TIDMVGAS
RNS Number : 7782T
Volga Gas PLC
01 April 2016
1 April 2016
VOLGA GAS PLC
Preliminary results for the year ended 31 December 2015
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 2015.
During 2015, the Group had to face significantly reduced oil
prices and devaluation of the Russian Ruble as well as relatively
higher rates of Mineral Extraction Taxes and disruptions to the
regional market for condensate. Nevertheless, the Group maintained
positive EBITDA and Operating Cash flow and remained in a positive
net cash position while increasing capital expenditure to
facilitate the completion of development drilling on its Vostochny
Makarovskoye ("VM") gas/condensate field.
As a result of successful drilling activities in 2015, the
effective production rates of the Group's fields increased by one
third from approximately 4,500 barrels of oil equivalent per day
("boepd") to the current level of over 6,000 boepd.
FINANCIAL RESULTS
-- Revenues of US$17.8 million (2014: US$39.4 million).
-- EBITDA of US$0.9 million (2014: US$17.4 million).
-- Loss before tax of US$5.0 million (2014: profit of US$16.3
million), after exploration expenses and impairments of US$3.7
million (2014: nil), a loss of $0.7 million from unauthorised
transfers from Group bank accounts in Russia (2014: nil) and a
foreign exchange gain of US$0.9 million (2014: US$3.3 million).
-- Net operating cash flow of US$1.2 million (2014: US$16.3 million).
-- Net cash decreased to US$6.7 million as at 31 December 2015
(31 December 2014: US$15.8 million) after utilising US$8.7 million
for capital expenditure (2014: US$5.5 million) and paying a final
dividend of US$1.0 million (2014: US$3.0 million interim
dividend).
PRODUCTION & DEVELOPMENT
-- Group average production in 2015 was 3,278 boepd (2014: 4,244 boepd).
-- Production from VM and Dobrinskoye fields was impacted by
disruption in the local market for condensate during early and
mid-2015 and consequently averaged 2,876 boepd in 2015 (2014: 3,549
boepd).
-- Drilling of the VM#3 well and of a sidetrack on VM#4 were
successfully completed during 2015, effectively concluding
development drilling on the VM field. The total wellhead capacity
is currently estimated to exceed the planned 1 million cubic metres
per day maximum output of the gas plant.
DOBRINSKOYE GAS PLANT
-- Dobrinskoye gas plant operated successfully during 2015 and
in December 2015 throughput was increased by 50% to 750,000 cubic
metres per day (26.5 mmcf/d), when the recently completed VM#4 well
was brought on line.
-- Completed minor additional modifications to meet regulatory
requirements and improve efficiency.
-- Completed feasibility and design work to increase throughput
and cost efficiency with Amine gas sweetening project.
CURRENT TRADING AND OUTLOOK
-- After the normal seasonal slow start in January, production
has been sustained at higher levels and is currently running
steadily at over 6,000 boepd.
-- Oil prices and the Russian Ruble weakened in January and,
although having recovered somewhat, remain at low levels compared
to recent years. In the current environment, the Group expects to
improve on the financial performance of 2015.
-- Exports now represent a substantial proportion of condensate
sales, protecting the business from disruptions to local
markets.
-- Capital expenditure commitments have been reduced to a
minimal level - to below US$1.5 million of new capital expenditure
in 2016.
-- Aim to preserve financial strength and to benefit from an eventual upturn in oil prices.
Andrey Zozulya, Chief Executive of Volga Gas, commented:
"The business environment in 2015 has been very challenging for
a small, domestically oriented Russian oil, gas and condensate
producer like Volga Gas. It is fortunate that the Group entered
this challenging period in sound financial condition so that it has
been able to complete the drilling on its main producing field with
successful outcomes. Now, with the majority of the current capital
programme executed, the Group should be able to benefit from its
increased production capacity and has a solid base from which to
grow its production.
"I am excited about the Group's assets and remain positive about
the potential for growth, both in reserves and production from our
licences. We will also continue seek value accretive opportunities,
beyond our existing licence areas, building a focused exploration
and production business."
For additional information please contact:
Volga Gas plc
Andrey Zozulya, Chief
Executive Officer +7 (903) 385 9889
Tony Alves, Chief Financial
Officer +44 (0)20 8622 4451
Stifel Nicolaus Europe
Limited
Michael Shaw
Ashton Clanfield +44 (0)20 7710 7600
FTI Consulting
Ed Westropp +44 (0)20 3727 1000
Alex Beagley
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
The Group's full report and accounts, including 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, 40 Dukes Place, London EC3A 7NH.
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
m(3) standard cubic metre
mmcf/d millions of standard cubic feet per day
mmcm/d millions of standard cubic metres per day
RUR Russian Rouble
Chairman's Statement
Dear Shareholder,
As anticipated by my predecessor in the 2014 Annual Report, 2015
was a challenging year for the oil and gas industry worldwide, for
Russia and no less challenging for Volga Gas. The collapse in oil
prices and in the value of the Russian Ruble had significant impact
on the financial statements and the performance of the Company as
reported in US dollars. Furthermore, changes to the production tax
formulae that came into effect in 2015 meant that a greater
proportion of gross revenue was paid out in taxes than in previous
years.
However, on an operational level, the results of 2015 were
satisfactory. The development drilling on the Vostochny
Makarovskoye ("VM") field was successfully concluded during the
year, which will enable this field, the Group's principal producing
asset, to reach and sustain the planned plateau production rate of
one million cubic metres per day of gas plus associated
condensate.
With production from the first of the two new wells coming only
in December 2015, this drilling activity did not make a significant
contribution to the production for the full year. However, during
mid December 2015, new the production from the VM#4 well enabled
total output from the VM and Dobrinskoye fields to reach the
intermediate target rate of 750,000 cubic metres per day of gas
plus 180 tonnes per day of condensate, in total approximately 5,700
barrels of oil equivalent per day. This production is the core of
stable production which provides the main cash generation engine
for the Group.
The next strategic development to be undertaken is further
enhancement of the existing gas processing facilities, first to
introduce a more efficient process for the sweetening of the gas
and secondly to capture for sale the liquid petroleum gases ("LPG")
that are currently vented and flared. The former is intended to
achieve significant cost savings and enable higher production rates
of over one million cubic metres per day of gas, while the latter
will provide an additional and potentially highly profitable
product stream.
In the meanwhile, however, the Group continues to face a number
of significant challenges, not the least of which is the general
economic situation in Russia, where the dramatic fall in
international oil prices has had a significant impact on the
domestic economy as well as on the profitability and cash
generation from our production.
While the Group remains in a healthy financial position, with
positive net cash balances, the Board has made the strategic
decision to preserve liquidity and to reduce capital expenditures
to a minimal level. This means that the strategic investments
outlined earlier will need to be deferred until cash generation
recovers to a sustainably higher level than currently being
experienced or acceptable external finance, consistent with a
prudent financial strategy, can be arranged.
Volga Gas continues to benefit from low operating costs and,
with its fields based close to market, is able to operate
profitability even with significantly reduced oil and gas prices.
During 2015 there were periods when local market conditions made it
difficult to sell our condensate production and during these
periods, gas and condensate production had to be suspended. Towards
the end of 2015, the Group developed channels for exporting
condensate and consequently there are alternatives to sales solely
into the local domestic market.
(MORE TO FOLLOW) Dow Jones Newswires
April 01, 2016 02:00 ET (06:00 GMT)
The Group holds significant proven reserves in its three
principal fields. These reserves form the basis of sustainable
production with growth potential in the near term. These assets
provide a platform for the Group to grow in the future, both
through successful exploration and by selective value accretive
acquisitions. The Board believes that Volga Gas has a strong asset
base and the financial and operational capability to develop and
extend these assets to provide long-term value growth for our
shareholders.
Finally, I would like to pay tribute to my predecessor as
Chairman, Aleksey Kalinin, for his leadership of the Company since
its foundation and appreciation for his continued service as a
non-executive director. I also welcome my successor as Chief
Executive Officer, Andrey Zozulya who assumed that position in May
2015. He has had to take up his responsibilities at a very
challenging time in our industry and has the full support and
confidence of the Board as he manages the future development of the
business.
Mikhail Ivanov
Chairman
Chief Executive's Report
As the Chairman has noted, Volga Gas faced significant
challenges during 2015, with market factors constraining gas and
condensate production during the first half of the year, declines
in production from the mature oil wells, dramatic reductions in
international oil prices and higher rates of production taxes. Each
of these factors has had an impact on the financial performance of
the Group.
There was, however, continued operational progress during the
year. Development drilling on our main field, Vostochny
Makarovskoye ("VM") was successfully concluded and towards the end
of 2015 we increased the rate of production from the VM and
Dobrinskoye fields by 50%. However, this late lift in production
did not make a material contribution to the Group's full year's
average daily production which was severely impacted by lower
production earlier in the year.
Another factor in the Group's overall production in 2015 was the
continuing decline in oil production from the mature Uzenskoye
field. However, Volga Gas had made very good returns from these
assets and management has identified opportunities to revive oil
production both by further development of proven reserves and by
exploration for new reserves. As part of this strategy, a number of
operations were carried out during 2015, as detailed in the
Operations Report below. Unfortunately, these did not result in
immediate success, but I am optimistic that the strategy will yield
significant levels of oil production in the future.
Following my appointment as Chief Executive on 5 May 2015, I
decided it would be most effective if I were to be based close to
the operations in the city of Saratov, rather than in Moscow. Since
then, I have initiated a restructuring of the operational teams
with the aim of improving the effectiveness of our operational
capabilities. In addition, following an incident that led to a loss
of funds from certain of our bank accounts, detailed below, I
decided to improve the online security and make changes to the
financial management in the operating companies. I believe that
with these changes implemented, the Group is well placed to develop
successfully in the future.
2016 Objectives and Medium Term Strategy
Having successfully completed the drilling of the VM#3 and VM#4
wells, the VM field is now effectively fully developed and is
expected to be able to deliver sufficient production to maintain a
production plateau of 1 million m(3) per day (35.3 million cubic
feet per day - "mmcf/d"). However, based on its current
configuration, we believe the gas processing plant is capable of
sustaining production at a rate of 750,000 m(3) per day (26.5
mmcf/d). Following extensive technical evaluation and consideration
of alternatives, it has been decided that the most effective
solution for the longer term is to re-configure the gas plant to
utilise an Amine-based gas sweetening process. We believe that this
can be achieved with a modest investment, recently estimated at
approximately US$8 million. If successful, this would significantly
reduce the costs of chemicals consumed in gas processing and allow
the gas plant to process the targeted 1 million m(3) per day (35.3
mmcf/d) of gas. A more ambitious plan, to install equipment to
capture and sell liquid petroleum gases ("LPG"), would be a
follow-on project which could add a valuable further income
stream.
Meanwhile, however, the Board of Volga Gas has decided to
preserve the financial strength of the Group and defer capital
expenditures while oil prices remain at very low levels. For the
time being, capital expenditure will be limited to completing
payments for ongoing projects and necessary items to maintain
producing assets.
A new commercial initiative that has been implemented is the
development of a channel for exports of our condensate production.
A small number of cargoes were exported in November and December
2015. It is our aim to provide a viable alternative for sales in
the event that the local domestic market for condensate closes, as
it did during a number of weeks during 2015.
Finance
In spite of the challenges mentioned above, the Group managed to
maintain positive net cash flow from operations, although as a
result of the capital expenditure incurred during 2015, there was a
net cash outflow of US$9.0 million. This includes a sum equivalent
to approximately US$0.7 million lost from certain Group bank
accounts as a result of unauthorized transfers in an apparent
cyber-attack. The Group remained in a net cash position and the
closing cash balance at 31 December 2015 was US$6.8 million with no
debt.
Further development and exploration expenditures in 2016 and
beyond have been deferred until the Board is confident that these
can be funded from operating cash flow. In addition, the Group may
consider a moderate level of borrowing to be appropriate to fund
significant value accretive investments such as the upgrade to
amine processing at the gas plant.
Current trading and outlook
During January and February 2016, Group production averaged
5,632 barrels of oil equivalent per day, in line with management's
plan. The gas plant is consistently operating at planned capacity
of 750,000 m(3) per day, with condensate output running at over
1,700 barrels per day, the majority of which is being sold to
export markets. International oil prices have recovered from the
low levels seen in January, as has the Ruble. Oil production is now
a minor part of the Group's output and has suffered moderate
disruption as the mild winter caused difficulties in transportation
of oil sales.
In the current environment, and at current production rates,
management expects the Group's financial performance in 2016 to
improve on that of 2015. Meanwhile, new capital expenditure
commitments have been reduced to minimal levels - below US$1.5
million.
Andrey Zozulya
Chief Executive Officer
Operational Review
Operations overview
The overall level of production in 2015, at 3,278 boepd, was 23%
below the 4,244 boepd achieved in 2014. The principal reason for
this was that in periods during January, February and again in May
and June 2015, the local market for our condensate was effectively
closed and production of gas and condensate had to be suspended for
a period of close to six weeks. In addition, we experienced
continued declines in oil production from the mature Uzen
field.
However, in the periods when the condensate market was
functioning normally, production from the VM and Dobrinskoye fields
was exactly as planned. Furthermore with the successful completion
of the drilling operations on the VM#3 and VM#4 wells, the
production capacity on the VM field increased significantly and, in
December 2015, the VM#4 well was brought into production, leading
to an immediate increase of 50% in gas and condensate
production.
As a consequence of the lower production in 2015, significantly
lower oil prices and the devaluation of the Ruble, revenues were
down by 56% in US dollar terms. The increase in formula rates of
Mineral Extraction Taxes put further pressure on EBITDA which,
although still positive, was down by 94% compared to the 2014
level. Full details are discussed in the Financial Review
below.
Gas/condensate production
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. Since November 2013, production has normally been running at
levels that reflect the capacity of the existing wells in the two
fields, that is approximately 500,000 m(3) per day (17.8 mmcf/d) of
gas and 120 tonnes per day (1,050 barrels per day ("bpd")) of
condensate.
During January and February 2015 and again during May and June
2015, production of gas and condensate had to be temporarily
suspended since it was not possible to sell the condensate produced
in the local market. (Gas and condensate are produced
simultaneously from the wells and once the storage capacity at the
gas plant is full, it is necessary to cease production.) In
addition, during July, Gazprom was undertaking extensive
maintenance to the local gas pipeline network and for this period,
there were limitations to the volume of gas that could be accepted
in the pipeline. For these reasons production during 2015 averaged
12.5 mmcf/d of gas and 784 bpd of condensate (2014: 15.5 mmcf/d of
gas and 966 bpd of condensate).
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Gas continues to be sold to Trans Nafta under contract at a
fixed Ruble contract gas sales price. The Ruble price increased
from RUR 3,887 per thousand cubic metres ("mcm") to RUR 4,201 per
mcm in July 2015. However, with the devaluation of the Ruble during
2015, the US Dollar equivalent of the price declined further during
2015. Historically, condensate was sold entirely into the local
domestic market. However, with the periods of low domestic demand
which impacted our business during 2015, it was decided to develop
new commercial channels for exporting condensate. During November
and December 2015, a number of cargoes of condensate were sold to
export customers in the Baltic region. While realisations were less
than we would normally achieve in the domestic market, exports
provide a viable alternative sales route for our production. We
continue to work on these sales and on improving the
realisations.
The average gas sales price for 2015 was the equivalent of
US$1.51 per thousand cubic feet, net of VAT (2014: US$2.15). During
2015 the average condensate sales price was US$23.89 per barrel
(2014: US$44.11 per barrel).
Average unit production costs on the gas-condensate fields
declined to US$5.06 per boe in 2015 (2014: US$6.49). The decline in
the Ruble, in which effectively all the costs are denominated,
partly offset higher costs associated with chemicals consumed in
gas processing and higher costs of waste disposal as well as other
inflationary cost increases.
During 2015, the main development activity was the drilling of
the VM#3 and VM#4 production wells. The VM#3 well had commenced
drilling in 2014, however, the local drilling contractor was unable
to overcome mechanical difficulties and the operations were
suspended after various attempts. Subsequently, the Group
contracted Eurasia Drilling to complete this well and to drill a
sidetrack to the VM#4 well, and a new rig was mobilised during
February 2015.
The initial operation was on VM#4, a well that was originally
drilled in 2008-2009 but which intersected a low permeability zone
in the target horizon. A productive target was identified with a
bottom-hole location approximately 500 metres from the original
well. By May 2015, drilling on the VM#4 sidetrack was concluded,
the deviated well section having intersected a total reservoir of
40 metres. Based on flow testing, management estimated that this
well could be the most productive on the VM field, being capable of
sustaining a flow rate of up to 350 mcm/d (12.4 mmcf/d). The tie
back of this well was undertaken and in December 2015 the well was
put in production. After a short build-up, by 16 December 2015, the
combined daily output of gas from four wells, VM#1, VM#2, VM#4 and
Dobrinskoye #22, produced 755,000 m(3) per day of sales gas.
On conclusion of the drilling on VM#4, the rig was mobilised to
the VM#3 location and in August 2015, the well reached the planned
target depth. In this well, the top of the reservoir section was
found higher than anticipated and total pay of close to 100 metres
was logged. In addition, the well was drilled deeper than the
original plan, and a high specification logging operation
undertaken to gather data that may be used for future development
of the field.
Given the strong flow rates from VM#4, and that current well
capacity is sufficient to fully utilise available plant capacity,
the tie-back of the VM#3 well has been deferred to the springtime
of 2016 when the operations can be concluded more conveniently.
Based on this successful drilling and with continuing management
of the existing well stock including, as appropriate, acid wash
treatments, it seems likely that no further drilling will be
required to produce the VM field at the target plateau rate of 1.0
mmcm/d (35.3 mmcf/d).
Gas processing plant
Since December 2015, the Dobrinskoye gas processing plant has
been consistently operating at rates of over 750,000 m(3) per day
(26.5 million cubic feet per day), a 50% increase above the normal
operating rates achieved in 2014 and most of 2015. While the
physical process plant and pipelines were designed to operate at 1
million m(3) per day, the need to dispose of bulky spent chemicals
used in gas sweetening is the principal constraint on the
operations.
During 2015, a number of technical and feasibility studies were
conducted, including consideration of alternative sweetening
chemical processes and a more ambitious project to simultaneously
install amine sweetening and LPG extraction. Given the financial
constraints, it was decided that these investments should be
deferred until a significant recovery in cash generation could be
confidently expected.
Oil production
Having completed its seventh year of full time production, the
Yuzhny Uzenskoye oil field is the Group's longest established
field. It continues to produce under natural reservoir pressure
drive although water cut has risen. As the oil has been produced,
the oil-water contact in the reservoir has risen and since the
start of 2013, wells at the edge of the field have exhibited some
water cut and were shut in. As a consequence, oil production from
the field has been managed at anticipated declining production
rates.
During 2015, a sidetrack from the currently non-producing Uzen
#8 well was drilled with the intention of producing oil from a
potentially bypassed "attic" in the Aptian reservoir. Unfortunately
this operation was not successful owing to mechanical difficulties,
although at the equivalent of US$0.4 million, the cost was
modest.
There remain significant proved undeveloped reserves in the
shallower Albian reservoir. Following a technical study carried out
during 2015, it appears that a viable development plan for this
reservoir would be to drill two horizontal production wells. The
cost of each of these wells is currently estimated to be US$2.0
million and would expect to develop over 2 million barrels of
reserves at a capital cost equating to US$4.00 per barrel of
reserves. Along with other discretionary capital expenditure,
however, this investment has been temporarily deferred.
Also during 2015, a sidetrack to the Sobolevskaya-11 well on the
Urozhainoye-2 licence was drilled. This well, which was originally
drilled by a previous licencee, had been produced by Volga Gas
during 2013 and 2014 but was depleted. The sidetrack was intended
to access a potential small undeveloped oil reserve. Mechanical
difficulties with the drilling prevented this sidetrack from
reaching the intended target and the operations have been
suspended. Further operations on this have been deferred pending
evaluation.
The Group's oil production, whilst of modest scale, has been
very profitable for the Group and a useful contributor of cash
flow.
Exploration
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. These provide low cost opportunities to add
potentially material oil reserves.
During December 2015, an exploration well was drilled on one of
these targets, the Yuzhno Mironovskaya prospect. This well was
drilled to a total vertical depth of 940 metres within a time of 21
days, a record drilling rate for the Group. After running logs, the
principal and secondary target zones in the Cretaceous post-salt
Albian and Aptian formations were found to be water bearing and the
well was plugged and abandoned. With the efficient well drilling,
the total cost of this well was limited to approximately US$0.6
million.
The Group has fulfilled all its licence commitments on the
Karpenskiy Licence Area and further drilling in the area is
discretionary. Nevertheless future development of the oil potential
in the Group's licences is a key element of management's medium
term strategy.
Oil, gas and condensate reserves as of 1 January 2016
During 2012, an independent evaluation of the Group's oil, gas
and condensate reserves was conducted by Miller and Lents Ltd.
The independent assessment of the reserves and net present value
of future net revenue ("NPV") attributable to the Group's three
principal fields, Dobrinskoye, Vostochny Makarovskoye and
Uzenskoye, as at 1 August 2012, was prepared in accordance with
reserve definitions set by the Oil and Gas Reserves Committee of
the Society of Petroleum Engineers ("SPE").
The following table shows the Proven and Probable reserves as
evaluated by Miller & Lents as at 1 August 2012, adjusted by
management for subsequent production.
Oil, gas and condensate reserves
Oil & Gas Total
Condensate
(mmbbl) (bcf) (mmboe)
------------------------ ------------ ------ --------
As at 31 December 2014
Proved reserves 13.428 147.1 37.894
Proved plus probable
reserves 14.732 158.0 41.020
------------------------ ------------ ------ --------
Production: 1 January
-31 December 2015 0.439 4.5 1.196
As at 31 December 2015
Proved reserves 12.989 142.6 36.698
Proved plus probable
reserves 14.293 153.5 39.824
------------------------ ------------ ------ --------
Notes:
1. There has been no external reassessment of reserves
subsequent to the Miller and Lents reserve study of 2012.
2. The above reserve estimates, prepared in accordance with
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.
Financial Review
Results for the year
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In 2015, the Group generated US$17.8 million in turnover (2014:
US$39.4 million) from the sale of 438,910 barrels of crude oil and
condensate (2014: 603,950 barrels) and 4,545 million cubic feet of
natural gas (2014: 5,671 million cubic feet).
The average price realised for liquids was the equivalent of
US$25.16 per barrel (2014: US$45.07 per barrel). Oil and condensate
sales were primarily made into the domestic market during the
period, although during November and December 2015 approximately
12,000 barrels of condensate, a little less than 2% of the total
liquids sales, were exported to customers in Lithuania (2014: nil).
Our oil and condensate sales prices in the domestic market reflect
international prices after adjusting for export taxes and
transportation costs.
The gas sales price during 2015 averaged US$1.49 per thousand
cubic feet (2014: US$2.15 per thousand cubic feet), the fall being
entirely attributable to the devaluation of the Ruble. The sales
price of gas in Rubles increased by 8.1% in July 2015 (9.5% in July
2014). Production activities generated a gross profit of US$2.2
million in 2015 (2014: US$16.9 million).
In 2015, the total cost of production decreased to US$7.4
million (2014: US$9.5 million), primarily reflecting the effect of
devaluation on our predominantly Ruble denominated costs.
Production based taxes were US$5.9 million (2014: US$8.3 million)
reflecting lower volumes and the impact of lower oil prices and
Ruble exchange rates on Mineral Extraction Tax ("MET") rates.
However, with formula changes coming into effect on 1 January 2015,
MET paid in 2015 represented 35% of revenues (2014: 22% of
revenues).
Operating and administrative expenses in 2015 were US$3.4
million (2014: US$4.2 million).
The Group experienced a significant reduction in EBITDA (defined
as operating profit before non-cash charges, including exploration
expense, depletion and depreciation) to US$0.9 million (2014:
US$17.4 million) as a result of the lower revenues, partly offset
by lower expenses.
After incurring exploration and evaluation expenses of US$0.6
million (2014: nil) on unsuccessful exploration drilling and other
asset impairment expenses, mainly arising from unsuccessful
drilling activities, of US$3.0 million (2014: nil) the Group
recorded an operating loss for 2015 of US$5.0 million (2014:
operating profit of US$12.8 million).
Including net interest income of US$0.1 million (2014: US$0.2
million) and other net gains of US$0.3 million (2014: US$3.3
million) the Group recognised a loss before tax of US$4.6 million
(2014: profit before tax of US$16.3 million) and reported net loss
after tax of US$4.1 million (2014: net profit after tax of US$13.1
million) after a deferred tax credit of US$0.6 million (2014:
deferred tax charge of US$3.2 million).
Included in Other gains and losses in 2015 was a foreign
exchange gain of US$1.0 million arising from US Dollar cash
balances held by Russian subsidiaries which have the Ruble as
functional currency (2014: US$3.3 million gain on foreign exchange)
and a loss of approximately US$0.7 million equivalent arising from
unauthorised withdrawals from bank accounts held by the Group's
Russian operating subsidiaries (2014: nil).
Cash flow
Group cash flow from operating activities was US$1.2 million
(2014: US$16.2 million). Net working capital movements contributed
cash inflow of US$0.8 million in 2015 (2014: US$0.6 million). With
higher capital expenditures in 2015, the net outflow from investing
activities was US$8.7 million (2014: US$5.5 million). Net cash
outflow from financing activities was US$1.0 million (2014: outflow
of US$3.0 million), in both cases related to payment of equity
dividends.
Dividend
In July 2014, the Board announced the adoption of a policy to
distribute approximately 50% of consolidated net profit after tax
as a cash dividend. Dividends of US$0.05 per ordinary share were
declared in respect of the year ended 31 December 2014. In light of
the material reduction in the oil price, adverse financial
conditions prevailing in Russia and the losses incurred, the Board
is not recommending a dividend in respect of the year ended 31
December 2015
Capital expenditure
During 2015 capital expenditure of US$10.4 million was incurred
(2014: US$5.6 million), of which US$9.8 million was on development
and producing assets (2014: US$ 5.6 million) and US$0.6 million was
incurred on exploration (2014: nil). The most significant
components of the capital expenditure in 2015 relate to successful
drilling on the VM field with additional sums on unsuccessful
drilling on the Uzenskoye and Sobolevskoye fields and on the Yuzhny
Mironovskaya exploration prospect. The unsuccessful expenditure has
been expensed.
Balance sheet and financing
As at 31 December 2015, the Group held cash and bank deposits of
US$6.8 million (2014: US$15.8 million) with no debt. All of the
Group's cash balances are held in bank accounts in the UK and
Russia and the majority of the Group's cash is held in US
Dollars.
As at 31 December 2015, the Group's intangible assets decreased
to US$2.9 million (2014: US$3.7 million). Property, plant and
equipment, decreased to US$48.3 million (2014: US$57.8 million),
primarily reflecting the impact of foreign exchange adjustments.
The carrying value of the Group's assets relating to its main cash
generating units have been subject to impairment testing. The
result of the impairment tests, including sensitivity analysis
around the central economic assumptions as detailed in Note 4(b) to
the Accounts, showed no requirement for impairment, although as
noted above there were impairments and write-offs relating to
unsuccessful operations.
On 9 July 2014 the capital reduction approved by shareholders at
the Company's Annual General Meeting on 6 June 2014 became
effective following confirmation by the High Court, the filing of
the Court Order and a Statement of Capital with Companies House and
the fulfilment of certain minor undertakings given to the Court. As
a result, the Share Premium Account of the Company, amounting to
US$165.9 million, was cancelled and the equivalent sum credited to
the Company's Profit and Loss Account, thereby creating
distributable reserves.
For the year ending 31 December 2015, the Group recorded a
currency retranslation expense of US$15.3 million (2014: US$49.0
million) in its Other comprehensive income, relating to the
devaluation of the Ruble against the US dollar.
The Group's committed capital expenditures are less than
expected cash flow from operations and cash-on-hand and such
expenditures can be managed in light of the sharp reduction in
international oil prices and the devaluation of the Ruble. The
Group may consider additional debt facilities to fund the
longer-term development of its existing licences and operational
facilities as appropriate.
The Group's financial statements are presented on a going
concern basis.
Tony Alves
Chief Financial Officer
Five year financial and operational summary
Sales volumes 2015 2014 2013 2012 2011
-------------------------- -------------- -------------- --------------- --------------- ---------------
Oil & condensate
(barrels) 438,910 603,950 547,257 529,501 546,817
Gas (mcf) 4,545 5,671 3,128 1,193 1,348
Total (boe) 1,196,410 1,549,117 1,068,585 728,334 771,479
Operating Results 2015 2014 2013 2012 2011
(US$ 000)
-------------------------- -------------- -------------- --------------- --------------- ---------------
Oil and condensate
sales 11,041 27,220 26,067 25,526 25,425
Gas sales 6,786 12,203 8,554 2,769 3,146
-------------- -------------- --------------- --------------- ---------------
Revenue 17,827 39,423 34,621 28,295 28,571
Production costs (6,016) (7,805) (5,946) (3,776) (3,126)
Production based
taxes (5,877) (8,344) (8,095) (8,951) (9,537)
Depletion, depreciation
and other (2,369) (4,656) (2,611) (2,280) (2,641)
Other (1,327) (1,709) (1,799) (1,562) (991)
-------------- -------------- --------------- --------------- ---------------
Cost of sales (15,589) (22,514) (18,451) (16,569) (16,295)
Gross profit 2,238 16,909 16,170 11,726 12,276
Selling expenses (319) - - - -
Exploration expense (635) - (2,519) (8,475) (200)
Write-off of development
assets (2,950) - (1,439) (188) (5,612)
Operating, admin
& other expenses (3,377) (4,157) (4,029) (8,969) (5,991)
-------------- -------------- --------------- --------------- ---------------
Operating profit/(loss) (5,043) 12,752 8,183 (5,906) 473
Net realisation 2015 2014 2013 2012 2011
-------------------------- -------------- -------------- --------------- --------------- ---------------
Oil & condensate
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(US$/barrel) 25.16 45.07 47.63 .21 46.50
Gas (US$/mcf) 1.49 2.15 2.73 2.32 2.33
Operating data (US$/boe) 2015 2014 2013 2012 2011
-------------------------- -------------- -------------- --------------- --------------- ---------------
Production and selling
costs 5.29 5.04 5.56 5.18 4.05
Production based
taxes 4.91 5.39 7.58 12.29 12.36
Depletion, depreciation
and other 1.98 3.01 2.44 3.13 3.42
EBITDA calculation 2015 2014 2013 2012 2011
(US$ 000)
-------------------------- -------------- -------------- --------------- --------------- ---------------
Operating profit/(loss) (5,043) 12,752 8,183 (5,906) 473
Exploration expense 635 - 2,519 8,475 200
DD&A and other non-cash
expense 5,319 4,656 4,050 5,413 8,253
-------------- -------------- --------------- --------------- ---------------
EBITDA 911 17,408 14,752 7,982 8,926
EBITDA per boe 0.76 11.24 13.81 10.96 11.57
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:
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 could impact the profitability of the Group's
activities. Additionally, the Group's production is predominantly
sold in the domestic Russian markets which are influenced by
domestic supply and demand factors, the level of Russian export
taxes and regional transportation costs.
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.
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 developed
arrangements to sell oil and condensate into regional export
markets to mitigate this risk. Gas sales are made, via an
intermediary, into the domestic market via the Gazprom pipeline
network. The region in which the Group operates is reliant on
external gas supplies. Consequently the risk of insufficient demand
for the Group's gas is considered low. Gas sales have generally
been conducted as expected, subject to occasional constraints
during pipeline maintenance operations. However, the Group is
studying the feasibility of construction of a separate pipeline to
connect with a facility owned by a nearby upstream operator.
Oil and gas production taxes
The Group's sales generated from oil and gas production are
subject to Mineral Extraction Taxes, which form a material
proportion of the total costs of sales. The rates of these taxes
are subject to changes by the Russian government. Changes to rates
which come into effect during 2015 materially increased the rates
on crude oil, condensate and natural gas. With oil prices at low
levels and Russian Government budgets under pressure, there are
risks of further adverse changes to production taxes.
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 is speculative and involves a high degree of risk.
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.
During 2012, the Group commissioned a reserve evaluation based
on reporting standards set by the Society of Petroleum Engineers.
If the actual results of producing the Group's fields are
significantly different to expectations, there may be changes in
the future estimates of reserves. These may impact the balance
sheet carrying values of the Group's Intangible Assets and the
Group's Property, Plant and Equipment.
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. 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 regards 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.
Foreign currency risk
The Group's capital expenditures and operating costs are
predominantly in Russian Rubles ("RUR") while a minority of
administrative costs are in US Dollars, Euros and Pounds Sterling.
Revenues are predominantly received in RUR so consequently 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, the significant
devaluation of the RUR against the US dollar negatively impacts 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 instability 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 developing 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.
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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 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 2015 the Group had US$6.8 million of cash and
cash equivalents of which US$2.0 million was held in bank accounts
in Russia. 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 2015 the Group has
budgeted capital expenditures of less than US$1 million primarily
for the continuing development of gas and condensate production and
approximately US$1.5 million of accounts payable relating to
capital expenditures incurred in the year ended 31 December 2015.
The Board considers that the Group will have sufficient liquidity
to meet its obligations. All current and planned capital
expenditures are discretionary and may be deferred or cancelled in
the light of the Group's cash generation and liquidity
position.
Through its ordinary course activities, the Group is exposed to
legal, operational and development risk that could delay growth in
its cash generation from operations or may require additional
capital investment that could place increased burden on the Group's
available financial resources.
The Group is also exposed to fraudulent transfers of funds from
its bank accounts. During the year ended 31 December 2015, the
Group significantly enhanced its protections and procedures after
suffering such fraudulent transfers.
Capital risk
The Group manages capital to ensure that it is able to continue
as a going concern whilst maximising the return to shareholders.
The Group is not subject to any externally imposed capital
requirements. The Board regularly monitors the future capital
requirements of the group, particularly in respect of its ongoing
development programme. Management expects that the cash generated
by the operating fields will be sufficient to sustain the Group's
operations and committed capital investment for the foreseeable
future and has a policy of maintaining a minimum level of liquidity
to cover forward obligations. Further short-term debt facilities
may be arranged to provide financial headroom for future
development activities.
Tony Alves
Chief Financial Officer
Abbreviated Financial Statements
for the year ended 31 December 2015
Group Income Statement
(presented in US$ 000)
Year ended 31 December Notes 2015 2014
Revenue 17,827 39,423
Cost of sales 4 (15,589) (22,514)
------------------ ------------------
Gross profit 2,238 16,909
Selling expenses 4 (319) -
Operating and administrative
expenses 4 (3,377) (4,157)
Exploration and evaluation
expense 4(a) (635) -
Write off of development
assets 4(b) (2,950) -
------------------ ------------------
Operating (loss)/profit (5,043) 12,752
Interest income 117 245
Interest expense - -
Other gains and losses -
net 5 306 3,290
------------------ ------------------
(Loss)/profit for the year
before tax (4,620) 16,287
Deferred income tax 559 (3,229)
Current income tax (3) -
------------------ ------------------
(Loss)/profit for the year (4,064) 13,058
Attributable to:
The owners of the parent
Company (4,064) 13,058
================== ==================
Basic and diluted (loss)/profit
per share (in US dollars) (0.05) 0.16
Weighted average number of
shares outstanding 81,017,800 81,017,800
Group Statement of Comprehensive Income
(presented in US$ 000)
Year ended 31 December 2015 2014
(Loss)/profit for the year attributable
to equity shareholders of the
Company (4,064) 8,559
Other comprehensive income items
that may be reclassified to profit
and loss:
Currency translation differences (15,301) (48,955)
Total comprehensive (expense)
for the year (19,366) (35,897)
Attributable to:
The owners of the Parent Company (19,366) (35,897)
Group Balance Sheet
(presented in US$ 000)
At 31 December Notes 2015 2014
ASSETS
Non-current assets
Intangible assets 6 2,867 3,746
Property, plant and equipment 7 48,290 57,819
Other non-current assets 155 68
Deferred tax assets 1,098 706
----------------- -----------------
Total non-current assets 52,410 62,339
Current assets
Cash and cash equivalents 8 6,769 15,767
Inventories 9 1,067 1,099
Other receivables 10 1,449 918
----------------- -----------------
Total current assets 9,285 17,784
Total assets 61,695 80,123
================= =================
EQUITY AND LIABILITIES
Equity
Share capital 1,485 1,485
Share premium (net of issue - -
costs)
Other reserves (86,117) (70,816)
Accumulated profits/(losses) 11 140,037 145,114
----------------- -----------------
Equity attributable to the
shareholders of the parent 55,405 75,783
Non-current liabilities
Asset retirement obligation 146 189
Deferred tax liabilities 1,995 2,478
----------------- -----------------
Total non-current liabilities 2,141 2,667
Current liabilities
Trade and other payables 12 4,149 1,673
----------------- -----------------
Total current liabilities 4,149 1,673
Total equity and liabilities 61,695 80,123
================= =================
Approved by the Board of Directors on 31 March 2016 and signed
on its behalf by
Tony Alves
Chief Financial Officer
Group Cash Flow Statements
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(presented in US$ 000)
Year ended 31 December Notes 2015 2014
(Loss)/profit for the year
before tax (4,620) 16,287
Adjustments to (loss)/profit
before tax:
Depreciation 2,369 4,683
E & E expense 635 -
Write off of development 2,950 -
assets
Other non-cash expenses - -
Foreign exchange differences (942) (5,297)
--------------- ---------------
Operating cash flow prior
to working capital 392 15,673
Working capital changes
(Increase)/decrease in trade
and other receivables (1,144) 1,621
Increase/(decrease) in payables 1,893 (971)
Decrease/(increase) in inventory 22 (77)
--------------- ---------------
Cash flow from operations 1,163 16,246
Income tax paid (3) -
Net cash flow generated from
operating activities 1,160 16,246
--------------- ---------------
Cash flows from investing
activities
Expenditure on exploration
and evaluation 6 (554) -
Purchase of property, plant
and equipment 7 (8,117) (5,520)
--------------- ---------------
Net cash used in investing
activities (8,671) (5,520)
--------------- ---------------
Cash flows from financing
activities
Equity dividends paid (1,013) (3,038)
--------------- ---------------
Net cash outflow from financing
activities (1,013) (3,038)
--------------- ---------------
Effect of exchange rate changes
on cash and cash equivalents (474) (2)
Net increase/(decrease) in
cash and cash equivalents (8,998) 7,686
Cash and cash equivalents
at beginning of the year 8 15,767 8,081
Cash and cash equivalents
at end of the year 8 6,769 15,767
=============== ===============
Group Statement of Changes in Shareholders' Equity
(presented in US$ 000)
Share Share Currency Share Accumulated Total
Capital Premium Translation Grant Profit/(Loss) Equity
Reserves Reserve
Opening equity
at 1 January
2015 1,485 - (76,049) 5,233 145,114 75,783
Loss for the
year - - - - (4,064) (4,064)
Transactions
with
owners
Equity
dividends
paid - - - - (1,013) (1,013)
-------------- ----------------- -------------------- -------------- -------------------- --------------
Total
transactions
with owners - - - - (1,013) (1,013)
Currency
translation
differences - - (15,301) - - (15,301)
-------------- ----------------- -------------------- -------------- -------------------- --------------
Total
comprehensive
income - - (15,301) - (4,064) (19,365)
Closing equity
at 31
December
2015 1,485 - (91,350) 5,233 140,037 55,405
============== ================= ==================== ============== ==================== ==============
Opening equity
at 1 January
2014 1,485 165,873 (27,094) 5,233 (30,779) 114,718
Profit for the
year - - - - 13,058 13,058
Transactions
with
owners
Equity
dividends
paid - - - - (3,038) (3,038)
Cancellation
of
share premium
account - (165,873) - - 165,873 -
-------------- ----------------- -------------------- -------------- -------------------- --------------
Total
transactions
with owners - (165,873) - - 162,835 (3,038)
Currency
translation
differences - - (48,955) - - (48,955)
-------------- ----------------- -------------------- -------------- -------------------- --------------
Total
comprehensive
income - - (48,955) - 13,058 (35,897)
Closing equity
at 31
December
2014 1,485 - (76,049) 5,233 145,114 75,783
============== ================= ==================== ============== ==================== ==============
Notes to the Abbreviated Financial Statements
for the year ended 31 December 2015
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 4.
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
set out in the Strategic Report in pages 4 to 11; the financial
position of the Group, its cash flows, liquidity position and
borrowing facilities are described in the Financial Review on pages
8 to 9. 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. Having reviewed the future
cash flow forecasts of the Group, the directors have concluded that
the Group will continue to have access to sufficient funds in order
to meet its obligations as they fall due for at least the
foreseeable future and thus continue to adopt the going concern
basis of accounting in preparing the annual financial
statements.
Disclosure of impact of new and future accounting standards
(a) New and amended standards and interpretations:
There are no IFRSs or IFRIC interpretations that are effective
for the first time for the financial year beginning on 1 January
2015 that have a material impact on the Group.
In accordance with the transitional provisions of IFRS 10, the
Group reassessed the control conclusion for its investees at 1
January 2015. No modifications of previous conclusions about
control regarding the Group's investees were required.
(b) Standards, amendments and interpretations to existing
standards that are not yet effective and have not been early
adopted by the Group. The following new standards, amendments to
standards and interpretations have been issued, but are not
effective for the financial year beginning 1 January 2015 and have
not been early adopted:
-- IFRS 9: Financial Instruments
-- IFRS 15: Revenue from Contracts with Customers
-- IFRS 16: Leases
The Group is yet to assess the full impact of these new
standards and amendments but does not expect them to have a
material impact on the financial statements, with the main effect
being the requirement for additional disclosures.
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1.2 Consolidation
(a) 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
No geographic segmental information is presented as all of the
companies operating activities are based in 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 Russian Federation.
The Group's gas sales, representing a substantial proportion of
revenues are made to a single customer. Details are provided in
Note 2.1(b).
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 the 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 2015 were:
-- GBP 1.517: US$ (2014: 1. 5532)
-- EUR 1.091: US$ (2014: 1. 2148)
-- US$ 1:72.883 RUR. (2014: 56.258)
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
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 and probable 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
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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
1.7 Inventories
Crude oil inventories are stated at the lower of cost of
production and net realisable value. Materials and supplies
inventories are recorded at average cost and are carried at amounts
which do not exceed the expected recoverable amount from use in the
normal course of business. Cost comprises direct materials and,
where applicable, direct labour plus attributable overheads based
on a normal level of activity and other costs associated in
bringing inventories to their present location and condition.
1.8 Trade and other receivables
Trade and other receivables are recorded initially at fair value
and subsequently measured at amortised cost using the effective
interest method, less provision for impairment. A provision for
impairment of trade receivables is established when there is
objective evidence that the Group will not be able to collect all
amounts due according to the original terms of the receivables. The
amount of the provision is the difference between the asset's
carrying amount and the present value of estimated future cash
flows, discounted at the original effective interest rate.
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.
(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 (2014:
$1.7 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 2.1(a)(i) of US$6,769,000
and US$15,767,000 at 31 December 2015 and 2014 respectively.
The Group's principal financial asset is cash and credit risk
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.
The Group's oil and condensate 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. Gas sales accounting for 38.4% of Group revenues in
2015 (2014: 33.3%) are made to OOO Trans Nafta. As at 31 December
2015 there were trade receivables of US$1.0million (31 December
2014: US$0.6 million) relating to gas sales. As at 31 December 2015
there was no provision for bad debts (2014: nil).
Rating of financial 31 December 31 December
institution (S&P) 2015 2014
A+ 4,794 7,123
BBB+ 1,579 4,971
BBB- 202 3,615
Other 195 58
----------------- ------------------
Total bank balance 6,769 15,767
================= ==================
(c) Liquidity risk
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 2016 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.
(d) 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 will be sufficient to sustain the Group's
operations and future capital investment for the foreseeable
future. Further short-term debt facilities may be arranged to
provide financial headroom for future development activities.
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 determine 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, and the Uzen oil field is a separate
CGU.
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,
inflation and discount rates. Key assumptions and estimates in the
impairment models relate to: commodity prices that are based on
forward curves for two years and the long-term corporate economic
assumptions which include a long term oil price of US$50 per
barrel. The models utilised are based on the remaining reserves in
the Proved category and future production profiles based on
established field development plans. Cost assumptions are based on
current experience and expectations, and levels of export and
mineral extraction taxes reflect rates set by current legislation.
A discount rate of 15% per annum is utilised in the models.
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As at 31 December 2015, the Group's impairment testing of the
property, plant and equipment related to each CGU indicated that no
impairment was required. Variations of the each of key economic
assumptions, including long term oil prices US$10 per barrel below
the central assumption, yielded net present values in excess of
carrying value for each CGU. However, following unsuccessful
operations on certain non-producing wells during 2015, management
decided to write off assets associated with these specific
operations. This is further detailed in Note 4(b).
(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 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. Management have
considered the sensitivity of this key assumption and in order for
an impairment issue to present itself to the Group, reserve
estimates would need to reduce by more than 25%.
An independent assessment of the reserves and net present value
of future net revenue ("NPV") attributable to the Group's three
principal fields, Dobrinskoye, Vostochny Makarovskoye and
Uzenskoye, as at 1 August 2012, was prepared in accordance with
reserve definitions set by the Oil and Gas Reserves Committee of
the Society of Petroleum Engineers ("SPE").
(c) Income taxes
Significant judgement is frequently required in estimating
provisions for deferred taxes. This process involves an assessment
of temporary differences resulting from differing treatment of
items for tax and accounting purposes. These differences result in
deferred tax assets and liabilities, which are included within the
balance sheet.
4. Cost of sales and administrative expenses - Group
Cost of sales and administrative expenses are as follows:
Year ended 31 December 2015 2014
US$ 000 US$ 000
Production expenses 7,368 9,530
Mineral extraction taxes 5,877 8,344
Depletion, depreciation
and amortisation 2,345 4,640
----------------------- -----------------------
Cost of Sales 15,589 22,514
======================= =======================
Total expenses are analysed
as follows:
Year ended 31 December 2015 2014
US$ 000 US$ 000
Export sales related expenses 319 -
Field operating expenses 6,016 7,805
Mineral extraction tax 5,877 8,344
Depreciation & amortization 2,369 4,656
Exploration & evaluation (a) 635 -
Write off of development (b) 2,950 -
assets
Salaries & staff benefits 2,471 2,896
Directors' emoluments and
other benefits 765 810
Audit fees 203 201
Taxes other than payroll
and mineral extraction 44 82
Legal & consulting 480 907
Fines and penalties - 99
Other 742 871
----------------------- -----------------------
Total 22,870 26,671
======================= =======================
(a) Exploration and evaluation: The principal component was the
write off of costs relating to the Yuzhny Mironovskaya prospect on
which an unsuccessful well was drilled during.
(b) Write off of development assets: In the year ended 31
December 2015, the principal sources of the write off of
development assets were impairment of the carrying value of the
Sobolevskoye field, the Urozhainoye-2 licence area in which it is
located and the cost of the attempted sidetrack to the
Sobolevskoye-11 well. There were also charges relating to
unsuccessful operations on well in the Uzen field and other minor
asset write offs.
5. Other gains and losses
Year ended 31 December 2015 2014
US$ 000 US$ 000
----------------- ----------------------
Foreign exchange gain 942 3,264
Loss from unauthorised (727) -
bank transfers
Other gains 91 27
----------------- ----------------------
Total other gains and losses 306 3,291
================= ======================
6. Intangible assets
Intangible assets represent exploration and evaluation assets
such as licenses, studies and exploratory drilling, which are
stated at historical cost, less any impairment charges or
write-offs.
Work in Exploration Total
progress: and evaluation
exploration
Note and evaluation
At 1 January 2015 151 3,595 3,746
Additions - 606 606
Write offs and
impairments 4(a) - (635) (635)
Transfers - - -
----------------- ----------------- -----------------
At 31 December
2015 151 3,566 3,717
Exchange adjustments (34) (816) (850)
----------------- ----------------- -----------------
At 31 December
2015 117 2,750 2,867
================= ================= =================
Work in Exploration Total
progress: and evaluation
exploration
and evaluation
At 1 January 2014 258 6,180 6,438
Additions - - -
Impairments - - -
Transfers - - -
----------------- ----------------- -----------------
At 31 December
2014 258 6,180 6,438
Exchange adjustments (107) (2,585) (2,692)
----------------- ----------------- -----------------
At 31 December
2014 151 3,595 3,746
================= ================= =================
7. Property, plant and equipment - Group
Movements in property, plant and equipment, for the years ended
31 December 2015 and 2014 are as follows:
Development Land Producing Other Total
Cost assets & buildings assets
US$ 000 US$ US$ 000 US$ US$
000 000 000
At 1 January 2015 8,523 842 57,944 701 68,010
Additions 378 - 9,422 - 9,800
Write-offs and
impairments (673) - (2,338) (51) (3,062)
Transfers (6,181) - 6,181 - -
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---------------------- ---------------- -------------- ------------- ------------
At 31 December
2015 2,046 842 71,210 650 74,747
Accumulated depreciation
At 1 January 2015 - - (9,589) (599) (10,188)
Adjustment for
assets written
off - - 10 51 61
Depreciation - - (2,384) (66) (2,450)
---------------------- ---------------- -------------- ------------- ------------
At 31 December
2015 - - (11,964) (614) (12,578)
Exchange adjustments (910) (192) (12,765) (13) (13,880)
---------------------- ---------------- -------------- ------------- ------------
NBV at 31 December
2015 1,136 650 46,481 23 48,290
====================== ================ ============== ============= ============
Development Land Producing Other Total
Cost assets & buildings assets
US$ 000 US$ US$ 000 US$ US$
000 000 000
At 1 January 2014 9,170 1,446 98,439 784 09,839
Additions 5,547 - 82 - 5,629
Transfers (901) - 901 - -
----------------------- --------------- -------------- ------------- ------------
At 31 December
2014 13,816 1,446 99,422 784 115,468
Accumulated depreciation
At 1 January 2014 - - (11,017) (551) (11,568)
Depreciation - - (4,635) (49) (4,684)
----------------------- --------------- -------------- ------------- ------------
At 31 December
2014 - - (15,652) (600) (16,252)
Exchange adjustments (5,293) (604) (35,418) (82) (41,397)
----------------------- --------------- -------------- ------------- ------------
NBV at 31 December
2014 8,523 842 48,352 102 57,819
======================= =============== ============== ============= ============
8. Term deposits, cash and cash equivalents
At 31 December 2015 2014
---------------- ----------------
US$ US$
000 000
Cash at bank and
on hand 6,769 15,767
Short term bank - -
deposits
Total cash and
cash equivalents 6,769 15,767
An analysis of Group deposits, cash and cash equivalents by bank
and currency is presented in the table below:
At 31 December 2015 2014
-------------- ---------------
Bank Currency US$ 000 US$ 000
United Kingdom
Barclays Bank PLC USD 4,750 6,943
Barclays Bank PLC GBP 44 180
Russian Federation
Unicreditbank RUR 70 123
Unicreditbank USD 195 3,492
ZAO Raiffeisenbank RUR 825 2,986
ZAO Raiffeisenbank USD 740 1,970
ZAO Raiffeisenbank EUR 132 15
Other banks and
cash on hand RUR 14 58
Total cash and cash equivalents 6,769 15,767
============== ===============
9. Inventories
At 31 December 2015 2014
US$ 000 US$ 000
Production consumables
and spare parts 704 1,060
Crude oil inventory 363 39
------------- --------------
Total inventories 1,067 1,099
============= ==============
10. Other receivables
At 31 December 2015 2014
US$ 000 US$ 000
VAT receivable 80 81
Prepayments 298 202
Trade receivables 987 579
Other accounts
receivable 84 56
-------------- --------------
Total other
receivables 1,449 918
============== ==============
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.
11. Accumulated profit/(loss)
At 31 December 2015 2014
US$ 000 US$ 000
--------------- ----------
Retained profits/(
losses) 145,114 (30,779)
Profit/(loss) for
the year (4,064) 13,058
Equity dividends
paid (1,013) (3,038)
Cancellation of
share premium - 165,873
--------------- ----------
Accumulated profit/(loss) 140,037 145,114
=============== ==========
12. Trade and other payables
At 31 December 2015 2014
US$ 000 US$ 000
--------------------- ----------------
Trade payables 2,467 268
Taxes other than
profit tax 750 881
Customer advances 932 524
--------------------- ----------------
Total 4,149 1,673
===================== ================
The maturity of the Group's and the Company's financial
liabilities are all between 0 to 3 months.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR AKDDQPBKDDNN
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