TIDMVGAS
RNS Number : 9832I
Volga Gas PLC
07 April 2020
7 April 2020
VOLGA GAS PLC
Preliminary results for the year ended 31 December 2019
Volga Gas plc ("Volga Gas", the "Group" or the "Company"), the
oil and gas exploration and production group operating in the Volga
region of Russia, announces its preliminary, unaudited annual
results for the year ended 31 December 2019.
The Group has recognised a 48% reduction in its oil, gas and
condensate reserves following the discovery of unexpectedly high
water levels in the main producing reservoir of the Vostochny
Makarovskoye ("VM") field. The main strategic objective of the
Company at this stage is to re-build its reserve and production
base and re-establish a growth profile. Management believes the
Company has the financial stability and resources to withstand
current challenges and pursue this objective.
In spite of reduced output from VM during H2 2019, the Group's
production was only slightly below that of 2018. Gross revenues
were level whilst EBITDA was 6% below 2018. The reserve reduction
and unsuccessful sidetracks to the VM2 and Uzen4 wells led to
one-off expenses for impairment and asset write offs totalling
US$10.9 million, as well as increased depletion charges. These were
the main contributing factors to the loss before tax of US$10.5
million reported today.
In common with many companies in the oil industry and several
economic sectors worldwide, we currently face the significant
additional challenges operationally and financially set by the
Covid-19 pandemic. Our immediate priority has been to modify our
operations so as to protect the health of our employees,
contractors and customers; and to follow all government mandated
measures. To date, our production operations and markets for our
products are not significantly affected, but we clearly recognise
the possibility that this may happen. The impact on oil prices,
exacerbated by competition between major oil producing countries in
light of falling global demand for oil, is already apparent.
However, we entered this crisis in a position of financial
strength, with a cash balance of US$14.1 million and no debt. Our
capital expenditures are almost entirely discretionary and can be
delayed or cancelled as necessary and we have taken action to
reduce the fixed costs of the business. Management is determined to
enable the Group to survive the current crisis and to re-build the
reserves and production for the benefit of shareholders.
Further, the Board has decided to conduct a formal review of the
various strategic options available to the Company to maximise
value for shareholders. Accordingly, the Company has today
separately announced a strategic review including formal sale
process under the City Code on Takeovers and Mergers and
established a special committee comprised of its independent
non-executive directors to oversee this process.
FINANCIAL RESULTS FOR 2019
-- Sales volumes down 2% to 4,871 boepd (2018: 4,956 boepd).
-- Gross revenues flat at US$46.0 million (2018: US$45.9 million).
-- Netback revenues (after export taxes and transport costs)
down 3% to US$42.2 million (2018: US$43.4 million), as more
condensate was exported in 2019.
-- EBITDA down 6% to US$15.9 million (2018: US$16.9 million).
-- EBITDA per barrel of oil equivalent sold was US$8.93 per boe (2018: US$9.36 per boe).
-- Gross profit of US$9.6 million (2018: US$16.3 million) as
depletion charges increased to US$14.9 million (2018: US$8.2
million).
-- Net cash flow from operations of US$15.0 million (2018: US$18.3 million).
-- One-off charges including impairment of US$8.3 million (2018:
nil) and write off of development assets of US$2.6 million (2018:
US$1.5 million), leading to an operating loss of US$9.9 million
(2018: profit of US$10.3 million).
-- Net cash of US$14.1 million as at 31 December 2019 (31
December 2018: US$13.5 million) after utilising US$9.6 million for
capital expenditure (2018: US$2.2 million), loan repayments of
US$1.7 million (2018:US$1.8 million), paying US$5.2 million in
equity dividends (2018: US$4.9 million) and purchase of own shares
for US$159,000 (2018: nil).
-- Debt free as at 31 December 2019 (31 December 2018 borrowings of: US$1.7 million).
PRODUCTION & DEVELOPMENT
-- Group average production in 2019 decreased 4.0% to 4,927 boepd (2018: 5,144 boepd).
-- At the VM field unsuccessful sidetracks led to reduced output
during H2 2019 and a reservoir study culminating in a 73% reduction
in reserves. Production from VM and Dobrinskoye in 2019 averaged
4,500 boepd (2018: 4,537 boepd).
-- At the Uzen field, drilling of slim hole wells commenced
during 2019, with six wells completed by the end of the year.
These, and additional slim hole wells completed more recently are
to be brought into production in 2020. Oil production averaged at
427 bopd in 2019 (2018: 607 bopd).
-- New reserves were discovered with a slim hole well in Upper
Aptian reservoir of the Uzen field. These reserves will be
quantified with appraisal drilling in 2020.
DOBRINSKOYE GAS PLANT
-- Improvements in the operation of the Redox based gas
sweetening enabled steady gas throughput and minimal unplanned
operational downtime in 2019.
-- An upgrade of the LPG extraction plant was completed in
during 2019 with the installation of a turbo compressor to improve
extraction rates.
DIVID
-- The Company paid a final dividend of US$0.065 per share for
2018 on 28 May 2019. The Board is not recommending a final dividend
in respect of 2019 and does not expect to declare dividends in
2020.
COVID-19 RESPONSE
Whilst our operations to date have seen little direct
operational impact from the Covid-19 pandemic, , we have focused on
implementing measures to ensure the safety of our employees and
contractors, the integrity of our operational facilities and to
prepare the business to face potential challenges that emerge. The
potential impacts are currently unknown but could include
production disruption due to government restrictions or customer
sales, impact on our workforce and supply chain disruption.
The Group has implemented the following actions to mitigate the
risks associated with the Covid-19 pandemic:
-- Majority of office staff are working from home with meetings conducted online.
-- Working shifts extended for field staff to minimise travel by the workforce.
-- Safe distancing guidelines and sanitising initiatives
implemented across office and operating facilities.
-- All business travel suspended.
-- Forward purchased catering to maintain buffer stock for field
canteens. Work underway to build a six month inventory of
production consumables to mitigate possible lack of supply or
logistics issues.
CURRENT TRADING AND OUTLOOK
-- Between January and March 2020, Group production averaged
4,203 boepd, in line with management's plan. During the quarter,
the Ruble has declined in value in tandem with oil prices, which
has impacted the US$ equivalent for gas sales. The average sales
prices for oil and condensate have declined with the international
market, averaging US$36.79 per barrel in 1Q 2020 and US$26.47 in
March 2020.
-- In the absence of any disruptions resulting from Covid-19 or
any other causes, management plans production to average close to
4,500 boepd in 2020. Achievement of these production rates depends
on the successful completion of development drilling, primarily on
the Uzen field, and may be impacted by delays in the execution of
the drilling programme.
-- Oil prices collapsed as a result of competition among major
producing countries and OPEC following the reduction in demand
caused by Covid-19. It is uncertain when and how rapidly oil prices
may recover in the course of the year, although there has been a
recent rally and forward prices are significantly higher than spot
prices for Brent oil and other key marker crude oils.
-- As at 31 December 2019, the Group budgeted capital
expenditure of US$8.3 million for 2020, of which only US$0.6
million is currently contracted. The remaining capital investments
can be delayed or cancelled as necessary to preserve the Group's
liquidity.
-- The Board has considered the Group's cash flow projections
under various scenarios including extended period of oil prices at
current levels and extended shut-ins of production for up to six
months and have concluded that it remains a going concern.
Audited results will be issued pending the completion of the
forensic examination, to be performed by external consultants, as
noted in the Chairman's statement below, and its review by the
Board of Directors and the Company's auditors KPMG.
Andrey Zozulya, Chief Executive of Volga Gas, commented:
"The financial results we are reporting today are satisfactory,
in spite of the adverse operating results and the downgrade to the
reserves in the VM field, and we are pleased that Volga Gas has the
financial strength to withstand the additional challenges posed by
the Covid-19 pandemic.
At this time, our first priority is the health and safety of all
the people who work for and with Volga Gas. We are also determined
to play our part in protecting the communities in which we
operate.
The Group remains cash flow positive at an operational level at
current oil prices, assuming no extensive disruptions, and thanks
to our strong balance sheet and our ability to delay or cancel
capital investment projects as necessary, the Board is confident
that the Group will be able to withstand the current crisis and
continue as a viable business for the long term.
We remain positive about the potential for the Group to rebuild
its reserves and production from our existing licences. We will
also continue to seek value accretive opportunities, beyond our
existing licence areas, building a focused exploration and
production business for the long term benefit of our
shareholders."
Market Abuse Regulation (MAR) Disclosure
Certain information contained in this announcement would have
been deemed inside information for the purposes of Article 7 of
Regulation (EU) No 596/2014 until the release of this
announcement.
For additional information please contact:
Volga Gas plc
+7 (903) 385 9889
Andrey Zozulya, Chief Executive Officer +7 (905) 381 4377
Vadim Son, Chief Financial Officer +44 (0)7824 884
Tony Alves, Investor Relations Consultant 342
+44 (0) 20 3470
S.P. Angel Corporate Finance LLP 0470
Richard Morrison, Richard Hail, Soltan Tagiev
+44 (0)20 3727
FTI Consulting 1000
Alex Beagley , Fern Duncan
Editors' notes:
Volga Gas is an independent oil and gas exploration and
production company operating in the Volga region of European
Russia. The Company has 100% interests in its four licence areas.
The information contained in this announcement has been reviewed
and verified by Mr. Andrey Zozulya, Director and Chief Executive
Officer of Volga Gas plc, for the purposes of the Guidance Note for
Mining, Oil and Gas companies issued by the London Stock Exchange
in June 2009. Mr. Andrey Zozulya has a degree in Geophysics and
Engineering from the Groznensky Oil & Gas Institute and is a
member of the Society of Petroleum Engineers.
Availability of report and accounts and investor
presentation
The Group's full report and accounts and the notice of the
annual general meeting of the Company will be dispatched to
shareholders as soon as is practicable. Copies will also be
available on the Company's website www.volgagas.com and on request
from the Company at, 6(th) floor, 65 Gresham Street, London EC2V
7NQ. The latest presentation for investors is also available on the
Company's website.
Glossary
Bpd/ Bopd Barrels per day /Barrels of oil per day
Boepd Barrels of oil equivalent per day, in which 6,000 cubic
feet of natural gas is equated to one barrel of oil
mcm thousands of standard cubic metres
mcm/d thousands of standard cubic metres per day
mmcf/d millions of standard cubic feet per day
Chairman's Statement
Dear Shareholder,
Overview and Strategy
In 2019, the events of greatest impact operationally and
financially for Volga Gas were at the Group's Vostochny
Makarovskoye ("VM") field. As we announced in July 2019, it was
found that water levels within the main producing reservoir in the
VM field had risen significantly above management's expectations.
An ongoing study on the reservoir was extended into a more
extensive collection of data to enable a production management
strategy to extract the maximum amounts of gas and condensate
possible economically as well as to provide an updated estimate of
the remaining economically recoverable reserves in the field. The
details of the new reserve estimates and the forward plans for the
VM field are covered by the Chief Executive in his Report.
The strategic challenge facing the Company at this stage is to
re-build its reserve and production base and re-establish a growth
profile. The Board and management have identified three key strands
to achieving this:
-- To maximise extraction from the VM field and extend the
field's economic life with optimal reservoir management;
-- To grow the Group's oil business centered on the Uzen field
and exploration in the Karpenskiy licence area in which it sits;
and
-- New business opportunities, both to utilise the Group's gas
processing infrastructure and expertise and to extend the Group's
activities into new areas
I am pleased that Group's financial strength gives us the
opportunity to survive the extreme challenges posed by the Covid-19
pandemic to the entire world economy and to start on the process of
rebuilding the Group's assets. The Chief Executive's report
outlines the actions being taken by management to deal with the
challenges of the pandemic.
Performance in 2019
During 2019 the external conditions for the oil and gas industry
remained generally stable although oil prices on average in 2019
were approximately 10% lower than 2018. Despite challenging
geopolitics, the Ruble and the Russian domestic energy market
conditions were also stable during 2019. The Group has continued to
benefit from the improved operational efficiency at the Dobrinskoye
gas processing plant from switching of the gas sweetening process
in 2018 to a Redox-based system. This is reflected in the lower
operating expense in 2019 than in 2018.
Apart from further minor improvements to the gas processing
facility, a further upgrade to the project for the capture of
liquid petroleum gases ("LPG") was undertaken to improve the
recovery of propane and butane from the gas stream. While the LPG
project as a whole will manifestly generate sufficient additional
revenues to recoup the costs, the final part of the project was
sanctioned before the problems with the VM field became apparent.
Given the now expected curtailment of the economic life of the
field, the additional investment may not be fully recouped by the
extra LPG that produced during the remaining economic field
life.
One of the potentially most important developments in 2019 for
the Group is the application of slim hole drilling. This technique
uses a light weight, truck-mounted drilling rig, of a design that
was originally developed for mineral exploration. These rigs
produce narrow bore holes which can used to develop the relatively
shallow oil and gas deposits in the Group's licences. The key
advantage is economic, as the cost of a producing slim hole well is
typically one-fifth of the cost of a conventional well. Slim hole
wells also provide a highly cost effective means of drilling
exploratory wells, which will be part of the forward strategy of
the Group.
These matters are discussed in greater detail by the Chief
Executive Officer in the Operational Review.
Outlook
The Board and Management are fully committed to responding
robustly to the numerous challenges posed and to start rebuilding
the asset base of the company and profitably deploying the skilled
operational team that has been carefully assembled.
The Board believes that Volga Gas has a stable operational
capability and the financial and operational capacity to withstand
the challenges posed by the Covid-19 pandemic, including potential
disruption to production operations, functioning of markets and the
current significant downturn in oil prices. We expect to emerge
from this and to pursue our recovery and re-growth as outlined in
the strategy statement above.
The Board remains ultimately committed to resuming dividend
distribution, bearing in mind the requirements of the business and
the need to maintain its financial strength. However, the immediate
priority is to preserve and rebuild the Group's finances so as to
re-establish a base of stable longer term production.
We remain determined to provide long-term value for our
shareholders.
Board and Governance
Finally, I would like to update you on the Board. As previously
announced, Ronald Freeman retired from the Board on 31 December
2019. Vladimir Koshcheev has also advised me of his intention to
retire from the Board at the next Annual General Meeting.
Similarly, Michael Calvey will be retiring by rotation and this
time will not be offering himself for re-election. I and my
colleagues express our warm thanks to all three of them for their
contributions to the Board over many years of service. I am
delighted to report the appointments of Stewart Dickson and Andrei
Yakovlev as independent non-executive directors of the Company.
System of internal controls
The Board is carrying out a review of the effectiveness of the
Group's internal control and risk management systems and is
potentially introducing a number of measures to strengthen them.
This work is ongoing.
The Audit Committee is in the process of appointing external
consultants to conduct a forensic examination of the process for
appointment of sales agents, and the manner in which payments to
these agents are calculated. This review will start in the coming
days and the results delivered to the Board as soon as
practicable.
Mikhail Ivanov
Chairman
Chief Executive's Report
As discussed in the Chairman's letter, the most significant
events of 2019 centered on the VM field, where the Company had to
downgrade reserves in the field by 73% and decide on a production
strategy to maximise the economic recovery of hydrocarbons. The
background to this is covered in greater detail in the operations
report and I cover the forward plan later in this Report.
When the logging in VM during H1 2019 indicated much higher than
anticipated levels of gas:water contact in the reservoir, the
management team decided to reduce the production rates in order to
prevent further rapid rise in water encroachment. For this reason,
Group total production in 2H 2019 averaged 4,220 boepd compared to
5,634 boepd in H1 2019, to average 4,927 boepd for 2019 as a whole
(2018: 5,144 boepd), a 4% reduction year on year.
On a more positive note, early in 2019, management identified an
opportunity to utilise slim hole well technology as an advantageous
way of developing relatively shallow hydrocarbon resources.
Initially using a contractor owned slim hole rig, the Company
drilled a six slim hole wells in and around the Uzen oil field.
This was in general a successful undertaking and provided the
drilling team with valuable experience which has been put to use
for the remainder of the programme. In mid-2019, the decision was
taken to acquire a Company-owned slim hole rig at a cost of US$0.7
million, equivalent to approximately 18 months of rig rental. By
the end of 2019, a total of six slim hole wells had been drilled
and three others were in progress.
Based on the experience acquired with slim hole drilling, an
extended drilling programme fully utilizing two rigs has been
proposed comprising 8 new wells during 2020, 6 on Uzen and 2 on VM,
and a further 20 wells during 2021-2022. In addition to the
development drilling programme there are plans for seven
exploratory wells to be drilled on identified structures in the
Group's Karpenskiy licence area. While success with any one of
these cannot be assumed, management is optimistic of being able to
report a measure of success in finding new oil reserves for the
Group. Equally importantly, any newly discovered oil reserves can
be rapidly and cost-effectively brought into production.
Included among the eight production wells included in the slim
hole drilling programme are two new wells on the VM field, which
will be required to produce the identified remaining reserves in
the field, and a new well on the Sobolevskoye field, a small
currently non-producing field in the Group's Urozhainoye-2 licence
area.
While during 2019, the most important aspects of the Group's
activities relate to the sub-surface, additional works were carried
out to improve the operational efficiency of the surface
facilities, most especially at the Dobrinskoye gas processing
plant.
The LPG unit, which was commissioned in May 2018 and has been
operating since then, was upgraded with an additional investment of
approximately US$2.0 million in a turbo expander which has enabled
a greater level of extraction of propane and butane from the gas
stream by achieving lower temperatures in the LPG extraction
vessel. This upgrade was completed in November 2019 with a notable
increase in LPG extraction.
There were also further improvements to the Redox-based
sweetening process to improve the operational efficiency of the
plant, improving the reliability of the process and reducing
operating costs.
In spite of the operational challenges, lower production rates
and lower oil prices than seen in 2018, the Group control costs,
especially overheads. This has enabled the Group to remain cash
flow positive throughout the year and to preserve its financial
strength and provide some cushion to deal with the present
challenges facing the Group. The Financial Review on below sets out
the details.
Medium-term strategy
Management's key objective is to rebuild the Group's reserve and
production base to rebuild asset value and provide a sustainable
profile of profit and cash generation. The key strategic actions
identified with the Board have been set out in the Chairman's
letter above. The specific actions to be undertaken in 2020
are:
-- Drilling of two new production wells on the VM field using
slim hole drilling and to undertake production management studies
to mitigate future formation water production. This is with the aim
of maintaining economic gas production and maximising the
extraction of the remaining reserves.
-- Sustained slim hole development drilling, especially of the
Albian reservoir in the Uzen field to increase oil production.
-- Commence a sustained exploration drilling in the Karpenskiy
licence area during 2020-2021 to test the maximum number of
prospects within the remaining exploration term, with the aim of
discovering material new oil reserves.
-- Business development activities to seek additional gas
throughput on the Dobrinskoye gas plant, including tolling of third
party production; and new licence areas and ventures which can
utilise the skills of the operational and management team.
Current trading and Covid-19 response
Between January and March 2020, Group production averaged 4,203
barrels of oil equivalent per day, in line with management's
expectations. Based on the planned levels of plant uptime and
expected results from the slim hole oil production wells, the
overall production rate anticipated for the whole of 2020 is
between 4,000 and 4,500 boepd.
Whilst our operations to date have seen little direct impact
from the Covid-19 pandemic, we have focused on implementing
measures to ensure the safety of our employees and contractors, the
integrity of our operational facilities and to prepare the business
to face potential challenges that emerge. The potential impacts are
currently unknown but could include production disruption due to
government restrictions or customer sales, impact on our workforce
and supply chain disruption. The actions implemented to mitigate
the risks associated with the Covid-19 pandemic are set out in the
Principal Risks and Uncertainties section. In the current
environment, with significantly lower oil prices and numerous
uncertainties in the global economy, management expects the Group's
financial performance in 2019 to be lower than that of 2018.
Nevertheless, management is confident that the Group's planned
capital expenditure of US$8.3 million will be covered by operating
cash flow and existing liquid resources. The Board is determined to
maintain the Group's financial strength, if necessary by deferring
capital expenditure, while taking the actions to rebuild the
Group's asset value.
Andrey Zozulya
Chief Executive Officer
Operational Review
Operations overview
As outlined above, Group production in 2019, at an average daily
rate of 4,927 boepd, was 4% lower than the 5,144 boepd achieved in
2018. Following higher production in H1 2019, in July the output
from the VM field was significantly reduced following the finding
of higher than anticipated levels of gas:water contact in the
reservoir.
International oil prices were on average approximately 9% lower
with the Urals oil price reaching an average level of US$63.71 per
barrel in 2019 compared to US$69.69 per barrel in 2018.
Nevertheless, the higher proportion of condensate to gas (as
mentioned below) mitigated the impact of lower volumes and lower
pricing on the total sales. Taking into account selling expenses,
netback revenues (defined as revenues less selling expenses as
shown in the Income statements) in 2019 of US$42.2 million were
just 3% lower than the US$43.4 million in 2018. The fall in total
sales volumes and oil prices were cushioned by a higher proportion
of oil and condensate in the product mix.
Overall production costs were lower, with benefits of savings
from improved operational efficiencies. On the other hand, the
scheduled adjustments to the rate formulas led to higher rates of
Mineral Extraction Tax. Consequently EBITDA for 2019 was 6% lower
at US$15.9 million (2018: US$16.9 million).
Gas/condensate production and development
The Dobrinskoye and VM fields are managed as a single business
unit. Production from the fields is processed at the gas plant
located next to the Dobrinskoye field, extracting the condensate
and processing the gas to pipeline standards before input into
Gazprom's regional pipeline system via an inlet located at the
plant. The VM field was developed with wells drilled by Volga Gas,
while the Dobrinskoye wells were acquired from previous
licensees.
Production during 2019 averaged 16.2 mmcf/d of gas and 1,507 bpd
of condensate and 287 bpd of LPG (2018: 18.8 mmcf/d of gas and
1,183 bpd condensate and 223 boepd LPG), a total of 4,500 boepd
(2018: 4,537 boepd). It is notable that while the overall
production volumes of hydrocarbons extracted from the wells
decreased from July 2019, the proportion of condensate increased
such that for the year as a whole, the average total production was
not materially lower on a barrel of oil equivalent basis.
The VM field has three active production wells, VM#1, VM#3 and
VM#4, in the principal reservoir, the Evlano Livinskiy carbonate,
and a further well in the secondary Bobrikovskiy sandstone
reservoir. Smaller volumes were also derived from the Dobrinskoye
#26 well which in January 2019 were revived with a successful
sidetrack.
A sidetrack well that commenced drilling late in 2018 on VM#2
was unsuccessful as several attempts made during early 2019 to cut
off water incursion into the well bore failed. Management
subsequently undertook logging in the VM#3 which showed that the
gas:water contact was higher than previously expected. The Company
appointed Schlumberger Ltd to conduct a comprehensive technical
evaluation and reservoir study on the VM and Dobrinskoye fields.
The study was completed recently and, based on the data
accumulated, a independent re-calculation of remaining reserves was
carried out.
These results indicate total estimates of Proved reserves for
the VM field of 3.2 million barrels of oil equivalent ("mmboe"), a
downward revision of approximately 7.6 mmboe, or 70%. The
preliminary Proved reserves for the Dobrinskoye field, as at 31
December 2019 are 0.4 mmboe, a downward revision of approximately
0.7 mmboe, or 64%.
Two new wells, VM#5 and VM#6 are to planned be drilled during H1
2020 on locations on the eastern flank of the field, where the
recently concluded study indicates there are undepleted resources
of gas and condensate that would be accessed by these wells. These
wells are to be drilled with slim holes to a vertical depth of
approximately 2,000 metres. While this is a greater depth than the
slim hole wells drilled hitherto, management is confident of
achieving its aims. The aim of this is to maintain economic levels
of production to cover the fixed costs of operating the gas
processing facility. On current estimates, this is considered
unlikely to extend beyond mid-2022.
Management estimates production in 2020 from the VM field to be
approximately 10.0 mmcfd of gas plus 1,300 bpd of condensate and
240 boepd of LPG, a total of 3,200 boepd. This rate is consistent
with the strategy of reservoir management adopted after the
detection of water influx in the wells. However, there is a
significant risk that in event of either disruption to our ability
to market condensate or a shortage of manpower to operate the gas
processing plant that may be caused by the Covid-19 pandemic,
production of gas and condensate may need to be curtailed during
the year. While there would be a financial impact, temporary
shut-downs are unlikely to have an impact on the future ability of
the VM wells to produce or on the remaining recoverable reserves in
the field. In addition, the effects of the pandemic may disrupt
plans to drill the new VM wells and may also lead management to
defer the drilling.
Gas, condensate and LPG sales
The Group has been making its gas sales directly to Gazprom
since 2017 and, although there is no long term contract, the
Directors expect the current arrangements to remain in place.
During 2019, the Ruble exchange rate was stable but slightly
weaker than in 2018. Since the gas pricing was fixed in Ruble
terms, in US Dollar terms the average gas sales realisations were
slightly lower in 2019 at US$1.98/mcf (2018: US$1.99), offsetting
the 4% increase in the Ruble sales price.
During 2019, the Group found it advantageous as times to export
its condensate. Consequently condensate exports in 2019 were 34% of
total sales (2018: 12%).
During 2019, the average condensate netback price (after
accounting for export taxes and transportation costs) was US$41.75
per barrel (2018: US$43.32).
LPG commenced on a pilot basis in May 2018. As a result of
production during the full year ended 31 December 2019 total sales
increased by 28% to 8,803 tonnes (2018: 6,903 tonnes). However the
average realisations were lower in 2019 at US$299 (2018:US$412) per
tonne. Our experience is that the selling price of LPG is highly
seasonal. Management hopes to increase selling flexibility in 2020
to gain an improved market position.
The impact of Covid-19 on the domestic market for condensate in
the Volga region of Russia is unpredictable. We will retain a
flexible policy of selling domestically or exporting as necessary.
However, possible disruption to logistics beyond the control of the
Group may impact marketing of both condensate and LPG, which may
lead to temporary shut-downs of production.
Production costs
Average unit production costs on the gas condensate fields
decreased to US$3.78 per boe in 2019 (2018: US$4.21). The decline
in the Ruble, in which effectively all the costs are denominated,
improved throughput rates during 1H 2019 which reduced the impact
of the fixed cost element of the operating expenses and benefits
further operational efficiencies all contributed.
Gas processing plant
Since June 2017, the plant has been operating entirely with
Redox-based gas sweetening. In this time, the process has been
progressively optimised and the efficiency of the process improved.
During 2019 the plant operated with expected uptime, with temporary
closures only for routine maintenance and in periods when Gazprom
was undertaking maintenance on its gas transmission lines.
Since May 2018, the LPG unit has been operational at the gas
plant and has been providing an additional high value product
stream from gas that was either previously flared or sold with
natural gas a lower value. During 2019, a turbo expander was added
to the LPG unit, enabling the system to operate a lower temperature
and thereby capturing a greater proportion of the butane and
propane in the gas stream.
The physical capacity of the plant is currently significantly
greater than well output. As the plant is on a fairly open
expansive site, it is possible to operate it while enabling
personnel to maintain a safe distance between them. As the majority
of staff live locally to the plant, travel restrictions should not
have a material impact on the ability of the plant to operate. The
Group has established changes to the work patterns, including to
the catering facilities on site, to preserve the health of our
workers.
Oil production and development
The Group's oil production is derived from the Uzen field.
During 2019 production averaged 427 bopd (2018: 607 bopd). Up to
and including 2019, the Uzen field has been producing oil from a
cretaceous Aptian reservoir at a depth of approximately 1,000
metres. This is now at a late stage of maturity of production. The
original mature wells produced at an average rate of 422 bopd in
2019 (2018: 595 bopd).
Early in 2019 the Group drilled a sidetrack to the Uzen#4 well
into an undeveloped pool in the Albian reservoir. After a series of
production tests, it was concluded that the pool into which the
well was drilled was charged primarily with gas rather than oil.
This small gas accumulation is not of significant commercial
potential - although the gas can be utilised for in field fuel
requirements. Consequently, the Group has decided to write off the
cost of this well.
The majority of remaining reserves in the Uzen field are in the
shallower Albian reservoir. The initial development of this
reservoir with conventional horizontal wells was found to be
economically marginal. For this reason, management sought a low
cost drilling alternative and opted for slim hole drilling. This
method uses a light, truck-mounted drilling rig that hitherto has
been used primarily for mineral exploration drilling. With suitable
adaptation and the use of appropriate tubing and tools, the Company
undertook an extended trial of this method. After an initial six
wells drilled with a rented rig, management decided to purchase a
Company-owned rig, with higher specifications.
By the end of 2019 a total of 6 slim hole oil wells had been
drilled, with a further 3 in progress. By 29 February a total of 10
wells have been drilled, with an eleventh in progress. Following
installation of production tubing and or artificial lift
mechanisms, the new wells are progressively being brought into
production.
One of the slim hole wells drilled in 2019 discovered oil in a
previously unevaluated geological layer, the Upper Aptian, at a
depth of approximately 900 metres. As a newly identified resource,
Volga Gas is required to prepare a drilling project, drill at least
one appraisal well, calculate the reserves and submit development
plans for approval by the State Reserves Committee. The normal
timeline for this approval process is approximately one year.
As with condensate sales, oil sales may be disrupted by the
effects of the Covid-19 pandemic. Production operations on the Uzen
field are not manpower intensive and not critically dependent on
external supplies. The Group has implemented changes to ensure the
health of personnel on the field. Drilling operations, on the other
hand, utilise more personnel on site and rely on the availability
of consumables, such as drill pipe and drilling mud. While the
Group has implemented enhanced health and safety processes on drill
sites, the operations may be disrupted by illness, travel
restrictions and supply constraints of consumables.
Exploration
During 2019, the Group's exploration activity was confined to
technical studies principally on prospects in the Karpenskiy block,
on which the Group has identified a number of exploration targets
in the Karpenskiy Licence Area at shallow horizons of between 1,000
and 2,000 metres' depth. With the acquisition of slim hole drilling
rigs and capability, the Group now has a highly cost effective
manner of evaluating its exploration prospects for the remaining
two year period of its exploration rights in the Karpenskiy licence
area. During 2020, a total of seven exploratory wells have been
identified for drilling in the Karpenskiy licence area.
In addition, the Group has acquired at low cost and with little
committed capital expenditure a new exploration project, the
Muradymovsky License Area, in the Bashkiriya region in an area of
active oil production. Studies on this indicate the potential for
material new reserves that could be brought rapidly into
production. However, Volga Gas has not to date prepared estimates
of any reserves or resources in this licence.
The comments of the potential impact of Covid-19 on development
drilling clearly apply equally to exploration drilling.
Oil, gas and condensate reserves as of 1 January 2020
During 2019, the Company appointed Schlumberger Ltd to conduct a
comprehensive technical evaluation and reservoir study on the VM
field. The study was completed in December 2019 and a
re-calculation of remaining reserves in the fields was carried out
by independent reserve engineers Panterra. The results presented to
the Company in February. As announced on 27 January 2019, there is
a significant reduction in the estimated remaining reserves in the
VM field as a result of this work. Separately, a re-assessment of
the reserves in the Dobrinskoye field was carried out and a
reduction in remaining reserves estimates was indicated there as
well.
At the Uzen field, as mentioned above there were two events in
2019 which may have an impact on reserve estimates on the Uzen
field: the Uzen #4 sidetrack than encountered mainly gas rather
than oil; and the discovery of oil in the Upper Aptian reservoir
with one of the slim hole wells. While further appraisal drilling
is required for an accurate determination of the Upper Aptian
reserves, management believes it realistic, if not conservative, to
assume no overall revision to oil reserves.
The changes to oil, gas, condensate and LPG reserves between 1
January 2019 and 31 December 2019 are summarised in the following
table.
Oil, gas and condensate reserves
Oil & Condensate Gas LPG Total
(mmbbl) (bcf) (tonnes (mmboe)
'000)
------------------------ ----------------- ------- --------- ---------
As at 31 December 2018
Proved reserves 9.174 50.5 141 19.247
Proved plus probable
reserves 10.472 70.7 198 24.592
------------------------ ----------------- ------- --------- ---------
Production: 1 Jan-31
Dec 2019 0.710 5.9 8.9 1.804
Revisions to reserves:
Proved reserves (1.446) (33.8) (108.5) (8.356)
Proved plus probable
reserves (2.745) (54.1) (165.5) (13.701)
As at 31 December 2019
Proved reserves 7.017 10.8 23.6 9.087
Proved plus probable
reserves 7.017 10.8 23.6 9.087
------------------------ ----------------- ------- --------- ---------
Revision as % of 2018 reserves
less 2019 production
Proved reserves (17%) (76%) (82%) (48%)
Proved plus probable
reserves (28%) (83%) (88%) (60%)
Notes:
1. Volga Gas (through its wholly owned subsidiaries PGK and GNS)
is the operator and has a 100% interest in five licences to explore
for and produce oil, gas and condensate in the Volga region.
2. The reserve estimates as at 31 December 2019 for gas,
condensate and LPG held by GNS were independently assessed in an
updated study conducted by OOO Panterra dated 7 February 2020. The
full reserve report is available on the Company's website:
www.volgagas.com .
3. There was an updated geological study by Panterra based on
the results of the 2019 drilling activities which concluded there
were no material net revision to oil reserves.
4. The reserve estimates were prepared in metric units: tonnes
for oil, condensate and LPG and standard cubic metres for gas. The
conversion ratios from tonnes to barrels applied in the table above
were 7.833 barrels per tonne of oil, 8.75 barrels per tonne of
condensate and 11.75 barrels per tonne of LPG. One cubic metre
equates to 35.3 cubic feet and one barrel of oil equivalent is
given by 6,000 standard cubic feet of gas.
5. The above reserve estimates, prepared in accordance with the
PRMS reserve definitions prepared by the Oil and Gas Reserves
Committee of the SPE, have been reviewed and verified by Mr Andrey
Zozulya, Director and Chief Executive Officer of Volga Gas plc, for
the purposes of the Guidance Note for Mining, Oil and Gas companies
issued by the London Stock Exchange in June 2009. Mr Zozulya holds
a degree in Geophysics and Engineering from the Groznensky Oil
& Gas Institute and is a member of the Society of Petroleum
Engineers.
Andrey Zozulya
Chief Executive Officer
Financial Review
Results for the year
In 2019, the Group generated US$46.0 million in turnover (2018:
US$45.9 million) from the sale of 729,147 barrels of crude oil and
condensate (2018: 649,541 barrels), 8,803 tonnes of LPG (2018:
6,904 tonnes) and 5,674 million cubic feet of natural gas (2018:
6,471 million cubic feet).
During 2019, 34% by volume of condensate sales were exported
(2018: 12%). In 2019 as in 2018 all oil sales were in the domestic
market.
The gas sales price during 2019 averaged US$1.98 per thousand
cubic feet (2018: US$1.99 per thousand cubic feet), the movement in
the Ruble/US Dollar exchange rate which offset the increase in the
Ruble selling prices. In 2019, as in 2018, the Group's gas sales
were direct to Gazprom.
In 2019, the total cost of production decreased to US$7.2
million (2018: US$8.3 million), driven mainly by cost savings from
chemicals used for gas sweetening and improved operational
efficiency at the gas processing plant. Unit field operating costs
were lower at US$4.07 per boe (2018: US$4.61 per boe), for similar
reasons.
Production-based taxes increased to US$14.3 million (2018:
US$13.2 million) reflecting the impact of higher oil Mineral
Extraction Tax ("MET") rates as well as the impact of further
formula changes that came into effect on 1 January 2019. MET paid
in 2019 represented 33.8% of netback revenues, defined as revenues
less selling expenses as shown in the Income statements (2018:
30.4% of netback revenues), reflecting a greater proportion of oil
and condensate relative to gas in the oil equivalent sales volumes.
Higher rates of MET apply to oil and condensate relative to
gas.
The Depletion, Depreciation and Amortisation ("DD&A") charge
in 2019 was US$14.9 million (2018: US$8.2 million) reflecting the
higher unit DD&A rate applied to comparable production
volumes.
As a consequence principally of higher DD&A, production
activities generated a gross profit of US$9.6 million in 2019
(2018: US$16.1 million).
Operating and administrative expenses in 2019 were US$4.8
million (2018: US$4.9 million).
The Group experienced a 6% decrease in EBITDA to US$15.9 million
(2018: US$16.9 million).
There were no significant exploration and evaluation expenses in
2019 (2018: nil) or other provisions (2018: nil). However, as a
result of the revision to reserves in the VM and Dobrinskoye
fields, the Group recorded an asset impairment charge of US$8.3
million mainly against the PP&E associated with those fields.
In addition, there was a US$2.6 million write off of development
assets in 2019 (2018: US$1.5 million), primarily as a result of
unsuccessful development drilling operations on sidetracks to the
VM#2 and the Uzen #4 wells. Consequently, the Group made an
operating loss of US$9.9 million in 2019 (2018: operating profit of
US$10.3 million).
Including net interest income of US$0.3 million (2018: US$0.4
million) and other net losses of US$0.9 million (2018: net losses
of US$0.2 million) the Group recognised a loss before tax of
US$10.5 million (2018: profit before tax of US$10.6 million).
The net loss after tax was US$10.0 million (2018: net profit
after tax US$8.4 million) after a current tax charge of US$2.2
million (2018: US$2.2 million) and a deferred tax credit of US$2.7
million (2018: deferred tax credit of US$0.1 million).
For the year ending 31 December 2019, the Group recorded a
currency retranslation gain of US$6.1 million (2018: expense of
US$11.8 million) in its other comprehensive income, relating to the
movements of the Ruble against the US Dollar.
Profitability by product
While the Group operates as a single business segment,
management estimates the relative profitability, which for this
purpose is defined to be gross profit less selling expenses, by
product to be as follows:
2019 2018
US$ 000 Oil Gas, LPG Oil Gas and
and condensate condensate
-------- ---------------- -------- ------------
Revenue 7,023 38,933 10,473 35,402
MET (4,039) (10,218) (5,575) (7,619)
Depreciation (1,010) (13,846) (944) (7,276)
Other Cost of sales (1,321) (5,910) (1,325) (7,023)
Selling expenses (40) (3,732) (59) (2,414)
-------- ---------------- -------- ------------
Gross profit net of selling
expenses 614 5,228 2,570 11,070
======== ================ ======== ============
Cash flow
Group cash flow from operating activities decreased by 18%
US$15.0 million (2018: US$18.3 million). Net working capital
movements contributed cash inflow of US$1.1 million in 2019 (2018:
net outflow of US$0.7 million). Included in cash flow from
operations was the receipt during 2018 was a sum of US$3.1 million
(2019: nil) being a court awarded settlement of a legal dispute.
During 2019 there were payments of profit tax of US$2.4 million
(2018: US$1.8 million).
With increased capital expenditures in 2019, the net outflow
from investing activities was US$9.6 million (2018: US$2.3
million).
Cash outflow from financing activities was US$7.2 million in
2019 (2018: US$6.7 million), comprising equity dividend payments of
US$5.2 million (2018: US$4.9 million), loan repayments of US$1.8
million (2018: US$1.8 million) and a net sum of US$159,000 (20128:
nil) spent on purchasing the Company's own shares which are held in
treasury.
After a positive adjustment of US$0.7 million for the exchange
rate effects on cash and cash equivalents (2018: negative
adjustment of US$2.7 million), there was a net decrease in cash by
US$1.1 million (2018: net increase of US$8.6 million), taking the
year end cash balance to US$14.1 million (2018:15.2 million).
Dividend
In May 2019 the Company paid a final dividend of US$0.065 per
ordinary share. No interim dividend was declared during 2019 (2018:
interim dividend of US$0.06 per Ordinary share, totaling US$4.9
million). The Directors do not propose a final dividend in respect
of 2019.
Capital expenditure
During 2019 expenditure of US$9.4 million was capitalized (2018:
US$2.8 million), of which US$9.0 million was added to PP&E in
development and producing assets (2018: US$2.6 million) and US$0.4
million on exploration and evaluation (2018: US$0.2 million).
The main capital expenditure in 2019 comprised the costs of
drilling of slim hole wells of US$3.4 million, installation of a
turbo expander at the LPG plant of US$2.0 million, drilling of well
#4 sidetrack on Uzen field of US$1.2 million, drilling of well #2
sidetrack on VM field of US$0.6 million, the acquisition of a slim
hold drilling rig of US$0.6 million.
Balance sheet and financing
As at 31 December 2019, the Group held cash and bank deposits of
US$14.1 million (2018: US$15.2 million). All of the Group's cash
balances are held in bank accounts in the UK and Russia.
Approximately 68% (2018: 61%) of the Group's cash is held in US
Dollars and 32% (2018: 38%) held in Russian Rubles.
In February 2019, the remaining balance of a bank facility,
which was utilised to fund purchases of equipment for the LPG
project, was repaid in full. There were no other finance loans or
leases outstanding either in 2019 or 2018.
As at 31 December 2019, the Group's intangible assets were
US$3.4 million (2018: US$3.3 million). Property, plant and
equipment decreased to US$34.0 million (2018: US$45.1 million),
reflecting higher depreciation charges, asset write offs and asset
impairments as outlined above. The carrying values of the Group's
assets relating to its main cash-generating units have been subject
to impairment testing. The impairment tests, including sensitivity
analysis around the central economic assumptions and taking into
account the reduction in oil and gas reserves are detailed in note
4(b) to the accounts. Based on this analysis, the Directors have
decided to take an impairment charge of US$8.3 million in the year
to 31 December 2019 (2018: nil).
The Group's committed capital expenditures are less than
expected cash flow from operations and cash-on-hand and such
expenditures can be managed in light of the volatility in
international oil prices and the Ruble. The Group may consider
additional debt facilities to fund the longer-term development of
its existing licences and operational facilities as appropriate.
However, management expects for the foreseeable future to maintain
capital expenditure within the level of operating cash flow and to
maintain an adequate level of liquidity to meet all of the Group's
commitments as and when they arise.
The Group's financial statements are presented on a going
concern basis, as outlined in Note 2.1 to the accounts.
Vadim Son
Chief Financial Officer
Five-year operational and financial summary
Sales volumes 2019 2018 2017 2016 2015
------------------------------- --------- --------- --------- --------- ---------
Oil & condensate (barrels
'000) 729 650 644 828 439
Gas (mcf) 5,674 6,471 6,378 9,320 4,545
LPG ('000 tonnes) 8.803 6.904 - - -
Total (boe) 1,778 1,809 1,707 2,381 1,196
Operating Results (US$ 2019 2018 2017 2016 2015
000)
------------------------------- --------- --------- --------- --------- ---------
Oil and condensate sales 32,093 30,154 23,952 25,380 11,041
Gas sales 11,228 12,880 13,114 14,032 6,786
LPG sales 2,635 2,841 - - -
------------------------------- --------- --------- --------- --------- ---------
Revenue 45,956 45,875 37,066 39,412 17,827
Field operating expenses (5,026) (5,865) (6,379) (9,367) (6,016)
Production based taxes (14,257) (13,194) (10,936) (10,255) (5,876)
Depletion, depreciation
and other (14,856) (8,220) (8,580) (5,037) (2,345)
Other production costs (2,204) (2,483) (2,941) (1,601) (1,352)
------------------------------- --------- --------- --------- --------- ---------
Cost of sales (36,343) (29,762) (28,836) (26,260) (15,589)
Gross profit 9,613 16,113 8,230 13,152 2,238
Selling expenses (3,771) (2,473) (2,221) (4,052) (319)
Exploration expense - - - (265) (635)
Write-off of development
assets (2,608) (1,513) (65) (1,798) -
Impairment charge (8,335) - - - -
Operating, admin & other
expenses (4,822) (4,921) (5,831) (4,525) (3,377)
Other operating income - 3,120 - - -
------------------------------- --------- --------- --------- --------- ---------
Operating (loss)/profit (9,923) 10,326 113 2,511 (2,093)
Net realisation 2019 2018 2017 2016 2015
------------------------------- --------- --------- --------- --------- ---------
Oil & condensate (US$/barrel) 44.02 46.39 37.19 30.65 25.16
Gas (US$/mcf) 1.98 1.99 2.06 1.51 1.49
LPG (US$/tonne) 299.37 411.50 - - -
Operating data (US$/boe) 2019 2018 2017 2016 2015
------------------------------- --------- --------- --------- --------- ---------
Production costs 4.07 4.61 5.46 4.61 6.16
Production based taxes 8.02 7.29 6.40 4.31 4.91
Depletion, depreciation
and other 8.42 4.54 5.02 2.11 1.96
EBITDA calculation (US$ 2019 2018 2017 2016 2015
000)
------------------------------- --------- --------- --------- --------- ---------
Operating profit/(loss) (9,923) 10,326 113 2,511 (2,093)
Exploration expense - - - 265 635
DD&A and other non-cash
expense 25,799 9,733 8,645 6,835 2,345
Other operating income - (3,120) - - -
------------------------------- --------- --------- --------- --------- ---------
EBITDA 15,876 16,939 8,758 9,612 887
EBITDA per boe 8.93 9.36 5.13 4.04 0.74
Netback realisation for oil and condensate is calculated by
deducting selling expenses from oil, gas and condensate sales.
EBITDA is calculated from Operating Profit as shown in the Group
Income Statement, adding back:
-- Depletion, depreciation and amortisation, as disclosed in
Note 6, analysis of Cost of Sales;
-- Write off of development assets, as disclosed in Note 6,
analysis of Total Expenses; and deducting
-- Other operating income as disclosed in Note 5(d)
Principal Risks and Uncertainties
The Group is subject to various risks relating to political,
economic, legal, social, industry, business and financial
conditions. The following risk factors, which are not exhaustive,
are particularly relevant to the Group's business activities. The
additional specific risks to which the Group is exposed as a result
of the Covid-19 pandemic are detailed separately.
Volatility of oil prices
The supply, demand and prices for oil are influenced by factors
beyond the Group's control. These factors include global and
regional demand and supply, exchange rates, interest and inflation
rates and political events. A significant prolonged decline in oil
and gas prices would impact the profitability of the Group's
activities.
All of the Group's revenues and cash flows come from the sale of
oil, gas and condensate. If sales prices should fall below and
remain below the Group's cost of production for any sustained
period, the Group may experience losses and may be forced to
curtail or suspend some or all of the Group's production, at the
time such conditions exist. In addition, the Group would also have
to assess the economic impact of low oil and gas prices on its
ability to recover any losses the Group may incur during that
period and on the Group's ability to maintain adequate
reserves.
The Group does not currently hedge its crude oil production to
reduce its exposure to oil price volatility as the structure of
taxes applied to oil and condensate production in Russia
effectively reduce the exposure to international market prices for
oil. In addition, the Ruble exchange rate has tended to move with
the oil price, reducing the overall volatility of oil prices when
translated into Russian Rubles.
In particular, the recent and sudden collapse in international
oil prices triggered by the Covid-19 pandemic have a material
impact on the Group's short term revenue and profitability outlook.
The Directors have examined the impact of current low oil prices in
preparing the financial statements:
-- In assessment of the Group as a going concern should oil
prices remain at US$25 per barrel for an extended period.
-- Impairment testing. A significant drop in oil prices were
considered in the sensitivity analysis conducted in relation to
impairment testing.
Market risks
The Group's revenues generated from oil and condensate
production have typically been from sales to local domestic
customers. There have been periods when the local market has been
unable to purchase condensate, causing temporary suspension of
production and loss of revenues. The Group has access to export
channels for its condensate into regional export markets to
mitigate this risk. Gas sales are currently made to Gazprom. While
the arrangement is formalised annually rather than as a long term
contract, the Directors believe the risk of renewal is low as the
region in which the Group operates is reliant on external gas
supplies. Gas sales have generally been conducted as expected,
subject to occasional constraints during pipeline maintenance
operations.
Oil and gas production taxes
The Group's sales generated from oil and gas production are
subject to Mineral Extraction Taxes ("MET"), which form a material
proportion of the total costs of sales. The rates of these taxes
are subject to changes by the Russian government, which relies
heavily on such taxes for its revenues. Changes to rate formulas
which came into effect during in recent years have materially
increased the rates on crude oil, condensate and, to a lesser
extent, natural gas. As of 2019, the Russian government's policy is
to transfer the burden of taxes from export taxes to MET and the
formulas for both taxes are being changed over a five-year period
from 2019. It is not certain that domestic oil sales prices will
rise sufficiently to reflect in full the reduction in export taxes
to compensate for the increase in MET on oil production sold in the
domestic market.
Exploration and reserve risks
Whilst the Group will seek to apply the latest technology to
assess exploration licences, the exploration for, and development
of, hydrocarbons involves a high degree of risk. In relation to the
exploration activities, these risks include the uncertainty that
the Group will discover sufficient commercially exploitable oil or
gas resources in unproven areas of its licences. Unsuccessful
exploration efforts may result in impairment to the balance sheet
value of exploration assets.
In July 2019, as detailed in the Operations Review, management
commissioned an extensive reservoir study on the VM field which
concluded with an updated reserve evaluation of the VM and
Dobrinskoye fields completed in February 2020. The reserve report,
delivered to and adopted by management on 7 February 2020, resulted
in a downward revision by approximately 48% to the Group's Proved
Reserves as at 31 December 2019. Management also commissioned an
updated geological resource estimate on the Uzen oil field,
completed in March 2020. Management considers the independent
reserve estimate to be in line with the currently available field
data and accordingly has chosen to adopt the estimates as the
statement of the Group's oil, gas and condensate reserves. The
Group's reserve statement is shown in the Operational Review. The
impact of the reserve revision in 2019 has been to increase the
depletion, depreciation and amortisation charge of the Group with
consequent reductions in the profit and net book value of the
Group's assets and to trigger an impairment of the net book value
of Group's Property Plant and Equipment. These impacts are
reflected in the Group's financial statements for the year ended 31
December 2019.
The Group's estimated reserves include substantial volumes that
are expected to be produced from wells that have yet to be
drilled:
On the VM and Dobrinskoye fields: 2.0 mmboe of reserves are
expected to be extracted from existing wells in 2020-2021, while
with the drilling of the new VM5 and VM6 wells an additional 1.5
mmboe of reserves are recovered from VM5 and VM6 and the production
profile extended to mid-2023. Management's expectations have been
formed on the basis of independent studies by Schlumberger and
Panterra. Should the drilling of new wells be unsuccessful, the
incremental reserves may not be extracted. This scenario was
considered in sensitivity analysis in impairment testing. See note
4a.
On the Uzen field, 75% of the reserves are expected to be
recovered from new wells from a multi-year slim hole drilling
programme.
If the costs of drilling these wells, of the results of these
wells differ significantly from expectations, there may be further
changes in the future estimates of reserves and to the value in use
of the related cash generating units. These may impact both the
future profitability and the balance sheet carrying values of the
Group's property, plant and equipment. Such scenarios are
considered in the impairment testing process.
Environmental risk
The oil and gas industry is subject to environmental hazards,
such as oil spills, gas leaks, ruptures and discharges of petroleum
products and hazardous substances, including waste materials
generated by the sweetening process formerly in use at the
Dobrinskoye gas processing plant. These environmental hazards could
expose the Group to material liabilities for property damages,
personal injuries, or other environmental harm, including costs of
investigating and remediating contaminated properties.
The Group is subject to stringent environmental laws in Russia
with regard to its oil and gas operations. Failure to comply with
such laws and regulations could subject the Group to material
administrative, civil, or criminal penalties or other liabilities.
Additionally, compliance with these laws may, from time to time,
result in increased costs to the Group's operations, impact
production, or increase the costs of potential acquisitions.
The Group liaises closely with the Federal Service of
Environmental, Technological and Nuclear Resources of the Saratov
and Volgograd Oblasts on potential environmental impact of its
operations and conducts environmental studies both as required by,
and in addition to, its licence obligations to mitigate any
specific risk. The Group's operations are regularly subject to
independent environmental audit. The Group did not incur any
material costs relating to the compliance with environmental laws
during the period.
Risk of operating oil and gas properties
The oil and gas business involves certain operating hazards,
such as well blowouts, cratering, explosions, uncontrollable flows
of oil, gas or well fluids, fires, pollution and releases of toxic
substances. Any of these operating hazards could cause serious
injuries, fatalities, or property damage, which could expose the
Group to liabilities. The settlement of these liabilities could
materially impact the funds available for the exploration and
development of the Group's oil and gas properties. The Group
maintains insurance against many potential losses and liabilities
arising from its operations in accordance with customary industry
practices, but the Group's insurance coverage cannot protect it
against all operational risks. The Group has established a rigorous
risk identification and reporting system throughout its operations
as a key risk mitigation activity.
Foreign currency risk
The Group's capital expenditures and operating costs are
predominantly in Russian Rubles ("RUR") while a minority of
administrative expenses is in US Dollars, Euros and Pounds
Sterling. Revenues are predominantly received in RUR, so the
operating profitability is not materially exposed to moderate
short-term exchange rate movements. The functional currency of the
Group's operating subsidiaries is the RUR and the Group's assets
and liabilities are predominantly RUR denominated. As the Group's
presentational currency is the US Dollar, fluctuations in the
exchange rate of the RUR against the US Dollar impact the Group's
financial statements.
Business in Russia
Amongst the risks that face the Group in conducting business and
operations in Russia are:
-- Economic instability, including in other countries or the
global economy that could lead to consequences such as
hyperinflation, currency fluctuations and a decline in per capita
income in the Russian economy.
-- Governmental and political actions that could disrupt, delay
or curtail economic and regulatory reform, increase centralised
authority or result in nationalisations.
-- Social instability from any ethnic, religious, historical or
other divisions that could lead to a rise in nationalism, social
and political disturbances or conflict.
-- Uncertainties in the legal and regulatory environment,
including, but not limited to, conflicting laws, decrees and
regulations applicable to the oil and gas industry and foreign
investment.
-- Unlawful or arbitrary action against the Group and its
interests by the regulatory authorities, including the suspension
or revocation of their oil or gas contracts, licences or permits or
preferential treatment of their competitors.
-- Lack of independence and experience of the judiciary,
difficulty in enforcing court or arbitration decisions and
governmental discretion in enforcing claims.
-- Unexpected changes to the federal and local tax systems.
-- Laws restricting foreign investment in the oil and gas
industry.
-- The imposition of sanctions upon certain entities in
Russia.
The Group's operations and financial management have not been
impacted directly by any sanctions to date.
Legal systems
Russia, and other countries in which the Group may transact
business in the future, have or may have legal systems that are
less well developed than those in the United Kingdom. This could
result in risks such as:
-- Potential difficulties in obtaining effective legal redress
in the court of such jurisdictions, whether in respect of a breach
of contract, law or regulation, including an ownership dispute.
-- A higher degree of discretion on the part of governmental authorities.
-- The lack of judicial or administrative guidance on
interpreting applicable rules and regulations.
-- Inconsistencies or conflicts between and within various laws,
regulations, decrees, orders and resolutions.
-- Relative inexperience and lack of transparency of the judiciary and courts in such matters.
In certain jurisdictions, the commitment of local business
people, government officials and agencies and the judicial system
to abide by legal requirements and negotiated agreements may be
more uncertain, creating particular concerns with respect to
licences and agreements for business. These may be susceptible to
revision or cancellation and legal redress may be uncertain or
delayed. There can be no assurance that joint ventures, licences,
licence applications or other legal arrangements will not be
adversely affected by the jurisdictions in which the Group
operates.
Liquidity risk
At 31 December 2019, the Group had US$14.1 million (2018:
US$15.2 million) of cash and cash equivalents, of which US$4.8
million was held in bank accounts in Russia (2018: $13.8 million).
As at 31 December 2019, there was no bank debt (2018: US$1.7
million), the balance of bank debt having been repaid in January
2019. The Group intends to fund its ongoing operations and
development activities from its cash resources and cash generated
by its established operations. At 31 December 2019 the Group had
budgeted capital expenditures of US$8.3 million, comprising
primarily expenditures on drilling production wells on the Group's
proven fields but also including up to US$1.0 million of
exploration expenditure. There were approximately US$1.0 million of
accounts payable relating to capital expenditures and other
expenses incurred in the year ended 31 December 2019 (2018: US$1.1
million). The Group's cash flow projections have been tested for
the ability to withstand an extended period of oil prices at US$30
per barrel.
The Board considers that the Group will have sufficient
liquidity to meet its obligations and to weather an extended period
of low oil prices. All current and planned capital expenditures are
discretionary and may be deferred or cancelled in the light of the
Group's cash generation and liquidity position.
Through the ordinary course of its activities, the Group is
exposed to legal, operational and development risk that could delay
growth in its cash generation from operations or may require
additional capital investment that could place increased burden on
the Group's available financial resources. However, with its asset
bsse already in production, this risk would not impede its ability
to continue as a going concern.
Capital risk
The Group manages capital to ensure that it is able to continue
as a going concern whilst maximising the return to shareholders.
The Group is not subject to any externally imposed capital
requirements. The Board regularly monitors the future capital
requirements of the Group, particularly in respect of its ongoing
development programme. Management expects that the cash generated
by the operating fields and the Group's existing cash reserves will
be sufficient to sustain the Group's operations and committed
capital investment for the foreseeable future. The Group has a
policy of maintaining a minimum level of liquidity to cover forward
obligations. Further short-term debt facilities may be arranged to
provide financial headroom for future development activities.
Bribery
The Company is subject to numerous requirements and standards,
including the UK Bribery Act. In addition the Group is subject to
anti-bribery and anti-corruption laws and regulations in all
jurisdictions in which it operates. Failure to comply with
regulations and requirements, such as failure to implement adequate
systems to prevent bribery and corruption, could result in
prosecution, fines or penalties imposed on the Company or its
officers or suspension of operations. The Group's mitigation
measures include compliance-related activities, training,
monitoring, risk management, due diligence and regular review of
policies and procedures. We prohibit bribery and corruption in any
form by all employees and by those working for, or connected with
the business. Employees are expected to report actual, attempted or
suspected bribery or other issues related to compliance to their
line managers or through our confidential reporting process, which
is available to all staff as well as third parties.
Fraud
The Group has been exposed to fraudulent transfers of funds from
its bank accounts and is at various times at risk to attempted
fraud. The Group has established enhanced protections of its
information technology infrastructure, operational systems and
procedures against fraudulent activities.
Covid 19
The Directors believe the Group, may be materially impacted by
several factors that arise as a result of the Covid 19 pandemic.
The following table sets out the specific business risk issues
identified by the Group, the potential impact and risk mitigation
action plans enacted by the Group. Where possible, the scale of the
exposure is indicated along with the probability. However, the
ultimate exposure and scale of impact depends on many factors such
as the scale and duration of the pandemic, which are presently
unknown. While the full range of possible effects are unknown, the
Directors considered the several severe adverse scenarios and are
satisfied that the Group has adequate resources to continue as
going concern. For details refer to Note 2.1.
Category Risk/probability Impact Mitigating Action
---------------- ------------------ ------------------ ------------------------------------------------------------
Industry Low oil pricing Revenues from
specific is already oil, condensate * Market monitoring, regularly updating forecasts.
risks, a reality and and LPG sales
primarily further falls and consequences
relating are possible. for * Deferral of capital expenditures as necessary
to oil profitability,
prices cash flow and
liquidity. The * Management of costs
impact is partly
offset by lower
production taxes.
Customers Reduction of Possible need
demand in the to shut-in * Diversity of customer relationships
regional markets. producing
(probability: wells once
uncertain) storage * Access to export markets Close contacts with
tanks are full. customers, flexible and quick price correction to
Failure of continue sale of products.
customers to
buy contracted
volume * Close monitoring our stock capacity to avoid shutting
(probability: down the wells
uncertain)
----------------
Credit default Delay with
(probability: payment * Continue sale of products only after prepayment is
low) or non-payment done
---------------- ------------------ ------------------ ------------------------------------------------------------
Supply Catering in High demand on
Chain, the field: food stuff can * Made upfront payment to catering company to make some
for production lack of food lead to catering buffer stock
and drilling provision. issues. Need to
and plant (Probability: find alternatives
maintenance unknown) to feed personnel
at field sites.
Drilling Delay in drilling
chemicals * Contracting & testing local alternatives
non-delivery
from Kazakhstan
(Probability:
unknown)
Cross border Delays in
/ logistics delivery * LPG parts (compressor parts from China) - change to
restrictions sea delivery from air. Looking for opportunities to
(Probability: local manufacture.
unknown)
---------------- ------------------ ------------------ ------------------------------------------------------------
Employees Illness due Office staff:
(including to being infected have been ordered * Following government advice on self-isolation and
production or quarantined to work remotely. reporting of symptoms.
(probability: Not expecting
moderate to severe impact.
high) * Online office working facilitated.
Production staff
have been ordered
to maintain safe * Disinfections in the office, installation of
distance from disinfecting dispensers
each other at
all times.
* First aid kits check
Drilling staff
is more at risk
due to living * Ventilate the rooms
in remote
locations
across Russia * Travel restrictions
and CIS
* Undertaking additional training of local staff
Financing Availability No impact in the
of external near future. Not * Close monitoring company liquidity and get ready in
finance anticipated to case own funding required from abroad.
(probability: be required
not known)
Other risks/Brexit
The Company is not significantly commercially exposed to the
outcome of the future trade negotiations between the UK and EU
following the departure of the UK from the EU.
-- Customers and supply chain : The Company conducts no trade between the UK and the EU.
-- Employees : The Group has no employees based in the UK or the EU.
-- Financing : The Company does not have significant external
financing in place and the day to day requirements are met from its
cash balances in Russia.
-- Regulations : There are no specific regulations which could
potentially have significant impact on the Company arising from
Brexit.
The Company continues to monitor the political and economic
events and forecasts to manage any potential impacts to its
business including its employees.
Vadim Son,
Chief Financial Officer
Abbreviated Financial Statements
for the year ended 31 December 2019
Group Income Statement
(presented in US$ 000)
Year ended 31 December Notes 2019 2018
Continuing Operations
Revenue 4 45,956 45,875
Cost of sales 5 (36,343) (29,762)
----------- -------------
Gross profit 9,613 16,113
Selling expenses 5(a) (3,771) (2,473)
Operating and administrative expenses 5 (4,822) (4,921)
Write-off of development assets 5(b) (2,608) (1,513)
Impairment charge (8,33 5 -
)
Other operating income - 3,120
----------- -------------
Operating (loss)/profit (9,923) 10,326
Interest income 292 425
Interest expense (18) -
Other net losses 6 (853) (192)
----------- -------------
(Loss)/profit for the year before
tax (10,502) 10,559
Current income tax (2,224) (2,254)
Deferred income tax 2,709 99
----------- -------------
(Loss)/profit for the year before
non-controlling interests (10,017) 8,404
Attributable to:
The owners of the Parent Company (10,017) 8,404
=========== =============
Basic and diluted (loss)/profit per
share (in US Dollars) 7 (0.1239) 0.1037
Weighted average number of shares
outstanding 7 80,823,327 81,017,800
Group Statement of Comprehensive Income
(presented in US$ 000)
Year ended 31 December 2019 2018
(Loss)/profit for the year attributable
to equity shareholders of the Company (10,017) 8,404
Other comprehensive income:
Items that are or may be reclassified subsequently
to profit or loss
Currency translation differences 6,094 (11,786)
Reversal of share grant reserve -
--------- ----------------
Total comprehensive income for the
year (3,923) (3,382)
Attributable to:
The owners of the Parent Company (3,923) (3,382)
========= ================
Group Balance Sheet
(presented in US$ 000)
At 31 December Notes 2019 2018
ASSETS
Non-current assets
Intangible assets 8 3,374 3,304
Property, plant and equipment 9 33,957 45,109
Deferred tax assets 1,459 804
--------- --------------
Total non-current assets 38,790 49,217
Current assets
Cash and cash equivalents 1 0 14,116 15,186
Inventories 1 1 594 938
Trade and other receivables 1 2 1,752 2,381
--------- --------------
Total current assets 16,462 18,505
Total assets 55,252 67,722
========= ==============
EQUITY AND LIABILITIES
Equity
Share capital 1,485 1,485
Other reserves (83,095) (89,189)
Accumulated profits 129,917 145,330
--------- --------------
Equity attributable to the shareholders
of the Parent Company 48,307 57,626
Non-current liabilities
Asset retirement obligation 315 361
Deferred tax liabilities - 2,028
--------- --------------
Total non-current liabilities 315 2,389
Current liabilities
Trade and other payables 1 3 6,630 6,047
Current portion of bank loans - 1,660
--------- --------------
Total current liabilities 6,630 7,707
Total equity and liabilities 55,252 67,722
========= ==============
Group Cash Flow Statement
(presented in US$ 000)
Year ended 31 December 2019 2018
(Loss)/profit for the year before tax (10,502) 10,559
Adjustments to loss before tax:
Depreciation 14,833 8,324
Write off of development assets 2,608 1,574
Impairment charge 8,335 -
Provision for obsolete inventory 16 391
Other non-cash operating (gains)/losses 456 (251)
Foreign exchange differences 575 133
------------- --------
Operating cash flow prior to working capital 16,321 20,730
Working capital changes
Decrease/(increase) in trade and other
receivables 768 (417)
(Decrease)/increase in payables (78) (138)
Decrease/(increase) in inventory 439 (112)
------------- --------
Cash flow from operations 17,450 20,063
Income tax paid (2,444) (1,811)
Government subsidies refunded (37) -
Net cash flow generated from operating
activities 14,969 18,252
------------- --------
Cash flows from investing activities
Expenditure on exploration and evaluation (399) (211)
Purchase of property, plant and equipment (9,190) (2,059)
------------- --------
Net cash used in investing activities (9,589) (2,070)
------------- --------
Cash flows from financing activities
Equity dividends paid (5,237) (4,861)
Purchase of treasury shares (1 59 ) -
Bank loans drawn/(repaid) (1,799) (1,839)
------------- --------
(7,19
Net cash provided by financing activities 5 ) (6,700)
------------- --------
Effect of exchange rate changes on cash
and cash equivalents 74 7 (2,713)
Net (decrease)/increase in cash and cash
equivalents (1,070) 6,569
Cash and cash equivalents at beginning
of the year 15,186 8,617
Cash and cash equivalents at end of the
year 14,116 15,186
============= ========
Group Statement of Changes in Shareholders' Equity
(presented in US$ 000)
Share Currency Accumulated Total Equity
Capital Translation Profit/(Loss
Reserves )
Opening equity at 1 January
2019 1,485 (89,189) 145,330 57,626
Profit for the year - - (10,017) (10,017)
Currency translation differences - 6,094 - 6,094
--------- ------------- -------------------- ---------------
Total comprehensive income - 6,094 (10,017) (3,923)
--------- ------------- -------------------- ---------------
Transactions with owners
Equity dividends paid - - (5,237) (5,237)
Purchase of treasury shares - - (159) (159)
--------- ------------- -------------------- ---------------
Total transactions with owners - - (5,396) (5,396)
Closing equity at 31 December
2019 1,485 (83,360) 129,917 48,307
========= ============= ==================== ===============
Opening equity at 1 January
2018 1,485 (77,403) 141,787 65,869
Profit for the year - - 8,404 8,404
Currency translation differences - (11,786) - (11,786)
--------- ------------- -------------------- ---------------
Total comprehensive income - (11,786) 8,404 (3,382)
--------- ------------- -------------------- ---------------
Transactions with owners
Equity dividends paid - - (4,861) (4,861)
--------- ------------- -------------------- ---------------
Total transactions with owners - - (4,861) (4,861)
Closing equity at 31 December
2018 1,485 (89,189) 145,330 57,626
========= ============= ==================== ===============
Notes to the Abbreviated Financial Statements
for the year ended 31 December 2019
1. Summary of significant 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.
1.1 Basis of preparation
Both the Parent Company financial statements and the Group
financial statements have been prepared in accordance with
International Financial Reporting Standards ("IFRSs"), as adopted
by the European Union ("EU"), International Financial Reporting
Interpretations Committee ("IFRIC") interpretations, and the
Companies Act 2006 applicable to companies reporting under IFRS.
The consolidated financial statements have been prepared under the
historical cost convention and in accordance with applicable
accounting standards.
The preparation of financial statements in conformity with IFRSs
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 3.
No income statement is presented for Volga Gas plc as permitted
by Section 408 of the Companies Act 2006.
The Group's business activities, together with the factors
likely to affect its future development, performance and position
are set out in the Strategic Report; the financial position of the
Group, its cash flows, liquidity position and borrowing facilities
are described in the Financial Review. In addition, the Group's
objectives, policies and processes for measuring capital, financial
risk management objectives, details of financial instruments and
exposure to credit and liquidity risks are described in Note 3.
Going Concern
Having reviewed the future cash flow forecasts of the Group in
the light of the reductions in oil and gas reserves, the recent
developments in the international oil prices and markets, and in
consideration of the current financial condition of the Group, the
Directors have concluded that the Group will continue to have
sufficient funds in order to meet its obligations as they fall due
for at least the 12 months from the approval of the financial
statements and thus continue to adopt the going concern basis of
accounting in preparing the annual financial statements.
In reaching this conclusion, the Directors have reviewed cash
flow projections using current spot and futures oil prices in the
period 2020-2022 and operational assumptions on production,
operating and capital costs in line with those used for impairment
testing (see Note 4). The Directors have also considered the
sensitivity of cash flow forecasts under a variety of scenarios
that have arisen and may arise as a result of the Covid-19 pandemic
and the economic impact of government measures taken to deal with
the outbreak in various countries in addition to risk factors that
are specific to the Group's operations. Included in these are:
-- Extended oil price weakness with the Urals oil price
declining to average US$20 per barrel in 2020 and US$30 per barrel
in 2021;
-- Disruption arising from Covid-19 that leads to a period of
shut-in for the Group's entire production of varying durations, up
to 6 months at the extreme, combined with the above mentioned lower
oil prices;
-- Unsuccessful outcomes from the drilling of the VM5 and VM6 wells;
-- A lower case outturn for slim hole development drilling on the Uzen field.
The Directors recognise that the long term viability of the
Group depends on successful development of oil reserves in the Uzen
field and on the discovery of new oil and gas reserves to replace
those that will be produced in the short and medium term. If these
activities are unsuccessful for a sustained period, it may be
necessary to reduce the ongoing overheads of the Group and may
reduce the Group's future ability to continue as going concern.
1.2 Consolidation
Subsidiaries
The consolidated financial statements include the financial
statements of the Company and its subsidiaries. Subsidiaries are
entities controlled by the Group. The Group controls an entity when
it 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. In assessing control,
the Group takes into consideration potential voting rights that are
currently exercisable. The acquisition date is the date on which
control is transferred to the acquirer. The financial statements of
subsidiaries are included in the consolidated financial statements
from the date that control commences until the date that control
ceases. Losses applicable to the non-controlling interests in a
subsidiary are allocated to the non-controlling interests even if
doing so causes the non-controlling interests to have a deficit
balance.
Investments in subsidiaries are accounted for at cost less
impairment. Cost is adjusted to reflect changes in consideration
arising from contingent consideration amendments. Cost also
includes direct attributable costs of investment.
Inter-company transactions, balances and unrealised gains on
transactions between Group companies are eliminated; unrealised
losses are also eliminated unless the cost cannot be recovered.
The Company and its subsidiaries outside the Russian Federation
maintain their financial statements in accordance with IFRSs as
adopted by the EU. The Russian subsidiaries of the Group maintain
their statutory accounting records in accordance with the
Regulations on Accounting and Reporting of the Russian Federation.
The consolidated financial statements are based on these statutory
accounting records, appropriately adjusted and reclassified for
fair presentation in accordance with International Financial
Reporting Standards as adopted by the EU.
1.3 Segment reporting
Segmental reporting follows the Group's internal reporting
structure.
Operating segments are defined as components of the Group where
separate financial information is available and reported regularly
to the chief operating decision maker, which is determined to be
the Board of Directors of the Company. The Board of Directors
decides how to allocate resources and assesses operational and
financial performance using the information provided.
No geographic segmental information is presented as all of the
Group's operating activities are based within a localised area of
the Russian Federation.
Management has determined, therefore, that the operations of the
Group comprise one class of business, being oil and gas
exploration, development and production and the Group operates in
only one geographic area - the Volga region of the Russian
Federation.
1.4 Foreign currency translation
(a) Functional and presentation currency
Items included in the financial statements of each of the
Group's entities are measured using the currency of the primary
economic environment in which the entity operates ("the functional
currency"). The consolidated financial statements are presented in
US Dollars, which is the Company's functional and the Group's
presentation currency.
The functional currency of the Group's subsidiaries that are
incorporated in the Russian Federation is the Russian Rouble
("RUR"). It is management's view that the RUR best reflects the
financial results of its Cyprus subsidiaries because they are
dependent on entities based in Russia that operate in an RUR
environment in order to recover their investments. As a result, the
functional currency of the subsidiaries continues to be the
RUR.
(b) Transactions and balances
Foreign currency transactions are translated into the functional
currency using the exchange rates prevailing at the dates of the
transactions. 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.
Foreign exchange gains and losses that relate to cash and cash
equivalents, borrowings and other foreign exchange gains and losses
are presented in the income statement within "Other gains and
losses".
(c) Group companies
The results and financial position of all the Group entities
(none of which has the currency of a hyper-inflationary economy)
that have a functional currency different from the presentation
currency are translated into the presentation currency as
follows:
(i) assets and liabilities for each balance sheet item presented
are translated at the closing rate at the date of that balance
sheet;
(ii) income and expenses for each income statement are
translated at average 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
(iii) all resulting exchange differences are recognised in other
comprehensive income.
The major exchange rates used for the revaluation of the closing
balance sheet at 31 December 2019 were:
-- GBP 1: US$1.3108 (2018: 1.2708)
-- EUR 1: US$1.2101 (2018: 1.1438)
-- US$ 1: RUR61.9057 (2018: 69.4706)
1.5 Oil and gas assets
The Company and its subsidiaries apply the successful efforts
method of accounting for exploration and evaluation ("E&E")
costs, in accordance with IFRS 6, "Exploration for and Evaluation
of Mineral Resources". Costs are accumulated on a field-by-field
basis.
Capital expenditure is recognised as property, plant and
equipment or intangible assets in the financial statements
according to the nature of the expenditure and the stage of
development of the associated field, i.e. exploration, development,
production.
(a) Exploration and evaluation assets
Costs directly associated with an exploration well, including
certain geological and geophysical costs, and exploration and
property leasehold acquisition costs, are capitalised as intangible
assets until the determination of reserves is evaluated. If it is
determined that a commercial discovery has not been achieved, these
costs are charged to expense after the conclusion of appraisal
activities. Exploration costs such as geological and geophysical
costs that are not directly related to an exploration well are
expensed as incurred.
Once commercial reserves are found, exploration and evaluation
assets are tested for impairment and transferred to development
assets. No depreciation or amortisation is charged during the
exploration and evaluation phase.
(b) Development assets
Expenditure on the construction, installation or completion of
infrastructure facilities, such as platforms, pipelines and the
drilling of development wells into commercially proven reserves, is
capitalised within property, plant and equipment. When development
is completed on a specific field, it is transferred to producing
assets as part of property, plant and equipment. No depreciation or
amortisation is charged during the development phase.
(c) Oil and gas production assets
Production assets are accumulated generally on a field by field
basis and represent the cost of developing the commercial reserves
discovered and bringing them into production together with E&E
expenditures incurred in finding commercial reserves and
transferred from the intangible E&E assets as described
above.
The cost of production assets also includes the cost of
acquisitions and purchases of such assets, directly attributable
overheads, finance costs capitalised and the cost of recognising
provisions for future restoration and decommissioning.
Where major and identifiable parts of the production assets have
different useful lives, they are accounted for as separate items of
property, plant and equipment. Costs of minor repairs and
maintenance are expensed as incurred.
(d) Depreciation/amortisation
Oil and gas properties are depreciated or amortised using the
unit-of-production method. Unit-of-production rates are based on
proved reserves, which are oil, gas and other mineral reserves
estimated to be recovered from existing facilities using current
operating methods. Oil and gas volumes are considered produced once
they have been measured through meters at custody transfer or sales
transaction points at the outlet valve on the field storage
tank.
(e) Impairment - exploration and evaluation assets
Exploration and evaluation assets are tested for impairment
prior to reclassification to development tangible assets, or
whenever facts and circumstances indicate that an impairment
condition may exist. An impairment loss is recognised for the
amount by which the exploration and evaluation assets' carrying
amount exceeds their recoverable amount. The recoverable amount is
the higher of the exploration and evaluation assets' fair value
less costs to sell and their value in use. For the purposes of
assessing impairment, the exploration and evaluation assets subject
to testing are grouped with existing cash-generating units of
production fields that are located in the same geographical
region.
(f) Impairment - proved oil and gas production properties
Proven oil and gas properties are reviewed for impairment
whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. An impairment loss is
recognised for the amount by which the asset's carrying amount
exceeds its recoverable amount. The recoverable amount is the
higher of an asset's fair value less costs to sell and value in
use. The cash-generating unit applied for impairment test purposes
is generally the field, except that a number of field interests may
be grouped together where the cash flows of each field are
interdependent, for instance where surface infrastructure is used
by one or more field in order to process production for sale.
(g) Decommissioning
Provision is made for the cost of decommissioning assets at the
time when the obligation to decommission arises. Such provision
represents the estimated discounted liability (the discount rate
used currently being at 10% per annum) for costs which are expected
to be incurred in removing production facilities and site
restoration at the end of the producing life of each field. A
corresponding item of property, plant and equipment is also created
at an amount equal to the provision. This is subsequently
depreciated as part of the capital costs of the production
facilities. Any change in the present value of the estimated
expenditure attributable to changes in the estimates of the cash
flow or the current estimate of the discount rate used are
reflected as an adjustment to the provision and the property, plant
and equipment. The unwinding of the discount is recognised as a
finance cost.
1.6 Other business and corporate assets
Property, plant and equipment not associated with exploration
and production activities are carried at cost less accumulated
depreciation. These assets are also evaluated for impairment when
circumstances dictate.
Land is not depreciated. Depreciation of other assets is
calculated on a straight line basis as follows:
Machinery and equipment 6-10 years
Office equipment in excess of US$5,000 3-4 years
Vehicles and other 2-7 years
Depreciation methods, useful lives and residual values are
reviewed at each balance sheet date.
1.7 Current and deferred income tax
The tax expense for the period comprises current and deferred
tax. Tax is recognised in the income statement, except to the
extent that it relates to items recognised in other comprehensive
income or directly in equity. In this case, the tax is also
recognised in other comprehensive income or directly in equity,
respectively.
The current income tax charge is calculated on the basis of the
tax laws enacted or substantively enacted at the end of the
reporting period in the countries where the Company's subsidiaries
operate and generate taxable income. Management periodically
evaluates positions taken in tax returns with respect to situations
in which applicable tax regulation is subject to interpretation. It
establishes provisions where appropriate on the basis of amounts
expected to be paid to the tax authorities.
Deferred income tax is recognised, using the liability method,
on temporary differences arising between the tax bases of assets
and liabilities and their carrying amounts in the consolidated
financial statements. However, the deferred income tax is not
accounted for if it arises from initial recognition of an asset or
liability in a transaction other than a business combination that
at the time of the transaction affects neither accounting nor
taxable profit or loss. Deferred income tax is determined using tax
rates (and laws) that have been enacted or substantially enacted by
the end of the reporting period and are expected to apply when the
related deferred income tax asset is realised or the deferred
income tax liability is settled.
Deferred income tax assets are recognised to the extent that it
is probable that future taxable profit will be available against
which the temporary differences can be utilised.
Deferred income tax assets and liabilities are offset when there
is a legally enforceable right to offset current tax assets against
current tax liabilities and when the deferred income taxes assets
and liabilities relate to income taxes levied by the same taxation
authority on either the same taxable entity or different taxable
entities where there is an intention to settle the balances on a
net basis.
1.8 Revenue recognition
Revenue is measured based on the consideration specified in a
contract with a customer and excludes amounts collected on behalf
of third parties. The Company recognises revenue when or as it
transfers control over a product or service to customer. An asset
is transferred when (or as) the customer obtains control of the
asset. Details of the revenue recognition policies are disclosed in
Note 5.
1.9 Prepayments
Prepayments are carried at cost less provision for impairment. A
prepayment is classified as non-current when the goods or services
relating to the prepayment are expected to be obtained after one
year, or when the prepayment relates to an asset which will itself
be classified as non-current upon initial recognition. Prepayments
to acquire assets are transferred to the carrying amount of the
asset once the Group has obtained control of the asset and it is
probable that future economic benefits associated with the asset
will flow to the Group. Other prepayments are written off to profit
or loss when the goods or services relating to the prepayments are
received. If there is an indication that the assets, goods or
services relating to a prepayment will not be received, the
carrying value of the prepayment is written down accordingly and a
corresponding impairment loss is recognised in profit or loss for
the year.
1.10 Provisions
Provisions for environmental restoration, restructuring costs
and legal claims are recognised when: the Group has a present legal
or constructive obligation as a result of past events; it is
probable that an outflow of resources will be required to settle
the obligation; and the amount has been reliably estimated.
Restructuring provisions comprise lease termination penalties and
employee termination payments. Provisions are not recognised for
future operating losses.
Where there are a number of similar obligations, the likelihood
that an outflow will be required in settlement is determined by
considering the class of obligations as a whole. A provision is
recognised even if the likelihood of an outflow with respect to any
one item included in the same class of obligations may be
small.
Provisions are measured at the present value of the expenditures
expected to be required to settle the obligation using a pre-tax
rate that reflects current market assessments of the time value of
money and the risks specific to the obligation. The increase in the
provision due to passage of time is recognised as interest
expense.
2. Financial risk management
2.1 Financial risk factors
The Group's activities expose it to a variety of financial
risks: market risk (including foreign exchange risk, price risk and
cash flow interest rate risk), credit risk, and liquidity risk. The
Group's overall risk management programme focuses on the
unpredictability of financial markets and seeks to minimise
potential adverse effects on the Group's financial performance.
(a) Market risk
(i) Foreign exchange risk
The Group is exposed to foreign exchange risk arising from
currency exposures, primarily with respect to the RUR. Foreign
exchange risk arises from future commercial transactions,
recognised assets and liabilities.
At 31 December 2019, if the US Dollar had weakened/strengthened
by 5% against the RUR with all other variables held constant,
post-tax profit for the year would have been US$57,797 (2018:
US$49,885) higher/lower, mainly as a result of foreign exchange
gains/losses on translation of RUR-denominated trade payables and
financial assets. At 31 December 2019, if the US Dollar had
weakened/strengthened by 5% against the Euro ("EUR") with all other
variables held constant, post-tax profit for the year would have
been US$30,658 (2018: nil) higher/lower, mainly as a result of
foreign exchange gains/losses on translation of EUR denominated
interest charges and financial liabilities. At 31 December 2019, if
the US Dollar had weakened/strengthened by 5% against the Pound
Sterling ("GBP") with all other variables held constant, post-tax
profit for the year would have been US$3,150 (2018: US$13,303)
higher/lower, mainly as a result of foreign exchange gains/losses
on translation of GBP-denominated trade payables and financial
assets.
If the US Dollar had weakened/strengthened by 5% against the RUR
with all other variables held constant, shareholders' equity would
have been US$2.2 million (2018: US$2.5 million) higher/lower, as a
result of translation of RUR-denominated assets. The sensitivity of
shareholders' equity to changes in the exchange rates between US
Dollar against GBP or EUR is immaterial.
The following table shows the currency structure of financial
assets and liabilities:
At 31 December 2019 Rubles US Dollars Sterling Total
US$ 000 US$ 000 US$ 000 US$ 000
Financial assets
Cash and cash equivalents 4,486 9,535 95 14,116
Trade and other financial receivables 1,471 - - 1,471
-------- ----------- --------- --------
Total financial assets 5,957 9,535 95 15,587
Financial liabilities (before
provision for UK taxes) 4, 222 - - 4, 222
======== =========== ========= ========
At 31 December 2018 Rubles US Dollars Sterling Total
US$ 000 US$ 000 US$ 000 US$ 000
Financial assets
Cash and cash equivalents 5,737 9,231 218 15,186
Trade and other financial receivables 1,823 - - 1,823
-------- ----------- --------- --------
Total financial assets 7,560 9,231 218 17,009
Financial liabilities (before
provision for UK taxes) 5,523 - - 5,523
======== =========== ========= ========
(ii) Price risk
The Group is not exposed to price risk as it does not hold
financial instruments of which the fair values or future cash flows
will be affected by changes in market prices. The Group is not
directly exposed to the levels of international marker prices of
crude oil or oil products, although these clearly influence the
prices at which it sells its oil and condensate. Mineral Extraction
Taxes ("MET") are calculated by reference to Urals oil prices and
are therefore directly influenced by this. Taking into account the
marginal rates of export taxes and MET, management estimates that
if international oil prices had been US$5 per barrel higher or
lower and all other variables been unchanged, the Group's profit
before tax would have been US$1.2 million higher or lower (2018:
$1.6 million).
(iii) Cash flow and fair value interest rate risk
As the Group currently has no significant interest-bearing
assets and liabilities, the Group's income and operating cash flows
are substantially independent of changes in market interest
rates.
(b) Credit risk
The Group's maximum credit risk exposure is the fair value of
each class of assets, presented in Note 3.1(a)(i) of US$15,587,000
and US$ US$17,009,000 at 31 December 2019 and 2018
respectively.
The Group's principal financial assets are cash and trade
receivables. Trade receivables relate to one customer Gazprom
Mezhregiongas Volgograd. This customer has been transacting with
the Group since 2017. To date this customer's balance has not been
ever written off and is not deemed credit-impaired at the reporting
date. The probability of default of Gazprom Mezhregiongas Volgograd
was assessed as low risk. Payments are made within 30 days and
there is no history of defaults. All trade receivables at the
reporting date were classified as current (less than 30 days) and
therefore no impairment was deemed required.
Credit risk also arises from cash and cash equivalents and
deposits with banks and financial institutions. It is the Group's
policy to monitor the financial standing of these assets on an
ongoing basis. Bank balances are held with reputable and
established financial institutions. Any impairment on cash and cash
equivalents has been measured on a 12-month expected loss basis and
reflects the short maturities of the exposures. The Group considers
that its cash and cash equivalents have low credit risk based on
the external credit ratings of the counterparties.
Rating of financial institution 31 December 31 December
(Fitch) 2019 2018
US$ 000 US$ 000
Barclays Bank A 9,299 1,412
ZAO Raiffeisenbank BBB- 4,784 13,769
Other 33 5
------------------ ------------
Total bank balance 14,116 15,186
================== ============
The Group's oil, condensate and LPG sales are normally
undertaken on a prepaid basis and accordingly the Group has no
trade receivables and consequently no credit risk associated with
the related trade receivables.
(c) Interest rate risk
The Group's sole interest rate exposure has been related to its
bank loan which as of 1 February 2019 was repaid in full.
(d) Liquidity risk
The remaining contractual maturities as at 31 December 2019 and
31 December 2018 are as follows:
Maturity period at 0 to 3 months 3 to 12 Over 1 year Total
31 December 2019 months
-------------- -------- ------------ ------
Trade and other payables 4,222 - - 4,222
-------------- -------- ------------ ------
Total 4,222 - - 4,222
Maturity period at 0 to 3 months 3 to 12 Over 1 year Total
31 December 2018 months
-------------- -------- ------------ ------
Trade and other payables 3,863 - - 3,863
Bank loan 1,660 - - 1,660
-------------- -------- ------------ ------
Total 5,523 - - 5,523
Cash flow forecasting is performed by Group finance. Group
finance monitors rolling forecasts of the Group's liquidity
requirements to ensure it has sufficient cash to meet operational
needs. The Group believes it has sufficient liquidity headroom to
fund its currently planned exploration and development
activities.
The Group expects to fund its capital investments, as well as
its administrative and operating expenses, through 2020 using a
combination of cash generated from its oil and gas production
activities, existing working capital and, when appropriate,
medium-term bank borrowings. If the Group is unsuccessful in
generating enough liquidity to fund its expenditures, the Group's
ability to execute its long-term growth strategy could be
significantly affected. The Group may need to raise additional
equity or debt finance as appropriate to fund investments beyond
its current commitments.
(e) Capital risk management
The Group manages capital to ensure that it is able to continue
as a going concern whilst maximising the return to shareholders.
The Group is not subject to any externally imposed capital
requirements. The Board regularly monitors the future capital
requirements of the Group, particularly in respect of its ongoing
development programme. Management expects that the cash generated
by the operating fields will be sufficient to sustain the Group's
operations and future capital investment for the foreseeable
future. During December 2016, one of the Group's operating
subsidiaries entered into a loan agreement of RUR 240 million to
fund its LPG project (see Note 20). This loan, which has a
three-year amortising term, was repaid in full on 1 February 2019.
Further short-term debt facilities may be arranged to provide
financial headroom for future development activities.
(f) Fair value measurement
The Company's financial instruments consist of cash and cash
equivalents, trade and other receivables, and trade and other
payables.
The carrying amounts of cash and cash equivalents, trade and
other receivables and trade and other payables reasonably
approximate their fair values due to the relatively short-term
nature of these financial instruments.
2.2 Fair value estimation
Effective 1 January 2009, the Group adopted the amendment to
IFRS 7 for financial instruments that are measured in the balance
sheet at fair value. This requires disclosure of fair value
measurements by level of the following fair value measurement
hierarchy:
-- Quoted prices (unadjusted) in active markets for identical assets or liabilities (level 1).
-- Inputs other than quoted prices included within level 1 that
are observable for the asset or liability, either directly (that
is, as prices) or indirectly (that is, derived from prices) (level
2).
-- Inputs for the asset or liability that are not based on
observable market data (that is, unobservable inputs) (level
3).
The Group has no financial assets and liabilities that are
required to be measured at fair value.
3. Critical accounting estimates and judgements
The Group makes estimates and assumptions concerning the future.
The resulting accounting estimates will, by definition, seldom
equal the related actual results. The estimates and assumptions
that have a significant risk of causing a material adjustment to
the carrying amounts of assets and liabilities within the next
financial year are discussed below.
a) Carrying value of fixed assets, intangible assets and
impairment
Fixed assets and intangible assets are assessed for impairment
when events and circumstances indicate that an impairment condition
may exist. The carrying value of fixed assets and intangible assets
are evaluated by reference to their value in use and primarily
looks to the present value of management's best estimate of the
cash flows expected to be generated from the asset. In identifying
cash flows, management firstly determines the cash-generating unit
or group of assets that give rise to the cash flows. The
cash-generating unit ("CGU") is the lowest level of asset at which
independent cash flows can be generated. For this purpose, the
Directors consider the Group to have two CGUs: the VM and
Dobrinskoye fields with the Dobrinskoye gas processing plant are
treated as a single CGU, known as "GNS" and the Uzen oil field is a
separate CGU, known as "PGK".
The estimation of forecast cash flows involves the application
of a number of significant judgements and estimates to a number of
variables including production volumes, commodity prices, operating
costs, capital investment, hydrocarbon reserves estimates and
discount rates. Key assumptions and estimates in the impairment
models relate to:
-- International oil prices: flat real prices reflecting the
average levels pertaining during the period 1 December 2019 to 31
January 2020, a Urals oil price of US$63 per barrel. No forward
price escalation is assumed.
-- Selling prices for oil, condensate and LPG that reflect
international oil prices, less export taxes at the applicable
official rates and a price differential of $5 per barrel. Russian
export taxes are being phased out over a five-year period starting
in 2019 - with the same levy being added to the Mineral Extraction
tax formula. It is assumed that domestic prices will continue to
track the netback pricing. Based on actual commercial experience
since May 2018, when production commenced LPG sales prices have on
average been similar to those for condensate. The models assume the
LNG sales price is 10% lower per tonne than condensate.
-- Gas sales price of RUR 4,289 per mcm excluding VAT and net of transportation costs.
-- Production profiles based on remaining reserves in the proved
category and approved field development plans. For the purposes of
impairment testing, the level of reserves used are those
established by the independent consultancy Panterra as at 31
December 2019, in relation to the VM and Dobrinskoye fields. In
respect of the Uzen field, the reserves were estimated by
management and supported by an independent geological review of the
impact of the results of wells drilled during 2019 that was
produced in March 2020. A further evaluation of reserves in Uzen
will be conducted during 2020, to include incremental reserves
discovered in the course of 2019 during development drilling as
detailed in the Operations Report. Meanwhile, management considers
that the after adjusting for subsequent production, the Uzen
reserves estimates remain in line with internal estimates.
-- Capital expenditures required to deliver the above production
profiles and to maintain the production assets throughout the field
life. Total development capital expenditure assumed for the period
2020-2024 is approximately US$14.2 million, primarily on drilling
of development wells, with future capital expenditure beyond that
time of up to US$0.2-1.0 million per annum. The calculation in use
excludes and positive contribution from successful exploratory
drilling or other improvements to the assets.
-- Cost assumptions are based on current experience and
expectations and are broadly in line with unit costs experienced in
the year ended 31 December 2019. The costs included in the analysis
include all field operating and production costs and allocated
overheads of the operating entities.
-- Export and mineral extraction taxes reflect rates set by
current legislation, including the phased transfer of export taxes
(levied on oil exports) to Mineral Extraction Tax (levied on all
oil and condensate production).
-- The model reflects real terms cash flows with no inflationary
escalation of revenues or costs.
-- A real discount rate of 10% per annum is utilised in the models.
-- An exchange rate reflecting the average levels pertaining
during the period 1 December 2019 to 31 January 2020 of RUR67 to
US$1.00 is assumed.
In addition to the base case, a number of sensitivity cases have
been carried out:
-- Varying gas prices by 10%,
-- Varying operating expenditure by 10%,
-- Varying capital expenditure by 20%,
-- Varying reserves by 20% and
-- Using a 12% real discount rate.
-- A lower oil price scenario using flat Urals prices of
US$25.00 per barrel for 2020, US$35.00 for 2021 and US$50.00 for
2022 onwards and an exchange rate of RUR 85 to US$1.00 for 2020,
RUR 75 for 2021 and RUR 70 for 2022 onwards was conducted.
-- As an further sensitivity scenario relating to the VM field a
further set of cases were conducted on the GNS CGU on the basis
that the two new wells on the field, VM#5 and VM#6 were
unsuccessful.
-- "Covid-19 scenario". An additional sensitivity based on
assuming an extreme 6 month shut-in of all production, combined
with the lower oil price assumptions detaild in the price
sensitivity above, was conducted. In this scenario, all production
and capital expenditure is assumed suspended for 6 months, while
the CGUs carry the full fixed operating and G&A costs during
shut-in.
The calculated value in use of the CGUs have been compared to
the net book values of the PP&E associated with the CGUs. The
table below summarises the results of this analysis, indicating the
level of impairment relected in the Base Case and the potential
additional impairments that may arise from each of the sensitivity
cases described above:
Cash generating GNS PGK
unit
(US$000) (US$000)
Net book value as at 31
December 2019
(prior to impairment) 28,786 14,797
Value in use 20,451 15,439
Calculated impairment from 8,335 -
value in use
Additional impairment (US$
million) if:
Reserves -20% 7,531 14,797
Low oil price 14,199 3,022
6 mth shut in 11,530 9,992
Gas price -10% 873 -
Opex +10% 566 416
Capex +20% 791 2,706
NPV 12% 373 2,706
Based on the above analysis, the book value of the GNS assets is
clearly impaired. Given the relatively short remaining field life
and the fact that the operating and capital costs are not
especially high, the cost sensitivities are not major, while the
oil price sensitivities are significantly more material. The value
in use, additionally, is significantly dependent on the reserve
sensitivities - especially in relation to the recognised risk
attached to the outcomes of VM#5 and VM#6. However, while
recognising the sensitivity to this risk factor, management does
not believe that there is a basis for expecting the new wells to be
unsuccessful.
Therefore, the Directors believe an impairment of RUR 375m or
approximately US$8.3 million is indicated and have decided to
include a charge of this amount in the financial statements for the
year ended 31 December 2019.
For the PGK assets, the value in use, under the base case
scenarios show a moderate level of headroom above the carrying
value of the assets. However, the analysis indicates that a very
small reduction in the Uzen field reserves could lead to asset
impairment. The 20% reserve downside case suggests a significant
reduction in value in use. However, management considers that in
event of lower than expected success with development wells, a
modification to development plans involving a reduction in future
capital expenditure would be implemented. This may mitigate the
impact suggested by the single variable sensitivity analysis.
Therefore the directors consider that while there is risk of
substantial future impairment, no impairment is currently indicated
for the PGK assets.
The "Covid-19 shut-in" scenario, while having an impact on the
NPV calculations carried out above, would most likely be reflected
in the results of operations rather than a future asset impairment,
in the absence of unforeseen damage to reservoir productivity
arising from an extended period of shut-in.
Should there be material adverse changes to the assumptions used
in future impairment tests, or should there be further reductions
in reserve estimates, there may be impairment of one or both of the
CGUs.
(b) Estimation of oil and gas reserves
Estimates of oil and gas reserves are inherently subjective and
subject to periodic revision. In addition, the results of drilling
and other exploration or development or production activity will
often provide additional information regarding the Group's reserve
base that may result in increases or decreases to reserve volumes.
Such revisions to reserves can be significant and are not
predictable with any degree of certainty. Management considers the
estimation of reserves to represent a significant judgement in the
context of the financial statements as reserve volumes are used as
the basis for assessing the useful life of oil and gas assets,
applying depreciation to oil and gas assets and in assessing the
carrying value of oil and gas assets. Decreases in reserve
estimates can lead to significant impairment of oil and gas assets
where revisions (positive or negative) can have a significant
effect on depreciation rates from period to period. Variation of
20% from the base level of reserves is among the sensitivity tests
carried out in impairment testing as described in Note 4(a)
above.
An independent assessment of the reserves and net present value
of future net revenues ("NPV") attributable to the Group's
Dobrinskoye and Vostochny Makarovskoye fields as at 31 December
2019, was prepared in accordance with reserve definitions set by
the Oil and Gas Reserves Committee of the Society of Petroleum
Engineers ("SPE"). The catalyst for this revision was the
indication of a significantly higher than anticipated level of
gas:water contact in the main reservoir of the VM field. Management
considered these revised estimates to be reasonable and adopted
them as the Group's reserves.
Independent reserves estimates of the Sobolevskoye and
Uzenskoye, as at 31 December 2017, were prepared in accordance with
reserve definitions set by the Oil and Gas Reserves Committee of
the Society of Petroleum Engineers ("SPE"). The reserve estimate as
at 31 December 2019 is accordingly only adjusted for the volumes
produced in the two years to 31 December 2019. An independent
geological review by Panterra Group, based on the updated data
provided from 2019 drilling activity on the Uzen field, supports
management's current estimates.
4. Revenue from contracts with customers
The Group generates revenue primarily from sales of oil, gas,
gas condensate and LPG. In the following table, revenue is
disaggregated by primary geographical market, major
products/service lines and timing of revenue recognition.
Year ended 31 December 2019 2018
Major products lines US$ 000 US$ 000
Oil 7,023 10,473
Condensate 25,070 19,681
LPG 2,635 2,841
Gas 11,228 12,880
-------- --------
Total revenues 45,956 45,875
======== ========
Year ended 31 December 2019 2018
Primary geographical markets US$ 000 US$ 000
Russia 34,726 42,281
Europe 11,230 3,594
--------
Total revenues 45,956 45,875
--------
Year ended 31 December 2019 2018
Timing of transfer of goods or services US$ 000 US$ 000
Products and services transferred
at a point in time 34,728 32,995
Products and services transferred
over time 11,228 12,880
--------
Total revenues 45,956 45,875
--------
5. Cost of sales and administrative expenses - Group
Cost of sales and administrative expenses are as follows:
Year ended 31 December 2019 2018
US$ 000 US$ 000
Production expenses 7,230 8,348
Mineral Extraction Taxes 14,257 13,194
Depletion, depreciation and amortisation 14,856 8,220
-------------------- -----------------------
Cost of Sales 36,343 29,762
==================== =======================
Total expenses are analysed as follows:
Year ended 31 December 2019 2018
US$ 000 US$ 000
(
a
Sales related expenses ) 3,771 2,473
Field operating expenses 5,026 5,865
Mineral extraction tax 14,257 13,194
Depreciation & amortization 14,865 8,237
(
b
Write off of development assets ) 2,608 1,513
Impairment charge 8,335 -
Inventory write off 16 391
Salaries & staff benefits 4,671 4,632
Directors' emoluments and other benefits 616 677
Audit fees 240 281
Taxes other than payroll and mineral
extraction 658 716
Legal & consulting 651 586
Other 165 104
-------------------- -----------------------
Total 55,879 38,669
==================== =======================
(b) Selling expenses: Comprise pipeline transit costs and fees
related to gas sales as well as export taxes and costs associated
with delivering gas condensate sales to export customers.
(b) Write-off of development assets - During the year ended 31
December 2019, the Group wrote off assets of US$2,608,000 (2018:
US$1,513,000) of capitalised costs, primarily relating to
unsuccessful drilling operations on two development wells. The
write off in 2018 related to the subject of a legal dispute with a
drilling contractor in which the Group received a court settlement
totalling US$3,120,000. This settlement was recognised as other
operating income in 2018.
6. Other gains and losses - Group
Year ended 31 December 2019 2018
US$ 000 US$ 000
-------- --------
Foreign exchange loss ( 574) ( 133)
Other losses (279) ( 59)
-------- --------
Total other gains and losses ( 853) (192)
======== ========
7. Basic and diluted profit per share - Group
Profit per share is calculated by dividing the profit
attributable to equity holders of the Company by the weighted
average number of ordinary and diluted shares in issue during the
year.
Year ended 31 December 2019 2018
Net (loss)/profit per share attributable
to equity shareholders (0.1239) 0.1037
Diluted net (loss)/profit per share attributable
to equity shareholders (0.1239) 0.1037
Net profit attributable to equity shareholders ( 10,017) 8,404
Basic weighted average number of shares 80,823,327 81,017,800
Dilutive share options in issue - -
Diluted number of shares 80,823,327 81,017,800
Since 1 January 2018 there have been no options outstanding. On
17 April 2019, the Company purchased 450,000 of its own Ordinary
shares, which were held in treasury. On 4 July 2019, 250,652
treasury shares were transferred to Andrey Zozulya in settlement of
his bonus award. The number of treasury shares was therefore
reduced to 199,348. For the year ended 31 December 2019, the
weighted average number of shares in issue, less treasury shares,
was 80,823,327 (2018: 81,017,800). As at 31 December 2019, the
total voting rights, being the number of shares in issue less
treasury shares was 80,818,452 (2018: 81,017,800).
8. Intangible assets - Group
Intangible assets represent exploration and evaluation assets
such as licences, studies and exploratory drilling, which are
stated at historical cost, less any impairment charges or
write-offs.
Work in progress: Exploration Total
exploration and
and evaluation evaluation
At 1 January 2019 122 3,182 3,304
Additions - 451 451
Write offs - (31) (31)
Transfers - (738) (738)
------------------ -------------- --------------
At 31 December 2019 122 2, 863 2, 985
Exchange adjustments 15 37 4 38 9
------------------ -------------- --------------
At 31 December 2019 137 3,237 3, 374
================== ============== ==============
Work in progress: Exploration Total
exploration and
and evaluation evaluation
At 1 January 2018 147 3,609 3,756
Additions 211 211
Write-offs - - -
------------------ -------------- --------------
At 31 December 2018 147 3,820 3,967
Exchange adjustments (25) (638) (663)
------------------ -------------- --------------
At 31 December 2018 122 3,182 3,304
================== ============== ==============
9 . Property, plant and equipment - Group
Movements in property, plant and equipment for the year ended 31
December 2019 are as follows:
Cost Development Land & Producing Other Total
assets buildings assets
US$ 000 US$ 000 US$ 000 US$ 000 US$ 000
At 1 January 2019 1,038 718 72,295 722 74,773
Additions 8,967 - - - 8,967
Write-offs (2,067) (255) (720) (146) (3,188)
Transfers (4,653) 311 4,786 294 738
Exchange adjustments 229 91 9,021 96 9,437
------------ ----------- ---------- -------- ---------
At 31 December
2019 3,514 865 85,382 966 90,727
Accumulated depreciation
At 1 January 2019 - (61) (28,929) (674) (29,664)
Depreciation - (25) (14,689) (119) (14,833)
Adjustment for
assets written
off - - 239 111 350
( 8,084 (8, 335
Impairments (123) ( 92 ) ) (36) )
------------ ----------- ---------- -------- ---------
Exchange adjustments - (9) (4,196) (83) (4,288)
------------ ----------- ---------- -------- ---------
At 31 December ( 187 (55, 659
2019 (123) ) ) ( 801 ) (56,770)
Net book value
at 31 December
2019 3, 391 678 29, 723 166 33,957
============ =========== ========== ======== =========
Movements in property, plant and equipment for the year ended 31
December 2018 are as follows:
Cost Development Land and Producing Other Total
assets buildings assets
US$ 000 US$ 000 US$ 000 US$ 000 US$ 000
At 1 January 2018 6,483 820 80,993 747 89,043
Additions 2,390 - 231 - 2,621
Write-offs (1,574) - - - (1,574)
Transfers (5,621) 42 5,465 114 -
Exchange adjustments (640) (144) (14,394) (139) (15,317)
--------------------- ----------- ---------- -------- ---------
At 31 December 2018 1,038 718 72,295 722 74,773
Accumulated depreciation
At 1 January 2018 - (42) (25,934) (738) (26,714)
Depreciation - (29) (8,227) (68) (8,324)
Exchange adjustments - 10 5,232 132 5,374
--------------------- ----------- ---------- -------- ---------
At 31 December 2018 - (61) (28,929) (674) (29,664)
--------------------- ----------- ---------- -------- ---------
Net book value
At 31 December 2018 1,038 657 43,366 48 45,109
===================== =========== ========== ======== =========
10. Cash and cash equivalents
Group
At 31 December 2019 2018
----------- --------
US$ 000 US$ 000
Cash at bank and on hand 14,116 15,186
Total cash and cash equivalents 14,116 15,186
An analysis of Group cash and cash equivalents by bank and
currency is presented in the table below:
Group
At 31 December 2019 2018
-------------- ---------------
Bank Currency US$ 000 US$ 000
United Kingdom
Barclays Bank PLC USD 9,204 1,193
Barclays Bank PLC GBP 95 218
Russian Federation
ZAO Raiffeisenbank RUR 4,453 5,731
ZAO Raiffeisenbank USD 331 8,038
Other banks and cash on hand RUR 33 6
Total cash and cash equivalents 14,116 15,186
============== ===============
1 1 . Inventories - Group
At 31 December 2019 2018
US$ 000 US$ 000
Production consumables and spare
parts 441 603
Crude oil inventory 153 335
------------- --------
Total inventories 594 938
============= ========
Inventory recognised as cost of sales in the year amounted to
US$2,526,000 (2018: US$2,474,000 ). In the year to 31 December 2019
there was a US$65,000 reversal of previous write-down of
inventories to net realisable value (2018: write down of
US$378,000). This is included in operating and administrative
expenses.
12. Trade and other receivables
At 31 December 2019 2018
US$ 000 US$ 000
Taxes recoverable 429 399
Prepayments 280 558
Trade receivables 875 1,411
Other accounts receivable 167 13
------------- --------------
Total other receivables 1,752 2,381
============= ==============
Prepayments are to contractors and relate to initial advances
made in respect of drilling, construction and other projects. Trade
receivables relate to sales of gas and condensate. The receivables
were settled on schedule subsequent to the balance sheet date.
1 3 . Trade and other payables
At 31 December 2019 2018
US$ 000 US$ 000
-------- --------
Trade payables 993 1,085
Taxes other than
profit tax 3,140 2,741
Customer advances 1,538 1,577
Other payables 959 645
-------- --------
Total 6,630 6,047
======== ========
The maturity of the Group's and the Company's financial
liabilities are all between zero to three months. Customer advances
are prepayments for oil and condensate sales, normally one month in
advance of delivery.
This information is provided by RNS, the news service of the
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END
FR SSMEEMESSESL
(END) Dow Jones Newswires
April 07, 2020 02:00 ET (06:00 GMT)
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