and other receivables, loans to subsidiary undertakings, all of which are classified as AC in accordance with IFRS 9.
Financial assets - classification and subsequent measurement - business model. The business model reflects how the Group manages the assets in order to generate cash flows - whether the Group's objective is: (i) solely to collect the contractual cash flows from the assets ("hold to collect contractual cash flows",) or (ii) to collect both the contractual cash flows and the cash flows arising from the sale of assets ("hold to collect contractual cash flows and sell") or, if neither of (i) and (ii) is applicable, the financial assets are classified as part of "other" business model and measured at FVTPL.
Business model is determined for a group of assets (on a portfolio level) based on all relevant evidence about the activities that the Group undertakes to achieve the objective set out for the portfolio available at the date of the assessment. Factors considered by the Group in determining the business model include past experience on how the cash flows for the respective assets were collected.
The Group's business model for financial assets is to collect the contractual cash flows from the assets ("hold to collect contractual cash flows").
Financial assets - classification and subsequent measurement - cash flow characteristics. Where the business model is to hold assets to collect contractual cash flows or to hold contractual cash flows and sell, the Group assesses whether the cash flows represent solely payments of principal and interest ("SPPI"). Financial assets with embedded derivatives are considered in their entirety when determining whether their cash flows are consistent with the SPPI feature. In making this assessment, the Group considers whether the contractual cash flows are consistent with a basic lending arrangement, i.e. interest includes only consideration for credit risk, time value of money, other basic lending risks and profit margin.
Where the contractual terms introduce exposure to risk or volatility that is inconsistent with a basic lending arrangement, the financial asset is classified and measured at FVTPL. The SPPI assessment is performed on initial recognition of an asset and it is not subsequently reassessed.
Financial assets - reclassification. Financial instruments are reclassified only when the business model for managing the portfolio as a whole changes. The reclassification has a prospective effect and takes place from the beginning of the first reporting period that follows after the change in the business model. The Group did not change its business model during the current and comparative period and did not make any reclassifications.
Financial assets impairment - credit loss allowance for ECL. The Group assesses, on a forward-looking basis, the ECL for debt instruments measured at AC and FVOCI and for the exposures arising for contract assets. The Group measures ECL and recognises Net impairment losses on financial and contract assets at each reporting date. The measurement of ECL reflects: (i) an unbiased and probability weighted amount that is determined by evaluating a range of possible outcomes, (ii) time value of money and (iii) all reasonable and supportable information that is available without undue cost and effort at the end of each reporting period about past events, current conditions and forecasts of future conditions.
Debt instruments measured at AC and contract assets are presented in the consolidated statement of financial position net of the allowance for ECL. For loan commitments and financial guarantees, a separate provision for ECL is recognised as a liability in the consolidated statement of financial position.
The Group applies a three stage model for impairment, based on changes in credit quality since initial recognition. A financial instrument that is not credit-impaired on initial recognition is classified in Stage 1. Financial assets in Stage 1 have their ECL measured at an amount equal to the portion of lifetime ECL that results from default events possible within the next 12 months or until contractual maturity, if shorter ("12 Months ECL"). If the Group identifies a significant increase in credit risk ("SICR") since initial recognition, the asset is transferred to Stage 2 and its ECL is measured based on ECL on a lifetime basis, that is, up until contractual maturity but considering expected prepayments, if any ("Lifetime ECL"). If the Group determines that a financial asset is credit-impaired, the asset is transferred to Stage 3 and its ECL is measured as a Lifetime ECL. For financial assets that are purchased or originated credit-impaired ("POCI Assets"), the ECL is always measured as a Lifetime ECL.
Financial assets - write-off. Financial assets are written-off, in whole or in part, when the Group exhausted all practical recovery efforts and has concluded that there is no reasonable expectation of recovery. The write-off represents a derecognition event. The Group may write-off financial assets that are still subject to enforcement activity when the Group seeks to recover amounts that are contractually due, however, there is no reasonable expectation of recovery.
Financial assets - derecognition. The Group derecognises financial assets when (a) the assets are redeemed or the rights to cash flows from the assets otherwise expire or (b) the Group has transferred the rights to the cash flows from the financial assets or entered into a qualifying pass-through arrangement whilst (i) also transferring substantially all the risks and rewards of ownership of the assets or (ii) neither transferring nor retaining substantially all the risks and rewards of ownership but not retaining control.
Financial assets - modification. If the modified terms are substantially different, the rights to cash flows from the original asset expire and the Company derecognises the original financial asset and recognises a new asset at its fair value. The date of renegotiation is considered to be the date of initial recognition for subsequent impairment calculation purposes, including determining whether a SICR has occurred. Any difference between the carrying amount of the original asset derecognised and fair value of the new substantially modified asset is recognised in profit or loss, unless the substance of the difference is attributed to a capital transaction with owners. If the modified asset is not substantially different from the original asset and the modification does not result in derecognition. The Group recalculates the gross carrying amount by discounting the modified contractual cash flows by the original effective interest rate (or credit-adjusted effective interest rate for POCI financial assets), and recognises a modification gain or loss in profit or loss.
Financial liabilities - measurement categories. Financial liabilities are classified as subsequently measured at AC, except for (i) financial liabilities at FVTPL: this classification is applied to derivatives, financial liabilities held for trading (e.g. short positions in securities), contingent consideration recognised by an acquirer in a business combination and other financial liabilities designated as such at initial recognition and (ii) financial guarantee contracts and loan commitments. The Group's financial liabilities include trade and other payables, all of which are classified as AC in accordance with IFRS 9.
Financial liabilities - derecognition. Financial liabilities are derecognised when they are extinguished (i.e. when the obligation specified in the contract is discharged, cancelled or expires).
Trade Receivables
Trade receivables are amounts due from customers for goods sold in the ordinary course of business. If collection is expected in one year or less, they are classified as current assets. If not, they are presented as non-current assets.
Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.
Prepayments
Prepayments are carried at cost less provision for impairment. A prepayment is classified as non-current when the goods or services relating to the prepayment are expected to be obtained after one year, or when the prepayment relates to an asset which will itself be classified as non-current upon initial recognition. Prepayments to acquire assets are transferred to the carrying amount of the asset once the Group has obtained control of the asset and it is probable that future economic benefits associated with the asset will flow to the Group. Other prepayments are written off to profit or loss when the services relating to the prepayments are received. If there is an indication that the assets, goods or services relating to a prepayment will not be received, the carrying value of the prepayment is written down accordingly and a corresponding impairment loss is recognised in profit or loss for the year.
Investments in subsidiaries
Investments made by the Company in its subsidiaries are stated at cost in the Company's financial statements and reviewed for impairment if there are indications that the carrying value may not be recoverable.
Loans issued to subsidiaries
Loans issued by the Company to its subsidiaries are initially recognised in the Company's financial statements at fair value and are subsequently carried at amortised cost using the effective interest method, less credit loss allowance. Net change in credit losses and foreign exchange differences on loans issued are recognised in the Company's statement of profit or loss in the period when incurred.
Trade Payables
Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less. If not, they are presented as non-current liabilities.
Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.
Lease liabilities
Liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:
-- 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 cash and cash equivalents definition. Current accounts and deposits held at banks, which do not meet cash and cash equivalents definition are measured initially at fair value and subsequently carried at amortised cost using the effective interest method. Interest received on other short-term investments is disclosed within operating cash flow.
The Group classifies its financial assets as at amortised cost only if both of the following criteria are met:
-- the asset is held within a business model whose objective
is to collect the contractual cash flows, and
-- the contractual terms give rise to cash flows that are solely
payments of principal and interest.
Interest income
Interest income is recognised as it accrues, taking into account the effective yield on the asset. Interest income on current bank accounts and on demand deposits or term deposits with the maturity less than three months recognised as part of cash and cash equivalents is recognised as other operating income. Interest income on term deposits other than those classified as cash and cash equivalents is recognised as finance income.
4. Changes in accounting policies
This note explains the impact of the adoption of IFRS 16 Leases on the Group's financial statements and also discloses the new accounting policies that have been applied from 1 January 2019.
The Group has adopted IFRS 16 retrospectively from 1 January 2019, but has not restated comparatives for the 2018 reporting period, as permitted under the specific transitional provisions in the standard. The reclassifications and the adjustments arising from the new leasing rules are therefore recognised in the opening balance sheet on 1 January 2019.
Adjustments recognised on adoption of IFRS 16
2019
$000
Operating lease commitments disclosed as at 31 December 2018 1,884
Discounted using the lessee's incremental borrowing rate at the date of initial
application (667)
(Less): short-term leases recognised on a straight-line basis as expense (85)
(Less): low-value leases recognised on a straight-line basis as expense (10)
--------------------------------------------------------------------------------- ------
Lease liability recognised as at 1 January 2019 1,122
--------------------------------------------------------------------------------- ------
Of which are:
Current lease liabilities 371
Non-current lease liabilities 751
--------------------------------------------------------------------------------- ------
On adoption of IFRS 16, the Group recognised lease liabilities in relation to leases which had previously been classified as 'operating leases' under the principles of IAS 17 Leases. These liabilities were measured at the present value of the remaining lease payments, discounted using the lessee's incremental borrowing rate as of 1 January 2019. The weighted average lessee's incremental borrowing rate applied to the lease liabilities on 1 January 2019 was 19.8% for contracts denominated in Ukrainian Hryvnia and 7.4% for contracts denominated in US Dollars.
Right-of-use assets were measured at the amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognised in the balance sheet as at 31 December 2018. There were no onerous lease contracts that would have required an adjustment to the right-of-use assets
at the date of initial application.
The recognised right-of-use assets relate to the following types of assets:
31 Dec 19 1 Jan 19
$000 $000
Properties 423 595
Land 299 311
Wells 218 216
940 1,122
The change in accounting policy affected the following items in the balance sheet on 1 January 2019:
-- right-of-use assets - increase by $1,122,000 -- lease liabilities - increase by $1,122,000.
Practical expedients applied
In applying IFRS 16 for the first time, the Group has used the following practical expedients permitted by the standard:
-- the use of a single discount rate to a portfolio of leases
with reasonably similar characteristics;
-- reliance on previous assessments on whether leases are onerous;
-- the accounting for operating leases with a remaining lease
term of less than 12 months as at 1 January 2019 as short-term
leases;
-- the exclusion of initial direct costs for the measurement
of the right-of-use asset at the date of initial application;
and
-- the use of hindsight in determining the lease term where the
contract contains options to extend or terminate the lease.
The Group has also elected not to reassess whether a contract is, or contains a lease at the date of initial application. Instead, for contracts entered into before the transition date, the Group relied on its assessment made applying IAS 17 and IFRIC 4 Determining whether an Arrangement contains a Lease.
The Group's leasing activities and how these are accounted for
The Group leases various wells, offices, equipment and land. Rental contracts are typically made for fixed periods of 1 to 25 years but may have extension options as described in (ii) below. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The lease agreements do not
impose any covenants, but leased assets may not be used as security for borrowing purposes.
Until 1 January 2019, leases of property, plant and equipment were classified as either finance or operating leases. Payments made under operating leases (net of any incentives received from the lessor) were charged to profit or loss on a straight-line basis over the period of the lease.
From 1 January 2019, leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group. Each lease payment is allocated between the liability and finance cost. The finance cost is charged to profit or loss over the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis.
Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:
-- fixed payments (including in-substance fixed payments), less
any lease incentives receivable;
-- variable lease payment that are based on an index or a rate;
-- the exercise price of a purchase option if the lessee is reasonably
certain to exercise that option; and
-- payments of penalties for terminating the lease, if the lease
term reflects the lessee exercising that option.
The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the lessee's incremental borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions.
Right-of-use assets are measured at cost comprising the following:
-- the amount of the initial measurement of lease liability;
-- any lease payments made at or before the commencement date
less any lease incentives received;
-- restoration costs.
Payments associated with short-term leases and leases of low-value assets are recognised on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less.
(i) Variable lease payments
Estimation uncertainty arising from variable lease payments
Some property leases contain variable payment terms that are linked to the volume of production. For wells, up to 100 per cent of lease payments are on the basis of variable payment terms. Variable payment terms are used for a variety of reasons, including minimising the fixed costs base for wells under reconstruction. Variable lease payments that depend on the volume of production are recognised in profit or loss in the period in which the condition that triggers those payments occurs.
(ii) Extension and termination options
Extension and termination options are included in a number of property and equipment leases across the Group. These terms are used to maximise operational flexibility in terms of managing contracts.
Critical judgements in determining the lease term
In determining the lease term, management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. Extension options (or periods after termination options) are only included in the lease term if the lease is reasonably certain to be extended (or not terminated).
The assessment is reviewed if a significant event or a significant change in circumstances occurs which affects this assessment and that is within the control of the lessee.
(iii) Residual value guarantees
The Group does not provide residual value guarantees in relation to equipment leases.
5. Critical Accounting Estimates and Judgments
The Group makes estimates and judgments concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and judgments which have a risk of causing material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.
Recoverability of Oil and Gas Development and Production Assets in Ukraine
According to the Group's accounting policies, costs capitalised as assets are assessed for impairment at each balance sheet date if impairment indicators exist. In assessing whether an impairment loss has occurred, the carrying value of the asset or cash-generating unit ("CGU") is compared to its recoverable amount. The recoverable amount is the greater of fair value less costs to dispose and value in use and is determined for an individual asset, unless the asset does not generate cash inflows that are largely independent of those from other assets or groups of assets. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount and the respective impairment loss is recognised as an expense immediately. A previously recognised impairment loss is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment loss was recognised. If that is the case, the carrying amount of the asset is increased to its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such reversals are recognised as income immediately.
The valuation method used for determination of recoverable value in use is based on unobservable market data, which is within Level 3 of the fair value hierarchy.
MEX-GOL and SV gas and condensate fields
The impairment assessment carried out at 31 December 2019 has not resulted in an impairment loss. Further details of this assessment, including the sensitivity to the above assumptions, are set out in Note 18.
VAS gas and condensate field
Following the successful outcome of the VAS-10 well and the subsequent revision of the field development plan for the VAS field in 2019, the Group considered it appropriate to undertake a reassessment of the reserves and resources at the VAS field. Accordingly, the Group engaged independent petroleum consultants DeGolyer and MacNaughton ("D&M") to prepare an updated estimate of remaining reserves and resources as of 31 December 2018. The revised field development plan for this field prepared in 2019 assumes an increase in the number of new wells from one to three wells. The final report issued by D&M in August 2019 provided an estimate of the Group's proved plus probable ("2P") reserves of 3.1 MMboe. The report represents a significant increase in the remaining reserves and resources in this field since the previous estimation undertaken by Senergy (GB) Limited as at 1 January 2016 (1.8 MMboe). The increase in 2P reserves caused the revision of the expected economic life of the field from 2024 to 2028. Further details of this reserves update are set out in the Company's announcement made on 21 August 2019.
The impairment assessment carried out at 31 December 2019 has not resulted in an impairment loss. Further details of this assessment, including the sensitivity to the above assumptions, are set out in Note 18.
Depreciation of Oil and Gas Development and Production Assets
Development and production assets held in property, plant and equipment are depreciated on a unit of production basis at a rate calculated by reference to proven and probable reserves at the end of the period plus the production in the period, and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions about the number of wells required to produce those reserves, the cost of the wells, future production facilities and operating costs, together with assumptions on oil and gas realisations, and are revised annually. The reserves estimates used are determined using estimates of gas in place, recovery factors, future hydrocarbon prices and also take into consideration the Group's latest development plan for the associated development and production asset. Additionally, the latest development plan and therefore the inputs used to determine the depreciation charge, assume that the current licences for the MEX-GOL and SV fields, which are due to expire in July 2024, can be extended until the end of the economic life of the fields.
In light of the revision of the field development plan for the VAS field and the re-assessment of the 2P reserves at this field performed in 2019 by D&M as described above, the Group has revised the estimate of 2P reserves and future cost of developing and extracting those reserves used for the depletion and amortisation calculation. The effect of the change in estimates made in the current reporting period was appropriately recognised in profit or loss in the period of the change and amounted to a decrease of $283,000 in the depletion charge of property, plant and equipment (the depletion charge decreased by $1,504,600 due to the increase in 2P reserves and increased by $1,787,000 due to the increase in future capital expenditure) and a decrease of $338,000 in amortisation of mineral reserves for the year 2019.
Provision for Decommissioning
The Group has decommissioning obligations in respect of its Ukrainian assets. The full extent to which the provision is required depends on the legal requirements at the time of decommissioning, the costs and timing of any decommissioning works and the discount rate applied to such costs.
A detailed assessment of gross decommissioning cost was undertaken on a well-by-well basis using local data on day rates and equipment costs. The discount rate applied on the decommissioning cost provision at 31 December 2019 was 3.68% (31 December 2018: 8.14%). The discount rate is calculated in real terms based on the yield to maturity of Ukrainian Government bonds denominated in the currency in which the liability is expected to be settled and with the settlement date that approximates the timing of settlement of decommissioning obligations.
The change in estimate applied to calculate the provision as at 31 December 2019 resulted from the revision of the estimated costs of decommissioning (increase of $711,000 in provision), the decrease in the discount rate applied (increase of $2,430,000 in provision) and the extension of the economic life of the VAS field as a result of the revision of the field development plan in 2019 (decrease of $289,000 in provision). The decrease in discount rate at 31 December 2019 resulted from the decrease in Ukrainian Eurobonds yield and the respective decrease of country risk premium. The costs are expected to be incurred by 2038 on the MEX-GOL field, by 2042 on the SV field, and by 2028 on the VAS field (31 December 2018: by 2038 on the MEX-GOL field, by 2042 on the SV field and 2024 on the VAS field respectively), which is the end of the estimated economic life of the respective fields. If the costs on the MEX-GOL and SV fields were to be incurred at the current expiry of the production licences in 2024, the provision for decommissioning at 31 December 2019 would be $11,564,000 (31 December 2018: $6,268,000).
Net Carrying Amount of Inter-Company Loans Receivable by the Company from a Subsidiary
The Company has certain inter-company loans receivable from a subsidiary, which are eliminated on consolidation. For the purpose of the Company's financial statements, these receivable balances are carried at amortised cost using the effective interest method, less credit loss allowance. Measurement of lifetime expected credit losses on inter-company loans is a significant judgment that involves models and data inputs including forward-looking information, current conditions and forecasts of future conditions impacting the estimated future cash flows that are expected to be recovered, time value of money, etc. In previous years, significant impairment charges were recorded against the carrying amount of the loans issued to subsidiaries as the present value of estimated future cash flows discounted at the original effective interest rate was less than carrying amount of the loans, and the resulting impairment losses were recognised in profit or loss in the Company's financial statements.
For the purpose of assessment of the credit loss allowance as at 31 December 2019, the Company considered all reasonable and supportable forward looking information available as of that date without undue cost and effort, which includes a range of factors, such as estimated future net cash flows to be generated by the subsidiaries operating in Ukraine, upcoming planned changes in the Group's structure, cash flow management and planned debt structuring between Group entities. All these factors have significant impact on the amounts subject to repayment on the loans. The estimated future discounted cash flows generated by the subsidiaries operating in Ukraine are considered as a primary source of repayment on the loans. For the purpose of this assessment, these cash flows were taken for a period of five years, as management believes there is no reasonably available information to build reliable expectations and demonstrate the ability to settle the loans in a longer perspective, especially in light of the anticipated changes in the Group's legal structure. As of 31 December 2019, the present value of future net cash flows to be generated by the subsidiaries operating in Ukraine during 2020 - 2024, adjusted for the subsidiaries' working capital as at 31 December 2019 and estimated amounts reserved by the Group for investment projects in the 5-year horizon was calculated. The decrease in the net present value of future net cash flows as at 31 December 2019 in comparison with 31 December 2018 was affected by the significant decrease in gas prices forecast and the revision of the field development plan for the VAS field in 2019 that included drilling of new wells in the 2021-2023 years. The resulting amount, net of the carrying value of the Company's investments in subsidiaries, was compared to the carrying value of the loans issued to subsidiaries as at 31 December 2019. As such, the Company has recorded $15,450,000 of loss, being the net change in credit loss allowance for loans issued to subsidiaries in the Company's statement of profit or loss for the year ended 31 December 2019.
As with any economic forecast, the projections and likelihoods of occurrence are subject to a high degree of inherent uncertainty, and therefore the actual outcomes may be significantly different to those projected. The Company considers these forecasts to represent its best estimate of the possible outcomes.
Exchange Differences on Intra-group Balances with Foreign Operations
As at 31 December 2018, a Group subsidiary, Regal Petroleum Corporation (Ukraine) Limited, planned to settle $9,000,000 of intra-group liability, however $20,616,000 was settled in the period. A further amount of $4,600,000 is planned to be settled by the end of 2020. As such, a foreign exchange difference of $3, 487 ,000 accumulated on the intra-group balance of $170,223,000 since the date of de-designation of this balance as part of the Company's net investment in the foreign operation up to 31 December 2019 was recognised in profit or loss in these consolidated financial statements. No reclassification of the foreign exchange difference accumulated in equity prior to de-designation was made as there has been no change in the Company's proportionate ownership interest in the foreign operation and therefore no disposal or partial disposal of the foreign operation. There were no changes in management's plans or intentions regarding the payment of intra-group balances not settled as at 31 December 2019, other than the above-mentioned amount of $4,600,000, and as such, a foreign exchange difference related to the balance designated as net investment in a foreign operation was recognised in other comprehensive income in the Company Statement of Comprehensive Income for the year ended 31 December 2019.
Recognition of Deferred Tax Asset
The recognition of deferred tax assets is based upon whether it is more likely than not that sufficient and suitable taxable profits will be available in the future against which the reversal of temporary differences can be deducted. This requires judgement for forecasting future profits. Further details of the deferred tax assets recognised can be found in Note 27.
6. Segmental Information
In line with the Group's internal reporting framework and management structure, the key strategic and operating decisions are made by the Board of Directors, who review internal monthly management reports, budget and forecast information as part of this process. Accordingly, the Board of Directors is deemed to be the Chief Operating Decision Maker within the Group.
The Group's only class of business activity is oil and gas exploration, development and production. The Group's operations are located in Ukraine, with its head office in the United Kingdom. These geographical regions are the basis on which the Group reports its segment information. The segment results as presented represent operating profit before depreciation, amortisation and impairment of non-current assets.
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 18)
There are no inter-segment sales within the Group and all products are sold in the geographical region in which they are produced. The Group is not significantly impacted by seasonality. Revenue is recognised at a point in time.
United
Ukraine Kingdom Total
2018 2018 2018
$000 $000 $000
Revenue
Gas sales 49,668 - 49,668
Condensate sales 12,772 - 12,772
Liquefied Petroleum Gas sales 3,658 - 3,658
------------------------------------ --------- -------- ---------
Total revenue 66,098 - 66,098
Segment result 41,311 (1,509) 39,802
Depreciation and amortisation ( 7 , 901
of non-current assets (7,9 01 ) - )
Reversal of impairment of property,
plant and equipment 34,469 - 34,469
Operating profit 66,370
Segment assets 95,782 27,557 123,339
Capital additions* 9 ,552 - 9, 552
During 2019, the Group was selling all of its gas production to its related party, LLC Smart Energy ("Smart Energy"). Smart Energy has oil and gas operations in Ukraine and is part of the PJSC Smart-Holding Group, which is ultimately controlled by Mr Vadym Novynskyi, who through an indirect 82.65% majority shareholding, ultimately controls the Group. This arrangement came about in 2017 as a consequence of the Ukrainian Government introducing a number of new provisions into the Ukrainian Tax Code over the last two years, including transfer pricing regulations for companies operating in Ukraine. The introduction of the new regulations has meant that there is an increased regulatory burden on affected companies in Ukraine who must prepare and submit reporting information to the Ukrainian Tax Authorities. Due to the corporate structure of the Group, a substantial proportion of its gas production is produced by a non-Ukrainian subsidiary of the Group, which operates in Ukraine as a branch, or representative office as it is classified in Ukraine. Under the current tax regulations, this places additional regulatory obligations on each of the Group's potential customers who may be less inclined to purchase the Group's gas and/or may seek discounts on sales prices. As a result of discussions between the Company and Smart Energy, Smart Energy agreed to purchase all of the Group's gas production and to assume responsibility for the regulatory obligations under the Ukrainian tax regulations. Furthermore, Smart Energy has agreed to combine the Group's gas production with its own gas production, and to sell such gas as combined volumes, which is intended to result in higher sales prices due to the larger sales volumes. At the commencement of this sales arrangement, in order to cover Smart Energy's sales, administration and regulatory compliance costs, the Group sold its gas to Smart Energy at a discount of 0.5% to the gas sales prices achieved by Smart Energy, who sold the combined volumes in line with market prices. Due to changes in the regulatory regime in Ukraine, which has increased the burden of administration and regulatory compliance obligations involved in the sale of gas, and in order to ensure that the Group is compliant with current transfer pricing regulations in Ukraine, the Group and Smart Energy agreed in 2019 to increase the discount on the price at which the Group sells its gas to Smart Energy from 0.5% to 2%. The terms of sale for the Group's gas to Smart Energy are (i) payment for one third of the estimated monthly volume of gas by the 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.
*Comprises additions to property, plant and equipment (Note 18)
7. Cost of Sales
2019 2018
$000 $000
Production taxes 11,636 14,902
Depreciation of property, plant and equipment 9,102 6,8 63
Rent expenses 5,317 4,474
Staff costs (Note 10) 2,450 2,084
Cost of inventories recognised as an expense 1,158 1,414
Transmission tariff for Ukrainian gas system 673 -
Amortisation of mineral reserves 510 804
Other expenses 1,569 1,334
---------------------------------------------- ------ ------
32,415 31,875
New legislation relating to the oil and gas sector in Ukraine has been introduced over the last year, and in this regard, with effect from 1 January 2019, the subsoil tax rates applicable to condensate production were reduced from 45% to 31% for condensate produced from deposits above 5,000 metres and from 21% to 16% for condensate produced from deposits below 5,000 metres.
From 1 January 2019, a transmission tariff for use of the Ukrainian gas system of UAH91.87 per 1000 m(3) of gas was introduced.
Due to implementation of IFRS 16 from 1 January 2019 the Group has changed its policy for accounting for rent expenses. Instead of rent expenses the Group recognises depreciation of the right-of-use assets and interest expense on the liability over the lease term. However some property leases contain variable payment terms that are linked to the volume of production. Variable lease payments that depend on the volume of production are recognised in profit or loss in the period in which the condition that triggers those payments occurs. Also payments associated with short-term leases and leases of low-value assets are recognised on a straight-line basis as an expense in profit or loss.
8. Administrative Expenses
201 9 201 8
$000 $000
Staff costs (Note 10) 4,282 3,620
Consultancy fees 869 509
Depreciation of other fixed assets 449 180
Auditors' remuneration 327 403
Rent expenses 138 323
Amortisation of other intangible assets 129 54
Other expenses 1,202 6 20
---------------------------------------------------- ------ ------
7,396 5,709
201 9 201 8
$000 $000
Audit of the Company and subsidiaries 119 166
Audit of subsidiaries in Ukraine 108 95
Audit related assurances services - interim review 28 70
---------------------------------------------------- ------ ------
Total assurance services 255 331
Tax compliance services 24 33
Legal services 12 25
Tax advisory services 36 14
Total non-audit services 72 72
---------------------------------------------------- ------ ------
Total audit and other services 327 403
All amounts shown as Auditors' remuneration in 2019 and 2018 were payable to the Group Auditors, PricewaterhouseCoopers LLP and other member firms of PricewaterhouseCoopers LLP.
9. Remuneration of Directors
201 9 201 8
$000 $000
Directors' emoluments 977 810
---------------------- ----- -----
The emoluments of the individual Directors were as follows:
Total Total
Emoluments emoluments
2019 2018
$000 $000
Executive Directors:
Sergii Glazunov 448 437
Bruce Burrows 206 -
Non-executive Directors:
Chris Hopkinson 128 133
Alexey Pertin 57 60
Yuliia Kirianova 57 60
Dmitry Sazonenko 57 15
Bruce Burrows 24 60
Philip Frank - 45
977 810
Bruce Burrows was appointed as Finance Director in June 2019, and is paid GBP276,000 per annum. Prior to his appointment as Finance Director, Mr Burrows was Non-Executive Director and was paid GBP45,000 per annum for the period from January 2019 to May 2019.
The emoluments include base salary, bonuses and fees. According to the Register of Directors' Interests, no rights to subscribe for shares in or debentures of the Group companies were granted to any of the Directors or their immediate families during the financial year, and there were no outstanding options to Directors.
10. Staff Numbers and Costs
Number of employees
2019 2018
Group
Management / operational 144 146
Administrative support 69 66
------------------------- ---------- ---------
213 212
The average monthly number of employees on a full time equivalent basis during the year (including Executive Directors) was as follows:
The aggregate staff costs of these employees were as follows:
2019 2018
$000 $000
Wages and salaries 5,874 4,969
Pension costs 772 661
Social security costs 86 74
6,732 5,704
11. Other operating gains, (net)
2019 2018
$000 $000
Interest income on cash and cash equivalents 4,751 3,024
Contractor penalties applied 15 225
Gain on sales of current assets - 26
Other operating income, net 207 112
4 ,973 3,387
12. Finance Income
During 2019, the Group recorded interest income of $nil (2018: $153,000) from placement of cash on long-term deposit accounts and recognised foreign exchange gains less losses of $ 3,487 ,000 (2018: $488,000).
13. Finance Costs
During 2019, the Group recorded an unwinding of discount on lease liabilities of $177,000 (2018: nil) and unwinding of a discount on provision for decommissioning of $273,000 (2018: $140,000) (Note 26).
14. Other losses, (net)
2019 2018
$000 $000
Foreign exchange losses 1,508 84
Unconfirmed tax credit on VAT 473 -
Charitable donations 107 96
Other income/(losses), net 306 (40)
2,394 140
15. Income tax expense
a) Income tax expense and (benefit):
2019 2018
$000 $000
Current tax
Overseas - current year 4,768 6 ,478
Deferred tax ( Note 27)
UK - current year 3,211 5,519
UK - prior year 1,996 821
Overseas - current year (406) (333)
Income tax expense 9,569 12,485
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:
2019 2018
$000 $000
Profit before taxation 21,768 66, 7 91
--------------------------------------------------- ------ --------
Tax charge at UK tax rate of 19.00% (2018: 19.00%) 4,136 12,6 90
Tax effects of:
Lower foreign corporate tax rates in Ukraine
(18%) (242) (5 8 )
Disallowed expenses and non-taxable income 3,598 543
Changes in tax losses previously not recognised
as deferred tax asset 81 (1,511)
Adjustments in respect of prior periods 1,996 821
--------------------------------------------------- ------ --------
Total tax expense for the year 9,569 12,485
The tax effect of d isallowed expenses and non-taxable income are mainly represented by foreign exchange differences of Regal Petroleum Corporation (Ukraine) Limited and the difference in capital allowances allowed under Ukrainian and UK taxation.
The tax effect losses not recognised as deferred tax assets are mainly represented by accumulated losses of Regal Petroleum Corporation (Ukraine) Limited.
16. Profit for the Year
The Company has taken advantage of the exemption allowed under section 408 of the Companies Act 2006 and has not presented its own Income Statement in these financial statements. The Group profit for the year includes Parent Company loss after tax of $17,507,000 for the year ended 31 December 2019 (2018: profit $12,057,000).
17. Earnings per Share
The calculation of basic profit per ordinary share has been based on the profit for the year and 320,637,836 (2018: 320,637,836) ordinary shares, being the weighted average number of shares in issue for the year. There are no dilutive instruments.
18. Property, Plant and Equipment
201 9 201 8
Oil and
Gas Oil and
Development Oil and Gas Oil and
and Gas Development Gas
Production Exploration Other and Production Exploration Other
assets and Evaluation fixed assets and Evaluation fixed
Ukraine Assets assets Total Ukraine Assets assets Total
Group $000 $000 $000 $000 $000 $000 $000 $000
Cost
At beginning of 104, 107,
year 809 1,259 1,293 361 101,927 - 1,104 103,031
Additions 16,132 962 578 17,672 7,967 1,259 326 9,5 52
Change in
decommissioning
provision 3,207 - - 3,207 ( 6 6) - - ( 6 6)
Disposals (130) - (17) (147) (23) - (125) (148)
Write-off of
assets - - - - (6,328) - - (6,328)
Exchange 1,3 3
differences 19,109 350 249 19,708 2 - (12) 1, 320
------------------ ------------- -------------- ------- ------- -------------- -------------- ------- --------
At end of year 143,127 2,571 2,103 147,801 104, 809 1,259 1,293 107, 361
------------------ ------------- -------------- ------- ------- -------------- -------------- ------- --------
Accumulated depreciation and
impairment
At beginning of 56, 5 57, 8 7 ,
year 67 - 60 2 1 69 591 - 47 8 88,069
Charge for year 9,983 - 237 10,220 6, 818 - 169 6,9 87
Reversal of
impairment - - - - (36,117) - - (36,117)
Impairment
charged
for individual
assets - - - - 1,648 - - 1,648
Disposals (85) - (15) (100) (7) - (42) (49)
Write-off of
assets - - - - (6,328) - - (6,328)
Exchange ( 3
differences 10,337 - 123 10,460 2 , 962 - ) 2 , 959
------------------ ------------- -------------- ------- ------- -------------- -------------- ------- --------
56, 5 57, 1
At end of year 76,802 - 947 77,749 67 - 60 2 69
------------------ ------------- -------------- ------- ------- -------------- -------------- ------- --------
Net book value
at
beginning of
year 48,242 1,259 691 50,192 14,336 - 626 14,962
------------------ ------------- -------------- ------- ------- -------------- -------------- ------- --------
Net book value
at
end of year 66,325 2,571 1,156 70,052 48,242 1,259 691 50,192
------------------ ------------- -------------- ------- ------- -------------- -------------- ------- --------
During the 2019 year, the Group completed the acquisition of new 3D seismic over the VAS field which will assist in the evaluation of the VAS licence, and particularly the VED area of the licence. Since the valuation procedures have not yet been completed for the VED area, the costs of the seismic over this area were capitalised within property, plant and equipment as exploration and evaluation assets.
In accordance with the Group's accounting policies, oil and gas development and production assets are tested for impairment at each balance sheet date. The Group determines the recoverable amount of its oil and gas development and production assets based on a Fair Value Less Costs of Disposal ("FVLCD") approach using a discounted cash flow methodology, where the cash flows are derived based on estimates that a typical market participant would use in valuing such assets.
The impairment assessment carried out at 31 December 2019 has not resulted in an impairment loss.
The key assumptions on which the Group has based its determination of FVLCD for its oil and gas development and production assets and to which these CGU's recoverable amounts are most sensitive are described below:
(i) Commodity prices - the model assumes gas prices of $170/Mm3
(UAH4,030/Mm3) in 2020 increasing to $265/Mm3 (UAH6,290/Mm3)
during 2021 - 2042 for the MEX-GOL and SV gas and condensate
fields and to $252/Mm3 (UAH5,970/Mm3) during 2021 - 2028
for the VAS gas and condensate field. The prices were estimated
based on the price of recent Group transactions, Central
European hub futures and the forecast of natural gas price
dynamics for Europe published by the World Bank.
(ii) Discount rate - reflects the current market assessment of
the time value of money and risks specific to the assets.
The discount rate has been determined as the post-tax weighted
average cost of capital based on observable inputs and inputs
from third party financial analysts. For 2020 and onwards,
the discount rate applied is 11.3% (15.1% during previous
measurement of the recoverable amount as at 31 December 2018).
The discount rate and future cash flows are determined in
real terms, i.e. they do not take into account the impact
of the estimated commodity price index during the period
of projection.
(iii) Production levels and Reserves, MEX-GOL and SV fields - production
levels at the MEX-GOL and SV fields are derived from the
estimate of remaining proven plus probable reserves of 50.0
MMboe assessed in the report prepared by D&M as at 31 December
2017. This report includes estimated production volumes,
including from new wells, over the remaining economic life
of the MEX-GOL and SV fields. The estimated production is
based on the Group's revised field development plan, which
includes the drilling of 24 new wells. Estimating oil and
gas reserves is a complex process requiring the knowledge
and experience of reservoir engineers. The quality of the
estimate of proved plus probable reserves depends on the
availability, completeness, and accuracy of data needed to
develop the estimate, including production history available,
and on the experience and judgement of the reservoir engineer.
Estimates of proved plus probable reserves inevitably change
over time as additional data become available and are taken
into account. The magnitude of changes in these estimates
can be substantial.
(iv) Production levels and Reserves, VAS field - production levels
at the VAS field are derived from the estimate of remaining
proven plus probable reserves of 3.1 MMboe assessed in the
report prepared by D&M as at 31 December 2018. The estimated
production is based on the Group's revised field development
plan, which includes the drilling of three new wells. The
quality of the estimate of proved plus probable reserves
depends on the availability, completeness, and accuracy of
data needed to develop the estimate, including production
history available, and on the experience and judgement of
the reservoir engineer. Estimates of proved plus probable
reserves inevitably change over time as additional data become
available and are taken into account. The magnitude of changes
in these estimates can be substantial.
(v) Production taxes - for existing wells, the Group assumed
production tax rates of 29% for gas and 45% for condensate
extracted from deposits up to depths of 5,000 metres and
14% for gas and 21% for condensate extracted from deposits
deeper than 5,000 metres. From 1 January 2019, production
tax rates for condensate produced from all wells was reduced
from 45% to 31% for condensate produced from deposits above
5,000 metres and from 21% to 16% for condensate produced
from deposits below 5,000 metres. For new wells drilled after
1 January 2018, production tax rates were reduced to 12%
for gas produced from deposits at depths above 5,000 metres
and to 6% for gas produced from deposits below 5,000 metres,
effective for the period 2018 - 2022.
(vi) Capital expenditures, MEX-GOL and SV gas and condensate fields
- management assumed that most capital expenditures are to
be incurred during 2020 - 2026. A capital expenditure allowance
of $625,000 per year is assumed for maintenance of the development
and producing assets of the MEX-GOL and SV gas and condensate
fields.
(vii) Capital expenditures, VAS gas and condensate fields - management
assumed that most capital expenditures are to be incurred
during 2020-2023. A capital expenditure allowance of $290,000
per year is assumed for maintenance of the development and
producing assets of the VAS gas and condensate field.
(viii) Life of field, MEX-GOL and SV fields - the current licences,
which are due to expire in 2024, can be extended under applicable
legislation in Ukraine until the end of the economic life
of the field, which is assessed to be 2038 for the MEX-GOL
field and 2042 for the SV field, based on the assessment
contained in the D&M reserves report. No application for
such an extension has been made at the date of this report,
but the Group considers the assumption to be reasonable based
on its intention to seek such extensions in due course and
that the Group is legally entitled to request such extensions.
However, if the extensions were not granted, it would result
in a further reduction of $239,050,000 in the recoverable
amount.
(viii) Life of field, VAS field - according to the D&M reserves
report, the economic life of the VAS field is limited to
2028. However, after additional drilling on the VED area
of the licence, management plans to undertake a further reserves
assessment.
The Group's discounted cash flow model for the VAS field in Ukrainian Hryvnia, flexed for sensitivities, produced the following results:
Recoverable Net book Headroom
amount value* / (Shortfall)
$000 $000 $000
------------------------------------------ ------------ --------- ---------------
13, 0
31 December 2019 13,800 00 8 00
Sensitivities:
13, 0 ( 2 , 4
1. 10% reduction in gas price 10,600 00 00)
13, 0
2. 10% increase in gas price 16,900 00 3, 9 00
13, 0
3. Breakeven gas price $ 169 /Mm(3) 13,590 00 590
4. Breakeven flow rates 21 Mm (3) 13, 0
/day for all wells 13,500 00 500
5. Breakeven discount rate 1 1,5 13, 0
% 13,640 00 6 40
*Net book value of the VAS asset is derived from property, plant and equipment, mineral reserve rights and other intangible assets (Note 19).
The Group's discounted cash flow model for the MEX-GOL and SV fields in Ukrainian Hryvnia is not sensitive.
19. Intangible Assets
2019 2018
Mineral Mineral Other
reserve Other intangible reserve intangible
rights assets Total rights assets Total
Group $000 $000 $000 $000 $000 $000
Cost
At beginning of year 6,709 330 7,039 6,618 257 6,875
Additions - 137 137 - 107 107
Disposals - - - - (36) (36)
Exchange differences 1,134 105 1,239 91 2 93
----------------------- -------- ---------------- ----- -------- ----------- ------
At end of year 7,843 572 8,415 6,709 330 7,039
----------------------- -------- ---------------- ----- -------- ----------- ------
Accumulated amortisation and impairment
At beginning of year 1,965 194 2,159 1,161 124 1,285
Charge for year 509 130 639 804 105 909
Disposals - - - - (35) (35)
Exchange differences 377 43 420 - - -
----------------------- -------- ---------------- ----- -------- ----------- ------
At end of year 2,851 367 3,218 1,965 194 2,159
----------------------- -------- ---------------- ----- -------- ----------- ------
Net book value at
beginning of year 4,744 136 4,880 5,457 133 5,590
----------------------- -------- ---------------- ----- -------- ----------- ------
Net book value at
end of year 4,992 205 5,197 4,744 136 4,880
----------------------- -------- ---------------- ----- -------- ----------- ------
Intangible assets consist mainly of the hydrocarbon production licence (Mineral reserve rights) relating to the VAS field which is owned by LLC Prom-Enerho Produkt. The Group amortises this intangible asset using the straight-line method over the term of the economic life of the VAS field until 2028. The economic life of the VAS field was extended as a result of the new assessment of 2P reserves, as described in Note 5.
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. Pursuant to the results of the impairment tests performed, there is no impairment of the Group's intangible assets as at 31 December 2019 (Note 18).
20. Leases
This note provides information for leases where the Group is a lessee.
Amount recognised in the balance sheet:
31 Dec 19 1 Jan 19*
$000 $000
Right-of-use assets
Properties 423 595
Land 299 311
Wells 218 216
-------------------- --------- ---------
940 1,122
31 Dec 19 1 Jan 19*
$000 $000
Lease liabilities
Current 454 371
Non-current 515 751
------------------ --------- ---------
969 1,122
* For adjustments recognised on adoption of IFRS 16 on 1 January 2019, please refer to Note 4.
Additions to the right-of-use assets during the 2019 financial year were $170,000 .
Amounts recognised in the statement of profit or loss:
2019
$000
Depreciation charge
Properties (297)
Land (16)
Wells (39)
--------------------------------------------------------- -------
(352)
Interest expense (included in finance cost) (177)
Expense relating to short-term leases (included in cost
of sales and administrative expenses) (123)
Expense relating to leases of low-value assets that -
are not shown above as short-term leases (included in
cost of sales and administrative expenses)
Expense relating to variable lease payments not included
in lease liabilities (included in cost of sales and
administrative expenses) (5,283)
Expense relating to lease payments for land under wells
not included in lease liabilities (included in cost
of sales) (49)
The total cash outflow for leases in 2019 was $7,934,000.
21. Investments and Loans to Subsidiary Undertakings
Shares in Loans to
subsidiary subsidiary
undertakings undertakings Total
$000 $000 $000
Company
At 1 January 2018 17,279 38,225 55,504
Additions including accrued interest - 6,301 6,301
Repayment of interests and loans - (4,200) (4,200)
Reversal of impairment of loans
to subsidiary - 10,923 10,923
Exchange differences - (3,697) (3,697)
------------------------------------- ------------- ------------- --------
At 31 December 2018 17,279 47,552 64,831
------------------------------------- ------------- ------------- --------
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
------------------------------------- ------------- ------------- --------
The Company has recorded a loss of $15,450,000, 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 2019 (Note 5).
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 2019:
Credit loss allowance Gross carrying amount
Stage Stage Stage Total Stage Stage Stage Total
1 2 3 1 2 3
---------- ---------
(12-months (lifetime (lifetime (12-months (lifetime (lifetime
ECL) ECL ECL for ECL) ECL for ECL for
for credit SICR) credit
SICR) impaired) impaired)
----------------- ----------- ----------- ---------- ---------- ----------- ---------- ---------- ---------
$000 $000 $000 $000 $000 $000 $000 $000
(1 93
At 1 January , 386 2 40 240
2019 - - ) (193,386) - - , 938 , 938
----------------- ----------- ----------- ---------- ---------- ----------- ---------- ---------- ---------
Movements with
impact on credit
loss allowance
charge for the
period:
Transfers:
- to - - - - - - - -
credit-impaired
(from Stage 1
and Stage 2 to
Stage 3)
(
Modification of ( 42,733 42,733
loans - - 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 2,60 2,60
difference - - 3 3 - - (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
On 22 July 2019, the loans to a subsidiary were assigned to the Company on different terms which is considered to be a modification of the financial assets. The gross carrying amount of loans was recalculated as the present value of the modified contractual cash flows that are discounted at the financial asset's original effective interest rate. As a result of modification the gross carrying amount of the loan and credit loss allowance decreased by $42,733,000.
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 2018:
Credit loss allowance Gross carrying amount
Stage Stage Stage Total Stage Stage Stage Total
1 2 3 1 2 3
--------------- --------
(12-months (lifetime (lifetime (12-months (lifetime (lifetime
ECL) ECL ECL for ECL) ECL for ECL for
for credit SICR) credit
SICR) impaired) impaired)
----------------- ------------------ ------------- -------------------- --------------- ---------------- ---------- ---------- --------
$000 $000 $000 $000 $000 $000 $000 $000
At 1 January
2018 - - (191,678) (191,678) - - 229,903 229,903
----------------- ------------------ ------------- -------------------- --------------- ---------------- ---------- ---------- --------
Movements with
impact on credit
loss allowance
charge for the
period:
Transfers:
- to - - - - - - - -
credit-impaired
(from Stage 1
and Stage 2 to
Stage 3)
Other movement* - - (12,578) (12,578) - - 12,578 12,578
Additions
including
accrued
interest - - (2,883) (2,883) - - 9,184 9,184
Payment of
interest - - - - - - (1,400) (1,400)
Repayment of
loans (2,800) (2,800)
Exchange
difference - - 2,830 2,830 - - (6,527) (6,527)
Changes to ECL
measurement
model
assumptions - - 10,923 10,923 - - - -
----------------- ------------------ ------------- -------------------- --------------- ---------------- ---------- ---------- --------
Total movements
with impact on
credit loss
allowance
charge for the
period - (1,708) (1,708) - - 11,035 11,035
----------------- ------------------ ------------- -------------------- --------------- ---------------- ---------- ---------- --------
At 31 December
2018 - - (193,386) (193,386) - - 240,938 240,938 ----------------- ------------------ ------------- -------------------- --------------- ---------------- ---------- ---------- --------
ECL - Expected credit losses
SICR - Significant increase in credit risk
*Gross up movement carrying amount of loans and credit loss allowance
Subsidiary undertakings
At 31 December 2019, the Company's subsidiary undertakings, all of which are included in the consolidated financial statements, were:
Registered address Country of Country of operation Principal activity % of shares held
incorporation
Regal Petroleum 26 New Street, St
Corporation Helier, Jersey, Oil & Natural Gas
Limited JE2 3RA Jersey Ukraine Extraction 100%
16 Old Queen
Regal Group Street, London,
Services Limited SW1H 9HP United Kingdom United Kingdom Service Company 100%
26 New Street, St
Regal Petroleum Helier, Jersey,
(Jersey) Limited JE2 3RA Jersey United Kingdom Holding Company 100%
162 Shevchenko
Str., Yakhnyky
Village,
Regal Petroleum Lokhvytsya
Corporation District, Poltava
(Ukraine) Limited Region, 37212 Ukraine Ukraine Service Company 100%
LLC Prom-Enerho 3 Klemanska Str., Oil & Natural Gas
Produkt Kiev, 02081 Ukraine Ukraine Extraction 100%
The Parent Company, Regal Petroleum plc, holds direct interests in 100% of the share capital of Regal Petroleum (Jersey) Limited and Regal Group Services Limited, with all other companies owned indirectly by the Parent Company. Regal Petroleum Corporation Limited is controlled through its 100% ownership by Regal Petroleum (Jersey) Limited. Regal Petroleum Corporation (Ukraine) Limited is controlled through its 100% ownership by Regal Petroleum (Jersey) Limited and Regal Group Services Limited, and LLC Prom-Enerho Produ kt is controlled through its 100% ownership by Regal Petroleum Corporation (Ukraine) Limited.
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 2019.
22. Inventories
Group
2019 2018
$000 $000
Current
Materials and spare parts 1,791 1,4 37
Finished goods 3,022 1 68
-------------------------- ------- --------
4,813 1,6 05
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 2019, production raw materials and fuel at the storage facility. Finished goods as at 31 December 2019 consist of produced gas held in underground gas storage facilities and condensate and LPG held at the processing facility prior to sale (2018: consist of produced condensate and LPG held at the processing facility prior to sale). The gas sales price in Ukraine has been lower, particularly in the second half of 2019, reflecting the lower prices in Europe. As a result the Group delayed sales and built up inventory to nearly 22.6 MMm(3) at the end of December 2019, which inventory was sold in the first quarter of 2020.
All inventories are measured at the lower of cost or net realisable value. There was no write down of inventory as at 31 December 2019 or 2018.
23. Trade and Other Receivables
Group Company
2019 2018 2019 2018
$000 $000 $000 $000
Trade receivables 2,881 5,012 - -
Other financial receivables 1,718 202 - -
Less credit loss allowance (155) (99) - -
---------------------------------- -------- -------- --------- ---------
Total financial receivables 4 , 444 5,115 - -
Prepayments and accrued
income 5,959 4 , 771 8 64
Other receivables 534 244 93 7 4
---------------------------------- -------- -------- --------- ---------
Total trade and other receivables 10,937 10,130 1 01 138
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 2019, the Group's total trade receivables amounted to $2, 726 ,000 and 100% were denominated in Ukrainian Hryvnia (31 December 2018: $4,918,000 and 100% were denominated in Ukrainian Hryvnia). Further description of financial receivables is disclosed in Note 32.
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 34). 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 $3,987,000 relating to the development of the SV field and $1,094,000 relating to the development of the VAS field (31 December 2018: $3,988,000 relating to the development of the MEX-GOL field).
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 Life-time Carrying Basis
amount ECL amount
$000 $000 $000
Trade receivables financial position
from related of related
parties 5 % 2,644 (3) 2,641 party
number of days
Trade receivables the asset past
- credit impaired 100% 152 (152) - due
historical
Trade receivables credit losses
- other 0. 36 % 85 (0) 85 experienced
Other financial individual
receivables 0.92%-2.05% 1,718 (0) 1,718 default rates
Total trade
and other
receivables
for which
individual
approach for
ECL is used 4 , 599 (155) 4 , 444
ECL - Expected credit losses
Analysis by credit quality of financial trade and other receivables and expected credit loss allowance as at 31 December 2018 is as follows:
Loss rate Gross carrying Life-time Carrying Basis
amount ECL amount
$000 $000 $000
Trade receivables financial position
from related of related
parties 5 % 4,918 (7) 4,911 party
number of days
Trade receivables the asset past
- credit impaired 100% 92 (92) - due
historical
Trade receivables credit losses
- other 0. 36 % 2 (0) 2 experienced
Other financial individual
receivables 0.92%-2.05% 202 (0) 202 default rates
Total trade and
other receivables
for which individual
approach for
ECL is used 5,214 (99) 5,115
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:
2019 2018
$000 $000
Trade receivables
Balance at 1 January 99 152
New originated or purchased 3 7
Financial assets derecognised during the
period - (3)
Changes in estimates and assumptions 30 (59)
Foreign exchange movements 23 2
------------------------------------------ ----- -----
Balance at 31 December 155 99
24. Cash and Cash Equivalents and Other Short-term Investments
Group Company
2019 2018 2019 2018
$000 $000 $000 $000
Cash and Cash Equivalents
Cash at bank 28,089 24,462 23,656 23,990
Demand deposits and term deposits
with maturity less than 3 months 34,385 24,791 18,015 -
Short-term government bonds - 3,969 - -
62,474 53,222 41,671 23,990
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:
Demand deposits
and term deposits
with maturity
Cash at bank less than 3 Short-term government Total cash and
and on hand months bonds cash equivalents
2019 2019 2019 2019
$000 $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
Demand deposits
and term deposits
with maturity
Cash at bank less than 3 Short-term government Total cash and
and on hand months bonds cash equivalents
2018 2018 2018 2018
$000 $000 $000 $000
A- to A+
rated 23,948 - - 23,948
B- to B+
rated 62 7,492 3,969 11,523
Unrated 452 17,299 - 17,751
24,462 24,791 3,969 53,222
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 2019 for non-rated banks. Based on this assessment, the Group concluded that the identified impairment loss was immaterial.
25. Trade and Other Payables
2019 2018
$000 $000
Accruals and other payables 2,418 2,314
Taxation and social security 1,092 2,312
Trade payables 277 105
Advances received 181 105
3,968 4 , 836
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 32.
26. Provision for Decommissioning
2019 2018
$000 $000
Group
At beginning of year 3,137 3,027
Amounts provided/(utilised) 355 (16)
Unwinding of discount 273 140
Change in estimate 2, 852 (50)
Effect of exchange difference 830 36
------------------------------ ------ ------
At end of year 7, 447 3,137
The provision for decommissioning is based on the net present value of the Group's estimated liability for the removal of the Ukraine production facilities and well site restoration at the end of production life.
2019 2018
$000 $000
Deferred tax asset recognised on tax
losses - Company and Group
At beginning of year 2,134 2 , 567
Charged to Income Statement - current
year (2,134) (433)
----------------------------------------------------- ------- --------
At end of year - 2,134
2019 2018
$000 $000
Deferred tax (liability)/asset recognised
relating to oil and gas development and
production assets and provision for decommissioning
- Group
At beginning of year 1,149 6,694
Charged to Income Statement - current
year (1,077) (5,086)
Charged to Income Statement - prior year (1,996) (821)
Effect of exchange difference (217) 362
----------------------------------------------------- ------- --------
At end of year (2,141) 1,149
2019 2018
$000 $000
Deferred tax liability recognised relating
mainly to oil and gas development and
production assets - Group
At beginning of year (504) (820 )
Credited to Income Statement - current
year 406 333
Effect of exchange difference (49) (1 7 )
----------------------------------------------------- ------- --------
At end of year (147) (50 4 )
The non-current provision of $ 7 , 447 ,000 (31 December 2018: $3,137,000) 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 2019 is explained in Note 5.
The principal assumptions used are as follows:
31 December 2019 31 December 2018
Discount rate , % 3 . 68% 8 . 14 %
Average cost of restoration per well , $000 406 3 57
--------------------------------------------- ----------------- -----------------
The sensitivity of the restoration provision to changes in the principal assumptions is presented below:
31 December 2019 31 December 201 8
$000 $000
Discount rate ( increase ) /decrease by 1% (1,086)/1,319 (313)/371
Change in average cost of restoration increase/ ( decrease ) by 1 0 % 523/(523) 219 /( 219 )
----------------------------------------------------------------------- ----------------- ------------------
27. Deferred Tax
At 31 December 2019, the Group derecognised a deferred tax asset of $ 2 , 134 ,000 due to losses expected in the foreseeable future. There was a further $85 million (31 December 2018: $85 million) of unrecognised UK tax losses carried forward for which no deferred tax asset has been recognised. These losses can be carried forward indefinitely, subject to certain rules regarding capital transactions and changes in the trade of the Company.
The deferred tax asset relating to the Group's provision for decommissioning at 31 December 2019 of $326,000 (31 December 2018: $161,000) was recognised on the tax effect of the temporary differences on 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 oil and gas development and production assets at 31 December 2019 of $2, 467 ,000 (31 December 2018 deferred tax asset of $ 988 ,000) was recognised on the tax effect of the temporary differences between the carrying value of the Group's oil and gas development and production assets 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 2019 of $329,000 (31 December 2018: $271,000) was recognised on the tax effect of the temporary differences on the Group's provision for decommissioning at the VAS field, and its tax base. The deferred tax liability relating to the Group's oil and gas development and production assets at 31 December 2019 of $ 476 ,000 (31 December 2018: $775,000) was recognised on the tax effect of the temporary differences between the carrying value of the Group's oil and gas development and production asset at the VAS field, and its tax base.
The impact of the UK losses surrendered to the Ukrainian operating subsidiary in relation to losses was $4,649,000 for 2015 . There were no UK losses surrendered for the years ended 31 December 2016-2019.
Losses accumulated in a Ukrainian subsidiary service company of UAH2,762,352,984 ($116,622,885) at 31 December 2019 and UAH2,856,563,453 ($103,168,745) at 31 December 2018 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 2019 and 2018, 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). This new law was substantively enacted on 17 March 2020 and has no significant impact on the financial statement as the proposal to keep the rate at 19% had not been substantively enacted at the balance sheet date, and therefore its effects are not included in these financial statements.
28. Called Up Share Capital
2019 2018
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.
29. Other Reserves
The holders of ordinary shares are entitled to receive dividends as declared and are entitled to one vote per share at general meeting of shareholders. Distributable reserves are limited to the balance of retained earnings. 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.
30. Operating Lease Arrangements
The Group leases various offices, equipment, wells, land under non-cancellable operating leases.
From 1 January 2019, the Group has recognised right-of-use assets for these leases, except for short-term and low-value leases (see Note 20 ).
2019 2018
Group and Company $000 $000
Amounts payable due:
- Within one year - 492
- After one year - 1,392
---------------------- ---- -----
- 1,884
Group Company
2019 2018 2019 2018
$000 $000 $000 $000
Lease payments under operating
leases recognised as an expense
for the year - 4,797 - 125
--------------------------------- -------- -------- --------- ---------
31. Reconciliation of Operating Profit to Operating Cash Flow
201 9 201 8
$000 $000
Group
Operating profit 21,093 66,370
Impairment/(Reversal of impairment) of property,
plant and equipment - (34,469)
Depreciation and amortisation 10,190 7,901
Less interest income recorded within operating
profit (4,751) (3,024)
Fines and penalties received (236) (225)
Gain on sales of current assets, net (27) (26)
Reversal of loss allowance on other financial
assets (46) (18)
Loss/(gain) from write off of non-current assets 47 (21)
Increase/(decrease) in provisions 67 (11)
( 3 , 208
Increase in inventory ) (76)
Decrease/(increase) in receivables 2,340 (2,487)
I ncrease in payables (868) 2,428
Cash generated from operations 2 4 ,6 01 36,342
2019 2018
$000 $000
Company
Operating (loss)/profit (15,016) 9,374
Interest received (3,162) -
Movement in provisions (including impairment
of subsidiary loans) 15,450 (10,923)
(Decrease)/increase in receivables (453) 4 09
(Increase)/decrease in payables 159 7
--------------------------------------------- -------- --------
Cash used in operations (3,022) (1,133)
32. Financial Instruments
Capital Risk Management
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.
The Group defines its capital as equity. The primary source of the Group's liquidity has been cash generated from operations.
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
2019 2018
$000 $000
Group
Cash and cash equivalents 62,474 53 , 222
Trade and other receivables 4,444 5,115
Prepayment for shares 500 -
67,418 58,337
2019 2018
$000 $000
Company
Cash and cash equivalents 41,671 23,990
Loans to subsidiary undertakings 14,181 47,552
Prepayment for shares 500 -
56,352 71 , 542
Financial Liabilities
2019 2018
$000 $000
Group
Lease liabilities 969 -
Trade payables 277 105
Accruals 1,018 1,284
----------------------- ------ ------
2,264 1,389
2019 2018
$000 $000
Company
Accruals 256 97
----------------------- ------ ------
256 97
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.
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.
2019 2018
Currency $000 $000
British Pounds 301 256
Euros 33 112
Net monetary assets less liabilities 334 368
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 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 (profit for the year ended 31 December 2018 would increase
by $92,000 in the event of 0.5% higher interest rates and
decrease by $92,000 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 (2018: 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.
Details of the Group's cash management policy are explained in Note 24.
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 $41.7 million of the overall cash and cash equivalents is held (31 December 2018: $24 million), the Group only deposits cash surpluses with major banks of high quality credit standing (Note 2 4 ). As at 31 December 2019, the remaining balance of $20.8 million of cash and cash equivalents was held in Ukraine (31 December 2018: $29.3 million). In September 2019 Standard & Poor's upgraded Ukraine's sovereign credit rating from "B-/B" to '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.
After several years of devaluation, the Ukrainian currency strengthened during 2019. With effect from April 2019, the National Bank of Ukraine ("NBU") launched a cycle of easing of monetary policy and a gradual decrease of its discount rate, for the first time in two years, from 18% in April 2019 to 11% in January 2020, which was justified by a sustainable trend of inflation deceleration.
Nevertheless 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:
Floating Fixed Floating Fixed
rate rate rate rate
financial financial financial financial
Currency Total assets assets Total assets assets
2019 2019 2019 2018 2018 2018
$000 $000 $000 $000 $000 $000
Euros 30 30 - 44 44 -
British Pounds 257 257 - 215 215 -
Ukrainian Hryvnia 17,881 - 17,881 25,264 - 25,264
US Dollars 44,306 44,306 - 27,699 23,730 3,969
62,474 44,593 17,881 53,222 23,989 29,233
Cash deposits included in the above balances comprise short-term deposits.
As at 31 December 2019, cash and cash equivalents of the Company of $42 million were held in US Dollars at a floating rate (2018: $24 million).
Interest Rate Risk Profile of Financial Liabilities
As at 31 December 2019 and 2018, 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:
2019 2018
$000 $000
Group
In one year or less 2,264 1,389
--------------------- ----- -----
2,264 1,389
2019 2018
$000 $000
Company
In one year or less 256 97
--------------------- ----- -----
256 97
Borrowing Facilities
As at 31 December 2019 and 2018, 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.
33. Contingencies and Commitments
Amounts contracted in relation to the Group's 201 9 investment programme in the MEX-GOL , SV and VAS fields in Ukraine, but not provided for in the financial statements at 31 December 201 9 , were $2,306 ,000 (2018: $2,607,000).
During 2010 - 2019, 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 2019 (31 December 2018: 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.
34. Related Party Disclosures
Key management personnel of the Group are considered to comprise only the Directors. Details of Directors' remuneration are disclosed in Note 9.
During the year, Group companies entered into the following transactions with related parties who are not members of the Group:
2019 2018
$000 $000
Sale of goods / services 38,417 49 ,691
Purchase of goods / services 963 508
Amounts owed by related parties 2,649 4, 912
Amounts owed to related parties 137 35
---------------------------------
All related party transactions were with subsidiaries of the ultimate Parent Company, and primarily relate to the sale of gas (see Note 6 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.
As of 31 December 2019, the Company's immediate parent company was Pelidona Services Limited, which is 100% owned by Lovitia Investments Limited, which is 100% owned by Mr Vadym Novynskyi. Accordingly, the Company was ultimately controlled by Mr Vadym Novynskyi.
The Group 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:
2019 2018
$000 $000
Interest income - 1
Bank charges 1 21
Closing cash balance (as at 31 December) 1 20
The bank charges represent cash transit fees.
At the date of this annoucement, none of the Company's controlling parties prepare s consolidated financial statements available for public use.
35. Post Balance Sheet Events
In March 2020 oil prices declined to levels not seen since 2016, and approximately two thirds lower than levels in 2018, as Saudi Arabia declared a "price war" on Russia. This added additional stress to financial markets already suffering amid concerns over the evolving situation with the Coronavirus (COVID-19) pandemic, which is a non-adjusting event. As a result, abnormally large volatility is being witnessed in commodity markets. The scale and duration of these developments remain uncertain but could impact Group's earnings, cash flow and financial condition.
On 24 March 2020, the Company completed the acquisition of a 100% shareholding interest in LLC Arkona Gas-Energy ("Arkona") pursuant to an acquisition agreement between (1) the Company and (2) Igor Mychko, Oleksandr Neschchotnyy, Dmitro Volonets and Oleg Olkhovoy (the "Sellers")). Akrona is the holder of the Svystunivsko-Chervonolutskyi ("SC") exploration licence in north-eastern Ukraine. The aggregate consideration for this acquisition is up to $8,630,000, comprising: (i) a first tranche of $4,315,000 (less certain adjustments for debt liabilities) paid on completion; (ii) a second tranche of $2,157,500 payable on satisfaction of certain conditions; and (iii) a third tranche of $2,157,500 payable in 12 months from the date of payment of the second tranche, provided that if the conditions for payment of the second tranche are not satisfied, then neither the second tranche nor the third tranche shall become payable. Further details can be found in the announcement dated 24 March 2020.
36. Accounting policies before 1 January 2019
Accounting policies applicable to the comparative period ended 31 December 2018 that were amended by IFRS 16, Leases, are as follows.
Operating leases
Where the Group is a lessee in a lease which does not transfer substantially all the risks and rewards incidental to ownership from the lessor to the Group, the total lease payments are charged to profit or loss for the year on a straight-line basis over the lease term. The lease term is the non-cancellable period for which the lessee has contracted to lease the asset together with any further terms for which the lessee has the option to continue to lease the asset, with or without further payment, when at the inception of the lease it is reasonably certain that the lessee will exercise the option.
Finance lease liabilities
Where the Group is a lessee in a lease which transferred substantially all the risks and rewards incidental to ownership to the Group, the assets leased are capitalised in property, plant and equipment at the commencement of the lease at the lower of the fair value of the leased asset and the present value of the minimum lease payments. Each lease payment is allocated between the liability and finance charges so as to achieve a constant rate on the finance balance outstanding. The corresponding rental obligations, net of future finance charges, are included in borrowings. The interest cost is charged to profit or loss over the lease period using the effective interest method. The assets acquired under finance leases are depreciated over their useful life or the shorter lease term, if the Group is not reasonably certain that it will obtain ownership by the end of the lease term.
This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.
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