TIDMRPT
RNS Number : 4613X
Regal Petroleum PLC
30 April 2019
30 April 2019
REGAL PETROLEUM PLC
2018 AUDITED RESULTS
Regal Petroleum plc (the "Company", and with its subsidiaries,
the "Group"), the AIM-quoted (RPT) oil and gas exploration and
production group, today announces its audited results for the year
ended 31 December 2018.
Highlights
Ukraine Operations
-- Aggregate average daily production from the MEX-GOL, SV and VAS fields over the year
to 31 December 2018 of 3,391 boepd, which compares with an aggregate average daily production
rate of 2,235 boepd during 2017, an increase of nearly 52%.
-- Aggregate 2018 year end production of approximately 4,377 boepd, compared with approximately
2,811 boepd at 2017 year end, representing an increase of nearly 56% during the year,
largely as a result of the significant contributions from the MEX-109 and SV-2 wells,
which were operational for the full year, and additional contributions coming on stream
during the year from the SV-12 and VAS-10 wells
-- Reserves upgrade at MEX-GOL and SV fields announced in July 2018, approximately quadrupling
2P reserves to 50.0 MMboe, enabling an enhanced development programme for these fields
-- Workover of SV-12 well successfully completed and brought on production in July 2018
-- VAS-10 well successfully completed and brought on production in November 2018
Finance
-- Revenue for the year to 31 December 2018 up 88.3% to $66.1 million (2017: $35.1 million)
-- Gross profit for the year up 216.7% to $34.2 million (2017: $10.8 million)
-- Cash generated from operations during the year of $36.8 million (2017: $18.0 million)
-- Net profit for the year of $54.3 million (2017: $2.3 million), including a one-off item
of $36.1 million relating to impairment reversal of oil and gas development and production
asset (as a result of reassessment of the remaining reserves and resources at the MEX-GOL
and SV fields as at 31 December 2017)
-- Average realised gas, condensate and LPG prices in Ukraine for the year to 31 December
2018 of $312/Mm(3) (UAH8,528/Mm(3) ), $72/bbl and $64/bbl respectively (2017: $241/Mm(3)
(UAH6,412/Mm(3) ) gas, $67/bbl condensate and $56/bbl LPG)
-- Cash and cash equivalents of $53.2 million at 31 December 2018 (31 December 2017: cash
resources of $30.2 million comprising cash and cash equivalents of $14.2 million and
short-term investments of $16.0 million), with cash and cash equivalents at 25 April
2019 of $54.2 million, held as $24.2 million equivalent in Ukrainian Hryvnia and the
balance of $30.0 million equivalent predominately in US Dollars, Euros and Pounds Sterling.
Outlook
-- Development work for 2019 at MEX-GOL and SV fields: completion of geophysical studies
on existing seismic data and refinement of new geological model; completion of MEX-119
well; commencement of new well in SV field; planning for further new well in SV field;
hydraulic fracturing of MEX-120 well; assessment and workover of existing wells; installation
of compression equipment; and continued investment in gas processing facilities, pipeline
network and other infrastructure
-- Development work for 2019 at VAS field: completion of processing and interpretation of
new 3D seismic data; development of new geological model; reassessment of remaining reserves
and resources; planning for a new well; installation of compression equipment; and continued
investment in gas processing facilities, pipeline network and other infrastructure
-- 2019 development programme expected to be funded from existing cash resources and operational
cash flow
The Annual Report and Financial Statements for 2018, together
with the Notice of Annual General Meeting, will be posted to
shareholders and published on the Company's website during May/June
2019.
This announcement contains inside information for the purposes
of Article 7 of EU Regulation 596/2014.
For further information, please contact:
Regal Petroleum plc Tel: 020 3427 3550
Chris Hopkinson, Chairman
Sergii Glazunov, Chief Eexecutive Officer
Strand Hanson Limited Tel: 020 7409 3494
Rory Murphy / Richard Tulloch
Citigate Dewe Rogerson Tel: 020 7638 9571
Nick Hayns / 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
bbl barrel
Bm(3) thousands of millions of cubic metres
boe barrels of oil equivalent
Bscf thousands of millions of scf
boepd barrels of oil equivalent per day
HSES health, safety, environment and security
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
Mm(3) thousand cubic metres
MMm(3) million cubic metres
Mtonnes thousand tonnes
MMbbl million barrels
MMboe million barrels of oil equivalent
% per cent
scf standard cubic feet measured at 20 degrees
Celsius and one atmosphere
SV Svyrydivske
$ United States Dollar
UAH Ukrainian Hryvnia
VAS Vasyschevskoye
VED Vvdenska
Chairman's Statement
I am delighted to introduce the 2018 Annual Report and Financial
Statements. This year has been an exceptional year for the Group,
with excellent progress in the development of the MEX-GOL, SV and
VAS gas and condensate fields in north-eastern Ukraine and an
extremely strong financial performance during the year. As
announced on 31 July 2018, a reassessment of reserves and resources
at the MEX-GOL and SV fields as at 31 December 2017 resulted in a
significant reserves upgrade, and operational successes have
resulted in significantly higher production levels.
At the MEX-GOL and SV fields, production was stable during the
first half of 2018, with much higher production volumes compared
with the same period last year following completion of the MEX-109
and SV-2 wells in June and August 2017 respectively. In July 2018,
the workover of the SV-12 well was successfully completed and the
well was put on production, with the well now producing at
approximately 824 boepd, providing a further significant boost to
production from the field. During the year, the VAS field continued
to produce consistently, and in November 2018, the VAS-10 well was
brought into production, providing a significant production
increase at the VAS field.
Aggregate average daily production from the MEX-GOL, SV and VAS
fields during 2018 was approximately 3,391 boepd, which compares
with an aggregate daily production rate of approximately 2,235
boepd during 2017, an increase of nearly 52%.
The Group's strong production performance is reflected in the
Group's financial performance for the year ended 31 December 2018,
which was also extremely strong and a significant improvement on
the prior year. During 2018, the Group grew its net profit to $54.3
million (2017: $2.3 million), predominantly as a result of improved
revenues of $66.1 million (2017: $35.1 million) from higher
production volumes and hydrocarbon prices, and a significant
reversal of an impairment of the Group's oil and gas production
assets of $36.1 million, which arose as a result of the
reassessment of the reserves and resources at the MEX-GOL and SV
fields, and which was a one-off item. Gross profits were much
higher at $34.2 million (2017: $10.8 million) and cash generated
from operations during the year was also much higher at $36.8
million (2017: $18.0 million).
The fiscal and economic situation in Ukraine has improved during
2018, with a better economic outlook, GDP growth, reduced inflation
and reasonable stability in the Ukrainian Hryvnia exchange rates.
Nevertheless, there are still fiscal and economic stresses in
Ukraine and a continued weakness in the Ukrainian banking
sector.
The Ukrainian Government has implemented a number of reforms in
the oil and gas sector in recent years, which include the
deregulation of the gas supply market in late 2015, and more
recently, reductions in the subsoil tax rates relating to oil and
gas production and a simplification of the regulatory procedures
applicable to oil and gas exploration and production activities in
Ukraine.
The deregulation of the gas supply market, supported by
electronic gas trading platforms and improved pricing transparency,
has meant that the market gas prices in Ukraine now broadly
correlate with the imported gas prices. During 2018, gas prices
were reasonably stable, allowing for some seasonal variation, and
were higher than in 2017. Furthermore, condensate and LPG prices
were also higher by comparison with last year.
Board and Management Changes
At the end of September 2018, there were a number of changes to
the management and Board of Directors of the Company. Yevhen (Gene)
Palyenka left his position as Chief Financial Officer to pursue
another opportunity, Phil Frank stepped down from the Board and
Dmitry Sazonenko joined the Board as Non-Executive Director.
On behalf of the Board, I would like to thank both Gene and Phil
for their valued contributions during their respective tenures with
the Company, and to welcome Dmitry to the Board.
Outlook
Whilst there are still challenges in the business environment in
Ukraine, the situation is improving gradually. After the
operational successes of 2018 and the increased production output
during the year, we are looking forward to achieving further
successes in the development activities planned for 2019 and
delivering a steadily increasing production and revenue stream in
the future.
In conclusion, on behalf of the Board, I would like to thank all
of our staff for the continued dedication and support they have
shown during the year.
Chris Hopkinson
Chairman
Chief Executive Officer's Statement
Introduction
The Group made excellent progress at its Ukrainian fields during
2018, with the increase in development activity at the MEX-GOL and
SV fields resulting in the successful workover of the SV-12 well,
which came on production in July 2018, and at the VAS field,
resulting in the successful drilling of the VAS-10 well, which came
on production in November 2018. These successes have provided a
significant boost to overall production rates.
During the year, the Group continued its work on the subsurface
analysis of the MEX-GOL and SV fields, utilising the results of
P.D.F Limited's comprehensive re-evaluation study to plan
additional development of these fields. Other work during the year
included interpretation of the reprocessed existing 3D seismic data
and the workover of the SV-12 well, as well as the upgrading of the
gas processing facilities and pipeline network, and undertaking
remedial work on existing wells.
At the VAS field, drilling of the VAS-10 well was completed in
July 2018, and after testing of different zones, the well was
hooked up to the gas processing facilities and put onto production
in November 2018. Planning for the acquisition of the remaining
coverage of 3D seismic over the field was undertaken after some
local access issues had caused delays, and the acquisition work was
completed in early 2019.
Health, Safety, Environment and Security ("HSES")
The Group is committed to maintaining the highest HSES standards
and the effective management of these areas is an intrinsic element
of the overall business ethos. Through strict enforcement of the
Group's HSES Management System, together with regular management
meetings, training and the appointment of dedicated safety
professionals, the Group strives to ensure that the impact of its
business activities on its staff, contractors and the environment
is as low as is reasonably practicable. The Group reports safety
and environmental performance in accordance with industry practice
and guidelines.
I am pleased to report that during 2018, a total of 398,773
man-hours of staff and contractor time were recorded without a Lost
Time Incident occurring. The total number of safe man-hours now
stands at over 2,277,175 man-hours without a Lost Time Incident. No
environmental incidents were recorded during the year.
Production
Average daily production from the MEX-GOL and SV fields over the
year ended 31 December 2018 was 341,216 m(3)/d of gas, 70 m(3)/d of
condensate and 36 m(3)/d of LPG (2,717 boepd in aggregate) (2017:
197,961 m(3) /d of gas, 47 m(3) /d of condensate and 24 m(3)/d of
LPG (1,629 boepd in aggregate). Production rates improved
significantly following the commencement of production from the
SV-12 well in July 2018.
Average daily production of gas and condensate from the VAS
field for the year ended 31 December 2018 was 94,752 m(3) /d of gas
and 8.2 m(3) /d of condensate (674 boepd in aggregate) ( 2017:
86,010 m(3) /d of gas and 6.5 m(3) /d of condensate (606 boepd in
aggregate)). Production rates were boosted significantly following
commencement of production from the VAS-10 well in November
2018.
The Group's average production for the period from 1 January
2019 to 25 April 2019 from the MEX-GOL and SV field was 402,245
m(3)/d of gas, 87 m(3)/d of condensate and 45 m(3)/d of LPG (3,245
boepd in aggregate) and from the VAS field was 139,900 m(3)/d of
gas and 15 m(3)/d of condensate (1,012 boepd in aggregate).
Operations
The much improved fiscal and economic conditions in Ukraine,
coupled with reasonable stability in the Ukrainian Hryvnia, higher
hydrocarbon prices, reductions in the subsoil tax rates and
improvements in the regulatory procedures in the oil and gas sector
in Ukraine over the last year, gave the Board the confidence to
expand and accelerate the Group's development programme at its
Ukrainian fields during 2018.
At the MEX-GOL and SV fields, the Group continued to work with
P.D.F. Limited to utilise their re-evaluation study of these
fields, which involved analysis of all available geological,
geophysical, petroleum engineering and well performance data. The
continuing work included interpretation of newly reprocessed
existing 3D seismic data, with the intention of utilising this data
to update the new geological subsurface model of the fields. This
work, undertaken in conjunction with P.D.F. Limited, is enabling
the Group to refine its strategies for the further development of
the fields, including the timing and level of future capital
investment required to exploit the hydrocarbon resources.
In early 2017, the Group entered into an agreement with NJSC
Ukrnafta, the majority State-owned oil and gas producer, relating
to the SV-2 well, which is a suspended well owned by NJSC Ukrnafta
located within the Group's SV licence area. Under the agreement,
the Group agreed to undertake a workover of the well, which was
successful, and resulted in the well being brought back into
production in August 2017. Pursuant to the agreement, the gas and
condensate produced from the well is sold under an equal net profit
sharing arrangement between the Group and NJSC Ukrnafta, with the
Group accounting for the hydrocarbons produced and sold from the
well as revenue, and the net profit share due to NJSC Ukrnafta
being treated as a lease expense in cost of sales.
Following on from the success of the SV-2 well operations, in
November 2017, the Group entered into a similar agreement with NJSC
Ukrnafta, in relation to the SV-12 well, which is also a suspended
well owned by NJSC Ukrnafta located within the SV licence area. The
terms of this agreement are fundamentally consistent with the
agreement relating to the SV-2 well, including the equal net profit
sharing arrangement between the Group and NJSC Ukrnafta. Workover
operations were undertaken on this well during the first half of
2018, which were successfully concluded in July 2018 and the well
was put on production from two intervals in the B-22 Visean
formation. The well is a strong producer, with stable production
rates of approximately 94,000 m(3) /d of gas, 27 m(3) /d of
condensate and 9 m(3) /d of LPG, which has significantly increased
production at the SV field.
In addition at the MEX-GOL and SV fields, the Group upgraded the
gas processing facilities and pipeline network, and undertook
remedial work on existing wells.
At the VAS field, planning took place for the acquisition of new
3D seismic data over the field, which was finally completed in
January 2019, after the seismic contractor experienced some local
access issues which delayed the acquisition field work. The data
acquired is now being processed and interpreted.
The VAS-10 well was spudded in March 2018 and drilled to a depth
of 3,380 metres. The well is located to the north-west of the VAS
field, at an offset of approximately 1 km from the nearest
producing well, and targeted two reservoir zones in the Visean
formation: the B-16/17 and the deeper B-25/26. The B-16/17
reservoir is currently the main production horizon in the VAS
field. In July 2018, one interval in the B-25/26 Visean formation
was perforated and short-term initial flow testing was undertaken,
and whilst there was gas flow, a stabilised flow rate was not
established. As a result, the shallower B-16/17 reservoir was
tested and flowed strongly. Accordingly, this interval was put on
production during November 2018, and is producing steadily at rates
of approximately 50,000 m(3) /d of gas and 8 m(3) /d of
condensate.
However, as announced on 12 March 2019, a regulatory issue did
arise when the State Service of Geology and Subsoil of Ukraine
issued an order for suspension (the "Order") of the production
licence for the VAS field. Under the applicable legislation, the
Order would lead to a shut down of production operations at the VAS
field, but the Group has issued legal proceedings to challenge the
Order, and has obtained a ruling suspending operation of the Order
pending a hearing of the substantive issues. The Group does not
believe that there are any grounds for the Order, and intends to
pursue its challenge to the Order through the Ukrainian Courts.
Reserves Update
In early 2018, the Group commissioned DeGolyer and MacNaughton
("D&M") to prepare an updated assessment of the remaining
reserves and resources at the MEX-GOL and SV fields as at 31
December 2017, in order to update the Group's reserves and
resources since the previous reserves estimation undertaken by ERC
Equipoise Limited ("ERCE") as at 31 December 2013.
D&M's report estimated the Proved (1P) reserves at 27.8
MMboe and the Proved + Probable (2P) reserves at 50.0 MMboe as at
31 December 2017, showing a material increase in these categories
of remaining reserves from the ERCE 2013 estimates, which were 1.9
MMboe and 11.7 MMboe respectively. These increases reflect a higher
level of confidence in the understanding of the subsurface at the
fields as a result of the re-evaluation study and new data obtained
since 2013, which has led to a revision of the development plan for
the fields, including an increase in the number of new wells (from
10 to 24) and an acceleration of the phasing of these new
wells.
Further details of the D&M assessment are set out in the
Company's announcement dated 31 July 2018.
Outlook
During 2019, the Group will continue to develop the MEX-GOL, SV
and VAS fields. At the MEX-GOL and SV fields, the development
programme includes revision of the geological model utilising the
newly interpreted reprocessed seismic data, completing the drilling
of the new development well, MEX-119, which was spudded in February
2019 and is designed to accelerate production from the B-20 Visean
reservoirs in the MEX-GOL field, commencement of a new well in the
SV field, planning for a further well in the SV field,
investigating workover opportunities for other existing wells,
installation of compression equipment, further upgrading of the gas
processing facilities and pipeline network, and remedial and
upgrade work on existing wells, pipelines and other
infrastructure.
At the VAS field, the processing and interpreting of the new 3D
seismic data will be completed, a new geological model will be
developed, and planning for a new well will be undertaken. It is
also intended to undertake further evaluation of the VED area of
the licence, which appears highly prospective on the current 2D
seismic data and will benefit from the improved imaging of the new
3D seismic data. Work is also planned to install compression
equipment, and upgrade the gas processing facilities, pipeline
network and other infrastructure.
The Group has also commissioned an updated assessment of the
remaining reserves and resources at the VAS field, which is being
undertaken by D&M. It is anticipated that the updated reserves
and resources assessment will be completed in mid-2019.
There has also been encouraging new legislation relating to the
oil and gas sector in Ukraine, demonstrating the Ukrainian
Government's stated intention to promote and support the domestic
oil and gas production industry. These new measures include
reductions in the subsoil taxes applicable to the production of
hydrocarbons, which became effective for gas production from new
wells drilled after 1 January 2018 and came into effect for
condensate production from all wells from 1 January 2019.
Furthermore, new legislation was introduced earlier this year to
simplify a number of the regulatory procedures relating to oil and
gas exploration and production activities in Ukraine.
These measures, and the general improvement in the business
climate in Ukraine, are encouraging and supportive of the
independent oil and gas producers in Ukraine.
Finally, I would like to add my thanks to all of our staff for
the continued hard work and dedication they have shown over what
has been a very successful year for the Group.
Sergii Glazunov
Chief Executive Officer
Overview of Assets and Reserves
Assets
1. MEX-GOL and SV fields
Regal Petroleum Corporation Limited (a wholly owned subsidiary
in the Group) holds a 100% working interest in and is the operator
of the MEX-GOL and SV fields. The production licences extend over a
combined area of 269 km(2), approximately 200 km east of Kiev. The
two licences are adjacent and the interests are operated and
managed as one field. The licences were granted in July 2004 and
have a duration of 20 years.
The fields are located, geologically, towards the middle of the
Dnieper-Donets sedimentary basin which extends across the majority
of north-east Ukraine. The vast majority of Ukrainian gas and
condensate production comes from this basin. The reservoirs
comprise a series of gently dipping Carboniferous sandstones of
Visean age ("B-Sands") inter-bedded with shales at approximately
4,700 metres below the surface, with a gross thickness between 800
metres and 1,000 metres. Analysis suggests that these deposits
range from fluvial to deltaic in origin, and much of the trapping
at these fields is stratigraphic in nature. Below these reservoirs
is a thick sequence of shale above deeper, similar, sandstones
which are encountered at a depth of around 5,800 metres. These
sands are of Tournasian age ("T-Sands") and may offer additional
gas potential. Deeper sandstones of Devonian age ("D-Sands") have
also been penetrated in the fields.
2. VAS field
LLC Prom-Enerho Produkt (a wholly owned subsidiary in the Group)
holds a 100% working interest in and is the operator of the VAS
field. The production licence extends over an area of 33.2 km(2)
and is located approximately 17 km south-east of Kharkiv. The
licence was granted in August 2012 and has a duration of 20
years.
The field is also located, geologically, towards the middle of
the Dnieper-Donets sedimentary basin in the north-east of Ukraine.
The field is trapped in an anticlinal structure broken into several
faulted blocks, which are gently dipping to the north, stretching
from the north-east to south-west along a main bounding fault. The
gas is located in Carboniferous sandstones of Bashkirian,
Serpukhovian and Visean age at depths of 2,900 - 3,400 metres below
the surface.
Reserves
1. MEX-GOL and SV fields
The Group's estimates of the remaining Reserves and Resources at
the MEX-GOL and SV licence areas are derived from an assessment
undertaken by independent petroleum consultants, DeGolyer and
MacNaughton ("D&M"), as at 31 December 2017 (the "D&M
Report"), which was announced on 31 July 2018. During the period
from 1 January 2018 to 31 December 2018, the Group has produced 1.0
MMboe from these fields.
The D&M Report estimated the remaining Reserves as at 31
December 2017 in the MEX-GOL and SV fields as follows:-
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 D&M 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 independent petroleum
consultants, Senergy (GB) Limited, as at 1 January 2016 (the
"Senergy Report"), which was announced on 5 July 2016. During the
period from 1 January 2016 to 31 December 2018, 0.7 MMboe were
produced from the field.
The Senergy Report estimates the remaining Reserves as at 1
January 2016 in the VAS field as follows:-
Proved Proved + Probable Proved + Probable
(1P) (2P) + Possible (3P)
Gas 91.5 MMm(3) 251.5 MMm(3) 448.6 MMm(3)
------------ ------------------ ------------------
6.90 Mtonne 19.0 Mtonne 33.82 Mtonne
Condensate
------------ ------------------ ------------------
0.66 MMboe 1.80 MMboe 3.21 MMboe
Total
------------ ------------------ ------------------
The Senergy Report estimates the Contingent Resources as at 1
January 2016 in the VAS field as follows:-
Contingent Resources Contingent Resources Contingent Resources
(1C) (2C) (3C)
Gas 153.0 MMm(3) 280.3 MMm(3) 515.4 MMm(3)
--------------------- --------------------- ---------------------
Condensate 6.3 Mm(3) 11.4 Mm(3) 20.7 Mm(3)
--------------------- --------------------- ---------------------
Total 158.6 MMm(3) 294.5 MMm(3) 538.0 MMm(3)
--------------------- --------------------- ---------------------
The Senergy Report estimates the Prospective Resources as at 1
January 2016 in the VED prospect as follows:-
Low Best High Mean
Gas and
Condensate 441.8 MMm(3) 1,078.9 MMm(3) 2,582.6 MMm(3) 1,234.7 MMm(3)
------------- --------------- --------------- ---------------
Finance Review
The Group achieved a very strong financial performance during
2018, with a significantly improved net profit of $54.3 million
(2017: $2.3 million) during the year ended 31 December 2018, mainly
as a result of improved revenue from combined higher production
volumes and hydrocarbon prices, and a significant reversal of an
impairment of the Group's oil and gas development and production
assets of $36.1 million as a result of the reassessment of the
remaining reserves and resources at the MEX-GOL and SV fields as at
31 December 2017, which was a one-off item.
Gross profit for the year ended 31 December 2018 more than
trebled to at $34.2 million (2017: $10.8 million), predominantly as
a result of higher production volumes and hydrocarbons prices, and
a decrease in the depreciation charge arising from the revision of
the depletion calculation following the positive re-assessment of
the Group's reserves at the MEX-GOL and SV fields as at 31 December
2017, which took place during the year.
During 2018, there was a significant reversal of an impairment
of the Group's oil and gas assets of $36.1 million. The amount of
the reversal was determined as $39.8 million, being the total
amount of the previous impairment accumulated on the MEX-GOL and SV
fields up to 30 June 2018, net of depreciation, that would have
been incurred had the fields not been previously impaired, less
$3.7 million of previous impairment allowance for the SV-69 well.
The Group did not reverse the previous impairment allowance
relating to the SV-69 well for the reasons explained in Note 4 to
the financial statements, and additionally the Group impaired the
remaining carrying value of this well to nil on the individual
basis and recorded the respective impairment loss of $1.6 million
as an expense during the year.
The reversal of impairment of the Group's oil and gas assets
also led to a consequential reversal of impairment of intra-group
loans of $10.9 million in the Company's financial statements as a
result of an increase in the present value of estimated future cash
flows following the reassessment of the carrying value of the
Group's oil and gas assets.
Revenue for the year, derived from the sale of the Group's
Ukrainian gas, condensate and LPG production, was also
significantly higher at $66.1 million (2017: $35.1 million).
Similarly, cash generated from operations during the year was much
higher at $36.8 million (2017: $18.0 million) as a result of higher
production volumes and hydrocarbon prices.
The average realised gas, condensate and LPG prices during the
2018 year were $312/Mm(3) (UAH8,528/Mm(3) ), $72/bbl and $64/bbl
respectively (2017: $241/Mm(3) (UAH6,412/Mm(3) ), $67/bbl and
$56/bbl respectively).
During the period from 1 January 2019 to 25 April 2019, the
average realised gas, condensate and LPG prices were $279/Mm(3)
(UAH7,597/Mm(3) ), $52/bbl and $47/bbl respectively. The current
realised gas price is $287/Mm(3) (UAH7,712/Mm(3) ).
Since the deregulation of the gas supply market in Ukraine in
October 2015, the market price for gas has broadly correlated to
the price of imported gas, which generally reflects trends in
European gas prices. Gas prices are also subject to seasonal
variation. During the 2018 year, gas prices were reasonably stable,
allowing for some seasonal variation, and were higher than in 2017,
as were condensate and LPG prices by comparison with 2017.
The subsoil tax rates applicable to gas and condensate
production were stable during the year at 29% for gas produced from
deposits at depths above 5,000 metres and 14% for gas produced from
deposits below 5,000 metres, and 45% for condensate produced from
deposits above 5,000 metres and 21% for condensate produced from
deposits below 5,000 metres.
However, new subsoil rates have been implemented, under which
(i) for new wells drilled after 1 January 2018, the subsoil tax
rates were reduced from 29% to 12% for gas produced from deposits
at depths above 5,000 metres and from 14% to 6% for gas produced
from deposits below 5,000 metres for the period between 2018 and
2022, and (ii) with effect from 1 January 2019 and applicable to
all wells, the subsoil tax rates for condensate were reduced from
45% to 31% for condensate produced from deposits above 5,000 metres
and from 21% to 16% for condensate produced from deposits below
5,000 metres.
In addition, with effect from 1 January 2019, a transmission
tariff of UAH91.87/Mm(3) ($3.23/Mm(3) ) for use of the Ukrainian
national pipeline system became applicable to oil and gas producers
in Ukraine, including the Group.
Cost of sales for the year ended 31 December 2018 was higher at
$31.9 million (2017: $24.3 million), mainly due to higher
production of hydrocarbons resulting in higher production taxes and
lease expenses relating to the profit share in respect of the SV-2
and SV-12 wells, offset by a decrease in the depreciation charge
arising from the revision of the depletion calculation following
the re-assessment of the Group's reserves at the MEX-GOL and SV
fields as at 31 December 2017, which took place during the
year.
Administrative expenses for the year were slightly higher at
$5.7 million (2017: $5.3 million), primarily as a result of an
increase in payroll and related taxes.
The tax charge for the year of $12.5 million (2017: $4.3 million
charge) comprises a current tax charge of $6.5 million (2017: $3.0
million charge) and a deferred tax charge of $6.0 million (2017:
$1.3 million charge). A significant deferred tax charge was
incurred in the year as a result of the reversal of the impairment
of the carrying value of the Group's MEX-GOL and SV development and
production asset, and the reversal of the impairment of intra-group
loans receivable by the Company.
The Group has recognised a deferred tax asset of $3.3 million at
31 December 2018 (31 December 2017: $9.3 million). This comprises a
deferred tax asset of $2.1 million (31 December 2017: $2.6 million)
in relation to UK tax losses carried forward, and $1.2 million (31
December 2017: $0.1 million) which is recognised on the tax effects
of the temporary differences of the provision for decommissioning
and the carrying value of the Group's oil and gas development and
production assets, and their tax bases.
A deferred tax liability relating to the development and
production asset at the VAS field of $0.5 million (31 December
2017: $0.8 million) was recognised at 31 December 2018 on the tax
effect of the temporary differences between the carrying value of
the development and production asset at the VAS field, and its tax
base.
Increased capital investment of $9.6 million reflects investment
in the Group's oil and gas development and production assets during
the year (2017: $4.0 million), primarily relating to the
expenditure associated with the drilling of the VAS-10 well.
Cash and cash equivalents held at 31 December 2018 were $53.2
million (31 December 2017: $14.2 million cash and cash equivalents
and $16.0 million other short-term investments). The Group's cash
and cash equivalents balance at 25 April 2019 was $54.2 million,
held as to $24.2 million equivalent in Ukrainian Hryvnia and the
balance of $30.0 million equivalent predominantly in US Dollars,
Euros and Pounds Sterling.
Since early 2014, the Ukrainian Hryvnia has devalued
significantly against the US Dollar, falling from UAH8.3/$1.00 on 1
January 2014 to UAH27.7/$1.00 on 31 December 2018, which resulted
in substantial foreign exchange translation losses for the Group
over that period, and in turn adversely impacted the carrying value
of the MEX-GOL and SV asset due to the translation of two of the
Group's subsidiaries from their functional currency of Ukrainian
Hryvnia to the Group's presentation currency of US Dollars. However
in 2018, the exchange rate between the Ukrainian Hryvnia and the US
Dollar has been reasonably stable averaging UAH27.2/$1.00 during
the period (average rate during 2017: UAH26.6/$1.00). Nevertheless,
further devaluation of the Ukrainian Hryvnia against the US Dollar
may affect the carrying value of the Group's assets in the
future.
Cash from operations has funded the capital investment during
the year, and the Group's current cash position and positive
operating cash flow are the sources from which the Group plans to
fund the development programmes for its assets in 2019.
The Group manages its revenue, cash from operations and
production volumes as key performance indicators. The achieved
results for 2018 were as follows:
-- revenue of $66.1 million (2017: $35.1 million)
-- cash from operations of $36.8 million (2017: $18.0 million)
-- daily production volumes from the MEX-GOL and SV fields for the year of 341,216 m(3)/d
of gas, 70 m(3)/d of condensate and 36 m(3)/d of LPG (2,717 boepd in aggregate) (2017:
197,961 m(3) /d of gas, 47 m(3) /d of condensate and 24 m(3)/d of LPG (1,629 boepd in
aggregate))
-- daily production volumes from the VAS field for the year of 94,752 m(3)/d of gas and
8.2 m(3)/d of condensate (674 boepd in aggregate) (2017: 86,010 m(3) /d of gas and 6.5
m(3) /d of condensate (606 boepd in aggregate))
-- aggregate production volumes from the MEX-GOL and SV fields for the year of 124,534,684
m(3) of gas, 25,414 m(3) of condensate and 13,052 m(3) of LPG, equating to a combined
total oil equivalent of 991,611 boe (2017: 72,255,906 m(3) of gas, 17,014 m(3) of condensate
and 8,763 m(3) of LPG (594,577 boe in aggregate))
-- aggregate production volumes from the VAS field for the year of 34,584,524 m(3) of gas
and 2,995 m(3) of condensate, equating to a combined total oil equivalent of 246,070
boe (2017: 31,393,518 m(3) of gas and 2,374 m(3) of condensate (221,202 boe in aggregate)).
Principal Risks and Uncertainties
The Group has a risk evaluation methodology in place to assist
in the review of the risks across all material aspects of its
business. This methodology highlights external, operational and
technical, financial and corporate risks and assesses the level of
risk and potential consequences. It is periodically presented to
the Audit Committee and the Board for review, to bring to their
attention potential risks and, where possible, propose mitigating
actions. Key risks recognised and mitigation factors are detailed
below:-
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 some recent improvements,
from the International Monetary the Ukrainian banking sector remains
Fund under a 14-month Stand-By weakly capitalised and so the risks
Arrangement aggregating $3.9 billion associated with the banks in Ukraine
approved in December 2018, which remain significant, including in
replaced a previous funding programme relation to the banks with which
from the International Monetary the Group operates bank accounts.
Fund. An initial tranche of $1.4 As a consequence, the Group also
billion has been disbursed, and maintains a significant proportion
the disbursement of further tranches of its cash holdings in international
is dependent on semi-annual reviews banks outside Ukraine.
of the status of fiscal, economic
and regulatory reforms in 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.
-----------------------------------------------
Operational and technical risks
-----------------------------------------------
Health, Safety, Environment and
Security ("HSES")
-----------------------------------------------
The oil and gas industry, by its The Group maintains an HSES management
nature, conducts activities which system and requires that management,
can cause health, safety, environmental staff and contractors adhere to
and security incidents. Serious this system. The system ensures
incidents can not only have a financial that 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.
-----------------------------------------------
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 has 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, although it costs are largely matched. In light
was relatively stable during 2018. of the previous devaluation and
This devaluation was a significant volatility of the Ukrainian Hryvnia
contributor to the imposition of against major world currencies,
the banking restrictions by the and since the Ukrainian Hryvnia
National Bank of Ukraine over recent does not benefit from the range
years. In addition, the geopolitical of currency hedging instruments
events in Ukraine over recent years, which are available in more developed
are likely to continue to impact economies, the Group has adopted
the valuation of the Ukrainian a policy that, where possible, funds
Hryvnia against major world currencies. not required for use in Ukraine
Further devaluation of the Ukrainian be retained on deposit in the United
Hryvnia against the US Dollar will Kingdom, principally in US Dollars.
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 mostly in US Dollars, with reputable
Ukrainian Hryvnia, high inflation financial institutions. The financial
and interest rates, and increased status of counterparties is carefully
credit risk relating to the Group's monitored to manage counterparty
key counterparties. 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, these licences carry
ongoing compliance obligations,
which if not met, may lead to the
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
2018 2017
Note $000 $000
Revenue 6 66,098 35,053
Cost of sales 7 (31,875) (24,272)
--------------------------------------------- ---- -------- --------
Gross profit 34,223 10,781
Administrative expenses 8 (5,709) (5,311)
Reversal of impairment/(impairment) of
property, plant and equipment 17 34,469 (180)
Other operating gains, (net) 11 3,387 1,109
--------------------------------------------- ---- -------- --------
Operating profit 66,370 6,399
Finance income 12 641 383
Finance costs 13 (140) (112)
Net impairment (losses) / gains on financial
assets 60 (31)
Other losses (net) (140) (50)
--------------------------------------------- ---- -------- --------
Profit before taxation 66,791 6,589
Income tax expense 14 (12,485) (4,301)
--------------------------------------------- ---- -------- --------
Profit for the year 54,306 2,288
--------------------------------------------- ---- -------- --------
Earnings per share (cents)
Basic and diluted 16 16.9c 0.7c
--------------------------------------------- ---- -------- --------
The Notes set out below are an integral part of these
consolidated financial statements.
Consolidated Statement of Comprehensive Income
2018 2017
$000 $000
Profit for the year 54,306 2,288
Other comprehensive expense:
Items that may be subsequently reclassified
to profit or loss:
Equity - foreign currency translation (1,329) (1,247)
Items that will not be subsequently reclassified
to profit or loss:
Re-measurements of post-employment benefit
obligations (142) (1)
Total other comprehensive expense (1,471) (1,248)
Total comprehensive income for the year 52,835 1,040
-------------------------------------------------- ------- -------
Company Statement of Comprehensive Income
Note 2018 2017
$000 $000
Profit for the year 15 12,057 12,239
---------------------------------------- ---- ------ ------
Total comprehensive income for the year 12,057 12,239
---------------------------------------- ---- ------ ------
The Notes set out below are an integral part of these
consolidated financial statements.
Consolidated Balance Sheet
2018 2017
Note $000 $000
Assets
Non-current assets
Property, plant and equipment 17 50,192 14,962
Intangible assets 18 4,880 5,590
Corporation tax receivable 27 37
Deferred tax asset 25 3283 9,261
------------------------------ ---- --------- ---------
58,382 29,850
Current assets
Inventories 20 1,605 1,394
Trade and other receivables 21 10,130 6,536
Other short-term investments 22 - 16,000
Cash and cash equivalents 22 53,222 14,249
------------------------------ ---- --------- ---------
64,957 38,179
Total assets 123,339 68,029
------------------------------ ---- --------- ---------
Liabilities
Current liabilities
Trade and other payables 23 (4,836) (2,423)
Corporation tax payable (1,297) (1,116)
(6,133) (3,539)
Net current assets 58,824 34,640
------------------------------ ---- --------- ---------
Non-current liabilities
Provision for decommissioning 24 (3,137) (3,027)
Defined benefit liability (468) (275)
Deferred tax liability 25 (504) (820)
(4,109) (4,122)
Total liabilities (10,242) (7,661)
------------------------------ ---- --------- ---------
Net assets 113,097 60,368
------------------------------ ---- --------- ---------
Equity
Called up share capital 26 28,115 28,115
Share premium account 555,090 555,090
Foreign exchange reserve 27 (102,261) (100,932)
Other reserves 27 4,273 4,273
Accumulated losses (372,120) (426,178)
Total equity 113,097 60,368
------------------------------ ---- --------- ---------
The Notes set out below are an integral part of these
consolidated financial statements.
Consolidated Statement of Changes in Equity
Called Share Capital Foreign
up share premium Merger contributions exchange Accumulated
capital account reserve reserve reserve* losses Total equity
$000 $000 $000 $000 $000 $000 $000
As at 1 January
2017 28,115 555,090 (3,204) 7,477 (99,684) (428,466) 59,328
Profit for the
year - - - - - 2,288 2,288
Other
comprehensive
expense
- exchange
differences - - - - (1,247) - (1,247)
-
re-measurements
of
post-employment
benefit
obligations - - - - (1) - (1)
----------------- --------------- -------- -------- -------------- -------------- -------------- ------------
Total
comprehensive
income/(expense) - - - - (1,248) 2,288 1,040
----------------- --------------- -------- -------- -------------- -------------- -------------- ------------
As at 31 December
2017 28,115 555,090 (3,204) 7,477 (100,932) (426,178) 60,368
----------------- --------------- -------- -------- -------------- -------------- -------------- ------------
Called Share Capital Foreign
up share premium Merger contributions exchange Accumulated
capital account reserve reserve reserve* losses Total equity
$000 $000 $000 $000 $000 $000 $000
As at 1 January
2018 28,115 555,090 (3,204) 7,477 (100,932) (426,178) 60,368
Change in
accounting
policy (Note 5) - - - - - (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
2018 28,115 555,090 (3,204) 7,477 (102,261) (372,120) 113,097
----------------- --------------- -------- -------- -------------- -------------- -------------- ------------
* 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
2018 2017
Note $000 $000
Operating activities
Cash generated from operations 29 36,342 17,982
Equipment rental income 8 -
Income tax paid (6,316) (2,133)
Interest received 3,038 906
----------------------------------------------------- ---- -------- --------
Net cash inflow from operating activities 33,072 16,755
----------------------------------------------------- ---- -------- --------
Investing activities
Purchase of property, plant and equipment (10,001) (6,151)
Purchase of intangible assets (95) (121)
Proceeds from sale of property, plant and equipment 74 8
Proceeds from disposal/(acquisition) of other
short-term investments 22 16,000 (16,000)
----------------------------------------------------- ---- -------- --------
Net cash inflow/(outflow) from investing activities 5,978 (22,264)
----------------------------------------------------- ---- -------- --------
Net increase/(decrease) in cash and cash equivalents 39,050 (5,509)
Cash and cash equivalents at beginning of year 14,249 19,966
Change in accounting policies 5 (9) -
ECL of cash and cash equivalents (13) -
Effect of foreign exchange rate changes (55) (208)
Cash and cash equivalents at end of year 22 53,222 14,249
----------------------------------------------------- ---- -------- --------
The Notes set out below are an integral part of these
consolidated financial statements.
Notes forming part of the financial statements
1. Statutory Accounts
The financial information set out above does not constitute the
Company's statutory accounts for the year ended 31 December 2018 or
2017, but is derived from those accounts. The Auditor has reported
on those accounts, and its reports were unqualified and did not
contain statements under sections 498(2) or (3) of the Companies
Act 2006.
The statutory accounts for 2018 will be delivered to the
Registrar of Companies following the Company's Annual General
Meeting.
While the financial information included in this preliminary
announcement has been prepared in accordance with International
Financial Reporting Standards as adopted by the European Union
("IFRS"), this announcement does not itself contain sufficient
information to comply with IFRS. The Company expects to distribute
the full financial statements that comply with IFRS in May/June
2019.
2. General Information and Operational Environment
Regal Petroleum plc (the "Company") and its subsidiaries (the
"Group") is a gas, condensate and LPG production group.
The Company is a public limited company quoted on the AIM Market
of London Stock Exchange plc and incorporated in England and Wales
under the Companies Act 2006. The Company's registered office is at
16 Old Queen Street, London, SW1H 9HP, United Kingdom and its
registered number is 4462555. The principal activities of the Group
and the nature of the Group's operations are set out in the
Directors' Report.
As of 31 December 2017 the Company's immediate parent company
was Energees Management Limited, which is 100% owned by Pelidona
Services Limited. On 11 December 2018, Energees Management Limited
transferred 100% of its shares in the Company to Pelidona Services
Limited. As at 31 December 2018, the Company's immediate parent
company was Pelidona Services Limited, which is 100% owned by
Lovitia Investments Limited, which is 100% owned by Mr V Novynskyi.
Accordingly, the Company was ultimately controlled by Mr V
Novynskyi.
The Group's gas, condensate and LPG extraction and production
facilities are located in Ukraine. The ongoing political and
economic instability in Ukraine, which commenced in late 2013, has
led to a deterioration of Ukrainian State finances, volatility of
financial markets, illiquidity on capital markets, higher inflation
and a depreciation of the national currency against major foreign
currencies, although there have been some gradual improvements
recently.
The Ukrainian economy is showing signs of stabilisation after
the previous years of political and economic tensions. The
year-on-year inflation rate in Ukraine decreased to 9.8% during
2018 (as compared to 13.7% in 2017), while GDP grew at 3.3% (after
2% growth in 2017).
The National Bank of Ukraine ("NBU") continued its inflation
targeting policy and periodically raised its key policy rate from
12.5% in May 2017 to 18% in September 2018. This has helped
restrain inflation below 10%, although the cost of domestic funding
has increased significantly. The NBU adhered to a floating
Ukrainian Hryvnia exchange rate, which finished the 2018 year at
UAH27.69/$1.00, compared to UAH28.07/$1.00 as at 31 December 2017.
Among the key mitigating factors for the relative stability of the
Ukrainian Hryvnia were the agreement on the International Monetary
Fund ("IMF") programme, strong revenues of agricultural exporters,
tight Ukrainian Hryvnia liquidity and a growth in remittances from
labour migrants.
In December 2018, the IMF approved a 14-month Stand-By
Arrangement ("SBA") programme for Ukraine, totalling $3.9 billion.
In December 2018, Ukraine received $2 billion from the IMF and the
European Union ("EU"), as well as $750 million credit guarantees
from the World Bank. The approval of the IMF programme
significantly increases the chance of Ukraine meeting its foreign
currency obligations in 2019, and thus will support the financial
and macroeconomic stability of the country. The IMF will decide on
further tranches in May and November 2019, depending on Ukraine's
success in fulfilling the terms of the Memorandum on Economic and
Financial Policies, which Ukraine plans to follow during the SBA
programme's implementation.
In 2019-2020, Ukraine faces major public debt repayments, which
will require the arrangement of substantial domestic and external
financing in an increasingly challenging financing environment for
emerging markets. In addition, presidential elections held in March
and April 2019 resulted in the election of a new President, and
parliamentary elections are scheduled for October 2019. As a
consequence of these elections, a degree of political uncertainty
will remain for the foreseeable future. Despite certain
improvements in 2018, the outcome of these matters and the ongoing
effects of the political and economic situation are difficult to
predict, but they may have further severe effects on the Ukrainian
economy and the Group's business.
Further details of risks relating to Ukraine can be found within
the Principal Risks and Uncertainties section of the Strategic
Report.
3. Accounting Policies
The principal accounting policies applied in the preparation of
these consolidated financial statements are set out below. These
policies have been consistently applied to all the years presented,
unless otherwise stated.
Basis of Preparation
The Group has prepared its consolidated financial statements and
the Company's financial statements under International Financial
Reporting Standards ("IFRSs") and interpretations issued by the
IFRS Interpretations Committee ("IFRS IC"), as adopted by the
European Union. The financial statements have been prepared in
accordance with the Companies Act 2006 as applicable to companies
using IFRS. The principal accounting policies applied in the
preparation of the consolidated financial statements are set out
below. Apart from the accounting policy changes resulting from the
adoption of IFRS 9 and IFRS 15 effective from 1 January 2018, these
policies have been consistently applied to all the periods
presented, unless otherwise stated (refer to Notes 5 and 34). The
principal accounting policies in respect of financial instruments
and revenue recognition applied until 31 December 2017 are
presented in Note 34.
The preparation of financial statements in conformity with IFRS
requires the use of certain critical accounting estimates. It also
requires management to exercise its judgement in the process of
applying the Group's accounting policies. The areas involving a
higher degree of judgement or complexity, or areas where
assumptions and estimates are significant to the consolidated
financial statements are disclosed in Note 4.
Going Concern
Based on the positive operational and financial performance of
the Group and for the reasons outlined in the Principal Risks and
Uncertainties section of the Strategic Report, the Directors have a
reasonable expectation that the Group has adequate resources to
continue in operational existence for the foreseeable future
regarded as at least 12 months after the date of signing of these
financial statements. Accordingly, the going concern basis has been
adopted in preparing its consolidated financial statements and the
Company's financial statements for the year ended 31 December 2018.
The use of this basis of accounting takes into consideration the
Company's and the Group's current and forecast financing position,
additional details of which are provided in the Principal Risks and
Uncertainties section of the Strategic Report. The Group does not
foresee any positive or negative impact on its operations as a
result of the ongoing Brexit negotiations or any outcome from those
negotiations.
New and amended standards adopted by the Group
The Group has applied the following new and revised standards
and interpretations for the first time for its annual reporting
period commencing 1 January 2018. The Group had to change its
accounting policies as a result of adopting the following
standards:
-- IFRS 9 Financial Instruments;
-- IFRS 15 Revenue from contracts with customers.
The impact of the adoption of these standards and the new
accounting policies are disclosed in Note 5 below.
The following amended standards became effective for the Group
from 1 January 2018, but did not have any material impact on the
Group:
-- Amendments to IFRS 2 Share-based Payment (issued on 20 June
2016 and effective for annual periods beginning on or after 1
January 2018).
-- Amendments to IFRS 4 - Applying IFRS 9 Financial Instruments
with IFRS 4 Insurance Contracts (issued on 12 September 2016 and
effective, depending on the approach, for annual periods beginning
on or after 1 January 2018 for entities that choose to apply
temporary exemption option, or when the entity first applies IFRS 9
for entities that choose to apply the overlay approach).
-- Annual Improvements to IFRSs 2014-2016 cycle -- Amendments to
IFRS 1 an IAS 28 (issued on 8 December 2016 and effective for
annual periods beginning on or after 1 January 2018).
-- IFRIC 22 Foreign Currency Transactions and Advance
Consideration (issued on 8 December 2016 and effective for annual
periods beginning on or after 1 January 2018).
-- Amendments to IAS 40 - Transfers of Investment Property
(issued on 8 December 2016 and effective for annual periods
beginning on or after 1 January 2018).
Impact of standards issued but not yet applied by the Group
Certain new accounting standards and interpretations have been
published that are not mandatory for the annual periods beginning
on or after 1 January 2019 or later, and which the Group has not
early adopted. The Group's assessment of the impact of these new
standards and interpretations is set out below.
I) IFRS 16 Leases (issued on 13 January 2016 and effective for
annual periods beginning on or after 1 January 2019)
The new standard sets out the principles for the recognition,
measurement, presentation and disclosure of leases. All leases
result in the lessee obtaining the right to use an asset at the
start of the lease and, if lease payments are made over time, also
obtaining financing. Accordingly, IFRS 16 eliminates the
classification of leases as either operating leases or finance
leases as is required by IAS 17 and, instead, introduces a single
lessee accounting model. Lessees will be required to recognise: (a)
assets and liabilities for all leases with a term of more than 12
months, unless the underlying asset is of low value; and (b)
depreciation of lease assets separately from interest on lease
liabilities in the statement of profit or loss and other
comprehensive income. IFRS 16 substantially carries forward the
lessor accounting requirements in IAS 17. Accordingly, a lessor
continues to classify its leases as operating leases or finance
leases, and to account for those two types of leases
differently.
The Group decided that it will apply the standard from its
mandatory adoption date of 1 January 2019 using the modified
retrospective method, without restatement of comparatives.
Right-of-use assets for property leases are measured on transition
as if the new rules had always applied. All other right-of-use
assets are measured at the amount of the lease liability on
adoption (adjusted for any prepaid or accrued expenses).
As at 31 December 2018, the Group has non-cancellable lease
commitments of $1,884,000. Of these commitments, approximately
$10,000 relate to low values leases and $85,000 to short-term
leases which will both be recognised on a straight-line basis as
expenses in profit or loss, leaving a balance of $1,789,000.
A reconciliation of the operating lease commitments disclosed in
Note 28 to the recognised liability is as follows:
1 January 2019
$000
Group
Total future minimum lease payments for non-cancellable operating leases (Note 28) 1,789
- effect of discounting to present value (667)
----------------------------------------------------------------------------------- --------------
Total lease liabilities 1,122
The Company has only short-term leases in the amount of $85,000
which will be recognised as expenses in profit or loss.
For the remaining lease commitments, the Group expects to
recognise right-of-use assets of approximately $1,122,000 on 1
January 2019, and lease liabilities of $1,122,000 (after
adjustments for prepayments and accrued lease payments recognised
as at 31 December 2018). Overall net current assets will be
approximately $371,000 lower due to the presentation of a portion
of the liability as a current liability. The Group expects that net
profit for the year ending 31 December 2019 will increase by
approximately $64,000 as a result of adopting the new rules.
Operating cash flows will increase and financing cash flows
decrease by approximately $406,000 as repayment of the principal
portion of the lease liabilities will be classified as cash flows
from financing activities.
II) IFRS 17 Insurance Contracts (issued on 18 May 2017 and
effective for annual periods beginning on or after 1 January
2021)
IFRS 17 replaces IFRS 4, which has given companies dispensation
to carry on accounting for insurance contracts using existing
practices. As a consequence, it was difficult for investors to
compare and contrast the financial performance of otherwise similar
insurance companies. IFRS 17 is a single principle-based standard
to account for all types of insurance contracts, including
reinsurance contracts that an insurer holds. The standard requires
recognition and measurement of groups of insurance contracts at:
(i) a risk-adjusted present value of the future cash flows (the
fulfilment cash flows) that incorporates all of the available
information about the fulfilment cash flows in a way that is
consistent with observable market information; plus (if this value
is a liability) or minus (if this value is an asset), and (ii) an
amount representing the unearned profit in the group of contracts
(the contractual service margin). Insurers will be recognising the
profit from a group of insurance contracts over the period they
provide insurance coverage, and as they are released from risk. If
a group of contracts is or becomes loss-making, an entity will be
recognising the loss immediately.
III) IFRIC 23 "Uncertainty over Income Tax Treatments" (issued
on 7 June 2017 and effective for annual periods beginning on or
after 1 January 2019)
IAS 12 specifies how to account for current and deferred tax,
but not how to reflect the effects of uncertainty. The
interpretation clarifies how to apply the recognition and
measurement requirements in IAS 12 when there is uncertainty over
income tax treatments. An entity should determine whether to
consider each uncertain tax treatment separately or together with
one or more other uncertain tax treatments based on which approach
better predicts the resolution of the uncertainty. An entity should
assume that a taxation authority will examine amounts it has a
right to examine and have full knowledge of all related information
when making those examinations. If an entity concludes it is not
probable that the taxation authority will accept an uncertain tax
treatment, the effect of uncertainty will be reflected in
determining the related taxable profit or loss, tax bases, unused
tax losses, unused tax credits or tax rates by using either the
most likely amount or the expected value, depending on which method
the entity expects to better predict the resolution of the
uncertainty. An entity will reflect the effect of a change in facts
and circumstances or of new information that affects the judgments
or estimates required by the interpretation as a change in
accounting estimate. Examples of changes in facts and circumstances
or new information that can result in the reassessment of a
judgment or estimate include, but are not limited to, examinations
or actions by a taxation authority, changes in rules established by
a taxation authority or the expiry of a taxation authority's right
to examine or re-examine a tax treatment. The absence of agreement
or disagreement by a taxation authority with a tax treatment, in
isolation, is unlikely to constitute a change in facts and
circumstances or new information that affects the judgments and
estimates required by the interpretation.
IV) Prepayment Features with Negative Compensation - Amendments
to IFRS 9 (issued on 12 October 2017 and effective for annual
periods beginning on or after 1 January 2019)
The amendments enable measurement at amortised cost of certain
loans and debt securities that can be prepaid at an amount below
amortised cost, for example at fair value or at an amount that
includes a reasonable compensation payable to the borrower equal to
present value of an effect of increase in market interest rate over
the remaining life of the instrument. In addition, the text added
to the standard's basis for conclusion reconfirms existing guidance
in IFRS 9 that modifications or exchanges of certain financial
liabilities measured at amortised cost that do not result in the
derecognition will result in a gain or loss in profit or loss.
Reporting entities will thus in most cases not be able to revise
the effective interest rate for the remaining life of the loan in
order to avoid an impact on profit or loss upon a loan
modification.
V) Annual Improvements to IFRSs 2015-2017 cycle - amendments to
IFRS 3, IFRS 11, IAS 12 and IAS 23 (issued on 12 December 2017 and
effective for annual periods beginning on or after 1 January
2019)
The narrow scope amendments impact four standards. IFRS 3 was
clarified that an acquirer should re-measure its previously held
interest in a joint operation when it obtains control of the
business. Conversely, IFRS 11 now explicitly explains that the
investor should not re-measure its previously held interest when it
obtains joint control of a joint operation, similarly to the
existing requirements when an associate becomes a joint venture and
vice versa. The amended IAS 12 explains that an entity recognises
all income tax consequences of dividends where it has recognised
the transactions or events that generated the related distributable
profits, e.g. in profit or loss or in other comprehensive
income.
It is now clear that this requirement applies in all
circumstances as long as payments on financial instruments
classified as equity are distributions of profits, and not only in
cases when the tax consequences are a result of different tax rates
for distributed and undistributed profits. The revised IAS 23 now
includes explicit guidance that the borrowings obtained
specifically for funding a specified asset are excluded from the
pool of general borrowings costs eligible for capitalisation only
until the specific asset is substantially complete.
VI) Amendments to IAS 19 "Plan Amendment, Curtailment or
Settlement" (issued on 7 February 2018 and effective for annual
periods beginning on or after 1 January 2019)
The amendments specify how to determine pension expenses when
changes to a defined benefit pension plan occur. When a change to a
plan - an amendment, curtailment or settlement - takes place, IAS
19 requires to remeasure net defined benefit liability or asset.
The amendments require to use the updated assumptions from this
remeasurement to determine current service cost and net interest
for the remainder of the reporting period after the change to the
plan. Before the amendments, IAS 19 did not specify how to
determine these expenses for the period after the change to the
plan. By requiring the use of updated assumptions, the amendments
are expected to provide useful information to users of financial
statements. The Group is currently assessing the impact of the
amendments on its financial statements.
VII) Amendments to the Conceptual Framework for Financial
Reporting (issued on 29 March 2018 and effective for annual periods
beginning on or after 1 January 2020)
The revised Conceptual Framework includes: a new chapter on
measurement; guidance on reporting financial performance; improved
definitions and guidance - in particular the definition of a
liability; and clarifications in important areas, such as the roles
of stewardship, prudence and measurement uncertainty in financial
reporting.
VIII) Definition of a business - Amendments to IFRS 3 (issued on
22 October 2018 and effective for acquisitions from the beginning
of annual reporting period that starts on or after 1 January
2020).
The amendments revise definition of a business. A business must
have inputs and a substantive process that together significantly
contribute to the ability to create outputs. The new guidance
provides a framework to evaluate when an input and a substantive
process are present, including for early stage companies that have
not generated outputs. An organised workforce should be present as
a condition for classification as a business if are no outputs. The
definition of the term "outputs" is narrowed to focus on goods and
services provided to customers, generating investment income and
other income, and it excludes returns in the form of lower costs
and other economic benefits. It is also no longer necessary to
assess whether market participants are capable of replacing missing
elements or integrating the acquired activities and assets. An
entity can apply a "concentration test". The assets acquired would
not represent a business if substantially all of the fair value of
gross assets acquired is concentrated in a single asset (or a group
of similar assets).
IX) Definition of materiality - Amendments to IAS 1 and IAS 8
(issued on 31 October 2018 and effective for annual periods
beginning on or after 1 January 2020)
The amendments clarify the definition of material and how it
should be applied by including in the definition guidance that
until now has featured elsewhere in IFRS. In addition, the
explanations accompanying the definition have been improved.
Finally, the amendments ensure that the definition of material is
consistent across all IFRS Standards. Information is material if
omitting, misstating or obscuring it could reasonably be expected
to influence the decisions that the primary users of general
purpose financial statements make on the basis of those financial
statements, which provide financial information about a specific
reporting entity.
The Group is currently assessing the impact of the
interpretation and amendments on its financial statements.
There are no other IFRSs or IFRIC interpretations that are not
yet effective that would be expected to have a material impact on
the Group in the current or future reporting periods and on
foreseeable future transactions.
Exchange differences on intra-group balances with foreign
operation
The Group has certain inter-company monetary balances of which
the Company is the beneficial owner. These monetary balances are
payable by a subsidiary that is a foreign operation and are
eliminated on consolidation.
In the consolidated financial statements, exchange differences
arising on such payables because the transaction currency differs
from the subsidiary's functional currency are recognised initially
in other comprehensive income if the settlement of such payables is
continuously deferred and is neither planned nor likely to occur in
the foreseeable future.
In such cases, the respective receivables of the Company are
regarded as an extension of the Company's net investment in that
foreign operation, and the cumulative amount of the abovementioned
exchange differences recognised in other comprehensive income is
carried forward within the foreign exchange reserve in equity and
is reclassified to profit or loss only upon disposal of the foreign
operation.
When the subsidiary that is a foreign operation settles its
quasi-equity liability due to the Company, but the Company
continues to possess the same percentage of the subsidiary, i.e.
there has been no change in its proportionate ownership interest,
such settlement is not regarded as a disposal or a partial
disposal, and therefore cumulative exchange differences are not
reclassified.
The designation of inter-company monetary balances as part of
the net investment in a foreign operation is re-assessed when
management's expectations and intentions on settlement change due
to a change in circumstances.
Where, because of a change in circumstances, a receivable
balance, or part thereof, previously designated as a net investment
into a foreign operation is intended to be settled, the receivable
is de-designated and is no longer regarded as part of the net
investment.
In such cases, the exchange differences arising on the
subsidiary's payable following de-designation are recognised within
finance costs / income in profit or loss, similar to foreign
exchange differences arising from financing.
Basis of Consolidation
The consolidated financial statements incorporate the financial
information of the Company and entities controlled by the Company
(and its subsidiaries) made up to 31 December each year.
Subsidiaries
Subsidiaries are all entities (including structured entities)
over which the Group has control. The Group controls an entity when
the Group is exposed to, or has rights to variable returns from its
involvement with the entity and has the ability to affect those
returns through its power over the entity. Subsidiaries are fully
consolidated from the date on which control is transferred to the
Group. They are deconsolidated from the date that control
ceases.
The Group applies the acquisition method to account for business
combinations. The consideration transferred for the acquisition of
a subsidiary is the fair value of the assets transferred, the
liabilities incurred to the former owners of the acquiree and the
equity interests issued by the Group. The consideration transferred
includes the fair value of any asset or liability resulting from a
contingent consideration arrangement. Identifiable assets acquired
and liabilities and contingent liabilities assumed in a business
combination are measured initially at their fair values at the
acquisition date. The Group recognises any non-controlling interest
in the acquiree on an acquisition-by-acquisition basis at the
non-controlling interest's proportionate share of the recognised
amounts of the acquiree's identifiable net assets.
Acquisition-related costs are expensed as incurred.
If the business combination is achieved in stages, the
acquisition date carrying value of the acquirer's previously held
equity interest in the acquiree is re-measured to fair value at the
acquisition date; any gains or losses arising from such
re-measurement are recognised in profit or loss.
Any contingent consideration to be transferred by the Group is
recognised at fair value at the acquisition date. Subsequent
changes to the fair value of the contingent consideration that is
deemed to be an asset or liability is recognised in accordance with
IFRS 9 in profit or loss.
Inter-company transactions, balances and unrealised gains on
transactions between Group companies are eliminated. Unrealised
losses are also eliminated. When necessary, amounts reported by
subsidiaries have been adjusted to conform with the Group's
accounting policies.
Segment reporting
The Group's only class of business activity is oil and gas
exploration, development and production. The Group's primary
operations are located in Ukraine, with its head office in the
United Kingdom. The geographical segments are the basis on which
the Group reports its segment information to management. Operating
segments are reported in a manner consistent with the internal
reporting provided to the Board of Directors.
Commercial Reserves
Proved and probable oil and gas reserves are estimated
quantities of commercially producible hydrocarbons which the
existing geological, geophysical and engineering data show to be
recoverable in future years from known reservoirs. Proved reserves
are those quantities of petroleum that, by analysis of geoscience
and engineering data, can be estimated with reasonable certainty to
be commercially recoverable from known reservoirs and under defined
technical and commercial conditions. Probable reserves are those
additional reserves which analysis of geoscience and engineering
data indicate are less likely to be recovered than proved reserves
but more certain to be recovered than possible reserves. The proved
and probable reserves conform to the definition approved by the
Petroleum Resources Management System.
Oil and Gas Exploration/Evaluation and Development/Production
Assets
The Group applies the successful efforts method of accounting
for oil and gas assets, having regard to the requirements of IFRS 6
"Exploration for and Evaluation of Mineral Resources".
Exploration costs are incurred to discover hydrocarbon
resources. Evaluation costs are incurred to assess the technical
feasibility and commercial viability of the resources found.
Exploration, as defined in IFRS 6 'Exploration and evaluation of
mineral resources', starts when the legal rights to explore have
been obtained. Expenditure incurred before obtaining the legal
right to explore is generally expensed; an exception to this would
be separately acquired intangible assets such as payment for an
option to obtain legal rights.
Expenditures incurred in exploration activities should be
expensed unless they meet the definition of an asset. An entity
recognises an asset when it is probable that economic benefits will
flow to the entity as a result of the expenditure. The economic
benefits might be available through commercial exploitation of
hydrocarbon reserves or sales of exploration findings or further
development rights. Exploration and evaluation ("E&E") assets
are recognised within property, plant and equipment in single field
cost centres.
The capitalisation point is the earlier of:
(a) the point at which the fair value less costs to sell of the
property can be reliably determined as higher than the total of the
expenses incurred and costs already capitalised (such as licence
acquisition costs); and
(b) an assessment of the property demonstrates that commercially
viable reserves are present and hence there are probable future
economic benefits from the continued development and production of
the resource.
E&E assets are reclassified from Exploration and Evaluation
when evaluation procedures have been completed. E&E assets that
are not commercially viable are written down. E&E assets for
which commercially viable reserves have been identified are
reclassified to Development and Production assets. E&E assets
are tested for impairment immediately prior to reclassification out
of E&E.
Once an E&E asset has been reclassified from E&E, it is
subject to the normal IFRS requirements. This includes impairment
testing at the cash-generating unit ("CGU") level and
depreciation.
Abandonment and Retirement of Individual Items of Property,
Plant and Equipment
Normally, no gains or losses shall be recognised if only an
individual item of equipment is abandoned or retired or if only a
single lease or other part of a group of proved properties
constituting the amortisation base is abandoned or retired as long
as the remainder of the property or group of properties
constituting the amortisation base continues to produce oil or gas.
Instead, the asset being abandoned or retired shall be deemed to be
fully amortised, and its costs shall be charged to accumulated
depreciation, depletion or amortisation. When the last well on an
individual property (if that is the amortisation base) or group of
properties (if amortisation is determined on the basis of an
aggregation of properties with a common geological structure)
ceases to produce and the entire property or group of properties is
abandoned, a gain or loss shall be recognised. Occasionally, the
partial abandonment or retirement of a proved property or group of
proved properties or the abandonment or retirement of wells or
related equipment or facilities may result from a catastrophic
event or other major abnormality. In those cases, a loss shall be
recognised at the time of abandonment or retirement.
Intangible Assets other than Oil and Gas Assets
Intangible assets other than oil and gas assets are stated at
cost less accumulated amortisation and any provision for
impairment. These assets represent exploration licences.
Amortisation is charged so as to write off the cost, less estimated
residual value on a straight-line basis of 20-25% per annum.
Depreciation, Depletion and Amortisation
All expenditure carried within each field is amortised from the
commencement of commercial production on a unit of production
basis, which is the ratio of gas production in the period to the
estimated quantities of commercial reserves at the end of the
period plus the production in the period, generally on a field by
field basis. In certain circumstances, fields within a single
development area may be combined for depletion purposes. Costs used
in the unit of production calculation comprise the net book value
of capitalised costs plus the estimated future field development
costs necessary to bring the reserves into production.
Impairment
At each balance sheet date, the Group reviews the carrying
amount of oil and gas development and production assets to
determine whether there is any indication that those assets have
suffered an impairment loss. This includes exploration and
appraisal costs capitalised which are assessed for impairment in
accordance with IFRS 6. If any such indication exists, the
recoverable amount of the asset is estimated in order to determine
the extent of the impairment loss.
For oil and gas development and production assets, the
recoverable amount is the greater of fair value less costs to
dispose and value in use. In assessing value in use, the estimated
future cash flows are discounted to their present value using an
expected weighted average cost of capital. If the recoverable
amount of an asset is estimated to be less than its carrying
amount, the carrying amount of the asset is reduced to its
recoverable amount. Impairment losses are recognised as an expense
immediately.
Should an impairment loss subsequently reverse, the carrying
amount of the asset is increased to the revised estimate of its
recoverable amount, but so that the increased carrying amount does
not exceed the carrying amount that would have been determined had
no impairment loss been recognised for the asset in prior years. A
reversal of an impairment loss is recognised as income
immediately.
Decommissioning Provision
Where a material liability for the removal of existing
production facilities and site restoration at the end of the
productive life of a field exists, a provision for decommissioning
is recognised. The amount recognised is the present value of
estimated future expenditure determined in accordance with local
conditions and requirements. The cost of the relevant property,
plant and equipment is increased with an amount equivalent to the
provision and depreciated on a unit of production basis. Changes in
estimates are recognised prospectively, with corresponding
adjustments to the provision and the associated fixed asset. The
unwinding of the discount on the decommissioning provision is
included within finance costs.
Property, Plant and Equipment other than Oil and Gas Assets
Property, plant and equipment other than oil and gas assets
(included in Other fixed assets in Note 17) are stated at cost less
accumulated depreciation and any provision for impairment.
Depreciation is charged so as to write off the cost of assets on a
straight-line basis over their useful lives as follows:
Useful lives in years
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.
Inventories
Inventories typically consist of materials, spare parts and
hydrocarbons, and are stated at the lower of cost and net
realisable value. Cost of finished goods is determined on the
weighted average bases. Cost of other than finished goods inventory
is determined on the first in first out basis. Net realisable value
represents the estimated selling price less all estimated costs of
completion and costs to be incurred in marketing, selling and
distribution.
Revenue Recognition
Revenue is income arising in the course of the Group's ordinary
activities. Revenue is recognised in the amount of transaction
price. Transaction price is the amount of consideration to which
the Group expects to be entitled in exchange for transferring
control over promised goods or services to a customer, excluding
the amounts collected on behalf of third parties.
Revenue is recognised net of indirect taxes and excise
duties.
Sales of gas, condensate and LPG are recognised when control of
the good has transferred, being when the goods are delivered to the
customer, the customer has full discretion over the goods, and
there is no unfulfilled obligation that could affect the customer's
acceptance of the goods. Delivery occurs when the goods have been
shipped to the specific location, the risks of obsolescence and
loss have been transferred to the customer, and either the customer
has accepted the goods in accordance with the contract, the
acceptance provisions have lapsed, or the Group has objective
evidence that all criteria for acceptance have been satisfied.
A receivable is recognised when the goods are delivered as this
is the point in time that the consideration is unconditional
because only the passage of time is required before the payment is
due.
The Group normally uses standardised contracts for the sale of
gas, condensate and LPG, which define the point of control
transfer. The price and quantity of each sale transaction are
indicated in the specifications to the sales contracts.
The control over gas is transferred to a customer when the
respective act of acceptance is signed by the parties to a contract
upon delivery of gas to the point of sale specified in the
contract, normally being a certain point in the Ukrainian gas
transportation system. Acts of acceptance of gas are signed and the
respective revenues are recognised on a monthly basis.
The control over condensate and LPG is transferred to a customer
when the respective waybill is signed by the parties to a contract
upon shipment of goods at the point of sale specified in the
contract, which is normally the Group's production site.
Foreign Currencies
The Group's consolidated financial statements and those of the
Company are presented in US Dollars. The functional currency of the
subsidiaries which operate in Ukraine is Ukrainian Hryvnia. The
remaining entities have US Dollars as their functional
currency.
The functional currency of individual companies is determined by
the primary economic environment in which the entity operates,
normally the one in which it primarily generates and expends cash.
In preparing the financial statements of the individual companies,
transactions in currencies other than the entity's functional
currency ("foreign currencies") are recorded at the rates of
exchange prevailing on the dates of the transactions. At each
balance sheet date, monetary assets and liabilities that are
denominated in foreign currencies are retranslated at the rates
prevailing on the balance sheet date. Foreign exchange gains and
losses resulting from the settlement of such transactions and from
the translation at year-end exchange rates of monetary assets and
liabilities denominated in foreign currencies are recognised in the
Income Statement. Non-monetary assets and liabilities carried at
fair value that are denominated in foreign currencies are
translated at the rates prevailing at the date when the fair value
was determined. Non-monetary items which are measured in terms of
historical cost in a foreign currency are not retranslated. Gains
and losses arising on retranslation are included in net profit or
loss for the period, except for exchange differences arising on
balances which are considered long term investments where the
changes in fair value are recognised directly in other
comprehensive income.
On consolidation, the assets and liabilities of the Group's
subsidiaries which do not use US Dollars as their functional
currency are translated into US Dollars as follows:
(a) assets and liabilities for each Balance Sheet presented are
translated at the closing rate at the date of that Balance
Sheet;
(b) income and expenses for each Income Statement are translated
at average monthly exchange rates (unless this average is not a
reasonable approximation of the cumulative effect of the rates
prevailing on the transaction dates, in which case income and
expenses are translated at the rate on the dates of the
transactions); and
(c) all resulting exchange differences are recognised in other comprehensive income.
The principal rates of exchange used for translating foreign
currency balances at 31 December 2018 were $1:UAH27.7 (2017:
$1:UAH28.1), $1:GBP0.8 (2017: $1:GBP0.7), $1:EUR0.9 (2017:
$1:EUR0.8).
None of the Group's operations are considered to use the
currency of a hyperinflationary economy, however this is kept under
review.
Pensions
The Group contributes to a local government pension scheme in
Ukraine and defined benefit plans. The Group has no further payment
obligations towards the local government pension scheme once the
contributions have been paid.
Defined benefit plans define an amount of pension benefit that
an employee will receive on retirement, usually dependent on one or
more factors such as age, years of service and compensation.
The Group companies participate in a mandatory Ukrainian
State-defined retirement benefit plan, which provides for early
pension benefits for employees working in certain workplaces with
hazardous and unhealthy working conditions. The Group also provides
lump sum benefits upon retirement subject to certain conditions.
The early pension benefit (in the form of a monthly annuity) is
payable by employers only until the employee has reached the
statutory retirement age. The pension scheme is based on a benefit
formula which depends on each individual member's average salary,
his/her total length of past service and total length of past
service at specific types of workplaces ("list II" category).
The liability recognised in the Balance Sheet in respect of
defined benefit pension plans is the present value of the defined
benefit obligation at the end of the reporting period less the fair
value of plan assets. The defined benefit obligation is calculated
annually by independent actuaries using the projected unit credit
method. The present value of the defined benefit obligation is
determined by discounting the estimated future cash outflows using
interest rates of high-quality corporate bonds that are denominated
in the currency in which the benefits will be paid, and that have
terms to maturity approximating to the terms of the related pension
obligation. Since Ukraine has no deep market in such bonds, the
market rates on government bonds are used.
The current service cost of the defined benefit plan, recognised
in the Income Statement in employee benefit expense, except where
included in the cost of an asset, reflects the increase in the
defined benefit obligation resulting from employee service in the
current year, benefit changes curtailments and settlements.
Past-service costs are recognised immediately in the Income
Statement.
The net interest cost is calculated by applying the discount
rate to the net balance of the defined benefit obligation and the
fair value of plan assets. This cost is included in employee
benefit expense in the Income Statement.
Actuarial gains and losses arising from experience adjustments
and changes in actuarial assumptions are charged or credited to
equity in other comprehensive income in the period in which they
arise.
Leases
Leases are classified as finance leases whenever the terms of
the lease transfer substantially all the risks and rewards of
ownership to the lessee. All other leases are classified as
operating leases.
Rentals payable / receivable under operating leases are charged
/ credited to the Income Statement on a straight-line basis over
the term of the relevant lease. Benefits received or given as an
incentive to enter into an operating lease are also spread on a
straight-line basis over the lease term.
Taxation
The tax expense represents the sum of the current tax and
deferred tax.
Current tax, including UK corporation and overseas tax, is
provided at amounts expected to be paid (or recovered) using the
tax rates and laws that have been enacted or substantively enacted
by the balance sheet date.
Deferred tax is the tax expected to be payable or recoverable on
differences between the carrying amounts of assets and liabilities
in the financial statements and the corresponding tax bases used in
the computation of taxable profit, and is accounted for using the
balance sheet liability method. Deferred tax liabilities are
generally recognised for all taxable temporary differences and
deferred tax assets are recognised to the extent that it is
probable that taxable profits will be available against which
deductible temporary differences can be utilised. Such assets and
liabilities are not recognised if the temporary difference arises
from goodwill or from the initial recognition (other than in a
business combination) of other assets and liabilities in a
transaction that affects neither the tax profit nor the accounting
profit.
Deferred tax liabilities are recognised for taxable temporary
differences arising on investments in subsidiaries and associates,
and interests in joint ventures, except where the Group is able to
control the reversal of the temporary difference and it is probable
that the temporary difference will not reverse in the foreseeable
future.
Deferred tax is calculated at the tax rates which are expected
to apply in the period when the liability is settled or the asset
is realised. Deferred tax is charged or credited in the Income
Statement, except when it relates to items charged or credited
directly to equity, in which case the deferred tax is also dealt
with in equity.
Other taxes which include recoverable value added tax, excise
tax and custom duties represent the amounts receivable or payable
to local tax authorities in the countries where the Group
operates.
Financial Instruments
Financial instruments - key measurement terms. Fair value is the
price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at
the measurement date. The best evidence of fair value is the price
in an active market. An active market is one in which transactions
for the asset or liability take place with sufficient frequency and
volume to provide pricing information on an ongoing basis.
Fair value of financial instruments traded in an active market
is measured as the product of the quoted price for the individual
asset or liability and the number of instruments held by the
entity. This is the case even if a market's normal daily trading
volume is not sufficient to absorb the quantity held and placing
orders to sell the position in a single transaction might affect
the quoted price.
A portfolio of financial derivatives or other financial assets
and liabilities that are not traded in an active market is measured
at the fair value of a group of financial assets and financial
liabilities on the basis of the price that would be received to
sell a net long position (i.e. an asset) for a particular risk
exposure or paid to transfer a net short position (i.e. a
liability) for a particular risk exposure in an orderly transaction
between market participants at the measurement date. This is
applicable for assets carried at fair value on a recurring basis if
the Group: (a) manages the group of financial assets and financial
liabilities on the basis of the Group's net exposure to a
particular market risk (or risks) or to the credit risk of a
particular counterparty in accordance with the Group's documented
risk management or investment strategy; (b) it provides information
on that basis about the group of assets and liabilities to the
Group's key management personnel; and (c) the market risks,
including duration of the Group's exposure to a particular market
risk (or risks) arising from the financial assets and financial
liabilities are substantially the same.
Valuation techniques such as discounted cash flow models or
models based on recent arm's length transactions or consideration
of financial data of the investees are used to measure fair value
of certain financial instruments for which external market pricing
information is not available. Fair value measurements are analysed
by level in the fair value hierarchy as follows: (i) level one are
measurements at quoted prices (unadjusted) in active markets for
identical assets or liabilities, (ii) level two measurements are
valuations techniques with all material inputs observable for the
asset or liability, either directly (that is, as prices) or
indirectly (that is, derived from prices), and (iii) level three
measurements are valuations not based on solely observable market
data (that is, the measurement requires significant unobservable
inputs). Transfers between levels of the fair value hierarchy are
deemed to have occurred
Transaction costs are incremental costs that are directly
attributable to the acquisition, issue or disposal of a financial
instrument. An incremental cost is one that would not have been
incurred if the transaction had not taken place. Transaction costs
include fees and commissions paid to agents (including employees
acting as selling agents), advisors, brokers and dealers, levies by
regulatory agencies and securities exchanges, and transfer taxes
and duties. Transaction costs do not include debt premiums or
discounts, financing costs or internal administrative or holding
costs.
Amortised cost ("AC") is the amount at which the financial
instrument was recognised at initial recognition less any principal
repayments, plus accrued interest, and for financial assets less
any allowance for expected credit losses ("ECL"). Accrued interest
includes amortisation of transaction costs deferred at initial
recognition and of any premium or discount to the maturity amount
using the effective interest method. Accrued interest income and
accrued interest expense, including both accrued coupon and
amortised discount or premium (including fees deferred at
origination, if any), are not presented separately and are included
in the carrying values of the related items in the consolidated
statement of financial position.
The effective interest method is a method of allocating interest
income or interest expense over the relevant period, so as to
achieve a constant periodic rate of interest (effective interest
rate) on the carrying amount. The effective interest rate is the
rate that exactly discounts estimated future cash payments or
receipts (excluding future credit losses) through the expected life
of the financial instrument or a shorter period, if appropriate, to
the gross carrying amount of the financial instrument. The
effective interest rate discounts cash flows of variable interest
instruments to the next interest repricing date, except for the
premium or discount which reflects the credit spread over the
floating rate specified in the instrument, or other variables that
are not reset to market rates. Such premiums or discounts are
amortised over the whole expected life of the instrument. The
present value calculation includes all fees paid or received
between parties to the contract that are an integral part of the
effective interest rate. For assets that are purchased or
originated credit impaired ("POCI") at initial recognition, the
effective interest rate is adjusted for credit risk, i.e. it is
calculated based on the expected cash flows on initial recognition
instead of contractual payments.
Financial instruments - initial recognition. Financial
instruments at fair value through profit or loss ("FVTPL") are
initially recorded at fair value. All other financial instruments
are initially recorded at fair value adjusted for transaction
costs. Fair value at initial recognition is best evidenced by the
transaction price. A gain or loss on initial recognition is only
recorded if there is a difference between fair value and
transaction price which can be evidenced by other observable
current market transactions in the same instrument or by a
valuation technique whose inputs include only data from observable
markets. After the initial recognition, an ECL allowance is
recognised for financial assets measured at AC and investments in
debt instruments measured at fair value through other comprehensive
income ("FVOCI"), resulting in an immediate accounting loss.
All purchases and sales of financial assets that require
delivery within the time frame established by regulation or market
convention ("regular way" purchases and sales) are recorded at
trade date, which is the date on which the Group commits to deliver
a financial asset. All other purchases are recognised when the
entity becomes a party to the contractual provisions of the
instrument.
Financial assets - classification and subsequent measurement -
measurement categories. The Group classifies financial assets in
the following measurement categories: FVTPL, FVOCI and AC. The
classification and subsequent measurement of debt financial assets
depends on: (i) the Group's business model for managing the related
assets portfolio and (ii) the cash flow characteristics of the
asset. The Group's financial assets include cash and cash
equivalents, trade and other receivables, loans to subsidiary
undertakings, all of which are classified as AC in accordance with
IFRS 9.
Financial assets - classification and subsequent measurement -
business model.The business model reflects how the Group manages
the assets in order to generate cash flows - whether the Group's
objective is: (i) solely to collect the contractual cash flows from
the assets ("hold to collect contractual cash flows",) or (ii) to
collect both the contractual cash flows and the cash flows arising
from the sale of assets ("hold to collect contractual cash flows
and sell") or, if neither of (i) and (ii) is applicable, the
financial assets are classified as part of "other" business model
and measured at FVTPL.
Business model is determined for a group of assets (on a
portfolio level) based on all relevant evidence about the
activities that the Group undertakes to achieve the objective set
out for the portfolio available at the date of the assessment.
Factors considered by the Group in determining the business model
include past experience on how the cash flows for the respective
assets were collected.
The Group's business model for financial assets is to collect
the contractual cash flows from the assets ("hold to collect
contractual cash flows").
Financial assets - classification and subsequent measurement -
cash flow characteristics. Where the business model is to hold
assets to collect contractual cash flows or to hold contractual
cash flows and sell, the Group assesses whether the cash flows
represent solely payments of principal and interest ("SPPI").
Financial assets with embedded derivatives are considered in their
entirety when determining whether their cash flows are consistent
with the SPPI feature. In making this assessment, the Group
considers whether the contractual cash flows are consistent with a
basic lending arrangement, i.e. interest includes only
consideration for credit risk, time value of money, other basic
lending risks and profit margin.
Where the contractual terms introduce exposure to risk or
volatility that is inconsistent with a basic lending arrangement,
the financial asset is classified and measured at FVTPL. The SPPI
assessment is performed on initial recognition of an asset and it
is not subsequently reassessed.
Financial assets - reclassification. Financial instruments are
reclassified only when the business model for managing the
portfolio as a whole changes. The reclassification has a
prospective effect and takes place from the beginning of the first
reporting period that follows after the change in the business
model. The Group did not change its business model during the
current and comparative period and did not make any
reclassifications.
Financial assets impairment - credit loss allowance for ECL. The
Group assesses, on a forward-looking basis, the ECL for debt
instruments measured at AC and FVOCI and for the exposures arising
for contract assets. The Group measures ECL and recognises Net
impairment losses on financial and contract assets at each
reporting date. The measurement of ECL reflects: (i) an unbiased
and probability weighted amount that is determined by evaluating a
range of possible outcomes, (ii) time value of money and (iii) all
reasonable and supportable information that is available without
undue cost and effort at the end of each reporting period about
past events, current conditions and forecasts of future
conditions.
Debt instruments measured at AC and contract assets are
presented in the consolidated statement of financial position net
of the allowance for ECL. For loan commitments and financial
guarantees, a separate provision for ECL is recognised as a
liability in the consolidated statement of financial position.
The Group applies a three stage model for impairment, based on
changes in credit quality since initial recognition. A financial
instrument that is not credit-impaired on initial recognition is
classified in Stage 1. Financial assets in Stage 1 have their ECL
measured at an amount equal to the portion of lifetime ECL that
results from default events possible within the next 12 months or
until contractual maturity, if shorter ("12 Months ECL"). If the
Group identifies a significant increase in credit risk ("SICR")
since initial recognition, the asset is transferred to Stage 2 and
its ECL is measured based on ECL on a lifetime basis, that is, up
until contractual maturity but considering expected prepayments, if
any ("Lifetime ECL"). If the Group determines that a financial
asset is credit-impaired, the asset is transferred to Stage 3 and
its ECL is measured as a Lifetime ECL. For financial assets that
are purchased or originated credit-impaired ("POCI Assets"), the
ECL is always measured as a Lifetime ECL.
Financial assets - write-off. Financial assets are written-off,
in whole or in part, when the Group exhausted all practical
recovery efforts and has concluded that there is no reasonable
expectation of recovery. The write-off represents a derecognition
event. The Group may write-off financial assets that are still
subject to enforcement activity when the Group seeks to recover
amounts that are contractually due, however, there is no reasonable
expectation of recovery.
Financial assets - derecognition. The Group derecognises
financial assets when (a) the assets are redeemed or the rights to
cash flows from the assets otherwise expire or (b) the Group has
transferred the rights to the cash flows from the financial assets
or entered into a qualifying pass-through arrangement whilst (i)
also transferring substantially all the risks and rewards of
ownership of the assets or (ii) neither transferring nor retaining
substantially all the risks and rewards of ownership but not
retaining control.
Financial assets - modification. If the modified terms are
substantially different, the rights to cash flows from the original
asset expire and the Company derecognises the original financial
asset and recognises a new asset at its fair value. The date of
renegotiation is considered to be the date of initial recognition
for subsequent impairment calculation purposes, including
determining whether a SICR has occurred. Any difference between the
carrying amount of the original asset derecognised and fair value
of the new substantially modified asset is recognised in profit or
loss, unless the substance of the difference is attributed to a
capital transaction with owners. If the modified asset is not
substantially different from the original asset and the
modification does not result in derecognition. The Group
recalculates the gross carrying amount by discounting the modified
contractual cash flows by the original effective interest rate (or
credit-adjusted effective interest rate for POCI financial assets),
and recognises a modification gain or loss in profit or loss.
Financial liabilities - measurement categories. Financial
liabilities are classified as subsequently measured at AC, except
for (i) financial liabilities at FVTPL: this classification is
applied to derivatives, financial liabilities held for trading
(e.g. short positions in securities), contingent consideration
recognised by an acquirer in a business combination and other
financial liabilities designated as such at initial recognition and
(ii) financial guarantee contracts and loan commitments. The
Group's financial liabilities include trade and other payables, all
of which are classified as AC in accordance with IFRS 9.
Financial liabilities - derecognition. Financial liabilities are
derecognised when they are extinguished (i.e. when the obligation
specified in the contract is discharged, cancelled or expires).
Trade Receivables
Trade receivables are amounts due from customers for goods sold
in the ordinary course of business. If collection is expected in
one year or less, they are classified as current assets. If not,
they are presented as non-current assets.
Trade receivables are recognised initially at fair value and
subsequently measured at amortised cost using the effective
interest method.
Investments in subsidiaries
Investments made by the Company in its subsidiaries are stated
at cost in the Company's financial statements and reviewed for
impairment if there are indications that the carrying value may not
be recoverable.
Loans issued to subsidiaries
Loans issued by the Company to its subsidiaries are initially
recognised in the Company's financial statements at fair value and
are subsequently carried at amortised cost using the effective
interest method, less credit loss allowance. Net change in credit
losses and foreign exchange differences on loans issued are
recognised in the Company's statement of profit or loss in the
period when incurred.
Trade Payables
Trade payables are obligations to pay for goods or services that
have been acquired in the ordinary course of business from
suppliers. Accounts payable are classified as current liabilities
if payment is due within one year or less. If not, they are
presented as non-current liabilities.
Trade payables are recognised initially at fair value and
subsequently measured at amortised cost using the effective
interest method.
Equity Instruments
Ordinary shares are classified as equity. Equity instruments
issued by the Company and the Group are recorded at the proceeds
received, net of direct issue costs. Any excess of the fair value
of consideration received over the par value of shares issued is
recorded as share premium in equity.
Cash and Cash Equivalents
Cash and cash equivalents comprise cash on hand and deposits
held at call with banks and other short-term highly liquid
investments which are readily convertible to a known amount of cash
with no significant loss of interest. Cash and cash equivalents are
carried at amortised cost. Interest income that relates to cash and
cash equivalents on current and deposit accounts is disclosed
within operating cash flow.
Other short-term investments
Other short-term investments include current accounts and
deposits held at banks, which do not meet cash and cash equivalents
definition. Current accounts and deposits held at banks, which do
not meet cash and cash equivalents definition are measured
initially at fair value and subsequently carried at amortised cost
using the effective interest method. Interest received on other
short-term investments is disclosed within operating cash flow.
The Group classifies its financial assets as at amortised cost
only if both of the following criteria are met:
- The asset is held within a business model whose objective is
to collect the contractual cash flows, and
- The contractual terms give rise to cash flows that are solely
payments of principal and interest.
Interest income
Interest income is recognised as it accrues, taking into account
the effective yield on the asset. Interest income on current bank
accounts and on demand deposits or term deposits with the maturity
less than three months recognised as part of cash and cash
equivalents is recognised as other operating income. Interest
income on term deposits other than those classified as cash and
cash equivalents is recognised as finance income.
4. Critical Accounting Estimates and Judgments
The Group makes estimates and judgments concerning the future.
The resulting accounting estimates will, by definition, seldom
equal the related actual results. The estimates and judgments which
have a risk of causing material adjustment to the carrying amounts
of assets and liabilities within the next financial year are
discussed below.
Recoverability of Oil and Gas Development and Production Assets
in Ukraine
According to the Group's accounting policies, costs capitalised
as assets are assessed for impairment at each balance sheet date if
impairment indicators exist. In assessing whether an impairment
loss has occurred, the carrying value of the asset or
cash-generating unit ("CGU") is compared to its recoverable amount.
The recoverable amount is the greater of fair value less costs to
dispose and value in use and is determined for an individual asset,
unless the asset does not generate cash inflows that are largely
independent of those from other assets or groups of assets. If the
recoverable amount of an asset is estimated to be less than its
carrying amount, the carrying amount of the asset is reduced to its
recoverable amount and the respective impairment loss is recognised
as an expense immediately. A previously recognised impairment loss
is reversed only if there has been a change in the estimates used
to determine the asset's recoverable amount since the last
impairment loss was recognised. If that is the case, the carrying
amount of the asset is increased to its recoverable amount, but so
that the increased carrying amount does not exceed the carrying
amount that would have been determined, net of depreciation, had no
impairment loss been recognised for the asset in prior years. Such
reversals are recognised as income immediately.
MEX-GOL and SV gas and condensate fields
As at 31 December 2017, no impairment indicators were identified
by the Group, and therefore no impairment test was performed for
the MEX-GOL and SV fields. In addition, at that date the Group
considered whether there were any triggers to reverse any
impairment loss recognised in prior years and concluded that there
was insufficient information to be able to do so.
Over the last two years, the Group has been undertaking certain
projects on the MEX-GOL and SV fields with the purpose of refining
its field development strategy, including the interpretation of a
reprocessed 3D seismic dataset, analysis of technical and economic
data and ongoing revision of the geological model. The new
information and understanding obtained as a result of the
comprehensive re-evaluation study of the geology, geophysics,
petroleum engineering and well performance of the fields, together
with the recent successful drilling and workover projects
implemented with enhanced drilling technologies, resulted in a
boost to production in the second half of 2017, and led to a
revision of the field development plan. The revised field
development plan for these fields prepared in 2018 assumes an
increase in the number of new wells from 10 to 24 and an
acceleration of the phasing of these new wells.
Following the successful outcomes of the recent drilling and
workover projects and subsequent revision of the field development
plan in 2018, the Group considered it appropriate to undertake a
reassessment of the reserves and resources at the MEX-GOL and SV
fields. Accordingly, the Group engaged independent petroleum
consultants DeGolyer and MacNaughton ("D&M") to prepare an
updated estimate of remaining reserves and resources as of 31
December 2017. The final report issued by D&M in July 2018
provided an estimate of the Group's proved plus probable ("2P")
reserves of 50.0 MMboe based on the Group's revised field
development plan and other relevant information available at the
date of the assessment. The report represents an update on the
Group's reserves and resources since the previous estimation
undertaken by ERC Equipoise Limited ("ERCE") as at 31 December
2013. Further details of the updated reserves report are set out in
the Chief Executive Officer's Statement above and in the Company's
announcement made on 31 July 2018.
In accordance with its accounting policy, at the end of each
reporting period, the Group assesses whether there is any
indication that an impairment loss recognised in prior periods for
its oil and gas development and production assets may no longer
exist or may have decreased. Given that the 2P reserves remaining
as at 31 December 2017, as estimated in the 2018 D&M report,
significantly exceeded the previous 2P reserves estimated by ERCE
(11.7 MMboe remaining as at 31 December 2013), the Group considered
that such a change in reserves estimate reflected a substantial
increase in the potential of the MEX-GOL and SV fields and
therefore triggered the re-assessment of the recoverable amount of
oil and gas development and production assets related to these
fields. As such, as at 30 June 2018, the Group determined the
recoverable amount based on the Fair Value Less Costs of Disposal
("FVLCD") approach using a discounted cash flow methodology. The
discounted after tax cash flows for the CGU were derived based on
estimates that a typical market participant would use in valuing
such assets. The Group has determined that the MEX-GOL and SV
fields are a single CGU, being the smallest group of assets that
generate independent cash inflows, as the investment decisions are
not based on a single well, but on the expected production of the
fields, and these fields are dependent on common infrastructure.
The estimate of FVLCD meets the definition of Level 3 fair value
measurements as it is determined mostly from unobservable inputs.
For the discounted cash flows to be calculated, the Group has used
a production profile based on the best estimate of 2P reserves and
a range of assumptions, including gas price, economic life of the
fields, future capital expenditures and a discount rate which,
taking into account other assumptions used in the calculation, are
considered to be reflective of the risks. These assumptions are
further described in Note 17.
The FVLCD determined by the Group as at 30 June 2018 amounted to
$311,100,000, mostly as a result of a substantial increase in the
forecasted volume of 2P reserves, accelerated production schedule,
growth in gas price and decrease in production tax rates for the
wells drilled after 1 January 2018. This resulted in the reversal
of the impairment loss of $36,117,000 being recorded as income for
the year ended 31 December 2018 in these consolidated financial
statements. The amount of the reversal was determined as
$39,773,000, being the total amount of the previous impairment
accumulated on the MEX-GOL and SV fields up to 30 June 2018, net of
depreciation, that would have been incurred had the fields not been
previously impaired, less $3,656,000 of previous impairment
attributed to the SV-69 well, net of depreciation, which was
assessed for impairment purposes separately as at 30 June 2018.
This development-type well has not resulted in any production for
the Group due to mechanical issues which occurred during its
drilling and the well was plugged back with initial plans for a
side track at a later stage. Since then, no side-tracking of this
well or drilling of an alternative well targeting the same location
has been performed and no information was obtained from this well
that could be applied to the development of the targeted area of
the field, which could lead to future production. No commercial
reserves were assigned to the respective field area in the reserves
and resources estimation by D&M in 2018 and the Group completed
abandonment of the well by the end of 2018. As such, as at 30 June
2018, the Group did not reverse the previous impairment allowance
related to this well and additionally the Group impaired the
remaining carrying value of the well to nil on the individual basis
and recorded the respective impairment loss of $1,648,000 as an
expense for the year ended 31 December 2018.
VAS gas and condensate field
At 31 December 2018, the Group performed an assessment of
external and internal indicators to ascertain whether there was any
indication of potential impairment. Based on the analysis
performed, the Group concluded that no external or internal
impairment indicators existed as at 31 December 2018, and
accordingly no impairment testing was required as at that date.
Depreciation of Oil and Gas Development and Production
Assets
Oil and gas development and production assets held in property,
plant and equipment are depreciated on a unit of production basis
at a rate calculated by reference to proven and probable reserves
at the end of the period plus the production in the period, and
incorporating the estimated future cost of developing and
extracting those reserves. Future development costs are estimated
using assumptions about the number of wells required to produce
those reserves, the cost of the wells, future production facilities
and operating costs, together with assumptions on oil and gas
realisations, and are revised annually. The reserves estimates used
are determined using estimates of gas in place, recovery factors,
future hydrocarbon prices and also take into consideration the
Group's latest development plan for the associated oil and gas
development and production assets. Additionally, the latest
development plan and therefore the inputs used to determine the
depreciation charge, assume that the current licences for the
MEX-GOL and SV fields, which are due to expire in July 2024, can be
extended until the end of the economic life of the fields.
In light of the revision of the field development plan for the
MEX-GOL and SV fields and the re-assessment of the 2P reserves at
these fields performed in 2018 by D&M as described above, the
Group has revised the estimate of 2P reserves and future cost of
developing and extracting those reserves used for the depletion
calculation. The effect of the change in estimates made in the
current reporting period was appropriately recognised in profit or
loss in the period of the change and amounted to a decrease of
$11,290,000 in depletion charge for the year 2018.
Provision for Decommissioning
The Group has decommissioning obligations in respect of its
Ukrainian assets. The full extent to which the provision is
required depends on the legal requirements at the time of
decommissioning, the costs and timing of any decommissioning works
and the discount rate applied to such costs.
A detailed assessment of gross decommissioning cost was
undertaken on a well-by-well basis using local data on day rates
and equipment costs. The discount rate applied on the
decommissioning cost provision at 31 December 2018 was 8.14% (31
December 2017: 4.70%). The discount rate is calculated in real
terms based on the yield to maturity of Ukrainian Government bonds
denominated in the currency in which the liability is expected to
be settled and with the settlement date that approximates the
timing of settlement of decommissioning obligations.
The change in estimate applied to calculate the provision as at
31 December 2018 resulted from the revision of the estimated costs
of decommissioning (increase of $1,133,000 in provision), the
increase in the discount rate applied (decrease of $1,003,000 in
provision) and the extension of the economic life of the MEX-GOL
and SV fields as a result of the revision of the field development
plan in 2018 (decrease of $180,000 in provision). The increase in
discount rate at 31 December 2018 resulted from the increase in
Ukrainian Eurobonds yield and the respective increase of country
risk premium. The costs are expected to be incurred by 2038 on the
MEX-GOL field, by 2042 on the SV field, and by 2024 on the VAS
field (31 December 2017: by 2036 on the MEX-GOL and SV fields and
2024 on the VAS field respectively), which is the end of the
estimated economic life of the respective fields. If the costs on
the MEX-GOL and SV fields were to be incurred at the current expiry
of the production licences in 2024, the provision for
decommissioning at 31 December 2018 would be $6,268,000 (31
December 2017: $2,613,000).
Net Carrying Amount of Inter-Company Loans Receivable by the
Company from a Subsidiary
The Company has certain inter-company loans receivable from a
subsidiary, which are eliminated on consolidation. For the purpose
of the Company's financial statements, these receivable balances
are carried at amortised cost using the effective interest method,
less credit loss allowance. Measurement of lifetime expected credit
losses on inter-company loans is a significant judgment that
involves models and data inputs including forward-looking
information, current conditions and forecasts of future conditions
impacting the estimated future cash flows that are expected to be
recovered, time value of money, etc. In previous years, significant
impairment charges were recorded against the carrying amount of the
loans issued to subsidiaries as the present value of estimated
future cash flows discounted at the original effective interest
rate was less than carrying amount of the loans, and the resulting
impairment losses were recognised in profit or loss in the
Company's financial statements.
For the purpose of assessment of the credit loss allowance as at
31 December 2018, the Company considered all reasonable and
supportable forward looking information available as of that date
without undue cost and effort, which includes a range of factors,
such as estimated future net cash flows to be generated by the
subsidiaries operating in Ukraine, upcoming planned changes in the
Group's structure, cash flow management and planned debt
structuring between Group entities. All these factors have
significant impact on the amounts subject to repayment on the
loans. The estimated future discounted cash flows generated by the
subsidiaries operating in Ukraine, which are considered as a
primary source of repayment on the loans, have significantly
increased following the revision of the field development plan and
reassessment of mineral reserves at the MEX-GOL and SV fields in
2018 as described above in this Note. For the purpose of this
assessment, these cash flows were taken for a period of five years,
as management believes there is no reasonably available information
to build reliable expectations and demonstrate the ability to
settle the loans in a longer perspective, especially in light of
the anticipated changes in the Group's legal structure and
reassignment of the loans to another subsidiary. As of 31 December
2018, the present value of future net cash flows to be generated by
the subsidiaries operating in Ukraine during 2019 - 2023, adjusted
for the subsidiaries' working capital as at 31 December 2018 and
estimated amounts reserved by the Group for investment projects in
the 5-years horizon was calculated. The resulting amount, net of
the carrying value of the Company's investments in subsidiaries,
was compared to the carrying value of the loans issued to
subsidiaries as at 31 December 2018. As such, the Company has
recorded $10,923,000 of gain, being the net change in credit loss
allowance for loans issued to subsidiaries in the Company's
statement of profit or loss for the year ended 31 December
2018.
As with any economic forecast, the projections and likelihoods
of occurrence are subject to a high degree of inherent uncertainty,
and therefore the actual outcomes may be significantly different to
those projected. The Company considers these forecasts to represent
its best estimate of the possible outcomes.
Exchange Differences on Intra-group Balances with Foreign
Operations
As at 31 December 2017, a Group subsidiary, Regal Petroleum
Corporation (Ukraine) Limited, planned to settle $6,000,000 of
intra-group liability, of which $4,200,000 was settled in the
period. A further amount of $9,000,000 (including $1,800,000 not
paid during 2018) is planned to be settled by the end of 2019. As
such, a foreign exchange difference of $488,000 accumulated on the
intra-group balance of $13,200,000 since the date of de-designation
of this balance as part of the Company's net investment in the
foreign operation up to 31 December 2018 was recognised in profit
or loss in these consolidated financial statements. No
reclassification of the foreign exchange difference accumulated in
equity prior to de-designation was made as there has been no change
in the Company's proportionate ownership interest in the foreign
operation and therefore no disposal or partial disposal of the
foreign operation. There were no changes in management's plans or
intentions regarding the payment of intra-group balances unsettled
as at 31 December 2018, other than the above-mentioned amount of
$9,000,000, and as such, a foreign exchange difference related to
the balance designated as net investment in a foreign operation was
recognised in other comprehensive income in the Company Statement
of Comprehensive Income for the year ended 31 December 2018.
Recognition of Deferred Tax Asset
The recognition of deferred tax assets is based upon whether it
is more likely than not that sufficient and suitable taxable
profits will be available in the future against which the reversal
of temporary differences can be deducted. This requires judgement
for forecasting future profits. Further details of the deferred tax
assets recognised can be found in Note 25.
5. Changes in accounting policies
This note explains the impact of the adoption of IFRS 9
'Financial Instruments' and IFRS 15 'Revenue from contracts with
customers' on the Group's financial statements and also discloses
the new accounting policies that have been applied from 1 January
2018, where they are different to those applied in prior
periods.
Impact on the financial statements
The Group adopted IFRS 9, Financial Instruments, from 1 January
2018. The Group elected not to restate comparative figures and
recognised any adjustments to the carrying amounts of financial
assets and liabilities in the opening retained earnings as of the
date of initial application of the standards, 1 January 2018.
The following table reconciles the carrying amounts of each
class of financial assets as previously measured in accordance with
IAS 39 and the new amounts determined upon adoption of IFRS 9 on 1
January 2018.
Measure-ment Carrying Effect Carrying
category value per value per
IAS 39 IFRS 9
(closing (opening
balance at balance
31 December at 1 January
2017) 2018)
IAS IFRS Remeasure-ment Reclassification
39 9
Group ECL*** Other Manda-tory Volunta-ry
$000 $000 $000 $000 $000 $000
Cash and
cash
equivalents L&R* AC** 14,249 (9) - - - 14,240
Other
short-term
investments L&R* AC** 16,000 (35) - - - 15,965
Trade and
other
accounts
receivable L&R* AC** 2,542 (62) - - - 2,480
--------------- -------- ------- -------------- --------- ------ -------------- ----------- ----------------
Total financial
assets 32,791 (106) - - - 32,685
*L&R - Loans and receivables
**AC - Amortised cost
***ECL - Expected credit losses
Measure-ment Carrying Effect Carrying
category value per value per
IAS 39 (closing IFRS 9 (opening
balance at balance
31 December at 1 January
2017) 2018)
IAS IFRS Remeasure-ment Reclassification
39 9
Company ECL Other Manda-tory Volunta-ry
$000 $000 $000 $000 $000 $000
Cash and
cash
equivalents L&R* AC** 4,411 (2) - - - 4,409
Other short-term
investments L&R* AC** 16,000 (35) - - - 15,965
Trade and
other accounts
receivable L&R* AC** 464 - - - - 464
Loans to
subsidiary
undertakings L&R* AC** 38,225 - - - - 38,225
----------------- -------- ------- ---------------- ------- -------- ----------- ----------- -----------------
Total financial
assets - - 59,100 (37) - - - 59,063
*L&R - Loans and receivables
**AC - Amortised cost
The Group has two types of financial assets that are subject to
IFRS 9's new expected credit loss ("ECL") model:
-- trade and other receivables,
-- other financial assets carried at amortised cost.
The Group was required to revise its impairment methodology
under IFRS 9 for each of these classes of financial assets. The
impact of the change in impairment methodology on the Group's
accumulated losses and equity is disclosed in the table above.
Under IFRS 9, loss allowances are measured on either of the
following bases:
-- 12-month ECLs: these are ECLs that result from possible
default events within the 12 months after the reporting date;
and
-- lifetime ECLs: these are ECLs that result from all possible
default events over the expected life of a financial
instrument.
The Group applies the IFRS 9 simplified approach to measuring
expected credit losses which uses a lifetime expected loss
allowance for all trade receivables. To measure the expected credit
losses, trade and other receivables have been grouped based on
shared credit risk characteristics and ageing.
The lifetime expected credit loss for loans issued to
subsidiaries is based on a forward-looking information, reflects
the amount that is considered to be the most probable outcome to be
recovered, takes into account current conditions, forecasts of
future conditions and time value of money
When determining whether the credit risk of a financial asset
has increased significantly since initial recognition and when
estimating expected credit losses, the Group considers reasonable
and supportable information that is relevant and available without
undue cost or effort. The calculation of expected credit losses is
carried out on an individual basis taking into account agreement
terms, expected repayment period and debtors` credit rating. This
includes both quantitative and qualitative information and analysis
based on the publicly available observable information, including
the information published by the credit ratings agencies and the
National Bank of Ukraine, used as benchmarks for expected credit
losses and taking into account forward-looking information. For
individually insignificant debtors, the Group calculates the
expected credit losses based on the Group's historical default
rates over the expected life of the financial assets and adjusted
for forward-looking estimates.
Impairment losses related to financial assets are presented as
part of other operating expenses in the statement of profit or
loss.
The total impact on the Group's accumulated losses as at 1
January 2018 is represented by the increase in impairment provision
on respective line items as presented in the above table, and is
based on estimated rates of expected loss amounts for receivables
from related parties and third parties.
Trade and other receivables
To measure the expected credit losses, trade and other
receivables have been grouped based on shared credit risk
characteristics. The loss allowances for trade and other
receivables as at 31 December 2017 reconcile to the opening loss
allowances on 1 January 2018 as follows:
Group
$000
At 31 December 2017 - calculated under IAS 39 90
Amounts restated through opening accumulated losses 62
---------------------------------------------------------------------- -----
Opening loss allowance as at 1 January 2018 - calculated under IFRS 9 152
The loss allowance decreased by a further $53,000 to $99,000 for
trade and other receivables during 2018.
Other financial assets at amortised cost
Other financial assets at amortised cost include cash and cash
equivalents and other short-term investments. Applying the expected
credit risk model resulted in the recognition of a loss allowance
of $44,000 on 1 January 2018 (previous loss allowance was nil) and
a further decrease in the allowance by $5,000 in 2018 due to the
decrease in other short-term investments.
IFRS 15 'Revenue from contracts with customers' - Impact of
adoption
Starting from 1 January 2018, the Group is obliged to apply IFRS
15 Revenue from Contracts with Customers. The new standard
recognition requirements provide more advanced guidance on complex
transactions, such as accounting for multiple-element arrangements.
The new standard introduces the core principle that revenue must be
recognised when the goods or services are transferred to the
customer, at the transaction price. Any bundled goods or services
that are distinct must be separately recognised, and any discounts
or rebates on the contract price must generally be allocated to the
separate elements. When the consideration varies for any reason,
minimum amounts must be recognised if they are not at significant
risk of reversal. Costs incurred to secure contracts with customers
have to be capitalised and amortised over the period when the
benefits of the contract are consumed.
IFRS 15 also includes a cohesive set of disclosure requirements
that would result in an entity providing users of financial
statements with comprehensive information about the nature, amount,
timing, and uncertainty of revenue and cash flows arising from the
entity's contracts with customers.
Based on management's assessment, the adoption of this standard
had no significant impact on these financial statements.
6. Segmental Information
In line with the Group's internal reporting framework and
management structure, the key strategic and operating decisions are
made by the Board of Directors, who review internal monthly
management reports, budget and forecast information as part of this
process. Accordingly, the Board of Directors is deemed to be the
Chief Operating Decision Maker within the Group.
The Group's only class of business activity is oil and gas
exploration, development and production. The Group's operations are
located in Ukraine, with its head office in the United Kingdom.
These geographical regions are the basis on which the Group reports
its segment information. The segment results as presented represent
operating profit before depreciation, amortisation and impairment
of non-current assets.
Ukraine United 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
of non-current assets (7,901) - (7,901)
Reversal of impairment/(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
*Comprises additions to property, plant and equipment (Note
17)
There are no inter-segment sales within the Group and all
products are sold in the geographical region in which they are
produced. The Group is not significantly impacted by seasonality.
Revenue is recognised at a point in time.
During 2017-2018, the Group sold all of its gas production to
its related party, LLC Smart Energy ("Smart Energy"). Smart Energy
has oil and gas operations in Ukraine and is part of the PJSC
Smart-Holding Group, which is ultimately controlled by Mr V
Novynskyi, who through an indirect 54% majority shareholding,
ultimately controls the Group. This arrangement came about in 2017
as a consequence of the Ukrainian Government introducing a number
of new provisions into the Ukrainian Tax Code over the last two
years, including transfer pricing regulations for companies
operating in Ukraine. The introduction of the new regulations has
meant that there is an increased regulatory burden on affected
companies in Ukraine who must prepare and submit reporting
information to the Ukrainian Tax Authorities. Due to the corporate
structure of the Group, a substantial proportion of its gas
production is produced by a non-Ukrainian subsidiary of the Group,
which operates in Ukraine as a branch, or representative office as
it is classified in Ukraine. Under the current tax regulations,
this places additional regulatory obligations on each of the
Group's potential customers who may be less inclined to purchase
the Group's gas and/or may seek discounts on sales prices. As a
result of discussions between the Company and Smart Energy, Smart
Energy agreed to purchase all of the Group's gas production and to
assume responsibility for the regulatory obligations under the
Ukrainian tax regulations. Furthermore, Smart Energy has agreed to
combine the Group's gas production with its own gas production, and
to sell such gas as combined volumes, with the intention to achieve
higher sales prices due to the larger sales volumes. In order to
cover Smart Energy's sales, administration and regulatory
compliance costs, the Group has agreed to sell its gas to Smart
Energy at a small discount to the gas sales prices achieved by
Smart Energy, who sell the combined volumes in line with market
prices. The terms of sale, effective from June 2017, for the
Group's gas to Smart Energy are (i) payment for one third of the
estimated monthly volume of gas by the 20th of the month of
delivery, and (ii) payment of the remaining balance by the 10th of
the month following the month of delivery.
United
Ukraine Kingdom Total
2017 2017 2017
$000 $000 $000
Revenue
Gas sales 24,936 - 24,936
Condensate sales 7,957 - 7,957
Liquefied Petroleum Gas sales 2,160 - 2,160
------------------------------ -------- -------- --------
Total revenue 35,053 - 35,053
Segment result 20,168 (1,773) 18,395
Depreciation and amortisation
of non-current assets (11,816) - (11,816)
Impairment of property, plant
and equipment (180) - (180)
Operating profit 6,399
Segment assets 44,630 23,399 68,029
Capital additions* 4,024 - 4,024
*Comprises additions to property, plant and equipment (Note
17)
7. Cost of Sales
2018 2017
$000 $000
Production taxes 14,902 7,856
Depreciation of property, plant and equipment 6,863 10,796
Rent expenses (Note 28) 4,474 707
Staff costs (Note 10) 2,084 1,867
Cost of inventories recognised as an expense 1,414 1,063
Amortisation of mineral reserves 804 822
Impairment of inventory - 179
Other expenses 1,334 982
---------------------------------------------- ------ ------
31,875 24,272
The increase in production taxes in 2018 is mainly represented
by the increase in the volume of production on existing wells and
the introduction of the new wells, MEX-109 and VAS-10, and the
leased well, SV-12.
As described in Note 4, as a result of the revision of the field
development plan and re-assessment of the Group's 2P reserves at
the MEX-GOL and SV fields in 2018, the Group has revised the
estimate of 2P reserves and future capital expenditure associated
with developing and extracting those reserves used for the
depletion calculation, which resulted in a significant decrease in
depreciation expenses.
8. Administrative Expenses
2018 2017
$000 $000
Staff costs (Note 10) 3,620 3,473
Consultancy fees 509 520
Auditors' remuneration 403 349
Rent expenses (Note 28) 323 266
Depreciation of other fixed assets 180 94
Amortisation of other intangible assets 54 104
Other expenses 620 505
---------------------------------------------------- ------ ------
5,709 5,311
2018 2017
$000 $000
Audit of the Company and subsidiaries 166 234
Audit of subsidiaries in Ukraine 95 -
Audit related assurances services - interim review 70 51
---------------------------------------------------- ------ ------
Total assurance services 331 285
Tax compliance services 33 63
Legal services 25 -
Tax advisory services 14 1
Total non-audit services 72 64
---------------------------------------------------- ------ ------
Total audit and other services 403 349
All amounts shown as auditors' remuneration in 2018 and 2017
were payable to the Group auditors, PricewaterhouseCoopers LLP and
other member firms of PricewaterhouseCoopers LLP.
9. Remuneration of Directors
2018 2017
$000 $000
Directors' emoluments 810 940
---------------------- ---- ----
The emoluments of the individual Directors were as follows:
Total Total
emoluments emoluments
2018 2017
$000 $000
Executive Directors:
Sergii Glazunov 437 174
Keith Henry - 432
Non-executive Directors:
Chris Hopkinson 133 31
Alexey Pertin 60 58
Yuliia Kirianova 60 58
Bruce Burrows 60 19
Philip Frank 45 12
Dmitry Sazonenko 15 -
Alastair Graham - 88
Adrian Coates - 68
810 940
Sergii Glazunov was appointed as Chief Executive Officer in
August 2017, and is paid $252,000 per annum. During the 2018 year,
he was also paid a bonus of $124,000.
Philip Frank stepped down as Non-Executive Director in September
2018. He was paid GBP45,000 per annum for the period from January
2018 to September 2018.
Dmitry Sazonenko was appointed as Non-Executive Director in
September 2018, and is paid GBP45,000 per annum.
The emoluments include base salary, bonuses and fees. According
to the Register of Directors' Interests, no rights to subscribe for
shares in or debentures of the Group companies were granted to any
of the Directors or their immediate families during the financial
year, and there were no outstanding options to Directors.
10. Staff Numbers and Costs
Number of employees
2018 2017
Group
Management / operational 146 130
Administrative support 66 66
------------------------- ---------- ---------
212 196
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:
2018 2017
$000 $000
Wages and salaries 4,969 4,739
Other pension costs 661 540
Social security costs 74 61
5,704 5,340
11. Other operating gains, (net)
2018 2017
$000 $000
Interest income on cash and cash equivalents 3,024 924
Contractor penalties applied 225 1
Gain on sales of current assets 26 117
Other operating income, net 112 67
3,387 1,109
12. Finance Income
During 2018, the Group recorded interest income of $153,000
(2017: $32,000) from placement of cash on long-term deposit
accounts and recognised foreign exchange gains less losses of
$488,000 (2017: $351,000).
13. Finance Costs
During 2018, the Group recorded an unwinding of a discount on
provision for decommissioning of $140,000 (2017: $112,000) (Note
23).
14. Income tax expense
a) Income tax expense and (benefit):
2018 2017
$000 $000
Current tax
Overseas - current year 6,478 3,037
Deferred tax (Note 25)
UK - current year 5,519 (603)
UK - prior year 821 1,516
Overseas - current year (333) 351
Income tax expense 12,485 4,301
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:
2018 2017
$000 $000
Profit before taxation 66,791 6,589
--------------------------------------------------- ------- -------
Tax charge at UK tax rate of 19.00% (2017: 19.25%) 12,690 1,268
Tax effects of:
Lower foreign corporate tax rates in Ukraine
(18%) (58) (33)
Disallowed expenses and non-taxable income 543 (2,905)
Changes in tax losses previously not recognised
as deferred tax asset (1,511) 4,455
Adjustments in respect of prior periods 821 1,516
--------------------------------------------------- ------- -------
Total tax expense for the year 12,485 4,301
The tax effect of disallowed expenses and non-taxable income are
mainly represented by foreign exchange differences of Regal
Petroleum Corporation (Ukraine) Limited.
The tax effect losses not recognised as deferred tax assets are
mainly represented by accumulated losses of Regal Petroleum
Corporation (Ukraine) Limited.
15. Profit for the Year
The Company has taken advantage of the exemption allowed under
section 408 of the Companies Act 2006 and has not presented its own
Income Statement in these financial statements. The Group profit
for the year includes Parent Company profit after tax of
$12,057,000 for the year ended 31 December 2018 (2017:
$12,239,000).
16. Earnings per Share
The calculation of basic profit per ordinary share has been
based on the profit for the year and 320,637,836 (2017:
320,637,836) ordinary shares, being the weighted average number of
shares in issue for the year. There are no dilutive
instruments.
17. Property, Plant and Equipment
2018 2017
Oil and Gas
Development Oil and Gas Oil and Gas
and Production Exploration Development
assets and Evaluation Other fixed and Production Other fixed
Ukraine Assets assets Total assets Ukraine assets Total
Group $000 $000 $000 $000 $000 $000 $000
Cost
At beginning of year 101,927 - 1,104 103,031 100,490 902 101,392
Additions 7,967 1,259 326 9,552 3,749 275 4,024
Change in
decommissioning
provision (66) - - (66) 1,119 - 1,119
Disposals (23) - (125) (148) (48) (13) (61)
Write-off of assets (6,328) - - (6,328) - - -
Exchange differences 1,332 - (12) 1,320 (3,383) (60) (3,443)
---------------------- --------------- --------------- ----------- -------- --------------- ----------- -------
At end of year 104,809 1,259 1,293 107,361 101,927 1,104 103,031
---------------------- --------------- --------------- ----------- -------- --------------- ----------- -------
Accumulated depreciation and
impairment
At beginning of year 87,591 - 478 88,069 79,649 389 80,038
Charge for year 6,818 - 169 6,987 10,812 119 10,931
Reversal of
impairment (36,117) - - (36,117) - - -
Impairment charged
for individual
assets 1,648 - - 1,648 180 - 180
Disposals (7) - (42) (49) (21) (11) (32)
Write-off of assets (6,328) - - (6,328) - - -
Exchange differences 2,962 - (3) 2,959 (3,029) (19) (3,048)
---------------------- --------------- --------------- ----------- -------- --------------- ----------- -------
At end of year 56,567 - 602 57,169 87,591 478 88,069
---------------------- --------------- --------------- ----------- -------- --------------- ----------- -------
Net book value at
beginning
of year 14,336 - 626 14,962 20,841 513 21,354
---------------------- --------------- --------------- ----------- -------- --------------- ----------- -------
Net book value at end
of
year 48,242 1,259 691 50,192 14,336 626 14,962
---------------------- --------------- --------------- ----------- -------- --------------- ----------- -------
MEX-GOL and SV gas and condensate fields
As described in Note 4, as at 30 June 2018, the Group determined
the recoverable amount of its oil and gas development and
production assets at the MEX-GOL and SV fields based on a FVLCD
approach using a discounted cash flow methodology, where the cash
flows were derived based on estimates that a typical market
participant would use in valuing such assets. This resulted in the
reversal of the previously accumulated impairment loss of
$36,117,000 recorded as income in 2018.
The key assumptions on which the Group has based its
determination of FVLCD for its oil and gas development and
production assets at the MEX-GOL and SV fields and to which this
CGU's recoverable amount is most sensitive are described below:
(i) Commodity prices - the model assumes a gas price of
$278/Mm(3) (UAH7,290/Mm(3) ) during 2018 - 2042 for the MEX-GOL and
SV fields. The prices were estimated based on the price of recent
Group transactions and the forecast of natural gas price dynamics
for Europe published by the World Bank.
(ii) Discount rate - reflects the current market assessment of
the time value of money and risks specific to the assets. The
discount rate has been determined as the post-tax weighted average
cost of capital based on observable inputs and inputs from third
party financial analysts. For 2018 and onwards, the discount rate
applied was 15.1% (13.8% during previous measurement of the
recoverable amount as at 31 December 2016). The discount rate and
future cash flows are determined in real terms, i.e. they do not
take into account the impact of the estimated commodity price index
during the period of projection.
(iii) Production levels and Reserves - production levels at the
MEX-GOL and SV fields are derived from the estimate of remaining
proven plus probable reserves of 50.0 MMboe assessed in the report
prepared by D&M as at 31 December 2017. This report includes
estimated production volumes, including from new wells, over the
remaining economic life of the MEX-GOL and SV fields. The estimated
production is based on the Group's revised field development plan,
which includes the drilling of 24 new wells. Estimating oil and gas
reserves is a complex process requiring the knowledge and
experience of a reservoir engineer. The quality of the estimate of
proved plus probable reserves depends on the availability,
completeness, and accuracy of data needed to develop the estimate,
including production history available, and on the experience and
judgement of the reservoir engineer. Estimates of proved plus
probable reserves inevitably change over time as additional data
become available and are taken into account. The magnitude of
changes in these estimates is often substantial.
(iv) Production taxes - for existing wells, the Group assumed
production tax rates of 29% for gas and 45% for condensate
extracted from deposits up to depths of 5,000 metres and 14% for
gas and 21% for condensate extracted from deposits deeper than
5,000 metres. From 1 January 2019, production tax rates for
condensate produced from all wells was reduced from 45% to 29% for
condensate produced from deposits above 5,000 metres and from 21%
to 14% for condensate produced from deposits below 5,000 metres.
For new wells drilled after 1 January 2018, production tax rates
were reduced to 12% for gas produced from deposits at depths above
5,000 metres and to 6% for gas produced from deposits below 5,000
metres, effective for the period 2018 - 2022.
(v) Capital expenditure - the Group assumed that capital
expenditure of $229,774,000 will be incurred during the period from
the second half of 2018 - 2042 under the revised field development
plan for the MEX-GOL and SV fields.
(vi) Life of field - the current licences for the MEX-GOL and SV
fields, which are due to expire in July 2024, can be extended under
applicable legislation in Ukraine until the end of the economic
life of the fields, which is assessed to be 2038 for the MEX-GOL
field and 2042 for the SV field, based on the assessment contained
in the D&M report. No application for such extensions have been
made at the date of this report, but the Group considers the
assumptions to be reasonable based on its intention to seek such
extensions in due course and that the Group is legally entitled to
request such extensions. However, if the extensions were not to be
granted, it would result in a further reduction of $128,953,000 in
the recoverable amount for these fields.
There are no reasonably possible changes in key assumptions on
which the Group has based its determination of the MEX-GOL and SV
CGU's recoverable amount, which could cause a change in the amount
of the reversal of previously accumulated impairment recorded in
the first half of 2018.
As described in Note 4, the Group has also recorded a $1,648,000
impairment loss on an individual basis in respect of the SV-69 well
in 2018.
Notwithstanding the reversal of impairment recorded at 30 June
2018, at 31 December 2018, the Group performed an assessment of
external and internal indicators to ascertain whether there was any
indication of potential impairment. Based on the analysis
performed, the Group concluded that no external or internal
impairment indicators existed as at 31 December 2018, and
accordingly no impairment testing was required as at that date.
During the 2018 year, the SV-69 well was abandoned, and was
fully depreciated and its cost of $6,328,000 was charged to
accumulated depreciation and impairment.
VAS gas and condensate fields
At 31 December 2018, the Group performed an assessment of
external and internal indicators to ascertain whether there was any
indication of potential impairment. Based on the analysis
performed, the Group concluded that no external or internal
impairment indicators existed as at 31 December 2018, and
accordingly no impairment testing was required as at that date.
During the 2018 year, the Group commenced acquisition of new 3D
seismic over the VAS field which will assist in the evaluation of
the VAS licence, and particularly the VED area of the licence.
Since no commercially viable reserves have been identified in the
VED area as yet, the costs of the seismic over this area were
capitalised within property, plant and equipment as exploration and
evaluation assets.
18. Intangible Assets
2018 2017
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 6,618 257 6,875 6,832 144 6,976
Additions - 107 107 - 150 150
Disposals - (36) (36) - (26) (26)
Exchange differences 91 2 93 (214) (11) (225)
----------------------- -------- ---------------- ------ -------- ----------- ------
At end of year 6,709 330 7,039 6,618 257 6,875
----------------------- -------- ---------------- ------ -------- ----------- ------
Accumulated amortisation and
impairment
At beginning of year 1,161 124 1,285 393 53 446
Charge for year 804 105 909 822 104 926
Disposals - (35) (35) - (26) (26)
Exchange differences - - - (54) (7) (61)
----------------------- -------- ---------------- ------ -------- ----------- ------
At end of year 1,965 194 2,159 1,161 124 1,285
----------------------- -------- ---------------- ------ -------- ----------- ------
Net book value at
beginning of year 5,457 133 5,590 6,439 91 6,530
----------------------- -------- ---------------- ------ -------- ----------- ------
Net book value at
end of year 4,744 136 4,880 5,457 133 5,590
----------------------- -------- ---------------- ------ -------- ----------- ------
Intangible assets consist mainly of the hydrocarbon production
licence relating to the VAS gas and condensate 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 licence
until 2024.
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 if impairment indicators exist. As at 31
December 2018, no impairment indicators were identified.
19. Investments and Loans to Subsidiary Undertakings
Shares in Loans to
subsidiary subsidiary
undertakings undertakings Total
$000 $000 $000
Company
At 1 January 2017 17,279 35,669 52,948
Additions including accrued interest - 3,886 3,886
Repayment of interests and loans - (12,450) (12,450)
Reversal of impairment of loans
to subsidiary - 6,360 6,360
Exchange differences - 4,760 4,760
------------------------------------- ------------- ------------- --------
At 31 December 2017 17,279 38,225 55,504
------------------------------------- ------------- ------------- --------
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
------------------------------------- ------------- ------------- --------
The Company has recorded a gain of $10,923,000, 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 2018 (Note 4).
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.
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)
Additions
including
accrued
interest - - - - - - 6,301 6,301
Repayment 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 - 13,753 13,753 - - (4,426) (4,426)
----------------- ------------------ ------------- -------------- ------------- ---------------- ---------- ---------- --------
At 31 December
2018 - - (177,925) (177,925) - - 225,477 225,477
----------------- ------------------ ------------- -------------- ------------- ---------------- ---------- ---------- --------
ECL - Expected credit losses
SICR - Significant increase in credit risk
Subsidiary undertakings
At 31 December 2018, 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%
162 Shevchenko
Str., Yakhnyky
Village,
Lokhvytsya
District, Poltava
Refin Limited Region, 37212 Ukraine Ukraine Service Company 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, Refin Limited is
controlled through its 100% ownership by Regal Petroleum (Jersey)
Limited and Regal Petroleum Corporation (Ukraine) Limited, and LLC
Prom-Enerho Produkt 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
2018.
20. Inventories
Group
2018 2017
$000 $000
Current
Materials and spare parts 1,437 1,178
Finished goods 168 216
-------------------------- -------- -------
1,605 1,394
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 2018,
production raw materials and fuel at the storage facility. Finished
goods as at 31 December 2018 consist of produced condensate and LPG
held at the processing facility prior to sale (2017: consist of
produced gas held in underground gas storage facilities and
condensate and LPG held at the processing facility prior to
sale).
All inventories are measured at the lower of cost or net
realisable value. There was no write down of inventory as at 31
December 2018 (2017: $179,000).
21. Trade and Other Receivables
Group Company
2018 2017 2018 2017
$000 $000 $000 $000
Trade receivables 5,012 2,582 - -
Other financial receivables 202 50 - 464
Less credit loss allowance (99) (90) - -
---------------------------------- --------- ------- --------- ---------
Total financial receivables 5,115 2,542 - 464
Prepayments and accrued
income 4,771 3,633 64 31
Other receivables 244 361 74 52
---------------------------------- --------- ------- --------- ---------
Total trade and other receivables 10,130 6,536 138 547
Due to the short-term nature of the current trade and other
receivables, their carrying amount is assumed to be the same as
their fair value. All trade receivables except provided for are
considered to be of high credit quality.
At 31 December 2018, the Group's total trade receivables
amounted to $4,918,000 and 100% were denominated in Ukrainian
Hryvnia (31 December 2017: $2,492,000 and 100% were denominated in
Ukrainian Hryvnia). Further description of financial receivables is
disclosed in Note 30.
The majority of the trade receivables are from a related party,
LLC Smart Energy, that purchases all of the Group's gas production
(see Note 32). The applicable payment terms are payment for one
third of the estimated monthly volume of gas by the 20th 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
$3,988,000 relating to the development of the MEX-GOL field (31
December 2017: $3,130,000 relating to the development of the VAS
field).
Analysis by credit quality of financial trade and other
receivables and expected credit loss allowance as at 31 December
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:
Credit loss Total
allowance
$000 $000
Trade receivables
Balance at 1 January 2018 (adjusted) 152 152
New originated or purchased 7 7
Financial assets derecognised during the
period (3) (3)
Changes in estimates and assumptions (59) (59)
Foreign exchange movements 2 2
------------------------------------------ ------------ ------
Balance at 31 December 2018 99 99
Analysis by credit quality of financial trade and other
receivables as at 31 December 2017 is as follows:
Group
2017
$000
Neither past due nor impaired
Trade receivables 2,492
Other financial receivables 62
------------------------------------------------ ------
Total neither past due nor impaired 2,542
Individually determined to be impaired (gross)
* over 360 days overdue 90
------------------------------------------------ ------
Total individually impaired 90
Less impairment provision (90)
------------------------------------------------ ------
Total trade receivables at 31 December 2017 2,542
Movements in the impairment provision for trade receivables
during 2017 are as follows:
Group
2017
$000
Provision for impairment at 1 January 2017 64
Provision charge for impairment during the year 31
Exchange differences (5)
------------------------------------------------- ------
Provision for impairment at 31 December 2017 90
22. Cash and Cash Equivalents and Other Short-term
Investments
Group Company
2018 2017 2018 2017
$000 $000 $000 $000
Cash and Cash Equivalents
Cash at bank and on hand 24,462 1,736 23,990 332
Demand deposits and term deposits
with maturity less than 3 months 24,791 12,513 - 4,079
Short-term government bonds 3,969 - - -
53,222 14,249 23,990 4,411
Other short term investments
Term deposits with maturity more
than 3 months - 16,000 - 16,000
- 16,000 - 16,000
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.
In December 2018, the Group acquired 4,000 short-term government
bonds from the Ministry of Finance of Ukraine with a nominal value
$1,000 each, at a discount for $996.06, which were held to maturity
at the end of January 2019.
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 Term deposits
Cash at with maturity Short-term Total cash with maturity Total other
bank and less than government and cash more than short term
on hand 3 months bonds equivalents 3 months investments
2018 2018 2018 2018 2018 2018
$000 $000 $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 - -
Demand deposits
and term
deposits Term deposits
Cash at with maturity Short-term Total cash with maturity Total other
bank and less than government and cash more than short term
on hand 3 months bonds equivalents 3 months investments
2017 2017 2017 2017 2017 2017
$000 $000 $000 $000 $000 $000
A- to A+
rated 691 4,079 - 4,770 16,000 16,000
B- to B+
rated - 7,241 - 7,241 - -
Unrated 1,045 1,193 - 2,238 - -
1,736 12,513 - 14,249 16,000 16,000
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 2018
for non-rated banks. Based on this assessment, the Group concluded
that the identified impairment loss was immaterial.
23. Trade and Other Payables
2018 2017
$000 $000
Accruals and other payables 2,314 1,369
Taxation and social security 2,312 965
Trade payables 105 67
Advances received 105 22
4,836 2,423
Accruals and other payables mainly consist of payables of
$773,000 relating to the rent of the SV-2 and SV-12 wells (31
December 2017: $232,000 relating to the rent of the SV-2 well).
The carrying amounts of trade and other payables are assumed to
be the same as their fair values, due to their short-term nature. A
description of financial payables is disclosed in Note 30.
24. Provision for Decommissioning
2018 2017
$000 $000
Group
At beginning of year 3,027 1,915
Amounts (utilised)/provided (16) 139
Unwinding of discount 140 112
Change in estimate (50) 980
Effect of exchange difference 36 (119)
------------------------------ ------ ------
At end of year 3,137 3,027
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.
The non-current provision of $3,137,000 (31 December 2017:
$3,027,000) 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 2018 is explained in Note 4.
The principal assumptions used are as follows:
31 December 2018 31 December 2017
Discount rate, % 8.14% 4.70%
Average cost of restoration per well, $000 357 179
-------------------------------------------- ----------------- -----------------
The sensitivity of the restoration provision to changes in the
principal assumptions is presented below:
31 December 2018 31 December 2017
$000 $000
Discount rate (increase)/decrease by 1% (313)/371 (344)/403
Change in average cost of restoration increase/ (decrease) by 10% 219/(219) 197/(197)
------------------------------------------------------------------- ----------------- -----------------
25. Deferred Tax
2018 2017
$000 $000
Deferred tax asset recognised on tax
losses - Company and Group
At beginning of year 2,567 3,717
Charged to Income Statement - current
year (433) (1,150)
----------------------------------------------------- ------- --------
At end of year 2,134 2,567
2018 2017
$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 6,694 7,404
(Charged)/credited to Income Statement
- current year (5,086) 1,051
Charged to Income Statement - prior year (821) (1,516)
Effect of exchange difference 362 (245)
----------------------------------------------------- ------- --------
At end of year 1,149 6,694
2018 2017
$000 $000
Deferred tax liability recognised relating
mainly to oil and gas development and
production assets - Group
At beginning of year (820) (1,187)
Credited to Income Statement - current
year 333 351
Effect of exchange difference (17) 16
----------------------------------------------------- ------- --------
At end of year (504) (820)
At 31 December 2018, the Group recognised a deferred tax asset
of $2,134,000 in relation to UK tax losses carried forward (31
December 2017: $2,567,000). There was a further $85 million (31
December 2017: $83 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 Directors consider it appropriate to recognise
deferred tax assets resulting from accumulated tax losses at 31
December 2018 to the extent that it is probable that there will be
sufficient future taxable profits.
The deferred tax asset relating to the Group's provision for
decommissioning at 31 December 2018 of $161,000 (31 December 2017:
$127,000) was recognised on the tax effect of the temporary
differences on the Group's provision for decommissioning at the
MEX-GOL and SV gas and condensate fields, and its tax base. The
deferred tax asset relating to the Group's oil and gas development
and production assets at 31 December 2018 of $988,000 (31 December
2017: $6,567,000) 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 gas and
condensate fields, and its tax base.
The deferred tax asset relating to the Group's provision for
decommissioning at 31 December 2018 of $271,000 (31 December 2017:
$277,000) was recognised on the tax effect of the temporary
differences on the Group's provision for decommissioning at the VAS
gas and condensate fields, and its tax base. The deferred tax
liability relating to the Group's oil and gas development and
production assets at 31 December 2018 of $775,000 (31 December
2017: $1,097,000) 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 gas and condensate
fields, 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
2016-2018.
Losses accumulated in a Ukrainian subsidiary service company of
UAH2,856,563,453 ($103,168,745) at 31 December 2018 and
UAH3,130,112,486 ($111,521,999) at 31 December 2017 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 2018 and 2017, 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
A change to the UK corporation tax rate was announced in the
Chancellor's Budget on 16 March 2016. The change announced is to
reduce the main tax rate to 17% from 1 April 2020. Changes to
reduce the UK corporation tax rate to 19% from 1 April 2017 and to
18% from 1 April 2020 were substantively enacted on 26 October
2015. Changes to reduce the UK corporation tax rate to 17% from 1
April 2020 were substantively enacted on 6 September 2016 and the
effect of these changes are included in the consolidated financial
statements.
26. Called Up Share Capital
2018 2017
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.
27. 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.
28. Operating Lease Arrangements
The Group as Lessee
Group Company
2018 2017 2018 2017
$000 $000 $000 $000
Lease payments under operating
leases recognised as an expense
for the year 4,797 973 125 120
--------------------------------- --------- ------- --------- ---------
Lease payments under operating leases recognised as an expense
for year ended 31 December 2018 amounted to $4,797,000 (year ended
31 December 2017: $973,000) and were mainly represented by the
leases of land and wells in Ukraine of $4,474,000 (year ended 31
December 2017: $707,000) and rentals of office properties in
Ukraine and the UK of $323,000 (year ended 31 December 2017:
$266,000). The increase in lease expenses during the year ended 31
December 2018 is mainly attributable to the profit share of NJSC
Ukrnafta relating to the SV-2 and SV-12 wells of $2,650,000 and
$1,803,000 respectively. The agreements for the lease of these
wells are concluded for the entire SV licence term, which expires
in 2024, but can be extended under applicable legislation in
Ukraine until the end of the economic life of the field, which is
assessed to be 2042 based on the assessment contained in the
D&M report. However, it is impracticable to estimate the
outstanding off-balance sheet commitments related to the lease of
wells as at 31 December 2018 as lease payments under these
agreements are determined monthly and are linked to the
changes in benchmark prices and future production from the
leased wells. At the balance sheet date, the Group had outstanding
off-balance sheet commitments for future minimum lease payments
under non-cancellable operating leases mostly for office properties
of $1,884,000 (31 December 2017: $103,000).
At the balance sheet date, the Group had outstanding off-balance
sheet commitments for future minimum lease payments under
non-cancellable operating leases which fall due as follows:
Land and buildings
2018 2017
Group and Company $000 $000
Amounts payable due:
- Within one year 492 103
- After one year 1,392 -
---------------------- ---------- --------
1,884 103
29. Reconciliation of Operating Profit to Operating Cash
Flow
2018 2017
$000 $000
Group
Operating profit 66,370 6,399
(Reversal of impairment)/impairment of property,
plant and equipment (34,469) 180
Depreciation and amortisation 7,901 11,816
Less interest income recorded within operating
profit (3,024) (924)
Fines and penalties received (225) -
Gain on sales of current assets, net (26) (117)
Reversal of loss allowance on other financial
assets (18) -
Gain from write off of non-current assets (21) (15)
Impairment of inventory - 179
Decrease in provisions (11) (5)
Increase in inventory (76) (182)
Increase in receivables (2,487) (403)
Increase in payables 2,428 1,054
Cash generated from operations 36,342 17,982
2018 2017
$000 $000
Company
Operating profit 9,374 4,588
Movement in provisions (including impairment
of subsidiary loans) (10,923) (6,360)
Increase/(decrease) in receivables 409 (8)
Decrease/(increase) in payables 7 (59)
--------------------------------------------- -------- -------
Cash used in operations (1,133) (1,839)
30. 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, Canadian Dollars
and Ukrainian Hryvnia. The Group does not have any 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
2018 2017
$000 $000
Group
Cash and cash equivalents 53,222 14,249
Other short-term investments - 16,000
Trade and other receivables 5,115 2,542
58,337 32,791
2018 2017
$000 $000
Company
Cash and cash equivalents 23,990 4,411
Other short-term investments - 16,000
Trade and other receivables - 464
Loans to subsidiary undertakings 47,552 38,225
71,542 59,100
Financial Liabilities
2018 2017
$000 $000
Group
Trade payables 105 67
Accruals 1,284 653
----------------------- ------ -----
1,389 720
2018 2017
$000 $000
Company
Accruals 97 90
----------------------- ------ -----
97 90
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.
2018 2017
Currency $000 $000
British Pounds 256 373
Euros 112 5
Canadian Dollars - 2
Net monetary assets less liabilities 368 380
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 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 (decrease of loss for the year ended 31 December
2017 by $55,000 in the event of 0.5% higher interest rates
and increase by $55,000 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 (2017: 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 22.
Liquidity risk for the Group is further detailed under the
Principal Risks and Uncertainties section of the Strategic
Report.
Credit Risk
Credit risk principally arises in respect of the Group's cash
balance and other short-term investments. In the UK, where $24
million of the overall cash and cash equivalents is held (31
December 2017: $4.8 million cash and cash equivalents and $16
million other short-term investments), the Group only deposits cash
surpluses with major banks of high quality credit standing (Note
22). As at 31 December 2018, the remaining balance of $25.3 million
of cash and cash equivalents and $4 million of other short-term
investments was held in Ukraine (31 December 2017: $9.4 million).
In April 2018 Standard & Poor's affirmed Ukraine's sovereign
credit rating of "B-/B", Outlook Stable. There is no international
credit rating information available for the specific banks in
Ukraine where the Group currently holds its cash and cash
equivalents.
The significant historic devaluation of the Ukrainian Hryvnia
has resulted in the National Bank of Ukraine, among other measures,
imposing comprehensive restrictions on the processing of client
payments by banks, on the purchase of foreign currency on the
inter-bank market and on the remittance of funds outside Ukraine.
These restrictions, and the many other economic issues in Ukraine,
have put great strain on the Ukrainian banking system, with
increasing risks in the capital strength, liquidity and
creditworthiness of a large number of Ukrainian banks, and very
high rates in the wholesale and overnight markets. In addition,
there have been significant deposit outflows from the banking
system and widespread restructuring of bank clients' maturing
liabilities. Furthermore, as a result of recommendations from the
International Monetary Fund, significant reforms to the Ukrainian
banking sector are being implemented, which are intended to
strengthen the capitalisation of the Ukrainian banks.
In light of the deterioration in the banking sector in Ukraine,
the Group has taken steps to diversify its banking arrangements
between a number of banks in Ukraine. These measures are designed
to spread the risks associated with each bank's creditworthiness,
but the Ukrainian banking sector remains weakly capitalised and so
the risks associated with the banks in Ukraine remain significant,
including in relation to the banks with which the Group operates
bank accounts.
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 2018 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
2018 2018 2018 2017 2017 2017
$000 $000 $000 $000 $000 $000
Canadian Dollars - - - 2 2 -
Euros 44 44 - 5 5 -
British Pounds 215 215 - 536 536 -
Ukrainian Hryvnia 25,264 - 25,264 9,479 - 9,479
US Dollars 27,699 23,730 3,969 20,227 4,227 16,000
53,222 23,989 29,233 30,249 4,770 25,479
Cash deposits included in the above balances comprise short-term
deposits.
As at 31 December 2018, cash and cash equivalents of the Company
of $24 million are held in US Dollars at a floating rate (2017: $4
million).
Interest Rate Risk Profile of Financial Liabilities
As at 31 December 2018 and 2017, 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:
2018 2017
$000 $000
Group
In one year or less 1,389 720
--------------------- ----- ----
1,389 720
2018 2017
$000 $000
Company
In one year or less 97 90
--------------------- ----- ----
97 90
Borrowing Facilities
As at 31 December 2018 and 2017, the Group did not have any
borrowing facilities available to it at the year end.
Fair Value of Financial Assets and Liabilities
The fair value of all financial instruments is not materially
different from the book value.
31. Contingencies and Commitments
Amounts contracted in relation to the Group's 2018 investment
programme in the MEX-GOL, SV and VAS gas and condensate fields in
Ukraine, but not provided for in the financial statements at 31
December 2018, were $2,607,000 (2017: $3,151,000).
During 2010 - 2018, 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 UAH 8,487,000
($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 as 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
2018 (31 December 2017: nil).
32. Related Party Disclosures
Key management personnel of the Group are considered to comprise
only the Directors. Details of Directors' remuneration are
disclosed in Note 9.
During the year, Group companies entered into the following
transactions with related parties who are not members of the
Group:
2018 2017
$000 $000
Sale of goods / services 49,691 25,030
Purchase of goods / services 508 369
Amounts owed by related parties 4,912 2,509
Amounts owed to related parties 35 30
--------------------------------- -------- --------
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 2018, the Company's immediate parent company
was Pelidona Services Limited, which is 100% owned by Lovitia
Investments Limited, which is 100% owned by Mr V Novynskyi.
Accordingly, the Company was ultimately controlled by Mr V
Novynskyi.
The Group operates bank accounts in Ukraine with a related party
bank, Unex Bank, which is ultimately controlled by Mr V Novynskyi.
There were the following transactions and balances with Unex Bank
during the year:
2018 2017
$000 $000
Interest income 1 -
Bank charges 21 56
Closing cash balance (as at 31 December) 20 6
The bank charges represent cash transit fees.
At the date of this report, none of the Company's controlling
parties prepares consolidated financial statements available for
public use.
33. Post Balance Sheet Events
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 for condensate
were reduced from 45% to 31% for condensate produced from deposits
above 5,000 metres and from 21% to 16% for condensate produced from
deposits below 5,000 metres.
On 21 February 2019, the Group announced the spud of the MEX-119
well at the MEX-GOL field. The well has a target depth of 4,850
metres, with drilling operations scheduled to be completed by
September 2019 and, subject to successful testing, production
hook-up during the fourth quarter of 2019.
The Group has commenced reassessment of the remaining reserves
and resources at the VAS field as at 1 January 2019, which
reassessment is being undertaken by an independent petroleum
reserves consultant.
On 4 March 2019, the Group disposed of its 100% shareholding in
Refin LLC to a company under common control.
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 the 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 a
hearing of the substantive issues of the case to be held in due
course. 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. 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 anticipate any
negative effects on its operations in respect of the matter.
34. Accounting policies before 1 January 2018
Accounting policies applicable to the comparative period ended
31 December 2017 that were amended by IFRS 9 and IFRS 15, are as
follows:
Classification of financial assets. The Group classifies its
financial assets into loans and receivables.
Loans and receivables include financial receivables created by
the Group by providing money, goods or services directly to a
debtor, other than those receivables which are created with the
intention to be sold immediately or in the short term, or which are
quoted in an active market. Loans and receivables comprise
primarily loans, trade and other accounts receivable.
Classification of financial liabilities. The Group classifies
its financial liabilities as other financial liabilities carried at
amortised cost.
Initial recognition of financial instruments. The Group's
principal financial instruments comprise trade debtors and trade
creditors, loans and borrowings and cash and cash equivalents. The
Group's financial assets and liabilities are initially recorded at
fair value plus 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.
All purchases and sales of financial instruments 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 that the Group commits to deliver a
financial instrument. All other purchases and sales are recognised
on the settlement date with the change in value between the
commitment date and settlement date not recognised for assets
carried at cost or amortised cost.
Subsequent measurement of financial instruments. Subsequent to
initial recognition, the Group's financial liabilities, loans and
receivables are measured at amortised cost. Amortised cost is
calculated using the effective interest rate method and, for
financial assets, it is determined net of any impairment losses.
Premiums and discounts, including initial transaction costs, are
included in the carrying amount of the related instrument and
amortised based on the effective interest rate over the expected
life of the instrument. The face values of financial assets other
than non-interest bearing loans, and of financial liabilities with
a maturity of less than one year, less any estimated credit
adjustments, are assumed to be their fair values. The fair value of
financial liabilities is estimated by discounting the future
contractual cash flows at the current market interest rate
available to the Group for similar financial instruments.
In assessing the fair value of financial instruments, the Group
uses a variety of methods and makes assumptions based on market
conditions existing at the reporting date. A provision for
impairment of loans and accounts receivable is established when
there is objective evidence that the Group will not be able to
collect all amounts due according to the original terms. The amount
of the provision is the difference between the asset's carrying
amount and the present value of estimated future cash flows
discounted at the financial asset's original effective interest
rate. The amount of the provision is recognised in the profit or
loss.
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 net carrying amount of the financial 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.
Derecognition of financial assets. The Group derecognises
financial assets when (i) the assets are redeemed or the rights to
cash flows from the assets have otherwise expired, or (ii) the
Group has transferred substantially all the risks and rewards of
ownership of the assets, or (iii) the Group has neither transferred
nor retained substantially all risks and rewards of ownership but
has not retained control. Control is retained if the counterparty
does not have the practical ability to sell the asset in its
entirety to an unrelated third party without needing to impose
additional restrictions on the sale.
Revenue recognition. Revenues from sales of goods are recognised
at the point of transfer of risks and rewards of ownership of the
goods, normally when the goods are shipped. If the Group agrees to
transport goods to a specified location, revenue is recognised when
the goods are passed to the customer at the destination point.
Sales of services are recognised in the accounting period in which
the services are rendered, by reference to stage of completion of
the specific transaction assessed on the basis of the actual
service provided as a proportion of the total services to be
provided.
Revenues from natural gas and condensate are stated gross of
production taxes. Sales are shown net of VAT and discounts.
Revenues are measured at the fair value of the consideration
received or receivable. When the fair value of goods received in a
barter transaction cannot be measured reliably, the revenue is
measured at the fair value of the goods or service given up.
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.
END
FR GMGZDVLDGLZM
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April 30, 2019 02:00 ET (06:00 GMT)
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